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

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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

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PART I

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

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

ITEM 1. BUSINESS

Overview

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

We maintain a subsidiary, BPZ Exploración & Producción S.R.L. (“BPZ E&P”),  registered in Peru through our wholly-owned subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership, and its subsidiary BPZ Energy, LLC, a Texas limited liability company.  Currently, we, through BPZ E&P, have license contracts for oil and gas exploration and production covering a total of approximately 2.2 million gross (1.9 million net) acres, in four blocks, in northwest Peru. Our license contracts cover ownership of the following properties: 51% working interest in Block Z-1 (0.6 million gross acres), 100% working interest in Block XIX (0.5 million gross acres), 100% working interest in Block XXII (0.9 million gross acres) and 100% working interest in Block XXIII (0.2 million gross acres). The Block Z-1 contract was signed in November 2001, the Block XIX contract was signed in December 2003 and 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.

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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.   

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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.

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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.

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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).

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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. 

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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.

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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.

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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.

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ITEM 1A.  RISK FACTORS

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

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

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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.

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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.

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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.

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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.

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

· fires;

· explosions;

· blow-outs and surface cratering;

· uncontrollable flows of natural gas, oil and formation water;

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

· pipe, cement, subsea well or pipeline failures;

· casing collapses;

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

· abnormally pressured formations; or

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

Experiencing any of these operating risks could lead to problems with any well bores, platforms, 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.

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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.  

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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.

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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.

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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.

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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.

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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. 

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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.

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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.

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ITEM 2.   PROPERTIES

Offices

Our corporate headquarters office is in Houston, Texas, where we lease approximately 13,300 square feet of office space under a lease agreement which expires in February 2016. We also currently lease administrative offices and warehouses in Peru. The administrative 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

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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 theCX11-16X 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.

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In the Piedra Redonda field, two wells were drilled by Belco in the late 1970s and early 1980s. Indications of natural gas were present in both wells. One well was completed, 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.

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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.

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

Under the Block XXII License Contract, we are required to relinquish at least 20% of the least prospective 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.

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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. 

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The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies.  NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.  Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Dan 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.

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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.

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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.

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ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

Market Information

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

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

	High		Low
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 13,154beneficial 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.

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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

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ITEM 6.  SELECTED FINANCIAL DATA

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

	For the Year Ended December 31,
Operating Results:	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

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

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

Overview

We are an independent oil and gas company focused on the exploration, development and production of oil and natural gas in Peru and Ecuador.  We also intend to utilize part of our planned future natural gas production as a supply source for the development of a gas-fired power generation facility in Peru, which we currently plan to 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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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%.

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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:

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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	)

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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

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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.

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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.

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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

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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.

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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.

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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.

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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	)

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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 deferredat 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.

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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.

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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.
 

	For the Year Ended December 31,
Cash Flows	2012			2011			2010
	(in thousands)
Cash provided by (used in):
Operating activities	$	(46,062	)	$	47,121		$	(5,125	)
Investing activities		(65,838	)		(93,883	)		(158,104	)
Financing activities		137,268			93,182			156,834

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2012 Operating Activities

Cash provided by operating activities decreased by $93.2 million to a use of cash of $46.1 million for the year ended December 31, 2012, from a source of cash of $47.1 million for the same period in 2011.  Cash flows in 2012 decreased due to higher geological, geophysical and engineering expense related to the Block Z-1 seismic program, lower sales volumes, higher costs and current taxes, partially offset by higher oil prices.  This resulted in a decrease of $63.3 million in cash flow before changes in operating assets and liabilities during 2012 compared to 2011.  Changes in cash flow as a result of changes in operating assets and liabilities provided a decrease in the use of cash of $29.9 million.  The decrease in the use of cash is due to:  (1) an increase in the change to value-added taxes of $27.9 million as we had more expenditures subject to value-added taxes and used less inventory in 2012 compared to the same period in 2011; (2) an increase in the change in accounts receivable due to amounts from our joint venture partner and the timing of oil deliveries and payments for those deliveries of $20.1 million; (3) an increase in inventory of $8.2 million and (4) an increase in the change of prepaid and other assets of $4.3 million.  Offsetting these uses of cash are changes in operating assets and liabilities providing sources of cash including: (1) an increase in the change to accounts payables of $20.6 million that includes amounts due from our joint venture partner; (2) an increase in the change to accrued and other liabilities balances of $7.3 million and (3) an increase in the changes of current tax receivables and payables as a result of the sale of a 49% participating interest in Block Z-1 and refunds of $2.7 million.

2011 Operating Activities

Cash provided by operating activities increased by $52.2 million to a source of cash of $47.1 million for the year ended December 31, 2011, from a use of cash of $5.1 million for the same period in 2010.  Cash flows in 2011 increased due to higher oil prices and the impact of working capital items, partially offset by lower sales volumes and higher costs.  This resulted in an increase of $18.6 million in cash flow before changes in operating assets during 2011 compared to 2010.  Changes in cash flow as a result of changes in operating assets and liabilities provided an increase in the source of cash of $33.6 million.  The increase in the source of cash was due to: (1) a decrease in the changes of current tax receivables and payables as a result of achieving commercial production and refunds of $17.2 million; (2) a decrease in the change in accounts receivable due to the timing of oil deliveries and payments for those deliveries of $12.8 million; (3) a decrease in the change to value-added taxes and inventory of $11.8 million as we had less expenses subject to VAT, an early VAT recovery and used more inventory in 2011 compared to the same period in 2010 (4) a decrease in inventory of $9.3 million; (5) an increase in the change to accrued and other liabilities balances of $3.2 million and (6) a decrease in the change of prepaid and other assets of $2.4 million. Offsetting these sources of cash was changes in operating assets and liabilities providing uses of cash including a decrease in the change to accounts payables of $23.1 million.

2012 Investing Activities

Net cash used in investing activities decreased by $28.1 million to $65.8 million for the year ended December 31, 2012 from $93.9 million for the same period in 2011.  The decrease in cash used in investing activities is due to net proceeds received from our divestiture of a 49% participating interest in Block Z-1 of $79.3 million and decreased capital expenditures of $7.6 million, primarily due to our funding of capital expenditures for Block Z-1 by Pacific Rubiales under the carry agreement in place after December 14, 2012, partially offset by an increase in cash used for restricted cash of $58.8 million related to our debt service reserve accounts under our credit agreements.

2011 Investing Activities

Net cash used in investing activities decreased by $64.2 million to $93.9 million for the year ended December 31, 2011 from $158.1 million for the same period in 2010.  The decrease in cash used in investing activities is due to decreased capital expenditures of $68.3 million in 2011, as our drilling operations were less in 2011 than in 2010 and the final payments for the GE Turbines made in 2010, partially offset by an increase in cash used for restricted cash of $4.1 million related to the establishment of debt service reserve accounts under our new credit agreements.

2012 Capital Expenditures

During the year ended December 31, 2012, we incurred gross capital expenditures of approximately $88.7 million associated with our development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of gas-fired power generation of electricity for sale in Peru.

During the year ended December 31, 2012, we incurred approximately $60.2 million related to costs incurred in the design, fabrication, installation and pipeline connections related to the CX-15 platform and incurred $7.8 million for the development of and equipment for permanent production facilities.

In addition, during the year ended December 31, 2012, we added approximately $7.2 million of costs to the power plant, which primarily consisted of capitalized interest, approximately $5.7 million related to the CX-15 development drilling program and incurred approximately $7.8 million related to other capitalized costs.

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The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012.  Pacific Rubiales provided funding for capital expenditures for Block Z-1 of $70.7 million for the year ended December 31, 2012, which we recorded as additions to property and equipment, until the closing date, at which time Pacific Rubilales exchanged for certain loans, plus any other amounts due to us or from us under the SPA.

For the year ended December 31, 2012 included in the amounts above, we capitalized approximately $0.5 million of depreciation expense and $15.6 million of interest expense to construction in progress.

2011 Capital Expenditures

During the year ended December 31, 2011, we incurred capital expenditures of approximately $90.5 million associated with our development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of gas-fired power generation of electricity for sale in Peru.

During the year ended December 31, 2011, we incurred approximately $26.6 million related to costs incurred in the design and fabrication of the CX-15 platform and incurred $22.3 million for development and equipment for permanent production facilities.

In 2011, we also incurred $11.0 million on the onshore Pampa la Gallina (PLG-1X) exploratory well in Block XIX.  In December 2011, the $12.3 million of costs associated with the PLG-1X well along with $0.3 million costs of a water well to be used with the PLG-1X well and a $0.5 million retirement obligation asset were written off as dry hole costs.  In the fourth quarter of 2011, after completing technical review of information obtained during the drilling of the PLG-1X well, management declared that the well had no further utility.

In addition, we incurred approximately $4.6 million for the development of the A-9G well, $4.6 million for the development of the A-13E well, $4.0 million for the development of the A-12F well, and $1.2 million for the development of the A-17D water injection well.

We also added approximately $6.3 million of costs to the development of our power plant, which primarily consists of capitalized interest, and incurred approximately $2.7 million on the Caleta Cruz dock.

For the year ended December 31, 2011, we incurred expenditures of approximately $1.6 million in computer hardware, software and telecommunication equipment, $1.2 million in machinery and equipment, $0.6 million for assets in transit, $0.3 million for costs for office equipment and leasehold improvements in its offices Peru and approximately $3.5 million of other capitalized costs.

For the year ended December 31, 2011 included in the amounts above, in accordance with the “successful efforts” method of accounting, we capitalized approximately $0.3 million of depreciation expense and $10.7 million of interest expense, to construction in progress.

2012 Financing Activities

Cash provided by financing activities increased by $44.1 million to a source of cash of $137.3 million for the year ended December 31, 2012, compared to a source of cash of $93.2 million for the same period in 2011. The increase in cash provided by financing activities is due to: (1) increased borrowings of $80.7 million, due to the new loans from Pacific Rubiales in 2012 versus the drawdown of the $40.0 million secured debt facility and the drawdown of the $75.0 million secured debt facility in 2011 and (2) lower debt issue costs of $2.4 million.  Partially offsetting the increases in cash are decreases in cash due to (1) higher repayments of borrowings of $38.1 million related to the $75.0 million secured debt facility and the $40.0 million secured debt facility and (2) lower proceeds from equity issuances of $0.8 million.

2011 Financing Activities

Cash provided by financing activities decreased by $63.6 million to $93.2 million for the year ended December 31, 2011, compared to $156.8 million for the same period in 2010. The decrease in cash provided by financing activities is due to decreased borrowings of $55.9 million and higher repayments of borrowings of $8.8 million that is partially offset by lower debt issue costs of $0.1 million and increased proceeds from equity issuances of $1.0 million.

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Shelf Registration

To finance our operations we may sell additional shares of our common stock or other securities. Our certificate of formation does not provide for preemptive rights, although we may grant similar rights by contract from time to time. 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. This registration statement will expire on December 20, 2013.

Lima Stock Exchange Listing

 In October 2011, we were approved for listing on the Bolsa de Valores in Lima, Peru (BVL).  Our common shares trade in United States dollar currency on the Lima stock exchange under the symbol BPZ. 

Debt and Capital Lease Obligations

At December 31, 2012 and  2011, debt and capital lease obligations consist of the following:

	December 31, 2012		December 31, 2011
	(in thousands)
$170.9 million Convertible Notes,  6.5%, due March 2015, net of discount of ($17.4) million at December 31, 2012 and ($24.1) million at December 31, 2011	$	153,479	$	146,781
$75.0 million Secured Debt Facility, 3-month LIBOR plus 9%, due July 2015		35,000		75,000
$40.0 million Secured Debt Facility, 3-month LIBOR plus 8%, due January 2015		32,727		40,000
Capital Lease Obligations		-		3,457
		221,206		265,238
Less: Current maturity of long-term debt and capital lease obligations		24,046		16,854
Long-term debt and capital lease obligations, net	$	197,160	$	248,384

$170.9 Million Convertible Notes due 2015

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

The interest rate on the 2015 Convertible Notes is 6.50% per year with interest payments due on March 1st and September 1st of each year.  The 2015 Convertible Notes mature with repayment of $170.9 million (assuming no conversion) due on March 1, 2015.

The initial conversion rate of 148.3856 shares per $1,000 principal amount (equal to an initial conversion price of approximately $6.74 per share of common stock) was adjusted on February 3, 2011 in accordance with the terms of the Indenture.

As a result, the conversion rate and conversion price changed to 169.0082 and $5.9169, respectively.  Should there be a conversion, we must deliver, at our option, either (1) a number of shares of its common stock determined as set forth in the Indenture, (2) cash, or (3) a combination of cash and shares of our common stock.

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Holders may convert their 2015 Convertible Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances:

(1) during any fiscal quarter (and only during such fiscal quarter) commencing after March 31, 2010, if the last reported sale price of our common stock is greater than or equal to 130% of the conversion price of the 2015 Convertible Notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter;

(2) prior to January 1, 2015, during the five business-day period after any ten consecutive trading-day period in which the trading price of $1,000 principal amount of the 2015 Convertible Notes for each trading day in the measurement period was less than 97% of the product of the last reported sale price of our common stock and the conversion rate on such trading day;

(3) if the 2015 Convertible Notes have been called for redemption; or

(4) upon the occurrence of one of a specified number of corporate transactions.

Holders may also convert the 2015 Convertible Notes at their option at any time beginning on January 3, 2015, and ending at the close of business on the second business day immediately preceding the maturity date.

On or after February 3, 2013, we may redeem for cash all or a portion of the 2015 Convertible Notes at a redemption price of 100% of the principal amount of the notes to be redeemed plus any accrued and unpaid interest to, but not including, the redemption date, plus a “make-whole” payment if: (1) for at least 20 trading days in any consecutive 30 trading days ending within 5 trading days immediately before the date we mail the redemption notice, the “last reported sale price” of our common stock exceeded 175% of the conversion price in effect on that trading day, and (2) there is no continuing default with respect to the notes that has not been cured or waived on or before the redemption date.

If we experience any one of certain specified types of corporate transactions, holders may require us to purchase all or a portion of their 2015 Convertible Notes. Any repurchase of the notes pursuant to these provisions will be for cash at a price equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the purchase date.

The Indenture agreement contains customary terms and covenants and events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the 2015 Convertible Notes.

Net proceeds from the sale of the 2015 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by us, were approximately $164.9 million.  The initial purchaser received commissions of approximately $5.5 million in connection with the sale and we incurred approximately $0.6 million of direct expenses in connection with the offering.  We used the net proceeds for general corporate purposes, including capital expenditures and working capital, reduction or refinancing of debt, and other corporate obligations.

We accounted for the 2015 Convertible Notes in accordance with Accounting Standard Codification (“ASC”) Topic 470, “Debt,” as it pertains to accounting for convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement).  Under the accounting guidance, convertible debt instruments that may be settled entirely or partially in cash upon conversion are required to be separated into liability and equity components, with the liability component amount determined in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The value assigned to the liability component is determined by measuring the fair value of a similar liability that does not have an equity conversion feature. The value assigned to the equity component is determined by deducting the fair value of the liability component from the initial proceeds. The excess of the principal amount of the liability component over its carrying amount (the non-cash discount) is amortized to interest cost using the effective interest method over the term of the debt agreement.  In addition, transaction costs incurred that directly relate to the issuance of convertible debt instruments must be allocated to the liability and equity components in proportion to the allocation of proceeds and accounted for as debt issuance costs and equity issuance costs, respectively.

We estimated our non-convertible borrowing rate at the date of issuance of the 2015 Convertible Notes to be 12%.  The 12% non-convertible borrowing rate represented the borrowing rate of similar companies with the same credit quality as us and was obtained through a quote from the initial purchaser.  Using the income method and discounting the principal and interest payments of the 2015 Convertible Notes using the 12% non-convertible borrowing rate, we estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $136.3 million with the discount being approximately $34.6 million.  The discount is being amortized as non-cash interest expense over the life of the notes using the effective interest method.  In addition, we allocated approximately $4.8 million of the $6.1 million of fees and commissions as debt issue costs that are being amortized as non-cash interest expense over the life of the loan using the effective interest method. The remaining $1.3 million of fees and commissions were treated as transaction costs associated with the equity component.

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The following table is the estimated remaining cash payments including interest payments related to the 2015 Convertible Notes, assuming no conversion (in thousands):

Year
2013	$	11,111
2014		11,111
2015		176,493
Total estimated remaining cash payments related to the 2015 Convertible Notes	$	198,715

We evaluated the 2015 Convertible Notes agreement for potential embedded derivatives, noting that the conversion feature and make-whole provisions did not meet the embedded derivative criteria as set forth in ASC Topic 815, “Derivatives and Hedging.”  Therefore, no additional amounts have been recorded for those items.

As of December 31, 2012, the net amount of $153.5 million includes the $170.9 million of principal reduced by $17.4 million of the remaining unamortized discount.  The net amount of the equity component is $33.3 million, which includes the initial discount of $34.6 million reduced by $1.3 million of direct transaction costs.  The remaining unamortized discount of $17.4 million will be amortized into interest expense, using the effective interest method, over the remaining life of the loan agreement, whose term expires in March 2015.  At December 31, 2012, using the conversion rate of 169.0082 shares per $1,000 principal amount of the 2015 Convertible Notes, if the $170.9 million of principal were converted into shares of common stock, the notes would convert into approximately 28.9 million shares of common stock.  As of December 31, 2012, there is no excess if-converted value to the holders of the 2015 Convertible Notes as the price of our common stock at December 31, 2012, $3.15 per share, is less than the conversion price.

For the year ended December 31, 2012, the annual effective interest rate on the 2015 Convertible Notes, including the amortization of debt issue costs, was approximately 12.6%.

The following table is the amount of interest expense related to the 2015 Convertible Notes, disregarding capitalized interest considerations, for the year ended December 31, 2012, 2011 and 2010, respectively:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Interest expense related to the contractual interest coupon	$	11,111	$	11,111	$	10,062
Amortization of debt discount expense		6,698		5,961		4,480
Amortization of debt issue costs		956		916		737
Interest expense related to the 2015 Convertible Notes	$	18,765	$	17,988	$	15,279

$75.0 Million Secured Debt Facility

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

Proceeds from the $75.0 million secured debt facility were utilized to pay certain fees and expenses under the $75.0 million secured debt facility, to fund a debt service reserve account under the $75.0 million secured debt facility, to reimburse certain affiliates of BPZ E&P for up to $14.0 million of capital and exploratory expenditures incurred by them in connection with the development of Block Z-1 and up to $6.0 million of capital and exploratory expenditures incurred by them in connection with the development in Block XIX in northwest Peru, and to finance BPZ E&P’s capital and exploratory expenditures in connection with the development of Block Z-1.

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As a result of the prepayment and amendment 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% were 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.  The $1.1 million of new debt issue costs was combined with the remaining $1.3 million of unamortized debt issue costs and will be amortized over the amended term, ending in July 2015, using the effective interest method.  For further information on debt issue costs see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

The $75.0 million secured debt facility, as amended, provides for ongoing fees payable by BPZ E&P to the lenders, including an administration fee of 0.50% of the principal amount outstanding and a Performance Based Arranger Fee whose amount is determined by the change in the price of Brent crude oil at inception of the loans and the price at each principal repayment date in accordance with the original loan principal repayment dates, subject to a 12% ceiling of the original principal amount borrowed.    For further information on the Performance Based Arranger Fee, see Note-11, “Derivative Financial Instruments” and Note-13, “Fair Value Measurements and Disclosures.”

The $75.0 million secured debt facility requires us to establish and maintain a debt service reserve account during the term of the debt facility.  At December 31, 2012 the debt service reserve account was fully funded for the outstanding principal balance of $35.0 million.  For further information regarding the debt service reserve account and its requirements, see Note-8, “Restricted Cash and Performance Bonds.”

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, a corporation owned by the Peruvian government empowered to become a party in the contracts for the exploration and/or exploitation of hydrocarbons in order to promote these activities in Peru, (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 amendment to the $75.0 million secured debt facility 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 that commenced in January 2013 and extending through July 2015.  The $75.0 million secured debt facility has an annual interest rate of the three month LIBOR rate plus 9%.  Interest is due and payable quarterly.

The $75.0 million secured debt facility, as amended, contains covenants that limit our ability to, among other things, incur additional debt other than the Pacific Rubiales loans, create certain liens, enter into transactions with affiliates, pay dividends on or repurchase our stock of the Company or our subsidiaries, or sell assets other than to Pacific Rubiales or merge with another entity.  In addition, we must complete certain projects in the Corvina and Albacora offshore fields in Block Z-1 by certain scheduled dates.  The $75.0 million secured debt facility as amended also contains customary financial covenants, including (i) a maximum consolidated leverage ratio, (ii) a minimum consolidated interest coverage ratio, (iii) a maximum capitalization ratio, (iv) a minimum oil production quota per quarter, (v) a minimum debt service coverage ratio, (vi) a minimum proved developed producing reserves coverage ratio, (vii) a maximum indebtedness, and (viii) a minimum liquidity ratio. For the quarter ending December 31, 2012, we obtained a waiver from Credit Suisse relating to our minimum oil production.  In addition on March 8, 2013, for the quarter ending March 31, 2013, we obtained a waiver from Credit Suisse relating to our minimum oil production and the date for first production from the CX-15 platform.  We were in compliance with these revised financial covenants at December 31, 2012.

The $75.0 million secured debt facility, as amended, provides for events of default customary for facilities of this type, the occurrence and continuation of which could result in the acceleration of amounts due under the facility. In addition, the $75.0 million secured debt facility provides that BPZ E&P has the right, at any time, to prepay the loans in whole, but not in part, subject to certain conditions and sets forth certain conditions for mandatory prepayments of the loan.

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The following table is the estimated remaining cash payments related to the $75.0 million secured debt facility, as amended, and excluding potential payments for the Performance Based Arranger Fee but including interest payments (in thousands).  Currently the principal component would be paid via release of the corresponding cash from the debt service reserve account.

Year
2013	$	12,038
2014		14,104
2015		14,164
Total estimated remaining cash payments related to the $75.0 million secured debt facility	$	40,306

$40.0 Million Secured Debt Facility

In January 2011, we, through our subsidiaries, completed a credit agreement with Credit Suisse where Credit Suisse provided a $40.0 million secured debt facility to our power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L.  On April 27, 2012, we and our subsidiaries, Empresa Eléctrica Nueva Esperanza S.R.L. and BPZ E&P, entered into a fourth amendment to the $40.0 million secured debt facility with Credit Suisse.

Proceeds from the $40.0 million secured debt facility were utilized to meet our 2011 capital expenditure budget, to finance our exploration and development work programs, and to reduce other debt obligations.

As a result of the amendment entered into during the second quarter of 2012, we incurred $0.8 million of debt issue costs.  The $0.8 million of new debt issue costs was combined with the remaining $0.6 million of debt issue costs and will be amortized over the amended term, ending in January 2015, using the effective interest method.  For further information on debt issue costs, see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

The $40.0 million secured debt facility, as amended, provides for ongoing fees payable to Credit Suisse including a Performance Based Arranger Fee whose amount is determined by the change in the price of Brent crude oil at inception of the loan and the price at each principal repayment date in accordance with the original loan principal repayment dates, subject to a 18% ceiling of the original principal amount borrowed.    For further information on the Performance Based Arranger Fee, see Note-11, “Derivative Financial Instruments” and Note-13, “Fair Value Measurements and Disclosures.”

The $40.0 million secured debt facility is secured, in part, by three LM6000 gas-fired packaged power units (approximately $74.0 million) 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 $40.0 million secured debt facility requires us to establish and maintain a debt service reserve account during the term of the facility.  At December 31, 2012, the debt service reserve account was fully funded for the outstanding principal balance of $32.7 million.  For further information regarding the debt service reserve account and its requirements, see Note-8, “Restricted Cash and Performance Bonds.”

The amendment to the $40.0 million secured debt facility extended the maturity of the facility to January 2015, with revised principal repayments due in quarterly installments of $3.6 million that commenced in July 2012 and extending through January 2015.  The $40.0 million secured debt facility has a revised annual interest rate of the three month LIBOR rate plus 8%.  Interest is due and payable quarterly.

The amended $40.0 million secured debt facility subjects us to various financial covenants calculated as of the last day of each quarter, including a maximum leverage ratio, a minimum consolidated interest coverage ratio, a maximum consolidated capitalization ratio and minimum oil production quota per quarter.  For the quarter ending December 31, 2012, we obtained a waiver from Credit Suisse relating to our minimum oil production.  In addition on March 8, 2013, for the quarter ending March 31, 2013, we obtained a waiver from Credit Suisse relating to our minimum oil production.  We were in compliance with these revised financial covenants at December 31, 2012.

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The $40.0 million secured debt facility provides for events of default customary for facilities of this type, the occurrence and continuation of which could result in the acceleration of amounts due under the facility. In addition, the $40.0 million secured debt facility provides for a mandatory repayment of the loans if we secure financing for our gas-to-power project.

The following table is the estimated remaining cash payments related to the $40.0 million secured debt facility, as amended, and excluding potential payments for the Performance Based Arranger Fee but including interest payments (in thousands).  Currently the principal component would be paid via release of the corresponding cash from the debt service reserve account.

Year
2013	$	16,365
2014		15,607
2015		3,712
Total estimated remaining cash payments related to the $40.0 million secured debt facility	$	35,684

     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 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.

$15.0 Million IFC Reserve-Based Credit Facility

In 2008, we secured a $15.0 million reserve-based lending facility (“IFC Facility”) agreement (the “Loan Agreement”) with IFC through our subsidiaries BPZ E&P and BPZ Marine Peru S.R.L. as borrowers. The IFC Facility was to originally mature in December 2012; however, following the $40.0 million secured debt facility issued by us January 2011, a portion of the proceeds was used to repay the amount outstanding to the IFC.

The IFC Facility bore interest at an approximate rate of LIBOR plus 2.75%, equivalent to 3.21% based on the six month LIBOR rate of 0.46% at December 31, 2010.  The maximum amount available under this facility begins at $15.0 million and was to be reduced by $2.5 million beginning on December 16, 2010 and every six months thereafter during the term of the Loan Agreement.  The amount available under the IFC Facility was subject to a semi-annual borrowing base determination based on the value of oil reserves.  In addition, we were subject to various financial covenants calculated as of the last day of each quarter, including a life of field coverage ratio, life of loan coverage ratio, debt to equity ratio and interest coverage ratio. The Loan Agreement also provided for events of default, cure periods and lender remedies customary for facilities of this type.  We were in compliance with all material covenants of the Loan Agreement as of December 31, 2010.

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Other

In July 2009, we, through our subsidiary, BPZ E&P, entered into a $5.1 million short-term loan agreement to finance the purchase of casing and accessories for use in our current and future operations. The $5.1 million short-term loan bore an annual interest rate of 5.45% and was repaid in five monthly installments of approximately $1.0 million starting September 2009.  In connection with the $5.1 million short-term loan agreement, we were required to deposit $1.0 million with the lending institution as a guaranty for the loan.  The $1.0 million was applied to the last installment of the loan repayments. As of December 31, 2009, the remaining principal amount was approximately $1.0 million and, along with the accrued interest due, was repaid with the $1.0 million deposit and cash in January 2010.

Capital Leases

In June 2007, we entered into a capital lease agreement, with an option to purchase, for two vessels, the Namoku and the Nu’uanu, to assist in the development of the Corvina oil field. The capital lease assets were recorded at $6.2 million, which represented the present value of the minimum lease payments, or the aggregate fair market value of the assets.

In May 2009, we entered into an amendment of our lease agreement for two vessels under charter, the Namoku and the Nu’uanu. Under the terms of the amended lease agreement, the charter, originally set to expire in November 2009, was extended for five years commencing on May 1, 2009.  During the first 18 months of the amended lease term, the daily charter rate for the use of both vessels was fixed. Commencing on November 2010, the daily charter rate for the use of both vessels is based on a tiered structure with the daily rate dependent upon the amount of the previous month’s average daily per barrel price of West Texas Intermediate Crude Oil (“WTI”), as indicated on the New York Mercantile Exchange. Any amount paid by us after November 2010 over the initial daily rate as a result of the escalated tiered structure based on the price of WTI is considered contingent rental payments.  The amount of the contingent lease payments paid in 2012 and 2011 was $0.6 million and $1.6 million, respectively. The amended lease agreement contains a $3.0 million purchase option after the third year of the lease, a $2.0 million purchase option after the fourth year of the lease and a mandatory $1.0 million purchase obligation by us after the fifth year of the lease. We accounted for the amended lease agreement in accordance with ASC Topic 840, “Leases.”  Under the guidance, the lease agreement continues to be accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 34.9%.

In June 2008, we entered into a two year capital lease agreement to acquire the production equipment used on board the Namoku resulting in additional capital assets of approximately $2.4 million. Further we capitalized an additional $2.8 million of production equipment in order to have the floating production, storage and offloading facility (“FPSO”) ready to receive and treat oil received from the CX-11 platform. The FPSO lease contains two bargain purchase options; therefore, depreciation of the leased asset will be over its useful life.  The lease contains a bargain purchase option of $1.0 million at the end of the first year of the lease and a $0.5 million bargain purchase option at the end of the second year of the lease. We accounted for the lease agreement in accordance with ASC Topic 840, “Leases.”  Under the guidance, the lease agreement was accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 28.3%.  In July 2010, the Company exercised the second year purchase option and purchased the capital lease production equipment used on board the Company’s FPSO, the Namoku.

In 2007, we entered into two capital loans for the purchase of office furniture.  Both loans have a term of 60 months, bearing interest at 5.94% and 9.44%, respectively, with principal and interest payments due on a monthly basis. During the fourth quarter of 2010, we made the final payments on the lease agreements and title of the office furniture was transferred to us.

In November 2009, we entered into a capital lease agreement for a construction vessel, the Don Fernando, resulting in additional capital assets of approximately $7.0 million.  In the fourth quarter of 2011, we made the final lease payment on the Don Fernando construction vessel, at which point title of the vessel was transferred to us.

In May 2012, we exercised the third year purchase option for $3.0 million and purchased the marine vessels, Namoku and the Nu’uanu, at which point titles to the vessels were transferred to us.

At December 31, 2012, we had no amounts outstanding under capital leases.

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Interest Expense

The following table is a summary of interest expense for the year ended December 31, 2012, 2011 and 2010, respectively:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Interest expense	$	31,719		$	30,446		$	21,250
Capitalized interest expense		(15,604	)		(10,674	)		(9,632	)
Interest expense, net	$	16,115		$	19,772		$	11,618

Restricted Cash and Performance Bonds

Below is a summary of restricted cash as of December 31, 2012 and December 31, 2011:

	December 31, 2012		December 31, 2011
	(in thousands)
Performance bonds totaling $5.6 million for properties in Peru	$	3,338	$	3,338
Insurance bonds for import duties related to a construction vessel		825		814
Performance obligations and commitments for the gas-to power site		650		650
Secured letters of credit		259		563
$75.0 million secured debt facility		35,000		2,500
$40.0 million secured debt facility		32,727		2,000
Unsecured performance bond  totaling $0.1 million for office lease agreement		-		-
Restricted cash	$	72,799	$	9,865
Current portion of restricted cash as of the end of the period	$	25,129	$	2,000
Long-term portion of restricted cash as of the end of the period	$	47,670	$	7,865

The $75.0 million secured debt facility we entered into in July 2011 required us to establish a $2.5 million debt service reserve account during the first 15 months the debt facility is outstanding.  After the first 15-month period, we are required to keep a balance in the debt service reserve account equal to the aggregate amount of principal and interest due on the next quarterly repayment date.  The requirement was subsequently amended subject to the closing of the sale of a 49% participating interest in Block Z-1 to require the funding of the debt service reserve account related to the $75.0 million secured debt facility in the amount of outstanding principal.  The restricted cash related to the current and non-current portion of the $75.0 million secured debt financing was $9.5 million and $25.5 million, respectively, at December 31, 2012.  The restricted cash related to the non-current portion of the $75.0 million secured debt financing was $2.5 million at December 31, 2011.

The $40.0 million secured debt facility we entered into in January 2011 required us to establish a $2.0 million debt service reserve account during the first 18-month period, and thereafter, we must maintain a balance in the debt service reserve account equal to the aggregate amount of payments of principal and interest on the $40.0 million secured debt facility due immediately on the succeeding principal repayment date.  The requirement was subsequently amended subject to the closing of the sale of a 49% participating interest in Block Z-1 to require the funding of the debt service reserve account related to the $40.0 million secured debt facility in the amount of outstanding principal.  The restricted cash related to the current and non-current portion of the $40.0 million secured debt financing was $14.5 million and $18.2 million, respectively, at December 31, 2012.  The restricted cash related to the current portion of the $40.0 million secured debt financing was $2.0 million at December 31, 2011.

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All of the performance and insurance bonds are issued by Peruvian banks and their terms are governed by the corresponding license contracts, customs laws, legal requirements or rental practices.

Other

Turbine Purchase Agreement, Amendment and Letter Agreement

On September 26, 2008, we, through our subsidiary Empresa Electrica Nueva Esperanza S.R.L., entered into a $51.7 million contract (the “Agreement”) for the purchase of three LM6000 gas-fired packaged  power units from GE Packaged Power, Inc. and GE International, Inc. Sucursal de Peru (collectively “GE”). The Agreement required an initial down payment of $5.1 million and monthly progress payments of $1.1 million per unit. In January 2009, BPZ and GE entered into an amendment of the contract. Under the terms of the amendment, both GE and BPZ agreed to a suspension period under the Agreement from and including December 15, 2008 through November 15, 2009, whereby no failure on the part of BPZ or GE to perform any obligations under the Agreement would give rise to a breach of contract or the right to terminate the contract, provided we make a $3.4 million progress payment no later than February 25, 2009 and a $3.5 million progress payment to GE no later than November 16, 2009. On February 24, 2009, we paid the first progress payment of $3.4 million. Under the terms of the Letter Agreement, GE and BPZ agreed to a variable monthly payment plan ending in December 2010 with a final $20.7 million payment due no later than five days after receiving the notice of issuance to ship. We received the notices to ship and made all final payments due to GE under the agreements in December 2010.

2013 Estimated Capital and Exploratory Expenditures Budget

We plan to spend approximately $27.0 million in 2013 on capital and exploratory expenditures, excluding capitalized interest, for our three onshore blocks in which we hold 100% working interests, as the capital and exploratory expenditures for offshore Block Z-1 are fully carried by Pacific Rubiales under the joint venture agreements.

Our 51% share of the Block Z-1 capital investments to be fully carried by Pacific Rubiales is budgeted at $79.0 million ($154.0 million gross).  Our planned activities at Block Z-1 include $35.0 million of CX-15 developmental drilling for six wells, $8.0 million for projects and engineering at the Corvina and Albacora fields and $3.0 million related to other expenditures.  On a contingent basis, the budget includes $18.0 million related to two-well drilling program and facilities at the Albacora field should 3-D seismic dictate a return to drilling, and $12.0 million for the Corvina gas pipeline to shore related to the proposed gas-to-power project.  In addition, exploratory expenditures include $3.0 million for the completion of 3-D seismic survey-related activity, including processing, as well as other engineering projects.

Our $27.0 million planned capital and exploratory expenditures onshore include contingent amounts subject to receipt of necessary permits which include $12.0 million for shallow drilling activities at Block XXIII as well as $9.0 million of 3-D and 2-D seismic work for Blocks XIX and XXII, respectively.  Other expenditures of $6.0 million are also included.

Liquidity Outlook

Our major sources of funding to date have been oil sales, equity and debt financing activities and asset sales.  With our current cash balance, current and prospective Corvina and Albacora oil development cash flow and the sale of a 49% participating interest in Block Z-1 to Pacific Rubiales (See Divestiture above for additional details on the joint venture), we believe we will have sufficient capital resources to execute our planned Corvina and Albacora oil development projects and our initial onshore projects, as well as service our current obligations.

On April 27, 2012, we and Pacific Rubiales 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, and Pacific Rubiales agreed to pay $150.0 million for a 49% participating interest in Block Z-1.  Pursuant to the SPA, Pacific Rubiales 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. The transaction provided for certain sale adjustments based upon the collection of revenues, the payment of expenses and income taxes 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 the unused portion of the agreed funding amount of $185.0 million. At December 31, 2012, based on our share of 2012 Block Z-1 capital and exploratory expenditures credited against the carry amount, and the sale adjustments, the carry amount available for our portion of future capital and exploratory expenditures in Block Z-1 was $126.3 million.

In 2010, we hired Credit Suisse Securities (USA) LLC, a financial advisor, to help us in pursuing joint venture partnerships and/or farm-outs for some of our assets in northwest Peru.  The data room for Blocks XIX and XXIII is 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 reviewing the data.

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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. Potential future equity financing, if any, would be dependent on the success of alternative sources of financing such as other possible joint venture arrangements, our cash position and market conditions.

Off-Balance Sheet Arrangements

As of December 31, 2012, we had no transactions, agreements or other contractual arrangements with unconsolidated entities or financial partnerships, often referred to as special purpose entities, which generally are established for the purpose of facilitating off-balance sheet arrangements.

On April 27, 2012, we and Pacific Rubiales executed a SPA under which we formed an unincorporated joint venture relationship to explore and develop the offshore Block Z-1 located in Peru.  Pursuant to the SPA, Pacific Rubiales agreed to fund $185.0 million of our share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012.

On December 14, 2012 Perupetro approved the terms of the amendment to the Block Z-1 license contract to recognize the sale of a 49% participating interest in offshore Block Z-1 to Pacific Rubiales.  We and Pacific Rubiales waived and modified certain contract conditions in order to effect an accelerated closing of 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 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 funding amount of $185.0 million by Pacific Rubiales for the Company’s share of capital and exploratory expenditures in Block Z-1.  At December 31, 2012 the carry amount was $126.3 million.

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Contractual Obligations

	Payments Due by Period at December 31, 2012
	Total		Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years
Contractual Obligations:	(in thousands)
Operating lease obligation (1)	$	20,512	$	18,859	$	1,596	$	57	$	-
Debt obligation (2)		277,690		42,499		235,191		-		-
Purchase obligation/Current and Non-current liabilities (3)		40,696		19,941		20,755		-		-
Total	$	338,898	$	81,299	$	257,542	$	57	$	-

(1)	Includes operating leases for our executive office in Houston, Texas (expires in 2016), and our branch offices in Lima, Peru (expires in 2014) and warehouses in Peru (expires in 2014), respectively.
	Includes the monthly lease expense for three of our drilling rigs.  Two leases are set to expire in the first quarter of 2013, the other lease is set to expire in December 2013.
	Includes the monthly lease expense for one of our oil transportation vessels whose lease is set to expire in April 2013.
(2)	Includes the debt and interest payments related to the $75.0 million secured credit facility. We estimate the remaining cash payments related to the $75.0 million secured debt facility, excluding potential payments for the performance based arranger fee, for the year ended December 31, 2013, 2014 and 2015 to be approximately $12.0 million, $14.1 million and $14.2 million, respectively.  At December 31, 2012 the debt service reserve account was fully funded for the principal outstanding principal balance of $35.0 million. Interest payments are based on the debt balance, scheduled maturities and interest rates in effect at December 31, 2012.  We estimate the cash payments related to the $75.0 million secured debt facility, for the performance based arranger fee, for the year ended December 31, 2013, 2014 and 2015 to be approximately $0.2 million, none and none, respectively.
	Includes the debt and interest payments related to the $40.0 million secured credit facility. We estimate the remaining cash payments related to the $40.0 million secured debt facility, excluding potential payments for the performance based arranger fee, for the years ended 2013, 2014 and 2015 to be approximately $16.4 million,  $15.6 million and $3.7 million, respectively.  At December 31, 2012 the debt service reserve account was fully funded for the principal outstanding principal balance of $32.7 million. Interest payments are based on the debt balance, scheduled maturities and interest rates in effect at December 31, 2012.  We estimate the cash payments related to the $40.0 million secured debt facility, for the performance based arranger fee, for the years ended 2013, 2014 and 2015 to be approximately $2.8 million, none and none, respectively.
	Includes the remaining principal amount along with the accrued interest due, on the $170.9 million convertible notes due 2015. The 2015 Convertible Notes at a rate of 6.50% per year on March 1 and September 1 of each year, beginning on September 1, 2010.  The 2015 Convertible Notes mature on March 1, 2015. Subsequent to December 31, 2011, using an adjusted conversion rate of 160.0082 shares per $1,000 principal amount of the 2015 Convertible Notes, if the $170.9 million of principal were converted into shares of common stock, the notes would convert into 28,889,927 shares of common stock.
(3)	Includes current and non-current liabilities related to exploratory expenditures for 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.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP” or “U.S. GAAP”). Management uses estimates and assumptions in preparing the consolidated financial statements in accordance with GAAP. Those estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses in the consolidated financial statements, and the disclosure of contingent assets and liabilities. We have identified the following as critical accounting policies directly related to our business and operations, and the understanding of our financial statements.

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Successful Efforts Method of Accounting

We follow the successful efforts method of accounting for our investments in oil and 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 found. If the determination is dependent upon the results of planned additional wells and required capital expenditures to produce the reserves found, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well and additional wells are underway or firmly planned to complete the evaluation of the well. All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive or at the one year anniversary of completion of the well if proved reserves have not been attributed and capital expenditures as described in the preceding sentence are not required. We assess our capitalized exploratory wells pending evaluation each quarter to determine whether costs should remain capitalized or should be charged to earnings. Other exploration costs, including geological and geophysical costs, are expensed as incurred. We recognize gains or losses on the sale of properties, should they occur, on a field-by-field basis.

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. The evaluations of oil and gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area.

The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding oil and gas reserves. Seismic costs can be substantial, which will result in additional exploration expenses when incurred. The initial exploratory wells may be unsuccessful and the associated costs will then be expensed as dry hole costs, and any associated leasehold costs may be impaired.

Oil and Gas Accounting Reserves Determination

The successful efforts method of accounting depends on the estimated reserves we believe are recoverable from our oil and gas reserves. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data.

To estimate the economically recoverable oil and natural gas reserves and related future net cash flows, we incorporate many factors and assumptions including:

·expected reservoir characteristics based on geological, geophysical and engineering assessments;

·future production rates based on historical performance and expected future operating and investment activities;

·future oil and gas quality differentials;

·assumed effects of regulation by governmental agencies; and

·future development and operating costs.

We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially going forward as additional data from development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the U.S. as prescribed by the Society of Petroleum Engineers. Reserve estimates are independently evaluated at least annually by our independent qualified reserves engineers, NSAI.

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Our Board of Directors (“Board”) oversees the review of our oil and gas reserves and related disclosures by our appointed independent reserve engineers. The Board meets with management periodically to review the reserves process, results, and to confirm that the independent reserve engineers have had access to sufficient information, including the nature and satisfactory resolution of any material differences of opinion between us and the reserve engineers.

Reserves estimates are critical to many of our accounting estimates, including:

· determining whether or not an exploratory well has found economically producible reserves;

· calculating our unit-of-production depletion rates. Proved reserves estimates are used to determine rates thatare applied to each unit-of-production in calculating our depletion expense; and

· assessing, when necessary, our oil and gas assets for impairment using undiscounted future cash flows based on management’s estimates.  If impairment is indicated, discounted values will be used to determine the fair value of the assets.  The critical estimates used to assess impairment, including the impact of changes inreserves estimates, are discussed below.

Revenue Recognition

We recognize revenues when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

We sell our production in the Peruvian domestic market on a contract basis.  Revenue is recorded net of royalties when the purchaser takes delivery of the oil.  At the end of the period, oil that has been produced but not sold is recorded as inventory at the lower of cost or market.  Cost is determined on a weighted average based on production costs.

Impairment of Long-Lived Assets

We periodically evaluate the recoverability of the carrying value of our long-lived assets and identifiable intangibles by monitoring and evaluating changes in circumstances that may indicate that the carrying amount of the asset may not be recoverable. Examples of events or changes in circumstances that indicate the recoverability of the carrying amount of an asset should be assessed include, but are not limited to, (a) a significant decrease in the market value of an asset, (b) a significant change in the extent or manner in which an asset is used or a significant physical change in an asset, (c) a significant adverse change in legal factors or in the business climate that could affect the value of an asset or an adverse action or assessment by a regulator, (d) an accumulation of costs significantly in excess of the amount originally expected to acquire or construct an asset, and/or (e) a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with an asset used for the purpose of producing revenue.

We consider historical performance and anticipated future results in our evaluation of potential impairment. Accordingly, when indicators of impairment are present, we evaluate the carrying value of these assets in relation to the operating performance of the business and future discounted and non-discounted cash flows expected to result from the use of these assets. Impairment losses are recognized when the expected future cash flows from an asset are less than its carrying value.

Future Dismantlement, Restoration, and Abandonment Costs

The accounting for future development and abandonment costs changed on January 1, 2003, with the issuance of ASC Topic 410, “Asset Retirement and Environmental Liabilities,” which requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The accrual is based on estimates of these costs for each of our properties based upon the type of production structure, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these costs is difficult and requires management to make estimates and judgments that are subject to future revisions based on numerous factors, including changing technology, the political and regulatory environment and estimates as to the proper discount rate to use and timing of abandonment.

In periods subsequent to initial measurement of the asset retirement obligation liability, we recognize period to period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate.  Revisions also result in increases or decreases in the carrying cost of the oil and gas asset.  Increases in the asset retirement obligation liability due to the passage of time impact income as accretion expense. The related capitalized cost, including revisions, is charged to expense as depreciation, depletion and amortization.

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Our plan of operations includes the drilling of wells.  We will be required to plug and abandon those wells and restore the well sites upon abandonment if they are abandoned prior to the end of the contract period.  See Note-9, “Asset Retirement Obligation” to the consolidated financial statements provided herein for further detail.

Principles of Consolidation

Our consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and branch offices. All intercompany balances and transactions have been eliminated.

Our accounting policy regarding partnership or joint venture interests in oil and gas properties is to consolidate such interests on a pro-rata basis in accordance with accepted practice in the oil and gas industry. However, we have not been able to receive timely information to allow us to proportionately consolidate the minority non-operated net profits interest owned by our consolidated subsidiary, SMC Ecuador Inc. See Note-7, “Investment in Ecuador Property” to the consolidated financial statements for further discussion regarding the investment in our Ecuador property. Accordingly, we account for this investment under the cost method. As such, we record our share of cash received or paid attributable to this investment as other income or expense and amortizes its investment into income over the remaining term of the license agreement which expires in May 2016.  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 and sharing of joint operating expenditures from that day forward was allocated to each partner. The sharing of any production or joint operating expenditures prior to that date for 2012 was handled as an adjustment to the carry amount under the SPA.  In addition, the carry of capital and exploratory expenditures for Block Z-1 by Pacific Rubiales began from December 14, 2012 forward, so expenditures for capital and exploratory activities at Block Z-1 have been shown 100% for the account of Pacific Rubiale during the period of December 14, though December 31, 2012. The BPZ share of the 2013 Block Z-1 capital and exploratory expenditures should be fully funded by our partner under the carry agreement in place.

Stock Based Compensation

We account for stock-based compensation at fair value in accordance with the provisions of ASC Topic 718, “Stock Compensation” (“ASC Topic 718”), which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employee directors. Under the provisions of ASC Topic 718, stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award, and is recognized as expense in the Consolidated Statements of Operations ratably over the employee’s or non-employee director’s requisite service period, which is generally the vesting period of the equity grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model.  Restricted stock awards and units are valued using the market price of our common stock on the grant date. Additionally, stock-based compensation cost is recognized based on awards that are ultimately expected to vest, therefore, the compensation cost recognized on stock-based payment transactions is reduced for estimated forfeitures based on our historical forfeiture rates. Additionally, no stock-based compensation costs were capitalized for the year ended December 31, 2012, 2011 and 2010. We provide compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans.

ASC Topic 230, “Statement of Cash Flows,” requires the cash flows resulting from tax deductions in excess of the compensation cost recognized for equity awards (excess tax benefits) to be classified as financing cash flows. However, as we are not able to use these tax deductions (see Note-18, “Income Taxes” for further information), we have no excess tax benefits to be classified as financing cash flows.

Income Taxes

We are subject to income and other taxes in Peru and the United States. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions.  Estimates of amounts of income tax to be recorded involve interpretation of complex tax laws, assessment of the effects of foreign taxes and domestic taxes.

Our consolidated balance sheets include deferred tax assets. Deferred tax assets arise when expenses are recognized in the financial statements before they are recognized in the tax returns or when income items are recognized in the tax returns before they are recognized in the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Ultimately, realization of a deferred tax asset depends on the existence of sufficient taxable income within the future periods to absorb future deductible temporary differences, loss carryforwards or credits.

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In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, we may determine, and we have determined in the past, that a deferred tax asset valuation allowance should be established. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.   See Note-18, “Income Taxes.”

Foreign Exchange

The U.S. Dollar is the functional currency for our operations in both Peru and Ecuador. Ecuador has adopted the U.S. Dollar as its official currency. Peru, however, still uses its local currency, Nuevo Sol, in addition to the U.S. Dollar and therefore our financial results are subject to favorable or unfavorable fluctuations in the exchange rate and inflation of that country. We have adopted ASC Topic 830, “Foreign Currency Matters,” which requires that the translation of the applicable foreign currency into U.S. dollars be performed for balance sheet monetary accounts using current exchange rates in effect at the balance sheet date, non-monetary accounts using historical exchange rates in effect at the time the transaction occurs, and for revenue and expense accounts using a weighted average exchange rate during the period reported. Accordingly, the gains or losses resulting from such translation are included in other income and expense in the consolidated Statements of Operations.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued additional guidance that clarifies application of fair value measurement and disclosure requirements and is effective for annual and interim periods beginning after December 15, 2011.  As of March 31, 2012, we adopted the provisions of this guidance, which did not impact the consolidated financial statements. The only impact was to fair value disclosures.

In December 2011, the FASB issued guidance that requires that an entity disclose information about offsetting and related arrangements to enable users of our financial statements to understand the effect of those arrangements on our financial position.  The guidance is effective for annual periods beginning on or after January 1, 2013.  The guidance for the disclosures will be applied retrospectively for all prior periods presented.  There was no impact on our financial position and results of operations.

On August 22, 2012, the SEC adopted rules mandated by the Dodd-Frank Act requiring entities who file reports with the SEC and commercially develop oil, natural gas or liquids (“resource extraction issuers”) to disclose certain payments made to the U.S. government or foreign governments.  The rules provide guidance on the types of payments and information about payments that must be disclosed.  The rules require a resource extraction issuer to disclose the information annually by filing a new form with the SEC (Form SD) no later than 150 days after the end of its fiscal year.  A resource extraction issuer is required to comply with the new rules for fiscal years ending after September 30, 2013.   As a result, beginning in 2014, we must annually 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. There will be no impact on our financial position and results of operations, but may require additional disclosures in future filings.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates, oil and natural gas prices and foreign currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

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 Interest Rate Risk.

As of December 31, 2012, we had long-term debt of approximately $197.2 million and current maturities of long-term debt of approximately $24.0 million.

The $75.0 million secured debt facility, which at December 31, 2012 had $35.0 million outstanding, is variable rate debt that exposes us to the risk of increased interest expense in the event of increases in short-term interest rates.  If the variable interest rate were to increase by 1% from the rate at inception, interest expense would increase by approximately $0.3 million annually.  The carrying value of the variable interest rate debt approximates fair value as it bears interest at current market rates.

The $40.0 million secured debt facility, which at December 31, 2012 had $32.7 million outstanding, is variable rate debt that exposes us to the risk of increased interest expense in the event of increases in short-term interest rates. If the variable interest rate were to increase by 1% from the rate at inception, interest expense would increase by approximately $0.3 million annually. The carrying value of the variable interest rate debt approximates fair value as it bears interest at current market rates.

In February and March 2010, we closed on the private offering for an aggregate $170.9 million convertible notes due 2015. The 2015 Convertible Notes are general senior unsecured obligations of BPZ and subject us to risks related to changes in the fair value of the debt, however, due to make-whole provisions within the Indenture, our exposure to potential gains if we were to repay or refinance such debt are minimal.

The fair value of our 6.5 % 2015 Convertible Notes as compared to the carrying value at December 31, 2012 and 2011, was as follows:

	December 31, 2012				December 31, 2011
	Carrying Amount		Fair Value (2)		Carrying Amount		Fair Value (2)
	(in thousands)				(in thousands)
$170.9 million Convertible Notes,  6.5%, due March 2015, net of discount of ($17.4) million at December 31, 2012 and ($24.1) million at December 31, 2011 (1)	$	153,479	$	147,861	$	146,781	$	140,460

(1) Excludes obligations under capital lease arrangements and variable rate debt.

(2) We estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $147.9 million and $140.5 million at December 31, 2012 and December 31, 2011, respectively, based on observed market prices for the same or similar type of debt issues.

We do not expect a significant change in the market interest rate to impact the interest on our term debt.  However, significant changes in market interest rates may significantly affect the level of financing that will be structured with respect to our project in Peru.

Commodity Price Risk

With respect to our oil and gas business, 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 continue to be volatile in the future.  Prices for oil and gas are subject to potentially wide fluctuations in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty, and a variety of additional factors that are beyond our control.

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.  A substantial or extended decline 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.

79

In January 2011, we closed on a $40.0 million secured debt facility whose fee contains a performance based fee that is dependent on the change in oil prices from the inception date of the debt agreement and the price of oil at each principal repayment date.  This performance based payment is subject to certain maximum limitations; however, this performance based fee exposes us to commodity price risk and may limit our ability to fully receive potential gains if oil prices increase above the price of oil at the inception of the debt agreement.

In July 2011, we closed on a $75.0 million secured debt facility whose fee contains a performance based fee that is dependent on the change in oil prices from the inception date of the debt agreement and the price of oil at each principal repayment date.  This performance based payment is subject to certain maximum limitations; however, this performance based fee exposes us to commodity price risk and may limit our ability to fully receive potential gains if oil prices increase above the price of oil at the inception of the debt agreement.

With respect to our planned electricity generation business, the price we can obtain from the sale of electricity through our proposed power plant may not rise at the same rate, or may not rise at all, to match a rise in the cost of production and transportation of our gas reserves which will be used to generate the electricity.  Prices for electricity in Peru have been volatile in the past and may be volatile in the future.  However, gas prices in Peru are regulated and therefore not volatile.

Foreign Currency Exchange Rate Risk

The U.S. Dollar is the functional currency for our operations in both Peru and Ecuador.  Ecuador has adopted the U.S. Dollar as its official currency.  Peru, however, uses its local currency, the Nuevo Sol, in addition to the U.S. Dollar, and therefore, our financial results are subject to favorable or unfavorable fluctuations in the exchange rate and inflation in that country.  Transaction differences have been nominal to date but are expected to increase as our activities in Peru continue to escalate.  During the year ended December 31, 2012, 2011, and 2010, exchange rate gains and losses were not material.

80

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

BPZ Resources, Inc. and Subsidiaries

Index to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm	82
Consolidated Balance Sheets as of December 31, 2012 and 2011	83
Consolidated Statements of Operations for the Years Ended December 31, 2012, 2011 and 2010	84
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010	85
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010	86
Notes to Consolidated Financial Statements	87

Supplemental Oil and Gas Disclosures (Unaudited) 125

81

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders

BPZ Resources, Inc. and Subsidiaries

Houston, Texas

We have audited the accompanying consolidated balance sheets of BPZ Resources, Inc. as of December 31, 2012 and 2011 and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BPZ Resources, Inc. at December 31, 2012 and 2011 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), BPZ Resources, Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 15, 2013 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, TX

March 15, 2013

82

BPZ Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands)

	December 31, 2012			December 31, 2011
ASSETS
Current assets:
Cash and cash equivalents	$	83,540		$	58,172
Accounts receivable		24,523			8,174
Income taxes receivable		-			1,212
Value-added tax receivable		20,569			24,720
Inventory		19,851			16,841
Restricted cash		25,129			2,000
Prepaid and other current assets		5,734			2,304
Total current assets		179,346			113,423
Property, equipment and construction in progress, net		238,557			381,602
Restricted cash		47,670			7,865
Other non-current assets		5,983			7,527
Investment in Ecuador property, net		632			820
Deferred tax asset		55,242			26,096
Total assets	$	527,430		$	537,333
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	21,978		$	19,520
Accrued liabilities		34,013			19,694
Other liabilities		21,792			1,015
Current income taxes payable		10,460			-
Accrued interest payable		5,234			6,064
Derivative financial instruments		2,984			1,096
Current maturity of long-term debt and capital lease obligations		24,046			16,854
Total current liabilities		120,507			64,243
Asset retirement obligation		2,708			1,304
Derivative financial instruments		-			950
Other non-current liabilities		20,755			-
Long-term debt and capital lease obligations, net		197,160			248,384
Total long-term liabilities		220,623			250,638
Commitments and contingencies (Note 20 and 21)
Stockholders’ equity:
Preferred stock, no par value, 25,000 authorized; none issued and outstanding		-			-
Common stock, no par value, 250,000 authorized; 116,932 and 115,910 shares issued and outstanding at December 31, 2012 and December 31, 2011, respectively		560,175			557,238
Accumulated deficit		(373,875	)		(334,786	)
Total stockholders’ equity		186,300			222,452
Total liabilities and stockholders’ equity	$	527,430		$	537,333

The accompanying notes are an integral part of these consolidated financial statements.

83

BPZ Resources, Inc. and Subsidiaries

Consolidated Statements of Operations

(In thousands, except per share data)

	Year Ended December 31,
	2012			2011			2010
Net revenue:
Oil revenue, net	$	122,708		$	139,354		$	110,075
Other revenue		250			4,386			389
Total net revenue		122,958			143,740			110,464
Operating and administrative expenses:
Lease operating expense		52,458			50,792			32,585
General and administrative expense		31,806			38,600			32,655
Geological, geophysical and engineering expense		40,686			9,315			19,107
Dry hole costs		-			13,082			32,778
Depreciation, depletion and amortization expense		45,873			38,944			33,755
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
Operating loss		(28,607	)		(11,522	)		(60,792	)
Other income (expense):
Income from investment in Ecuador property, net		62			412			740
Interest expense, net		(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
Other income (expense)		(159	)		1,083			19
Total other expense, net		(26,096	)		(19,870	)		(10,587	)
Loss before income taxes		(54,703	)		(31,392	)		(71,379	)
Income tax expense (benefit)		(15,614	)		2,435			(11,608	)
Net loss	$	(39,089	)	$	(33,827	)	$	(59,771	)
Basic net loss per share	$	(0.34	)	$	(0.29	)	$	(0.52	)
Diluted net loss per share	$	(0.34	)	$	(0.29	)	$	(0.52	)
Basic weighted average common shares outstanding		115,631			115,367			114,919
Diluted weighted average common shares outstanding		115,631			115,367			114,919

The accompanying notes are an integral part of these consolidated financial statements.

84

BPZ Resources, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity

Years Ended December 31, 2012, 2011 and 2010

(In thousands)

	Common  Stock					Accumulated
	Shares		Amount			Deficit			Total
Balances at January 1, 2010		115,224	$	513,145		$	(241,188	)	$	271,957
Long-term incentive compensation plans, net of forfeitures		268		5,813			-			5,813
Common stock sold for cash, net of offering costs		-		(42	)		-			(42	)
Proceeds of convertible notes allocated to equity, net of debt issuance costs		-		33,369			-			33,369
Net loss		-		-			(59,771	)		(59,771	)
Balances at December 31, 2010		115,492		552,285			(300,959	)		251,326
Exercise of stock options		242		939			-			939
Long-term incentive compensation plans, net of forfeitures		176		4,019			-			4,019
Common stock sold for cash, net of offering costs		-		(5	)		-			(5	)
Net loss		-		-			(33,827	)		(33,827	)
Balances at December 31, 2011		115,910		557,238			(334,786	)		222,452
Long-term incentive compensation plans, net of forfeitures		982		2,841			-			2,841
Common stock sold for cash, net of offering costs		40		96			-			96
Net loss		-		-			(39,089	)		(39,089	)
Balances at December 31, 2012		116,932	$	560,175		$	(373,875	)	$	186,300

The accompanying notes are an integral part of these consolidated financial statements.

85

BPZ Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)

	For the Year Ended December 31,
	2012			2011			2010
Cash flows from operating activities:
Net loss	$	(39,089	)	$	(33,827	)	$	(59,771	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Stock-based compensation		2,841			4,019			5,813
Depreciation, depletion and amortization		45,873			38,944			33,755
Amortization of investment in Ecuador property		188			188			188
Deferred income taxes		(29,165	)		2,047			(13,559	)
Dry hole costs		-			13,082			32,778
Net loss on abandoned assets		-			-			12,089
Loss on extinguishment of debt		7,318			-			-
(Gain) on divestiture		(26,864	)		-			-
Amortization of discount and deferred financing fees		9,833			8,648			5,272
Unrealized loss on derivatives		938			2,046			-
Changes in operating assets and liabilities:
(Increase) decrease in accounts receivable		(16,349	)		3,762			(9,069	)
(Increase) decrease in value-added tax receivable		(21,259	)		6,632			(5,200	)
(Increase) decrease in inventory		(5,641	)		2,546			(6,748	)
(Increase) decrease in other assets		(3,379	)		935			(1,480	)
Decrease in income taxes receivable		-			9,003			-
Increase (decrease) in accounts payable		2,458			(18,159	)		4,981
Increase in accrued liabilities		13,708			7,412			4,083
Increase (decrease) in income taxes payable		11,691			-			(8,194	)
Increase (decrease) in other liabilities		836			(157	)		(63	)
Net cash provided by (used in) operating activities		(46,062	)		47,121			(5,125	)
Cash flows from investing activities:
Property and equipment additions		(82,203	)		(89,778	)		(158,064	)
Divestiture of properties and equipment		79,299			-			-
Increase in restricted cash		(62,934	)		(4,105	)		(40	)
Net cash provided by (used in) investing activities		(65,838	)		(93,883	)		(158,104	)
Cash flows from financing activities:
Borrowings		195,688			115,000			170,938
Repayments of borrowings		(54,919	)		(16,807	)		(7,994	)
Deferred and other loan fees		(3,597	)		(5,945	)		(6,068	)
Proceeds from exercise of stock options, net		-			939			-
Proceeds from sale of common stock, net		96			(5	)		(42	)
Net cash provided by (used in) financing activities		137,268			93,182			156,834
Net increase (decrease) in cash and cash equivalents		25,368			46,420			(6,395	)
Cash and cash equivalents at beginning of period		58,172			11,752			18,147
Cash and cash equivalents at end of period	$	83,540		$	58,172		$	11,752

Supplemental cash flow information:
Cash paid (refund) for:
Interest	$	22,716	$	20,007		$	11,812
Income tax		1,793		(8,969	)		10,534
Non — cash items:
Debt exchanged in divestiture for value added tax receivable	$	24,196	$	-		$	-
Debt exchanged in divestiture included in the $150.0 million sale proceeds		65,000
Debt exchanged in divestiture for 2012 Block Z-1 property additions		65,795
Debt transferred to current and other non-current liabilities related to 2012 Block Z-1 exploratory expenditures		40,697		-			-
Purchase and additions to equipment with the issuance of a capital lease obligation		-		154			172
Depletion allocated to production inventory		648		419			287
Depreciation on support equipment capitalized to construction in progress		472		317			1,773
Asset retirement obligation capitalized to property and equipment, net of revisions		1,314		339			21
Property and equipment transferred to / from current assets or other non-current assets		-		1,158			-
Gain on capital lease repayment capitalized to property and equipment		180		-			-

The accompanying notes are an integral part of these consolidated financial statements.

86

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Note 1 — Basis of Presentation and Significant Accounting Policies

Organization

BPZ Resources, Inc., (together with its subsidiaries, collectively referred to as the “Company” or “BPZ” unless the context requires otherwise) a Texas corporation, is based in Houston, Texas with offices in Lima, Peru and Quito, Ecuador. The Company is focused on the exploration, development and production of oil and natural gas in Peru and to a lesser extent Ecuador. The Company also intends to utilize part of its planned future natural gas production as a supply source for the complementary development of a gas-fired power generation facility which is expected to be wholly- or partially-owned by the Company.

The Company maintains a subsidiary, BPZ Exploración & Producción S.R.L. (“BPZ E&P”), registered in Peru through its wholly-owned subsidiary BPZ Energy, LLC, a Texas limited liability company, and its subsidiary, BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership. Currently, the Company, through BPZ E&P, has 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. The Company’s 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 up to an additional three years to a maximum of ten years. However, this exploration extension is subject to government approval and specific provisions of each license contract can vary the exploration phase of the contract as established Hydrocarbon Law. The license contracts require the Company to conduct specified activities in the respective blocks during each exploration period in the exploration phase. If the exploration activities are successful, the Company may decide to enter the exploitation phase and the 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 the Company’s Block Z-1 contract, the 40-year term may apply to oil production as well.

Additionally, through its wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, the Company owns 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 license agreement and new operating agreement covering the property extends through May 2016.

The Company is in the process of developing its Peruvian oil and gas reserves.  The Company entered commercial production for the Block Z-1 in November 2010 and produce and sell oil under the Company’s current sales contract.  The Company completed the installation of the new CX-15 platform in the Corvina field to continue the development of the field.  The Company is also appraising the potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1.  The Company received the required environmental permit for gas and produced water injection at Albacora on October 29, 2012, and is producing and selling oil under the Company’s current sales contract.  Additionally, the Company’s activities in Peru include (i) analysis and evaluation of technical data on its 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.

On December 14, 2012 Perupetro S.A (“Perupetro”), a corporation owned by the Peruvian government empowered to become a party in the contracts for the exploration and/or exploitation of hydrocarbons in order to promote these activities in Peru, approved the terms of the amendment to the Block Z-1 license contract to recognize the sale of a 49% participating interest (“closing”) in offshore Block Z-1 to Pacific Rubiales Energy Corp. (“Pacific Rubiales”). Under terms of the agreements signed on April 27, 2012, the Company (together with its 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 $150.0 million for a 49% participating interest in Block Z-1 and agreed to fund $185.0 million of the Company’s share of capital and exploratory expenditures in Block Z-1 (‘the carry amount”) from the effective date of the Stock Purchase Agreement (“SPA”), January 1, 2012.  At December 31, 2012 the carry amount was $126.3 million.  On December 30, 2012, the Peruvian Government signed the Supreme Decree for the execution of the amendment to the Z-1 license contract.

87

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of BPZ Resources, Inc. and its wholly-owned subsidiaries and branch offices. All intercompany balances and transactions have been eliminated.

The Company’s accounting policy regarding partnership or joint venture interests in oil and gas properties is to consolidate such interests on a pro-rata basis in accordance with generally accepted practice in the oil and gas industry. However, the Company has not been able to receive timely information to allow it to proportionately consolidate the minority non-operating net profits interest owned by its consolidated subsidiary, SMC Ecuador Inc. See Note-7, “Investment in Ecuador Property” to the consolidated financial statements for further discussion regarding the Company’s investment in its Ecuador property. Accordingly, the Company accounts for this investment under the cost method. As such, the Company records its share of cash received or paid attributable to this investment as other income or expense and amortizes its investment into income over the remaining term of the license agreement which expires in May 2016.  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 and sharing of joint operating expenditures from that day forward was allocated to each partner. At closing, the sharing of any production or joint operating expenditures prior to that date for 2012 was treated by the parties as an adjustment to the carry amount under the SPA.

Use of Estimates

The preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP” or “U.S. GAAP”) requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses in the consolidated financial statements, and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

Estimates of crude oil reserves are the most significant of the Company’s estimates. All of the reserves data are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.

Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment, including impairment and asset retirement obligations and deferred income tax assets. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.  Current credit market conditions combined with volatile commodity prices have resulted in increased uncertainty inherent in such estimates and assumptions. As future events and their effects cannot be determined accurately, actual results could differ significantly from these estimates.

Reclassification

Certain reclassifications have been made to the 2011 and 2010 consolidated financial statements to conform to the 2012 presentation.  These reclassifications were not material to the accompanying consolidated financial statements.

Revenue Recognition

The Company recognizes revenues when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.

The Company sells its production in the Peruvian domestic market on a contract basis. Revenue is recorded net of royalties when the purchaser takes delivery of the oil. At the end of the period, oil that has been produced but not sold is recorded as inventory at the lower of cost or market. Cost is determined on a weighted average based on production costs. See Note–15, “Revenue” for further information.

88

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Reporting and Functional Currency

The U.S. Dollar is the functional currency for the Company’s operations in both Peru and Ecuador. Ecuador has adopted the U.S. Dollar as its official currency. Peru, however, uses its local currency, Nuevo Sol, in addition to the U.S. Dollar and therefore its financial results are subject to foreign currency gains and losses. The Company has adopted Accounting Standard Codification  (“ASC”) Topic 830, “Foreign Currency Matters,” which requires that the translation of the applicable foreign currency into U.S. dollars be performed for balance sheet monetary accounts using current exchange rates in effect at the balance sheet date, non-monetary accounts using historical exchange rates in effect at the time the transaction occurs, and for revenue and expense accounts using a weighted average exchange rate during the period reported. Accordingly, the gains or losses resulting from such translation are included in other income and expense in the consolidated statements of operations. Due to the relatively low level of activity to date and the relatively steady exchange rate in Peru, foreign exchange gains and losses for the year ended December 31, 2012, 2011, and 2010 were not material to the Company’s financial statements.  

Cash and Cash Equivalents

The Company considers cash on hand, cash in banks, money market mutual funds and highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Certain of the Company’s cash balances are maintained in foreign banks which are not covered by deposit insurance. The cash balance in the Company’s U.S. bank accounts may exceed federally insured limits.

Restricted Cash and Performance Bonds

As discussed in Note-8, “Restricted Cash and Performance Bonds,” the Company has secured various performance bonds, collateralized by certificates of deposit, to guarantee its obligations and commitments in connection with its exploratory properties in Peru. All of the performance bonds have been issued by Peruvian banks and their terms are dictated by the corresponding license contract or agreement.  The Company’s $75.0 million secured debt facility and $40.0 million secured debt facility require it to establish a debt service reserve account (See Note-8.) while the secured debt facilities are outstanding. 

Accounts Receivable and Allowance for Doubtful Accounts

Currently, the Company’s contract terms regarding oil sales have a relatively short settlement period.  Also included in accounts receivable are amounts receivable ($15.9 million) from the Company’s joint venture partner at December 31, 2012.  The Company regularly reviews all aged accounts receivables for collectability and establishes an allowance as necessary for balances greater than 90 days outstanding. Currently, the majority of all receivables are current or were outstanding less than thirty days.

It is the Company’s belief that there are no balances in accounts receivable that will not be collected and that an allowance was not necessary at December 31, 2012 and December 31, 2011, respectively.

Inventories

Inventories consist primarily of crude oil, tubular goods, accessories and spare parts for production equipment used in the Company’s oil and gas operations, stated at the lower of average cost or market.  The cost of crude oil inventory includes production costs and depreciation, depletion and amortization of oil and gas properties.  See Note-4, “Inventory.”

89

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Property, Equipment and Construction in Progress

The Company follows the successful efforts method of accounting for its costs of acquisition, exploration and development of oil and 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. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved developed crude oil reserves on a field-by-field basis.Certain costs of exploratory wells are capitalized pending determinations that proved reserves have been found.  Exploratory well costs continue to be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If the determination is dependent upon the results of planned additional wells and required capital expenditures to produce the reserves found, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well and additional wells are underway or firmly planned to complete the evaluation of the well. All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive.

The Company assesses its capitalized exploratory wells pending evaluation each quarter to determine whether costs should remain capitalized or should be charged to earnings. Other exploration costs, including geological, geophysical and engineering costs, are expensed as incurred. The Company recognizes gains or losses on the sale of properties, should they occur, on a field-by-field basis.

Projects under construction are not depreciated or amortized until placed in service. For assets the Company constructs, it capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and interest. As of December 31, 2012, property and equipment consists of office equipment, vehicles and leasehold improvements made to the Company’s offices. All such values are stated at cost and are depreciated on a straight-line basis over the estimated useful life of the assets which ranges between three and ten years, or the term of the lease. Vessels and related equipment are depreciated on a straight-line basis over the estimated useful life of the asset, which is between two and fifteen years.  Maintenance and repairs are expensed as incurred. Replacements, upgrades or expenditures which improve and extend the life of the assets are capitalized. When assets are sold, retired or otherwise disposed, the applicable costs and accumulated depreciation and amortization are removed from the appropriate accounts and the resulting gain or loss is recorded.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities at December 31, 2012 and 2011 consist mainly of accounts payable and accrued liabilities related to costs for which goods and services have been received in support of the Company’s oil and gas operations, including drilling operations, seismic and lease operating costs.  Also included in accounts payable at December 31, 2012 are $4.4 million of amounts payable to the Company’s joint venture partner.

Other Current Liabilities

Other current liabilities included in the Company’s balance sheet at December 31, 2012 also consists of $19.9 million  related to exploratory expenditures for 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.

Asset Retirement Obligation

Asset retirement obligations consist of dismantlement and abandonment costs, excluding salvage values, are initially recorded and the carrying amount of the related oil and natural gas properties is increased. The fair value of the asset retirement obligation asset and liability is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon the Company’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using the Company’s credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost.  See Note-9, “Asset Retirement Obligation.”

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BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Other Non-current Liabilities

The other non-current liabilities included in the Company’s balance sheet at December 31, 2012 consists of non-current liabilities related to exploratory expenditures for Block Z-1 under funding by Pacific Rubiales of the exploratory expenditures in Block Z-1 incurred in 2012.  This amount ($20.8 million) will be settled by the Company and Pacific Rubiales under the terms of the SPA.

Oil and Gas Accounting Reserves Determination

The successful efforts method of accounting depends on the estimated reserves the Company believes are recoverable from its oil and gas reserves. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data.

To estimate the economically recoverable oil and natural gas reserves and related future net cash flows, the Company incorporates many factors and assumptions including:

·expected reservoir characteristics based on geological, geophysical and engineering assessments;

·future production rates based on historical performance and expected future operating and investmentactivities;

·future oil and gas quality differentials;

·assumed effects of regulation by governmental agencies; and

·future development and operating costs.

The Company believes its assumptions are reasonable based on the information available to it at the time it prepared the estimates. However, these estimates may change substantially going forward as additional data from development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.

Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with the Security and Exchange Commission (“SEC”) requirements and generally accepted industry practices in the US as prescribed by the Society of Petroleum Engineers. Reserve estimates are independently evaluated at least annually by independent qualified reserves engineers, Netherland, Sewell & Associates, Inc (“NSAI”). The estimate of the Company’s proved reserves as of December 31, 2012 and 2011 has been prepared and presented in accordance with SEC rules and accounting standards. These rules require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month unweighted first-day-of-the-month average pricing.

The Company’s Board of Directors oversees the review of its oil and gas reserves and related disclosures by the Company’s appointed independent reserve engineers. The Board meets with management periodically to review the reserves process, results, and to confirm that the independent reserve engineers have had access to sufficient information, including the nature and satisfactory resolution of any material differences of opinion between the Company and the reserve engineers. 

Reserves estimates are critical to many of the Company’s accounting estimates, including:

● Determining whether or not an exploratory well has found economically producible reserves;

● Calculating the Company’s unit-of-production depletion rates. Proved reserves estimates are used to determine rates that are applied to each unit-of-production in calculating its depletion expense; and

● Assessing, when necessary, the Company’s oil and gas assets for impairment using undiscounted future cash flows based on management’s estimates.  If impairment is indicated, discounted values will be used to determine the fair value of the  assets.  The critical estimates used to assess impairment, including the impact of changes in reserves estimates, are discussed below.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Impairment of Long-Lived Assets

The Company periodically evaluates the recoverability of the carrying value of its long-lived assets by monitoring and evaluating changes in circumstances that may indicate that the carrying amount of the asset may not be recoverable.  Examples of events or changes in circumstances that indicate that the recoverability of the carrying amount of an asset should be assessed include but are not limited to the following: a significant decrease in the market value of an asset, a significant change in the extent or manner in which an asset is used or a significant physical change in an asset, a significant adverse change in legal factors or in the business climate that could affect the value of an asset or an adverse action or assessment by a regulator, an accumulation of costs significantly in excess of the amount originally expected to acquire or construct an asset, and/or a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with an asset used for the purpose of producing revenue.

The Company considers historical performance and anticipated future results in its evaluation of potential impairment. Accordingly, when indicators of impairment are present, the Company evaluates the carrying value of these assets in relation to the operating performance of the business and future discounted and non-discounted cash flows expected to result from the use of these assets. Impairment losses are recognized when the expected future cash flows from an asset are less than its carrying value.  For the year ended December 31, 2012, 2011 and 2010, there were no impairment losses recognized by the Company.

Stock Based Compensation

The Company accounts for stock-based compensation at fair value in accordance with the provisions of ASC Topic 718, “Stock Compensation” (“ASC Topic 718”), which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employee directors.  Under the provisions of ASC Topic 718, stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award, and is recognized as expense in the Consolidated Statements of Operations  ratably over the employee’s or non-employee director’s  requisite service period, which is generally the vesting period of the equity grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of the Company’s common stock on the grant date. Additionally, stock-based compensation cost is recognized based on awards that are ultimately expected to vest, therefore, the compensation cost recognized on stock-based payment transactions is reduced for estimated forfeitures based on the Company’s historical forfeiture rates. Additionally, no stock-based compensation costs were capitalized for the year ended December 31, 2012, 2011 and 2010. The Company provides compensation benefits to employees and non-employee directors under stock-based payment arrangements, including various employee stock option plans. See Note-12, “Stockholders’ Equity,” for further discussion of the Company’s stock-based compensation plans.

ASC Topic 230, “Statement of Cash Flows,” requires the cash flows resulting from tax deductions in excess of the compensation cost recognized for equity awards (excess tax benefits) to be classified as financing cash flows. However, as the Company is not able to use these tax deductions (see Note-18, “Income Taxes” for further information), it has no excess tax benefits to be classified as financing cash flows.

Capitalized Interest

Certain interest costs have been capitalized as part of the cost of oil and gas properties under development, including wells in progress and related facilities.  Total interest costs capitalized during the year ended December 31, 2012, 2011 and 2010 were $15.6 million, $10.7 million and $9.6 million, respectively.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash, restricted cash, trade receivables, trade payables, debt and derivatives. The book values of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of those instruments. For further information regarding the fair value of the Company’s fixed rate debt see Note-13, “Fair Value Measurements and Disclosures.”  For the Company’s variable rate debt at December 31, 2012 and 2011, the carrying value of the debt approximates fair value as the interest rates are based on floating rates identified by reference to market rates and because the interest rates charged are at rates at which the Company can currently borrow.  The Company’s derivative financial instruments consist of variable financing arranger fee payments that are dependent on the change in oil prices from the loan origination date of the Company’s variable rate debt and the oil price on each repayment date. The Company estimates the fair value of these payments based on published forward commodity price curves at each financial reporting date.

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BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Income Taxes

The Company accounts for income taxes in accordance with ASC Topic 740, “Income Taxes.”  Under ASC Topic 740, deferred tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities, and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized.

Environmental

The Company is subject to environmental laws and regulations of various U.S. and international jurisdictions. These laws and regulations, which are subject to change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.

Environmental costs that relate to current operations are expensed or capitalized as appropriate. Costs are expensed when they relate to an existing condition caused by past operations and will not contribute to current or future revenue generation. Liabilities related to environmental assessments and/or remedial efforts are accrued when property or services are provided and when such costs can be reasonably estimated. The Company’s cost for environmental impact assessments related to the Company’s properties for the year ended December 31, 2012, 2011 and 2010 were approximately $0.5 million, $1.6 million and $2.4 million, respectively.

Loss per Common Share

In accordance with provisions of ASC Topic 260, “Earnings per Share,” basic earnings (loss) per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted earnings per share is computed based upon the weighted-average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. Diluted loss per share equals basic loss per share for the periods presented because the effects of potentially dilutive securities are antidilutive.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued additional guidance that clarifies application of fair value measurement and disclosure requirements and is effective for annual and interim periods beginning after December 15, 2011.  As of March 31, 2012, the Company adopted the provisions of this guidance, which did not impact the consolidated financial statements. The only impact was to fair value disclosures.

In December 2011, the FASB issued guidance that requires that an entity disclose information about offsetting and related arrangements to enable users of the Company’s financial statements to understand the effect of those arrangements on the Company’s financial position.  The guidance is effective for annual periods beginning on or after January 1, 2013.  The guidance for the disclosures will be applied retrospectively for all prior periods presented.  There was no impact on the Company’s financial position and results of operations.

On August 22, 2012, the SEC adopted rules mandated by the Dodd-Frank Act requiring entities who file reports with the SEC and commercially develop oil, natural gas or liquids (“resource extraction issuers”) to disclose certain payments made to the U.S. government or foreign governments.  The rules provide guidance on the types of payments and information about payments that must be disclosed.  The rules require a resource extraction issuer to disclose the information annually by filing a new form with the SEC (Form SD) no later than 150 days after the end of its fiscal year.  A resource extraction issuer is required to comply with the new rules for fiscal years ending after September 30, 2013.   As a result, beginning in 2014, the Company must annually 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. There will be no impact on the Company's financial position and results of operations, but may require additional disclosures in future filings.

93

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Note 2 — Divestiture

On April 27, 2012, the Company and Pacific Rubiales (together with its subsidiaries) executed a SPA under which the Company 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 the Company’s share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012.  In order to finalize the joint venture, Peruvian governmental approvals were needed to allow Pacific Rubiales to become a party to the Block Z-1 License Contract.  Until the required approvals were obtained, Pacific Rubiales had agreed to provide the Company a $65.0 million down payment on the purchase price and other funds which the Company initially accounted for as loans to continue to fund the Company’s 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.  The Company 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 the Company or from the Company under the SPA, for the interests and assets obtained from the Company 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 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 the Company’s share of capital and exploratory expenditures in Block Z-1.  The December 31, 2012 carry amount was $126.3 million.

At December 31, 2012, the Company 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.

Note 3 — Value-Added Tax Receivable

Value-added tax (referred to as “IGV” in Peru) is generally imposed on goods and services at a rate of 18% effective March 2011 and 19% in previous periods.

Peru currently has an IGV early recovery program for oil and gas companies during the exploration phase. Under this program, IGV paid on the acquisition of certain goods and services used directly in hydrocarbon exploration activities can be recovered prior to a commercial discovery taking place or the initiation of production and revenue billings. Because the Company has oil sales in the Corvina field and Albacora field in commercial production, it is no longer eligible for the IGV early recovery program. Accordingly, the Company is recovering its IGV receivable with IGV payables associated with future oil sales under the normal IGV recovery process.

Under the SPA and carry agreement entered into with Pacific Rubiales related to the sale of a 49% participating interest in Block Z-1, Pacific Rubiales funded the IGV incurred for the 100% of capital and exploratory expenditures of Block Z-1.  Upon closing of the transaction, the IGV balance related to this funding was transferred to them along with their respective share of assets.  See Note-2, “Divestitures.”

94

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Activity related to the Company’s value-added tax receivable for December 31, 2012 and 2011 is as follows:

	December 31, 2012			December 31, 2011
	(in thousands)
Value-added tax receivable as of the beginning of the period	$	24,720		$	31,352
IGV accrued related to expenditures during period		67,846			28,780
IGV reduced related to sale of oil during period		(46,586	)		(35,412	)
IGV related to the sale of a 49% participating interest in Block Z-1		(24,196	)		-
Value-added tax receivable as of the end of the period	$	21,784		$	24,720
Current portion of value-added tax receivable as of the end of the period	$	20,569		$	24,720
Long-term portion of value-added tax receivable as of the end of the period	$	1,215		$	-

See Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets” for further information on the long-term portion of the value-added tax receivable.

Note 4 — Inventory

Inventories consist primarily of crude oil, tubular goods, accessories and spare parts for production equipment, stated at the lower of average cost or market. 

The Company maintains crude oil inventories in storage vessels until the inventory quantities are at a sufficient level to make a delivery to the refinery in Talara.  Crude oil inventory is stated at the lower of average cost or market value.  Cost is determined on a weighted average basis based on production costs.

The crude oil inventory amount at December 31, 2012 reflects the 51% ownership share by the Company after the sale of a 49% participating interest in Block Z-1 assets, including ending inventory.

Below is a summary of inventory as of December 31, 2012 and 2011:

	December 31, 2012		December 31, 2011
	(in thousands)
Tubular goods, accessories and spare parts	$	18,343	$	13,541
Crude oil		1,508		3,300
Inventory	$	19,851	$	16,841

	December 31, 2012		December 31, 2011
Crude oil (barrels)		17,876		46,105
Crude oil (cost per barrel)	$	84.34	$	71.57

95

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Note 5 — Prepaid and Other Current Assets and Other Non-Current Assets

Below is a summary of prepaid and other current assets as of December 31, 2012 and 2011:

	December 31, 2012		December 31, 2011
	(in thousands)
Prepaid expenses and other	$	4,538	$	588
Prepaid insurance		441		961
Insurance receivable		755		755
Prepaid and other current assets	$	5,734	$	2,304

Prepaid expenses and other are primarily related to prepayments for drilling services, equipment rental and material procurement and deposits that are primarily rent deposits in connection with the Company’s offices in Houston and Peru. Prepaid insurance consists of premiums related to the Company’s operations as well as general liability and directors’ and officers’ insurance policies. The insurance receivable is related to an incident that occurred in the third quarter of 2011 where, while in the process of moving certain equipment from the A platform in Albacora to the CX-11 platform in Corvina using third parties, certain equipment was damaged.  The Company expects to recover the receivable amount from either the third parties or its insurance carrier.

Below is a summary of other non-current assets as of December 31, 2012 and 2011:

	December 31, 2012		December 31, 2011
	(in thousands)
Debt issue costs, net	$	4,768	$	7,527
Value-added tax receivable		1,215		-
Other non-current assets	$	5,983	$	7,527

Other non-current assets consist of direct transaction costs incurred by the Company in connection with its debt capital raising efforts.

At December 31, 2012 and 2011 the Company had net debt issue costs of $4.8 million and $7.5 million, respectively.

In connection with the prepayment made on the $75.0 million secured debt facility and the amendments to both the $75.0 million secured debt facility and the $40.0 million secured debt facility in April 2012, the debt issue costs associated with those agreements were modified in accordance with ASC Topic 470 as follows:

(1) Prior to the $40.0 million prepayment on the $75.0 million secured debt facility, the original debt issue costs of $4.4 million had an unamortized balance of $2.8 million. Approximately 53% of the remaining debt issue costs related to the $75.0 million secured debt facility was expensed ($1.5 million) when the Company prepaid 53% of the principal balance in May 2012. In addition, the Company added $1.1 million of debt issue costs incurred with the fourth amendment to the remaining debt issue costs of $1.3 million as the amendment was not considered a substantial modification of debt.  The $2.4 million of debt issue costs will be amortized to expense over the remaining term of the $75.0 million secured debt facility, ending in July 2015, using the effective interest method.

(2) Prior to the fourth amendment on the $40.0 million secured debt facility, the original debt issue costs of $1.5 million had an unamortized balance of $0.6 million.  The Company added $0.8 million of debt issue costs incurred with the fourth amendment to the remaining unamortized debt issue costs of $0.6 million as the amendment was not considered a  substantial modification of debt.  The $1.4 million of debt issue costs will be amortized to expense over the remaining term of the $40.0 million secured debt facility, ending in January 2015, using the effective interest method.

96

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The Company incurred $4.8 million of original debt issue costs associated with $170.9 million of convertible notes due 2015 (the “2015 Convertible Notes”). The debt issue costs are being amortized over the life of the $170.9 million Convertible Notes, using the effective interest method.

The following table is the amount of debt issue costs amortized into interest expense for the year ended December 31, 2012, 2011 and 2010, respectively:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Amortization of debt issue costs	$	3,135	$	2,687	$	792
	$	3,135	$	2,687	$	792

For further information regarding the Company’s debt, see Note-10, “Debt and Capital Lease Obligations.”

At December 31, 2012, the Company classified $1.2 million of its value-added tax receivable balance as a long-term asset as it believed it would take longer than one year to receive the benefit of this portion of the value-added tax receivable. For further information see Note-3, “Value-Added Tax Receivable.”

Note 6 — Property, Equipment and Construction in Progress

Below is a summary of property, equipment and construction in progress as of December 31, 2012 and 2011:

	December 31, 2012			December 31,  2011
	(in thousands)
Construction in progress:
Power plant and related equipment	$	73,958		$	66,903
Platforms and wells		15,611			48,469
Pipelines and processing facilities		11,784			20,089
Other		1,689			2,504
Producing properties (successful efforts method of accounting)		141,219			258,583
Producing equipment		27,758			17,143
Barge and related equipment		53,425			78,710
Office equipment, leasehold improvements and vehicles		9,249			10,824
Accumulated depletion, depreciation and amortization		(96,136	)		(121,623	)
Property, equipment and construction in progress, net	$	238,557		$	381,602

The property, equipment and construction in progress, net amount at December 31, 2012 reflects the sale of a 49% participating interest in Block Z-1.

Exploratory well costs capitalized greater than one year after completion of drilling were $6.6 million and $13.0 million as of December 31, 2012, and December 31, 2011.  The exploratory well costs relate to the CX11-16X gas well that was drilled in 2007, which tested sufficient quantities of gas and is currently shut-in until such time as a market is established for selling the gas.  The Company plans to use the gas from the CX11-16X well for its gas-to-power project.  The December 31, 2012 amount reflects the sale of a 49% participating interest in Block Z-1.  See Note-20, “Commitments and Contingencies” for further information on the gas-to-power project.

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BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

During the year ended December 31, 2012 and 2011, the Company incurred gross capital expenditures of approximately $88.7 million and $90.5 million, respectively, associated with its development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of gas-fired power generation of electricity for sale in Peru.

Approximately $102.1 million and $20.5 million were transferred from construction in progress to producing properties for the year ended December 31, 2012 and 2011, respectively.

During the year ended December 31, 2012, the Company incurred approximately $60.2 million related to costs incurred in the design, fabrication, installation and pipeline connections related to the CX-15 platform, and incurred $7.8 million for the development of and equipment for permanent production facilities.

In addition, during the year ended December 31, 2012, the Company added approximately $7.2 million of costs to the power plant, which primarily consisted of capitalized interest, approximately $5.7 million related to the CX-15 development drilling program and incurred approximately $7.8 million related to other capitalized costs.

The transfer of a 49% participating interest in Block Z-1 to Pacific Rubiales was effective on December 14, 2012.  Pacific Rubiales provided funding for capital expenditures for Block Z-1 of $70.7 million for the year ended December 31, 2012, which the Company recorded as additions to property and equipment, until the closing date, at which time Pacific Rubilales exchanged for certain loans, plus any other amounts due to the Company or from the Company under the SPA.

During the year ended December 31, 2011, the Company incurred approximately $26.6 million related to costs incurred in the design and fabrication of the CX-15 platform and incurred $22.3 million for the development of and equipment for permanent production facilities.

Also, the Company incurred $11.0 million on the onshore Pampa la Gallina exploratory well (PLG-1X) in Block XIX during the year ended December 31, 2011.  In December 2011, the $12.3 million of costs of the PLG-1X well along with $0.3 million costs of a water well to be used with the PLG-1X well and a $0.5 million retirement obligation asset were written off as dry hole costs.  In the fourth quarter of 2011, after completing technical review of information obtained during the drilling of the Pampa la Gallina (PLG-1X) well, the Company declared that the well had no further utility.

In addition, during the year ended December 31, 2011, the Company incurred approximately $4.6 million for the development of the A-9G well, $4.6 million for the development of the A-13E well, $4.0 million for the development of the A-12F well, and $1.2 million for the development of the A-17D water injection well.

Also, during the year ended December 31, 2011, the Company added approximately $6.3 million of costs to the power plant, which primarily consists of capitalized interest, and incurred approximately $2.7 million on the Caleta Cruz dock.

For the year ended December 31, 2011, the Company incurred approximately $1.6 million in computer hardware, software and telecommunication equipment, $1.2 million in machinery and equipment, $0.6 million for assets in transit, $0.3 million in costs for office equipment and leasehold improvements in its offices Peru and approximately $3.5 million of other capitalized costs.

98

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The following table is the amount of interest expense and depreciation expense capitalized to construction in progress for the year ended December 31, 2012 and 2011, respectively:

	Year Ended December 31,
	2012			2011
	(in thousands)
Interest expense capitalized		$	15,604		$	10,674
Depreciation expense capitalized			472			317

Note 7 — Investment in Ecuador Property

The Company has a 10% non-operating net profits interest in the Santa Elena Property, an oil and gas property in Ecuador.  The Company accounts for this investment under the cost method and records its share of cash received or paid as other income or expense. Since the Company’s investment represents ownership of an oil and gas property, which is a depleting asset, the Company is amortizing the cost of the investment on a straight-line basis over the remaining term of the agreement, which expires in May 2016. 

Below is a summary reflecting the Company’s income from the investment in the Ecuador property for the year ended December 31, 2012, 2011 and 2010, respectively, and the investment in the Ecuador property at December 31, 2012 and 2011, respectively:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Distributions received from investment in Ecuador property	$	250		$	600		$	928
Amortization of investment in Ecuador property		(188	)		(188	)		(188	)
Income from investment in Ecuador property, net	$	62		$	412		$	740

	December 31, 2012		December 31, 2011
	(in thousands)
Investment in Ecuador property, net	$	632	$	820

99

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Note 8 — Restricted Cash and Performance Bonds

Below is a summary of restricted cash as of December 31, 2012 and December 31, 2011:

	December 31, 2012		December 31, 2011
	(in thousands)
Performance bonds totaling $5.6 million for properties in Peru	$	3,338	$	3,338
Insurance bonds for import duties related to a construction vessel		825		814
Performance obligations and commitments for the gas-to power site		650		650
Secured letters of credit		259		563
$75.0 million secured debt facility		35,000		2,500
$40.0 million secured debt facility		32,727		2,000
Unsecured performance bond  totaling $0.1 million for office lease agreement		-		-
Restricted cash	$	72,799	$	9,865
Current portion of restricted cash as of the end of the period	$	25,129	$	2,000
Long-term portion of restricted cash as of the end of the period	$	47,670	$	7,865

The $75.0 million secured debt facility entered into by the Company in July 2011 required the Company to establish a $2.5 million debt service reserve account during the first 15 months the debt facility is outstanding.  After the first 15-month period, the Company is required to keep a balance in the debt service reserve account equal to the aggregate amount of principal and interest due on the next quarterly repayment date.  The requirement was subsequently amended subject to the closing of the sale of a 49% participating interest in Block Z-1 to require the funding of the debt service reserve account related to the $75.0 million secured debt facility in the amount of outstanding principal.  The restricted cash related to the current and non-current portion of the $75.0 million secured debt financing was $9.5 million and $25.5 million, respectively, at December 31, 2012.  The restricted cash related to the non-current portion of the $75.0 million secured debt financing was $2.5 million at December 31, 2011.

The $40.0 million secured debt facility entered into by the Company in January 2011 required the Company to establish a $2.0 million debt service reserve account during the first 18-month period and, thereafter, the Company must maintain a balance in the debt service reserve account equal to the aggregate amount of payments of principal and interest on the $40.0 million secured debt facility due immediately on the succeeding principal repayment date.  The requirement was subsequently amended subject to the closing of the sale of a 49% participating interest in Block Z-1to require the funding of the debt service reserve account related to the $40.0 million secured debt facility in the amount of outstanding principal.  The restricted cash related to the current and non-current portion of the $40.0 million secured debt financing was $14.5 million and $18.2 million, respectively, at December 31, 2012.  The restricted cash related to the current portion of the $40.0 million secured debt financing was $2.0 million at December 31, 2011.

All of the performance and insurance bonds are issued by Peruvian banks and their terms are governed by the corresponding license contracts, customs laws, legal requirements or rental practices.

Note 9 —Asset Retirement Obligation

An obligation was recorded for the future plug and abandonment of the oil wells in the Corvina and Albacora fields, and the Pampa la Gallina well in Block XIX in accordance with the provisions of ASC Topic 410, “Asset Retirement and Environmental Obligations.” ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon the Company’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using the Company’s credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the asset retirement cost.

100

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Activity related to the Company’s ARO for the year ended December 31, 2012 and December 31, 2011 is as follows:

	December 31, 2012			December 31, 2011
	(in thousands)
ARO as of the beginning of the period	$	1,304		$	855
Liabilities incurred during period		-			680
Liabilities settled during period		(2,093	)		-
Accretion expense		89			110
Revisions in estimates during period		3,408			(341	)
ARO as of the end of the period	$	2,708		$	1,304

The 2012 and 2011 revisions in estimates are due to the shift in timing of cash flows associated with expected payment of the ARO liability.  As revisions to estimated costs both in 2012 and 2011, the present value of the liabilities was adjusted and, as a result, the Company adjusted both the liability and capitalized asset by approximately $3.4 million and $0.3 million, respectively, in accordance with ASC Topic 410.

Liabilities settled in 2012 include $2.1 million related to the sale of a 49% participating interest in Block Z-1.

Note 10 —Debt and Capital Lease Obligations

At December 31, 2012 and 2011, debt and capital lease obligations consist of the following:

	December 31, 2012		December 31, 2011
	(in thousands)
$170.9 million Convertible Notes,  6.5%, due March 2015, net of discount of ($17.4) million at December 31, 2012 and ($24.1) million at December 31, 2011	$	153,479	$	146,781
$75.0 million Secured Debt Facility, 3-month LIBOR plus 9%, due July 2015		35,000		75,000
$40.0 million Secured Debt Facility, 3-month LIBOR plus 8%, due January 2015		32,727		40,000
Capital Lease Obligations		-		3,457
		221,206		265,238
Less: Current maturity of long-term debt and capital lease obligations		24,046		16,854
Long-term debt and capital lease obligations, net	$	197,160	$	248,384

101

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The following is a summary of scheduled debt maturities by year (in thousands):

2013	$	24,046
2014		26,545
2015		188,074
2016		-
2017		-
Thereafter		-
	$	238,665

$170.9 Million Convertible Notes due 2015

During the first quarter of 2010, the Company closed on a private offering for an aggregate of $170.9 million of convertible notes due 2015.  The 2015 Convertible Notes are the Company’s general senior unsecured obligations and rank equally in right of payment with all of the Company’s other existing and future senior unsecured indebtedness.  The 2015 Convertible Notes are effectively subordinate to all of the Company’s secured indebtedness to the extent of the value of the assets collateralizing such indebtedness.  The 2015 Convertible Notes are not guaranteed by the Company’s subsidiaries.

The interest rate on the 2015 Convertible Notes is 6.50% per year with interest payments due on March 1st and September 1st of each year.  The 2015 Convertible Notes mature with repayment of $170.9 million (assuming no conversion) due on March 1, 2015.

The initial conversion rate of 148.3856 shares per $1,000 principal amount (equal to an initial conversion price of approximately $6.74 per share of common stock) was adjusted on February 3, 2011 in accordance with the terms of the Indenture.

As a result, the conversion rate and conversion price changed to 169.0082 and $5.9169, respectively. Should there be a conversion, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the Indenture, (2) cash, or (3) a combination of cash and shares of its common stock.

Holders may convert their 2015 Convertible Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances:

(1) during any fiscal quarter (and only during such fiscal quarter) commencing after March 31, 2010, if the last reported sale price of the Company’s common stock is greater than or equal to 130% of the conversion price of the 2015 Convertible Notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter;

(2) prior to January 1, 2015, during the five business-day period after any ten consecutive trading-day period in which the trading price of $1,000 principal amount of the 2015 Convertible Notes for each trading day in the measurement period was less than 97% of the product of the last reported sale price of the Company’s common stock and the conversion rate on such trading day;

(3) if the 2015 Convertible Notes have been called for redemption; or

(4) upon the occurrence of one of a specified number of corporate transactions.

Holders may also convert the 2015 Convertible Notes at their option at any time beginning on January 3, 2015, and ending at the close of business on the second business day immediately preceding the maturity date.

On or after February 3, 2013, the Company may redeem for cash all or a portion of the 2015 Convertible Notes at a redemption price of 100% of the principal amount of the notes to be redeemed plus any accrued and unpaid interest to, but not including, the redemption date, plus a “make-whole” payment if: (1) for at least 20 trading days in any consecutive 30 trading days ending within 5 trading days immediately before the date the Company mails the redemption notice, the “last reported sale price” of its common stock exceeded 175% of the conversion price in effect on that trading day, and (2) there is no continuing default with respect to the notes that has not been cured or waived on or before the redemption date.

102

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

If the Company experiences any one of certain specified types of corporate transactions, holders may require the Company to purchase all or a portion of their 2015 Convertible Notes. Any repurchase of the notes pursuant to these provisions will be for cash at a price equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the purchase date.

The Indenture agreement contains customary terms and covenants and events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the 2015 Convertible Notes.

Net proceeds from the sale of the 2015 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by the Company, were approximately $164.9 million.  The initial purchaser received commissions of approximately $5.5 million in connection with the sale and the Company incurred approximately $0.6 million of direct expenses in connection with the offering.  The Company used the net proceeds for general corporate purposes, including capital expenditures and working capital, reduction or refinancing of debt, and other corporate obligations.

The Company accounts for the 2015 Convertible Notes in accordance with ASC Topic 470, “Debt,” as it pertains to accounting for convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement).  Under the accounting guidance, convertible debt instruments that may be settled entirely or partially in cash upon conversion are required to be separated into liability and equity components, with the liability component amount determined in a manner that reflects the issuer’s non-convertible debt borrowing rate. The value assigned to the liability component is determined by measuring the fair value of a similar liability that does not have an equity conversion feature. The value assigned to the equity component is determined by deducting the fair value of the liability component from the initial proceeds. The excess of the principal amount of the liability component over its carrying amount (the non-cash discount) is amortized to interest cost using the effective interest method over the term of the debt agreement.  In addition, transaction costs incurred that directly relate to the issuance of convertible debt instruments must be allocated to the liability and equity components in proportion to the allocation of proceeds and accounted for as debt issuance costs and equity issuance costs, respectively.

The Company estimated its non-convertible borrowing rate at the date of issuance of the 2015 Convertible Notes to be 12%. The 12% non-convertible borrowing rate represented the borrowing rate of similar companies with the same credit quality as the Company and was obtained through a quote from the initial purchaser. Using the income method and discounting the principal and interest payments of the 2015 Convertible Notes using the 12% non-convertible borrowing rate, the Company estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $136.3 million with the discount being approximately $34.6 million. The discount is being amortized as non-cash interest expense over the life of the notes using the effective interest method. In addition, the Company allocated approximately $4.8 million of the $6.1 million of fees and commissions as debt issue costs that are being amortized as non-cash interest expense over the life of the notes using the effective interest method. The remaining $1.3 million of fees and commissions were treated as transaction costs associated with the equity component.

The following table is the estimated remaining cash payments including interest payments related to the 2015 Convertible Notes, assuming no conversion (in thousands):

Year
2013	$	11,111
2014		11,111
2015		176,493
Total estimated remaining cash payments related to the 2015 Convertible Notes	$	198,715

103

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The Company evaluated the 2015 Convertible Notes agreement for potential embedded derivatives, noting that the conversion feature and make-whole provisions did not meet the embedded derivative criteria as set forth in ASC Topic 815, “Derivatives and Hedging.” Therefore, no additional amounts have been recorded for those items.

As of December 31, 2012, the net amount of $153.5 million includes the $170.9 million of principal reduced by $17.4 million of the remaining unamortized discount. The net amount of the equity component is $33.3 million, which includes the initial discount of $34.6 million reduced by $1.3 million of direct transaction costs. The remaining unamortized discount of $17.4 million will be amortized into interest expense, using the effective interest method, over the remaining life of the loan agreement, whose term expires in March 2015.  At December 31, 2012, using the conversion rate of 169.0082 shares per $1,000 principal amount of the 2015 Convertible Notes, if the $170.9 million of principal were converted into shares of common stock, the notes would convert into approximately 28.9 million shares of common stock.  As of December 31, 2012, there is no excess if-converted value to the holders of the 2015 Convertible Notes as the price of the Company’s common stock at December 31, 2012, $3.15 per share, is less than the conversion price.

For the year ended December 31, 2012, the annual effective interest rate on the 2015 Convertible Notes, including the amortization of debt issue costs, was approximately 12.6%.

The following table is the amount of interest expense related to the 2015 Convertible Notes, disregarding capitalized interest considerations, for the year ended December 31, 2012, 2011 and 2010, respectively:

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Interest expense related to the contractual interest coupon	$	11,111	$	11,111	$	10,062
Amortization of debt discount expense		6,698		5,961		4,480
Amortization of debt issue costs		956		916		737
Interest expense related to the 2015 Convertible Notes	$	18,765	$	17,988	$	15,279

$75.0 Million Secured Debt Facility

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

Proceeds from the $75.0 million secured debt facility were utilized to pay certain fees and expenses under the $75.0 million secured debt facility, to fund a debt service reserve account under the $75.0 million secured debt facility, to reimburse certain affiliates of BPZ E&P for up to $14.0 million of capital and exploratory expenditures incurred by them in connection with the development of Block Z-1 and up to $6.0 million of capital and exploratory expenditures incurred by them in connection with the development in Block XIX in northwest Peru, and to finance BPZ E&P’s capital and exploratory expenditures in connection with the development of Block Z-1.

As a result of the prepayment and amendment during the second quarter of 2012, the Company 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 the Company prepaid $40.0 million of principal.  The $1.1 million of new debt issue costs was combined with the remaining $1.3 million of unamortized debt issue costs and will be amortized over the amended term, ending in July 2015, using the effective interest method.  For further information on debt issue costs see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

104

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The $75.0 million secured debt facility, as amended, provides for ongoing fees payable by BPZ E&P to the lenders, including  an administration fee of 0.50% of the principal amount outstanding and a performance based arranger fee (the “Performance Based Arranger Fee”) whose amount is determined by the change in the price of Brent crude oil at inception of the loans and the price at each principal repayment date in accordance with the original loan principal repayment dates, subject to a 12% ceiling of the original principal amount borrowed.    For further information on the Performance Based Arranger Fee, see Note-11, “Derivative Financial Instruments” and Note-13, “Fair Value Measurements and Disclosures.”

The $75.0 million secured debt facility requires the Company to establish and maintain a debt service reserve account during the term of the debt facility.  At December 31, 2012 the debt service reserve account was fully funded for the outstanding principal balance of $35.0 million.  For further information regarding the debt service reserve account and its requirements, see Note-8, “Restricted Cash and Performance Bonds.”

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 S.A. (“Perupetro”), a corporation owned by the Peruvian government empowered to become a party in the contracts for the exploration and/or exploitation of hydrocarbons in order to promote these activities in Peru, (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. The Company and its subsidiary, BPZ Energy LLC, also agreed to unconditionally guarantee the remaining portion of the $75.0 million secured debt facility.

The amendment to the $75.0 million secured debt facility 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 that commenced in January 2013 and extending through July 2015.  The $75.0 million secured debt facility has an annual interest rate of the three month LIBOR rate plus 9%.  Interest is due and payable quarterly.

The $75.0 million secured debt facility, as amended, contains covenants that limit the Company’s ability to, among other things, incur additional debt other than the Pacific Rubiales loans, create certain liens, enter into transactions with affiliates, pay dividends on or repurchase stock of the Company or its subsidiaries, or sell assets other than to Pacific Rubiales or merge with another entity.  In addition, the Company must complete certain projects in the Corvina and Albacora offshore fields in Block Z-1 by certain scheduled dates.  The $75.0 million secured debt facility as amended also contains customary financial covenants, including (i) a maximum consolidated leverage ratio, (2) minimum consolidated interest coverage ratio, (iii) a maximum capitalization ratio, (iv) a minimum oil production quota per quarter, (v) a minimum debt service coverage ratio, (vi) a minimum proved developed producing reserves coverage ratio, (vii) a maximum indebtedness, and (viii) a minimum liquidity ratio.  For the quarter ending December 31, 2012 the Company obtained a waiver from Credit Suisse relating to the Company’s minimum oil production.  In addition on March 8, 2013, for the quarter ending March 31, 2013, the Company obtained a waiver from Credit Suisse relating to its minimum oil production and the date for first production from the CX-15 platform.  The Company was in compliance with these revised financial covenants at December 31, 2012.

The $75.0 million secured debt facility, as amended, provides for events of default customary for facilities of this type, the occurrence and continuation of which could result in the acceleration of amounts due under the facility. In addition, the $75.0 million secured debt facility provides that BPZ E&P has the right, at any time, to prepay the loans in whole, but not in part, subject to certain conditions and sets forth certain conditions for mandatory prepayments of the loan.

105

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The following table is the estimated remaining cash payments related to the $75.0 million secured debt facility, as amended and excluding potential payments for the Performance Based Arranger Fee but including interest payments (in thousands).  Currently the principal component would be paid via release of the corresponding cash from the debt service reserve account.

Year
2013	$	12,038
2014		14,104
2015		14,164
Total estimated remaining cash payments related to the $75.0 million secured debt facility	$	40,306

$40.0 Million Secured Debt Facility

In January 2011, the Company, through its subsidiaries, completed a credit agreement with Credit Suisse where Credit Suisse provided a $40.0 million secured debt facility to the Company’s power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L.  On April 27, 2012, the Company and its subsidiaries, Empresa Eléctrica Nueva Esperanza S.R.L. and BPZ E&P, entered into a fourth amendment to the $40.0 million secured debt facility with Credit Suisse.

Proceeds from the $40.0 million secured debt facility were utilized to meet the Company’s 2011 capital expenditure budget, to finance its exploration and development work programs, and to reduce other debt obligations.

As a result of the amendment entered into during the second quarter of 2012, the Company incurred $0.8 million of debt issue costs.  The $0.8 million of new debt issue costs was combined with the remaining $0.6 million of unamortized debt issue costs and will be amortized over the amended term, ending in January 2015, using the effective interest method.  For further information on debt issue costs, see Note-5, “Prepaid and Other Current Assets and Other Non-Current Assets.”

The $40.0 million secured debt facility, as amended, provides for ongoing fees payable to Credit Suisse including a Performance Based Arranger Fee whose amount is determined by the change in the price of Brent crude oil at inception of the loan and the price at each principal repayment date in accordance with the original loan principal repayment dates, subject to a 18% ceiling of the original principal amount borrowed.    For further information on the Performance Based Arranger Fee, see Note-11, “Derivative Financial Instruments” and Note-13, “Fair Value Measurements and Disclosures.”

The $40.0 million secured debt facility is secured, in part, by three LM6000 gas-fired packaged power units (approximately $74.0 million) that were purchased by the Company from GE through its 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. The Company and its subsidiary, BPZ E&P, also agreed to unconditionally guarantee the $40.0 million secured debt facility on an unsecured basis. 

The $40.0 million secured debt facility requires the Company to establish and maintain a debt service reserve account during the term of the facility.  At December 31, 2012 the debt service reserve account was fully funded for the  outstanding principal balance of $32.7 million.  For further information regarding the debt service reserve account and its requirements, see Note-8, “Restricted Cash and Performance Bonds.”

The amendment to the $40.0 million secured debt facility extended the maturity of the facility to January 2015, with revised principal repayments due in quarterly installments of $3.6 million that commenced in July 2012 and extending through January 2015.  The $40.0 million secured debt facility has a revised annual interest rate of the three month LIBOR rate plus 8%.  Interest is due and payable quarterly.

The amended $40.0 million secured debt facility subjects the Company to various financial covenants calculated as of the last day of each quarter, including a maximum leverage ratio, a minimum consolidated interest coverage ratio, a maximum consolidated capitalization ratio and minimum oil production quota per quarter.  For the quarter ending December 31, 2012, the Company obtained a waiver from Credit Suisse relating to the Company’s minimum oil production.  In addition on March 8, 2013, for the quarter ending March 31, 2013, the Company obtained a waiver from Credit Suisse relating to its minimum oil production.  The Company was in compliance with these revised financial covenants at December 31, 2012.

The $40.0 million secured debt facility provides for events of default customary for facilities of this type, the occurrence and continuation of which could result in the acceleration of amounts due under the facility. In addition, the $40.0 million secured debt facility provides for a mandatory repayment of the loans if the Company secures financing for its gas-to-power project.

106

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The following table is the estimated remaining cash payments related to the $40.0 million secured debt facility, as amended and excluding potential payments for the Performance Based Arranger Fee but including interest payments (in thousands).  Currently the principal component would be paid via release of the corresponding cash from the debt service reserve account.

Year
2013	$	16,365
2014		15,607
2015		3,712
Total estimated remaining cash payments related to the $40.0 million secured debt facility	$	35,684

Pacific Rubiales Loans

On April 27, 2012, the Company and Pacific Rubiales executed a SPA where the Company 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 Company’s 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 the Company $65.0 million and other funds as loans to continue to fund the Company’s 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 the Company or from the Company under the SPA, for the interests and assets obtained from the Company under the SPA and under the Block Z-1 License Contract.

The Company 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.

$15.0 Million IFC Reserve-Based Credit Facility

The Company had a $15.0 million reserve-based lending facility (“IFC Facility”) agreement (the “Loan Agreement”) with IFC through its subsidiaries BPZ E&P and BPZ Marine Peru S.R.L. as borrowers. The IFC Facility had $12.5 million outstanding maturing in December 2012; however, following the $40.0 million secured debt facility issued by the Company in January 2011, a portion of the proceeds was used to repay the amount outstanding to IFC.

The IFC Facility had interest at an approximate rate of LIBOR plus 2.75%, equivalent to 3.21% based on the six-month LIBOR rate of 0.46% at December 31, 2010.  The maximum amount available under this facility began at $15.0 million and was to be reduced by $2.5 million beginning on December 16, 2010 and every six months thereafter during the term of the Loan Agreement.  The amount available under the IFC Facility was subject to a semi-annual borrowing base determination based on the value of oil reserves.  In addition, the Company was subject to various financial covenants calculated as of the last day of each quarter, including a life of field coverage ratio, life of loan coverage ratio, debt to equity ratio and interest coverage ratio. The Loan Agreement also provided for events of default, cure periods and lender remedies customary for agreements of this type. The Company was in compliance with all material covenants of the Loan Agreement as of December 31, 2010.

107

BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Other

In July 2009, the Company, through its subsidiary, BPZ E&P, entered into a $5.1 million short-term loan agreement to finance the purchase of casing and accessories for use in its current and future operations. The $5.1 million short-term loan bore an annual interest rate of 5.45% and was repaid in five monthly installments of approximately $1.0 million starting September 2009.  In connection with the $5.1 million short-term loan agreement, the Company was required to deposit $1.0 million with the lending institution as a guaranty for the loan.  The $1.0 million was applied to the last installment of the loan repayments. As of December 31, 2009, the remaining principal amount was approximately $1.0 million and, along with the accrued interest due, was repaid with the $1.0 million deposit and cash in January 2010.

Capital Leases

In June 2007, the Company entered into a capital lease agreement, with an option to purchase two vessels, the Namoku and the Nu’uanu, to assist in the development of the Corvina oil field. The capital lease assets were recorded at $6.2 million, which represented the present value of the minimum lease payments, or the aggregate fair market value of the assets.

In May 2009, the Company entered into an amendment of its lease agreement for the two vessels under charter, the Namoku and the Nu’uanu. Under the terms of the amended lease agreement, the charter, originally set to expire in November 2009, was extended for five years commencing on May 1, 2009.  During the first 18 months of the amended lease term, the daily charter rate for the use of both vessels was fixed. Commencing in November 2010, the daily charter rate for the use of both vessels will be based on a tiered structure with the daily rate dependent upon the amount of the previous month’s average daily per barrel price of West Texas Intermediate Crude Oil (“WTI”), as indicated on the New York Mercantile Exchange. Any amount paid by the Company after November 2010 over the initial daily rate as a result of the escalated tiered structure based on the price of WTI is considered contingent rental payments.  The amount of the contingent lease payments paid in 2012 and 2011 was $0.6 million and $1.6 million, respectively. The amended lease agreement contains a $3.0 million purchase option after the third year of the lease, a $2.0 million purchase option after the fourth year of the lease and a mandatory $1.0 million purchase obligation by the Company after the fifth year of the lease. The Company accounted for the amended lease agreement in accordance with ASC Topic 840, “Leases.”  Under the guidance, the lease agreement continues to be accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 34.9%.

In June 2008, the Company entered into a two year capital lease agreement to acquire the production equipment used on board the Namoku resulting in additional capital assets of approximately $2.4 million. Further, the Company capitalized an additional $2.8 million of production equipment in order to have the Company’s floating production, storage and offloading facility (“FPSO”) ready to receive and treat oil received from the CX-11 platform. The FPSO lease contains two bargain purchase options; therefore, depreciation of the leased asset was over its useful life. The lease contains a bargain purchase option of $1.0 million at the end of the first year of the lease and a $0.5 million bargain purchase option at the end of the second year of the lease.  The Company accounted for the lease agreement in accordance with ASC Topic 840, “Leases.”  Under the guidance, the lease agreement was accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 28.3%.   In July 2010, the Company exercised the second year purchase option and purchased the capital lease production equipment used on board the FPSO, the Namoku.

In 2007, the Company entered into two capital loans for the purchase of office furniture.  Both loans have a term of 60 months, bearing interest at 5.94% and 9.44%, respectively, with principal and interest payments due on a monthly basis. During the fourth quarter of 2010, the Company made the final payments on the lease agreements and title of the office furniture was transferred to the Company.

In November 2009, the Company entered into a capital lease agreement for a construction vessel, the Don Fernando, resulting in additional capital assets of approximately $7.0 million.  In the fourth quarter of 2011, the Company made the final lease payment on the Don Fernando construction vessel, at which point title of the vessel was transferred to the Company.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

In May 2012, the Company exercised the third year purchase option for $3.0 million and purchased the marine vessels, the Namoku and the Nu’uanu, at which point titles to the vessels were transferred to the Company.

At December 31, 2012, the Company had no amounts outstanding under capital leases.

Interest Expense

The following table is a summary of interest expense for the year ended December 31, 2012, 2011 and 2010, respectively:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Interest expense	$	31,719		$	30,446		$	21,250
Capitalized interest expense		(15,604	)		(10,674	)		(9,632	)
Interest expense, net	$	16,115		$	19,772		$	11,618

Note 11 — Derivative Financial Instruments

Objective and Strategies for Using Derivative Instruments:

In connection with the $40.0 million secured debt facility and the $75.0 million secured debt facility, the Company and Credit Suisse agreed that a portion of the arranger fee would be based on the performance for oil prices and be payable at each of the principal repayment dates.  The fee is calculated by multiplying the principal payment amount by the change in oil prices from the loan origination date and the oil price at each principal repayment date. Additionally, the fee is capped at 18% of the $40.0 million secured debt facility and 12% of the $75.0 million secured debt facility.  The Performance Based Arranger Fee is being accounted for as an embedded financing derivative under ASC Topic 815, “Derivatives and Hedging” and accordingly, is being recorded at fair value with any mark-to-market changes in value reflected as loss on derivatives in the accompanying consolidated statements of operations.

Derivative Financial Instruments Not Designated as Hedging Instruments

Amount of Loss on Derivative Instruments Recognized in Income

	Year ended December 31,
	2012			2011			2010
	(in thousands)
Realized derivative gain (loss)	$	(1,672	)	$	-		$	-
Unrealized derivative gain (loss)		(938	)		(2,046	)		-
Total gain (loss) on derivative financial instruments	$	(2,610	)	$	(2,046	)	$	-

See Note-13, “Fair Value Measurements and Disclosures” for a discussion of methods and assumptions used to estimate the fair values of the Company’s derivative instruments.

Note 12 — Stockholders’ Equity

The Company has 25,000,000 shares of preferred stock, no par value and 250,000,000 shares of common stock, no par value, authorized for issuance.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Potentially Dilutive Securities

Basic earnings (loss) per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings (loss) per share of common stock may include the effect of the Company’s shares issuable under a convertible debt agreement, outstanding stock options or shares of restricted stock, except in periods in which there is a net loss. The following table summarizes the calculation of basic and diluted earnings (loss) per share:

	Year Ended December 31,
	2012			2011			2010
	(in thousands, except per share data)
Net loss	$	(39,089	)	$	(33,827	)	$	(59,771	)
Shares:
Basic weighted average common shares outstanding		115,631			115,367			114,919
Incremental shares from assumed conversion of dilutive share based awards		-			-			-
Diluted weighted average common shares outstanding		115,631			115,367			114,919
Excluded share based awards (1)		6,723			5,493			5,660
Excluded convertible debt shares (1)		28,890			28,890			25,365
Basic net loss per share	$	(0.34	)	$	(0.29	)	$	(0.52	)
Diluted net loss per share	$	(0.34	)	$	(0.29	)	$	(0.52	)

(1) Inclusion of the shares for these awards would have had an antidilutive effect.

The following table summarizes stock-based compensation costs recognized under ASC Topic 718, “Stock Compensation,” for the year ended December 31, 2012, 2011, and 2010, respectively, and is generally included in “General and administrative expense” on the Consolidated Statements of Operations:

	For the Year Ended December 31,
	2012		2011		2010
	(in thousands)
Employee stock—based compensation costs	$	2,283	$	2,689	$	4,290
Director stock—based compensation costs		532		1,330		1,523
Employee stock purchase plan costs		26		-		-
	$	2,841	$	4,019	$	5,813

Stock Option and Restricted Stock Plans

The Company has in effect the 2007 Long-Term Incentive Compensation Plan, as amended in 2010 to increase the number of shares available (the “2007 LTIP”), and the 2007 Directors’ Compensation Incentive Plan (the “Directors’ Plan”). The 2007 LTIP and Directors’ Plan provide for awards of options, stock appreciation rights, restricted stock, restricted stock units, performance awards, other stock-based awards and cash-based awards to any of the Company’s officers, employees, consultants and the employees of certain of the Company’s affiliates as well as non-employee directors. The number of shares authorized under the amended 2007 LTIP and Directors’ Plan is 8.0 million and 2.5 million, respectively. As of December 31, 2012, approximately 2.2 million shares remain available for future grants under the 2007 LTIP and 0.7 million shares remain available for future grants under the Directors’ Plan.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Restricted Stock Awards and Performance Shares

At December 31, 2012, there were approximately 1,189,311 shares of restricted stock awards outstanding to officers, directors and employees all of which generally vest with the passage of time on the second or third anniversary of the date of grant. Restricted stock is subject to certain restrictions on ownership and transferability when granted. The fair value of restricted stock awards is based on the market price of the Common Stock on the date of grant. Compensation cost for such awards is recognized ratably over the vesting or service period, net of forfeitures; however, compensation cost related to performance shares will not be recorded or will be reversed if the Company does not believe it is probable that such performance criteria will be met or if the service provider (employee or otherwise) fails to meet such criteria.

A summary of the Company’s restricted stock award activity for the year ended December 31, 2012 and related information is presented below:

	Number of Restricted Shares			Weighted— Average Fair Value Per Share
Outstanding at the begining of the year		425,364		$	5.61
Granted		992,237			3.29
Vested		(217,540	)		5.45
Forfeited or expired		(10,750	)		4.00
Outstanding at the end of the year		1,189,311		$	3.73

The weighted average grant-date fair value of restricted stock awards granted for the year ended December 31, 2011 and 2010 was $5.89 and $5.28, respectively.  The fair value of restricted stock awards that vested during the year ended December 31, 2012, 2011 and 2010 was $1.2 million, $0.8 million, and $4.9 million, respectively. As of December 31, 2012, there was $2.5 million of total unrecognized compensation cost related to non-vested restricted stock awards, which is expected to be recognized over a weighted-average period of 2.1 years.

Stock Options

Incentive and non-qualified stock options issued to directors, officers, employees and consultants are typically granted at the fair market value on the date of grant. The Company’s stock options generally vest in equal annual installments over a two to three year period and expire ten years from the date of grant.

The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options, which have no vesting restrictions and are fully transferable and negotiable in a free trading market. This model does not consider the employment, transfer or vesting restrictions that are inherent in the Company’s stock options.

Use of an option valuation model includes highly subjective assumptions based on long-term predictions, including the expected stock price volatility and expected option term of each stock option grant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The following table presents the weighted-average assumptions used in the option pricing model for options granted during the year ended December 31:

	2012			2011			2010
Expected life (years) (a)		4.2			4.5			4.5
Risk-free interest rate  (c)		0.8	%		2.1	%		2.0	%
Volatility (b)		85.8	%		84.1	%		91.7	%
Dividend yield (d)		-			-			-
Weighted-average fair value per share at grant date	$	2.48		$	3.88		$	3.26

(a)	The expected life was derived based on a weighting between (a) the Company’s historical exercise and forfeiture activity and (b) the average midpoint between vesting and the contractual term and (c) from the analysis of other companies of a similar size and operational life cycle.
(b)	The volatility is based on the historical volatility of our stock for a period approximating the expected life.
(c)	The risk-free interest rate is based on the observed U.S.  Treasury yield curve in effect at the time the options were granted.
(d)	The dividend yield is based on the fact the Company does not anticipate paying any dividends.

A summary of the Company’s stock option activity for the year ended December 31, 2012 and related information is presented below:

	Number of Options			Weighted— Average Exercise Price Per Option		Weighted Average Remaining Contractual Term		Aggregate Intrinsic Value
Outstanding at the begining of the year		5,067,634		$	8.67
Granted		594,613			3.96
Exercised		-			-
Forfeited or expired		(128,680	)		7.67
Outstanding at the end of the year		5,533,567		$	8.18		5.74	$	199,409
Exercisable at the end of the year		4,551,466		$	8.95		5.10	$	185,809

As of December 31, 2012, there was $1.3 million of unrecognized compensation cost related to non-vested stock options that is expected to be recognized over a weighted average period of 1.9 years.  The total intrinsic value of stock options (defined as the amount by which the market price of the Common Stock on the date of exercise exceeds the exercise price of the stock option) exercised during the year ended December 31, 2012, 2011, and 2010 was none, $0.3 million and none, respectively.  Cash received from stock option exercises for the year ended December 31, 2012, 2011 and 2010 was none, $0.9 million and none, respectively. 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The following table summarizes information about stock options outstanding as of December 31, 2012:

					Outstanding						Exercisable
Range of Exercise Prices					Number of Options		Weighted- Average Remaining Contractual Life (In years)		Weighted Exercise Price		Number of Options		Weighted- Average Exercise Price Per Option
Below		to	$	2.12		99,248		1.7	$	1.30		99,248	$	1.30
$	2.13	to	$	4.23		1,352,883		6.3		3.63		711,082		3.34
$	4.24	to	$	6.35		1,522,231		6.1		5.07		1,423,416		5.11
$	6.36	to	$	8.47		667,705		6.5		6.48		426,220		6.50
$	8.48	to	$	10.58		190,000		5.0		10.17		190,000		10.17
$	10.59	to	$	25.53		1,701,500		5.0		15.43		1,701,500		15.43
Total						5,533,567		5.7	$	8.18		4,551,466	$	8.95

Employee Stock Purchase Plan

The employee stock purchase plan (“ESPP”), which was approved by the shareholders on June 24, 2011, provides eligible employees the opportunity to acquire shares of BPZ Resources, Inc. common stock at a discount, through payroll deductions. Employees are allowed to purchase up to 2,500 shares in any one offering period (not longer than twenty-seven months), within IRS limitations and plan rules.  The offering period means each period of time which common stock is offered to participants.  Unless otherwise determined by the compensation committee, a new offering period shall commence on the first day of each calendar quarter.  Generally, the purchase price for stock acquired under the plan is the lower of 85% (subject to compensation committee adjustment) of the fair market value of the common stock on the grant date or the fair market value of the common stock on the investment date. Under this plan, 2,000,000 common shares have been reserved for issuance and purchase by eligible employees.  Activity under this plan began in the first quarter of 2012.  At December 31, 2012, 1,959,989 shares were available for issuance.  On January 2, 2013, 5,181 shares were issued to employees at a price of $2.38 per share.

The fair value of all ESPP grants is estimated using the Black-Scholes pricing model.  The table below represents the valuation assumptions used to value the ESPP grants and the weighted average fair value for the year ended December 31:

	2012			2011		2010
Expected life (months)		3			-		-
Risk-free interest rate		0.08	%		-		-
Volatility		35.3	%		-		-
Dividend yield		-			-		-
Weighted-average fair value of grants	$	0.58			-		-
Shares purchased during year		40,011			-		-
Average number of participants per quarter		12			-		-

Note 13— Fair Value Measurements and Disclosures

The Company records certain of its assets and liabilities on the balance sheet at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

·	Level 1 —	Fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.
·	Level 2 —	Fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.
·	Level 3 —	Fair value measurements which use unobservable inputs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The following describes the valuation methodologies the Company uses for its fair value measurements.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Cash and Cash Equivalents

Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value because of the short maturity of these instruments.

Restricted Cash

Restricted cash includes all cash balances which are associated with the Company’s long-term assets, short-term debt and long-term debt. The carrying amount approximates fair value because the nature of the restricted cash balance is the same as cash.  The fair value of restricted cash is measured using Level 1 inputs within the three-level valuation hierarchy.

Derivative Financial Instruments   

The Company’s derivative financial instruments consist of variable financing arranger fee payments that are dependent on the change in oil prices from the loan origination date of the Company’s $40.0 million secured debt facility, the $75.0 million secured debt facility and the oil price on each repayment date. The Company estimates the fair value of these payments based on published forward commodity price curves at each financial reporting date. The discount rate used to discount the associated cash flows is based on the Company’s credit-adjusted risk-free rate. Accordingly, these derivatives are considered to be a Level 2 measurement on the fair value hierarchy.  For further information regarding the Company’s derivatives, see Note-11, “Derivative Financial Instruments.”

114

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:

		Fair Value Measurements Using:
	Balance Sheet Location	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
		(in thousands)
December 31, 2012
Financial Liabilities
Derivative Financial Instruments
	Current Liabilities	$	-	$	2,984	$	-
	Non-current Liabilities		-		-		-
		$	-	$	2,984	$	-
December 31, 2011
Financial Liabilities
Derivative Financial Instruments
	Current Liabilities	$	-	$	1,096	$	-
	Non-current Liabilities		-		950		-
		$	-	$	2,046	$	-

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as impairments of long-lived assets, at fair value on a non-recurring basis. As none of the Company’s non-financial assets and liabilities were impaired as of December 31, 2012 and December 31, 2011, and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures were not provided.

Additional Fair Value Disclosures

Debt with Variable Interest Rates

The fair value of the Company’s $75.0 million secured debt facility and $40.0 million secured debt facility at December 31, 2012 approximates the carrying value because the interest rates are based on floating rates identified by reference to market rates, and because the interest rates charged are at rates at which the Company could borrow under similar terms.  The floating rate debt is considered to be a Level 2 measurement on the fair value hierarchy.

115

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Debt with Fixed Interest Rates

The fair value information regarding the Company’s fixed rate debt is as follows:

	December 31, 2012				December 31, 2011
	Carrying Amount		Fair Value (2)		Carrying Amount		Fair Value (2)
	(in thousands)				(in thousands)
$170.9 million Convertible Notes,  6.5%, due March 2015, net of discount of ($17.4) million at December 31, 2012 and ($24.1) million at December 31, 2011 (1)	$	153,479	$	147,861	$	146,781	$	140,460

(1) Excludes obligations under capital lease arrangements and variable rate debt.

(2) The Company estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $147.9 million and $140.5 million at December 31, 2012 and December 31, 2011, respectively, based on observed market prices for the same or similar type of debt issues.  The fair value of the $170.9 million 2015 Convertible Notes is considered to be a Level 1 measurement on the fair value hierarchy.

Note 14 — Affiliate and Related Party Transactions

For the year ended December 31, 2012, 2011 and 2010, the Company had not entered into any transactions with affiliates or related parties.

Note 15 — Revenue

At December 31, 2012, the Company had developed nine gross (4.6 net) wells in the Corvina field and four gross (2.0 net) wells in the Albacora field.  Of these wells, seven gross (3.6 net) wells were producing oil, four gross (2.0 net) wells were producing oil intermittently, one gross (.51 net) well was being used for gas injection and the remaining gross (.51 net) well was being used for water reinjection.   At December 31, 2011, the Company was producing oil from five (gross and net) wells, six (gross and net) wells were producing oil intermittently, one (gross and net) well was being used for gas injection and the remaining (gross and net) well was being used for water reinjection.  At December 31, 2010, the Company was producing oil from seven (gross and net) wells with the remaining (gross and net) wells being shut-in.

The oil is delivered by vessel to the refinery owned by the Peruvian national oil company, Petroleos del Peru - PETROPERU S.A. (“Petroperu”), in Talara, located approximately 70 miles south of the platform.  Produced oil is kept in production inventory until inventory quantities are at a sufficient level to make a delivery to the refinery in Talara.  Although all of the Company’s oil sales are to Petroperu, it believes that the loss of Petroperu as its sole customer would not materially impact the Company’s business because it could readily find other purchasers for the Company’s oil production both in Peru and throughout the world.

The Company’s revenues 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

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

	Year Ended December 31,
	2012		2011		2010
	(in thousands)
Royalty costs	$	6,605	$	7,469	$	6,292
	$	6,605	$	7,469	$	6,292

Note 16— Other Expense

For the year ended December 31, 2012, the Company reported $2.3 million of abandonment charges in the Consolidated Statements of Operations as “Other expense.”  The Company accrued $2.3 million of abandonment costs related to a platform in the Piedra Redonda field in Block Z-1, as it is 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, see below.  There were no similar expenses incurred by the Company in 2011.

For the year ended December 31, 2010, the Company reported $12.9 million of charges in the Consolidated Statements of Operations as “Other expense.” These charges include $10.7 million of charges related to certain engineering, consulting, environmental and legal costs for the Company’s 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 of these engineering and development costs associated with the Company’s current gas plant, pipeline and gas-to-power project plans.  Accordingly, the Company wrote off these costs. With respect to the $2.2 million of platform abandonment costs, the Company 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 the Company acquired the rights to the offshore Block Z-1 in northwest Peru, are not suitable for the Company’s future oil development plans. Accordingly, the Company wrote off the $1.4 million of costs incurred to evaluate the feasibility of refurbishing and using these platforms. In addition, the Company accrued $0.8 million of abandonment costs related to the platform in the Piedra Redonda field as it is obligated to ensure the platform does not cause a threat to marine vessels operating in the area or marine wildlife.

Note 17— Standby Costs

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

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

For the year ended December 31, 2011, the Company incurred $4.5 million in standby costs which includes $3.9 million of standby rig costs.  Additionally, the Company incurred $0.6 million of allocated expenses associated with drilling operations for the year ended December 31, 2011. 

During 2011, the Company 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

For the year ended December 31, 2010, the Company incurred $7.5 million in standby costs, which includes $4.9 million of standby rig costs.  Additionally, the Company incurred $2.6 million of allocated expenses associated with drilling operations for the year ended December 31, 2010. 

Note 18 — Income Taxes

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

	2012			2011			2010
United States	$	(6,465	)	$	(14,148	)	$	(12,688	)
Foreign		(48,238	)		(17,244	)		(58,691	)
Loss before income taxes	$	(54,703	)	$	(31,392	)	$	(71,379	)

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

	2012			2011		2010
Current Taxes
Federal	$	-		$	-	$	(200	)
Foreign		13,551			179		2,151
Total Current		13,551			179		1,951
Deferred Taxes
Federal	$	-		$	-	$	-
Foreign		(29,165	)		2,256		(13,559	)
Total Deferred		(29,165	)		2,256		(13,559	)
Total income tax expense (benefit)	$	(15,614	)	$	2,435	$	(11,608	)

The income tax expense (benefit) for the year ended December 31, 2012, 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):

	2012			2011			2010
Federal statutory income tax rate	$	(18,599	)	$	(10,673	)	$	(24,269	)
Increases (decreases) resulting from:
Peruvian income tax - rate difference less than 34% statutory		7,791			2,771			5,763
Permanent book/tax differences		(621	)		1,016			(365	)
Non-deductible intercompany expenses and other		2,763			4,623			(2,922	)
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			10,185
Total income tax expense (benefit)	$	(15,614	)	$	2,435		$	(11,608	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

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, the Company has 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, the Company 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, the Company 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 it believes, 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 the Company has no operations within the U.S. taxing jurisdiction, it is likely that sufficient generation of revenue to offset the Company’s deferred tax asset is remote. 

In 2011, the Company amended its 2009 U.S. Federal Tax return to elect to deduct its previously benefited foreign income tax credits.  This resulted in an increase to the Company’s net operating loss carryforward and the elimination of the foreign income tax credit carryforward previously accrued as a deferred tax asset.  Since the Company 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, the Company 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.  The Company is subject to Peruvian income tax on its earnings at a statutory rate, as defined in the Block Z-1 License Contract, of 22%.  The Company assessed the realizability of the deferred tax asset generated in Peru.  The Company 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, the Company believes it is more likely than not that it will realize the majority of the these deductible differences at December 31, 2012.  In addition, the Company has 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 it believes it may not receive the full benefit of these deductions.  As a result, the Company recognized a net deferred tax asset of $55.3 million related to its foreign operations as of December 31, 2012.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The Company 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 the Company’s 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 the Company’s significant net operating loss carryforward position the Company has not recognized 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.  The Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the year ended December 31, 2012, 2011 or 2010.  The Company 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.

Note 19 — Business Segment Information

The Company determines and discloses its segments in accordance with ASC Topic 280, “Segment Reporting” (“ASC Topic 280”), which uses a “management” approach for determining segments. The management approach designates the internal organization that is used by management for making operating decisions and assessing performance as the source of the Company’s reportable segments. ASC Topic 280 also requires disclosures about products or services, geographic areas, and major customers. The Company’s management reporting structure provided for only one segment for the year ended December 31, 2012, 2011 and 2010. Accordingly, no separate segment information is presented. In addition, the Company operates only in Peru and has only one customer for its oil production, Petroperu. The majority of the Company’s long-lived assets are located in Peru. Management does not consider its investment in Ecuador as a separate business segment.

Note 20 — Commitments and Contingencies

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 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 Extended Well Test (“EWT”) period must be submitted to the General Directorate of Hydrocarbons (“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, the Company must also obtain gas flaring permits for each well in order for it to be in compliance with Peruvian environmental legislation.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Albacora Extended Well Testing Program

The Company 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, the Company’s 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, the Company received an environmental permit from the Direccion General de Asuntos Ambientales Energeticos ("DGAAE") allowing the Company to begin the drilling and subsequent operation of all production and injection facilities on the new CX-15 platform at the Corvina field.

Ecuadorian Hydrocarbon Law

In July 2010, the Company was notified of changes to the Ecuadorian hydrocarbon law that included provisions that will allow the Ecuadorian government to nationalize oil fields if a private operator does not agree to contractual changes mandated by the new hydrocarbon laws.  The consortium, of which the Company is a participant, successfully negotiated a service contract during the fourth quarter of 2010; accordingly, the Company does not believe there is a significant risk of nationalization of its interest in the Santa Elena field. The Company is still reviewing the impact of this new law, if any, as it pertains to its 10% net investment interest in an oil and gas property in Ecuador. For further information see Note-7, “Investment in Ecuador Property.”  However, the Company does not believe any such impact on its Ecuadorian investment will have a material impact on the Company’s overall financial position.

Profit Sharing

The Constitution of Peru and Legislative Decree Nos. 677 and 892 give employees working in private companies engaged in activities generating income as defined by the Income Tax Law the right to share in the company’s profits.  According to Article 3 of the United Nations International Standard Industrial Classification, BPZ E&P’s tax category is classified under the “mining companies” section, which sets the rate at 8%. However, in Peru, the Hydrocarbon 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 5% of income is determined by calculating a percentage of the Company’s Peruvian subsidiaries’ annual total revenues subject to income tax less the expenses required to produce revenue or maintain the source of revenues. The benefit granted by the law to employees is calculated on the basis of “income subject to taxation” per the Peruvian tax code, and not based on income/(loss) before incomes taxes as reported under GAAP. For the year ended December 31, 2012, December 31, 2011 and December 31, 2010, respectively, profit sharing expense was not material to the Company as the Company’s Peruvian subsidiaries did not have a material amount of “income subject to taxation” per the Peruvian tax code as a result of declaring commercial production in the Corvina field, which allowed certain exploration and development costs to be deductible in 2012, 2011 and 2010 that were not deductible in previous years.  The Company is subject to profit sharing expense any year its Peruvian subsidiaries are profitable according to the Peruvian tax laws.

Gas-to-Power Project Financing

The 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 the building of an approximately 135 megawatt (“MW”) simple-cycle electric generating plant.  The power plant site is located adjacent to an existing substation and power transmission lines, which, after the Peruvian government completes their expansion, are 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The Company currently estimates 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 estimated cost of the construction of the natural gas pipeline. While the Company has 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, the Company has not entered into any definitive agreements with a potential partner. In the event the Company is able to identify and reach an agreement with a potential joint venture partner, it may only retain a minority position in the project. However, the Company along with its Block Z-1 partner, Pacific Rubiales, expects to retain the responsibility for the construction of the pipeline as well as retain ownership of the pipeline.  The Company has obtained certain permits and is in the process of obtaining additional permits to move the project forward.

Note 21 — 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 the Company’s 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 the Company’s 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, the Company 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.

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

Additionally, the Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

Note 22 — Operating Leases and Purchase Obligations

The Company is committed under various operating leases.  Rent expense incurred for the year ended December 31, 2012, 2011 and 2010 was approximately $1.2 million, $1.1 million and $1.6 million, respectively. See Note-17, “Standby Costs,” for drilling rig equipment expense included in the Consolidated Statements of Operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Minimum non-cancelable lease, purchase commitments, current and  non-current liabilities as of December 31, 2012 are as follows (in thousands):

2013	$	38,800
2014		1,261
2015		21,090
2016		57
2017		-
Thereafter		-
Total minimum lease, purchase commitments and current and non-current liabilities	$	61,208

Includes operating leases for the Company's executive office in Houston, Texas (expires in 2016), and the Company's branch offices in Lima, Peru (expires in 2014) and warehouses in Peru (expires in 2014), respectively.

Includes the monthly lease expense for three of our drilling rigs.  Two leases are set to expire in the first quarter of 2013, the other lease is set to expire in December 2013.

Includes the monthly lease expense for one of the Company's oil transportation vessels whose lease is set to expire in February 2013.

Includes current ($19.9 million) and non-current ($20.8 million) liabilities related to exploratory expenditures for 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 terms of the SPA.

Note 23 — Subsequent Events

On January 14, 2013, the Company obtained waivers to the $75.0 million secured debt facility and the $40.0 million secured debt facility with Credit Suisse in respect of the Company’s minimum crude oil barrel production for the fiscal quarter ended December 31, 2012.

On March 4, 2013, the Company 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.

On March 8 2013, the Company obtained waivers to the $75.0 million secured debt facility and the $40.0 million secured debt facility with Credit Suisse in respect of the Company’s minimum crude oil barrel production covenants for the first quarter of 2013 and the date for first production from the CX-15 platform.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Note 24 — Quarterly Results of Operations (Unaudited)

	Three Months Ended
	March 31,			June 30,			September 30,			December 31, (a)
	(in thousands except per share data)
2012
Total net revenue	$	36,553		$	32,681		$	28,672		$	25,052
Operating income (loss)		(18,932	)		(6,693	)		(13,229	)		10,247
Other expense		(12,669	)		(3,229	)		(6,526	)		(3,672	)
Net income (loss)	$	(27,291	)	$	(8,500	)	$	(17,141	)	$	13,843
Basic net income (loss) per share	$	(0.24	)	$	(0.07	)	$	(0.15	)	$	0.12
Diluted net income (loss) per share	$	(0.24	)	$	(0.07	)	$	(0.15	)	$	0.12
Basic weighted average common shares outstanding		115,513			115,573			115,694			115,742
Diluted weighted average common shares outstanding		115,513			115,573			115,694			115,928

	Three Months Ended
	March 31,			June 30,			September 30,			December 31,
	(in thousands except per share data)
2011
Total net revenue	$	38,705		$	36,939		$	36,210		$	31,886
Operating income (loss)		290			8,957			7,115			(27,884	)
Other expense		(7,647	)		(5,285	)		(335	)		(6,603	)
Net income (loss)	$	(8,093	)	$	292		$	5,705		$	(31,731	)
Basic net income (loss) per share	$	(0.07	)	$	0.00		$	0.05		$	(0.27	)
Diluted net income (loss) per share	$	(0.07	)	$	0.00		$	0.05		$	(0.27	)
Basic weighted average common shares outstanding		115,180			115,322			115,460			115,484
Diluted weighted average common shares outstanding		115,180			115,776			115,547			115,484

(a) In December 2012, the Company sold a 49% participating interest in Block Z-1.

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SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Supplemental Oil and Gas Disclosures (Unaudited)

Oil and Natural Gas Producing Activities

The following disclosures for the Company are made in accordance with ASC Topic 932, “Extractive Activities –Oil and Gas” and SEC rules for oil and gas reporting disclosures. Users of this information should be aware that the process of estimating quantities of proved, proved developed and proved undeveloped crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas ultimately recovered.

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

SEC and FASB Updates on Oil and Gas reporting

On December 31, 2008 the SEC adopted the final rules regarding amendments to current oil and gas reporting requirements. See Recent Accounting Pronouncements under Note-1, “Basis of Presentation and Significant Accounting Policies” for further information. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology.  Additionally, in January 2010, the FASB issued Accounting Standard Update 2010-3, “Oil and Gas Reserve Estimation and Disclosures,” to align its reporting guidance with the new SEC rules. The Company adopted these rules effective December 31, 2009 and the changes, including those related to pricing, are included in the Company’s reserve estimates.

The most significant changes to the Company’s reserve estimates as a result of the new rules are as follows:

· Requiring companies to report oil and gas reserves using an un-weighted average price based upon the prior 12-month period rather than year-end prices;

· Requiring companies to report the independence and qualifications of a preparer or auditor, based on current Society of Petroleum Engineers criteria;

· Requiring the filing of reports for companies that rely on a third party to prepare reserves estimates or conduct a reserves audit; and

· Limiting proved undeveloped reserves locations to those that are scheduled to be drilled within the next five years.

Reserves

Proved reserves represent estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.

Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.

Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Our relevant management controls over proved reserve attribution, estimation and evaluation include:

· controls over and processes for the collection and processing of all pertinent operating data and documents needed by our independent reservoir engineers to estimate our proved reserves;

· engagement of well qualified and independent reservoir engineers for review of our operating data and documents and preparation of reserve reports annually in accordance with all SEC reserve estimation guidelines;

· review by our senior reservoir engineer and his staff of the independent reservoir engineers’ reserves reports for completion and accuracy; and

· oversight and review by our Technical Committee, made up of independent members of the Board of Directors,  who 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.

Beginning December 31, 2009, an unweighted average of the first-day-of-the month price based upon the prior 12-month period is used for future sales of natural gas, crude oil and natural gas liquids. Future operating costs, production taxes and capital costs are based on current costs as of each year-end, with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the standardized measure should not be construed as the current market value of the proved oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risks.

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

As of December 31, 2012, we had a total quantity of 22 PUDs contributing 14.3 MMbbls to our 2012 proved oil reserves.  Of the total 22 PUDs, 18 PUDs are associated to the Corvina field and 4 PUDs are associated to the Albacora field. During the year ended December 31, 2012, no PUD that contributed to the 2011 proved oil reserves was converted into proved developed reserves in the Corvina field or the Albacora field.  Costs incurred to advance the development of PUDs in 2012 were approximately $60.2 million associated with the CX-15 platform of which $56.8 million was reimbursed by our partner in Block Z-1, Pacific Rubiales.  As of December 31, 2012, we did not have any PUDs previously disclosed that have remained undeveloped for five years or more. As of December 31, 2012, we have no PUD locations included in our proved oil reserves that are scheduled to be drilled after five years.   In December 2012, the Company completed the sale of a 49% participating interest in the Block Z-1 license contract.  The Company now owns a 51% participating interest in Block Z-1.

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SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Capitalized Costs Relating to Oil and Gas Producing Activities

The following table sets forth the capitalized costs relating to the Company’s natural gas and crude oil producing activities at December 31, 2012 and 2011:

	2012			2011
	(in thousands)
Proved properties	$	194,761		$	354,246
Unproved properties		11,078			20,116
Total		205,839			374,362
Less: Accumulated depreciation, depletion and amortization		(65,054	)		(94,482	)
Net capitalized cost		140,785			279,880
Company's share of cost method investees’ costs of property acquisition, exploration and development (1)	$	-		$	-

(1)       The Company purchased the Investment in Ecuador Property in 2004.

Pursuant to ASC Topic 410, “Asset Retirement and Environmental Obligations,” net capitalized cost includes asset retirement cost of $2.7 million and $1.3 million as of December 31, 2012 and December 31, 2011, respectively.

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

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SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the year ended December 31, 2012 and 2011 (in thousands):

	Total
Year Ended December 31, 2012:
Acquisition costs of properties
Proved	$	-
Unproved		-
Total acquisition costs		-
Exploration costs		41,496
Development costs (2)		77,596
Total	$	119,092
Company’s share of cost method investees’ costs of property acquisition, exploration and development (1)	$	-
Year Ended December 31, 2011:
Acquisition costs of properties
Proved	$	-
Unproved		-
Total acquisition costs		-
Exploration costs		22,885
Development costs		62,803
Total	$	85,688
Company’s share of cost method investees’ costs of property acquisition, exploration and development (1)	$	-

(1) The Company purchased the Investment in Ecuador Property in 2004.

(2)In December 2012, the Company completed the sale of a 49% participating interest in the Block Z-1 license contract.  The Company now owns a 51% participating interest in Block Z-1.  Pacific Rubiales provided funding for capital expenditures for Block Z-1 of $70.7 million for the year ended December 31, 2012.

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SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Results of Operations for Oil and Natural Gas Producing Activities

The results of operations for oil and natural gas producing activities, excluding general and administrative expenses and interest expense, are as follows for the periods indicated:

	Year Ended December 31,
	2012			2011		2010
	(in thousands)
Oil revenue, net	$	122,708		$	139,354	$	110,075
Geological, geophysical and engineering expense		40,686			9,315		19,107
Dry hole costs		-			13,082		32,778
Lease operating expense		52,458			50,792		32,585
Depletion and amortization expense		31,453			26,845		28,514
Income (loss) before income taxes		(1,889	)		39,320		(2,909	)
Income tax provision (benefit)		(415	)		8,650		(640	)
Results of continuing operations	$	(1,474	)	$	30,670	$	(2,269	)
Company’s share of cost method investees’ results of operations for producing activities(1)	$	250		$	600	$	928

(1)       Investment in Ecuador Property

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

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SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Net Proved Reserve Summary

The following table sets forth the Company’s net proved developed and undeveloped reserves at December 31, 2012, 2011 and 2010, and the changes in the net proved reserves for each of the three years. All of the Company’s proved reserves are located in Peru. The Company’s net profit interest in the Santa Elena property is located in Ecuador and is based on a service contract.

	Natural gas (MMcf)(4)		Natural gas liquids and crude oil  (MBbls)(1)			(MBbls) equivalents(2)
Net proved reserves at December 31, 2009		-		37,484			37,484
Revisions of previous estimates (6)		-		319			319
Purchases of minerals in place		-		-			-
Extensions, discoveries and other additions (5)		-		2,600			2,600
Sales of reserves in place		-		-			-
Production (8)		-		(1,527	)		(1,527	)
Other		-		-			-
Net proved reserves at December 31, 2010		-		38,876			38,876
Revisions of previous estimates (6)		-		(2,798	)		(2,798	)
Purchases of minerals in place		-		-			-
Extensions, discoveries and other additions (5)		-		-			-
Sales of reserves in place		-		-			-
Production (8)		-		(1,376	)		(1,376	)
Other		-		-			-
Net proved reserves at December 31, 2011		-		34,702			34,702
Revisions of previous estimates (6)		-		(681	)		(681	)
Purchases of minerals in place		-		-			-
Extensions, discoveries and other additions (5)		-		-			-
Sales of reserves in place (7)		-		(16,410	)		(16,410	)
Production (8)		-		(1,185	)		(1,185	)
Other		-		-			-
Net proved reserves at December 31, 2012		-		16,426			16,426
Company’s proportional interest in reserves of investees accounted for by the cost method—December 31, 2012 (3)		-		146			146

130

BPZ RESOURCES, INC AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

	Natural gas (MMcf)(4)		Natural gas liquids and crude oil  (MBbls)(1)		(MBbls)  equivalents(2)
Proved Developed Reserves as of:
December 31, 2008		-		4,223		4,223
December 31, 2009		-		9,912		9,912
December 31, 2010		-		12,231		12,231
December 31, 2011		-		6,546		6,546
December 31, 2012		-		2,125		2,125
Proved Undeveloped Reserves as of:
December 31, 2008		-		12,930		12,930
December 31, 2009		-		27,573		27,573
December 31, 2010		-		26,645		26,645
December 31, 2011		-		28,156		28,156
December 31, 2012		-		14,301		14,301

(1)	Includes crude oil, condensate and natural gas liquids.
(2)	Natural gas volumes have been converted to equivalent natural gas liquids and crude oil volumes using a conversion factor of six thousand cubic feet of natural gas to one barrel of natural gas liquids and crude oil.
(3)	Based on an independent reservoir engineer’s report provided by the operator of the Santa Elena Property.
(4)	The Company does not currently have the financial capacity or commitments for a development program of this magnitude for its gas reserves. Accordingly, the Company has not included amounts of natural gas reserves in its SEC filings. At such time as the Company obtains sufficient financial commitments to proceed with the full development of the gas-to-power project and all other conditions necessary to record proved gas reserves are met, the Company expects to record SEC proved gas reserves as permitted under SEC rules and disclose such reserves in future SEC filings.
(5)	The 2010 extensions, discoveries and other additions of 2.6 MMBbls were due to additional wells drilled in the Corvina field.  In 2011 and 2012, there were no changes to the extensions, discoveries and other additions.
(6)	The 2010 reserve analysis as prepared by NSAI included positive revisions due to price of approximately 347 MBbls that were partially offset by negative revisions of approximately 28 MBbls due to performance.  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 developed in 2011 in the Corvina field and in the Albacora field.  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, 2011 and 2010 reserve reports as prepared by NSAI used a $108.10 per barrel price, a $106.56 per barrel price and a $76.92 per barrel price, respectively.
(7)	During 2012, sales of reserves in place of 16.4 MMBbls relates to the Company’s sale of a 49% participating interest in Block Z-1.
(8)	The 2010 oil production of 1,527 MBbls includes 1,123 MBbls from the Corvina field and 404 MBbls from the Albacora field.  The 2011 oil production of 1,376 MBbls includes 1,255 MBbls from the Corvina field and 121 MBbls from the Albacora field.  The 2012 oil production of 1,185 MBbls includes 908 MBbls from the Corvina field and 277 MBbls from the Albacora field.

131

BPZ RESOURCES, INC AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following information has been developed utilizing procedures prescribed by U.S. GAAP and based on natural gas and crude oil reserve and production volumes estimated by the independent petroleum reservoir engineers. This information may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company’s oil and natural gas assets.

The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas and crude oil reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available under current laws and which relate to oil and natural gas producing activities.

Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

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

132

BPZ RESOURCES, INC AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s crude oil reserves for the year ended December 31, 2012, 2011 and 2010 (in thousands):

December 31, 2012
Future cash inflows (5)	$	1,775,659
Future production costs		(235,932	)
Future development costs		(81,413	)
Future income tax expenses		(261,259	)
Future net cash flows		1,197,055
Discount to present value at 10% annual rate		(305,742	)
Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	891,313
Company’s share of cost method investees’ standardized measure of discounted future net cash flows (1) (4)	$	7,575
December 31, 2011
Future cash inflows (5)	$	3,697,799
Future production costs		(492,542	)
Future development costs		(378,128	)
Future income tax expenses		(569,664	)
Future net cash flows		2,257,465
Discount to present value at 10% annual rate		(723,732	)
Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	1,533,733
Company’s share of cost method investees’ standardized measure of discounted future net cash flows (1) (2)	$	6,409
December 31, 2010
Future cash inflows (5)	$	2,990,334
Future production costs		(500,267	)
Future development costs		(383,728	)
Future income tax expenses		(403,964	)
Future net cash flows		1,702,375
Discount to present value at 10% annual rate		(604,014	)
Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	1,098,361
Company’s share of cost method investees’ standardized measure of discounted future net cash flows (1) (3)	$	9,924

(1) Investment in Ecuador Property

(2) Based on an independent reservoir engineer’s preliminary report provided by the operator of the Santa Elena Property.

(3) Based on an independent reservoir engineer’s report provided by the operator of the Santa Elena Property.

(4) Based on management’s estimate.

(5) The per barrel price used in determining future cash inflows for the year ended December 31, 2012, 2011 and 2010 were $108.10, $106.56 and $76.92, respectively.

133

BPZ RESOURCES, INC AND SUBSIDIARIES

SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

YEARS ENDED DECEMBER 31, 2012, 2011 and 2010

The following table sets forth the principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil reserves.  The information is presented for the year ended December 31, 2012, 2011 and 2010 as follows:

	Year Ended December 31,
	2012			2011			2010
	(in thousands)
Standardized measure of discounted future net cash flows, beginnning of the year	$	1,533,733		$	1,098,361		$	738,559
Sales and transfers of natural gas, natural gas liquids and crude oil produced, net of production costs		(70,250	)		(88,562	)		(79,547	)
Change in estimated future development costs		56,152			1,897			(88,751	)
Net changes in prices and production costs		(14,265	)		620,670			387,269
Extensions, discoveries, additions and improved recovery, net of related costs		-			-			107,711
Development costs incurred		867			3,300			63,672
Revisions of previous quantity estimates		(37,362	)		(97,134	)		1,012
Accretion of discount		190,766			130,388			51,417
Net change in income taxes		178,588			(122,894	)		(79,113	)
Sales of reserves in place		(972,568	)		-			-
Changes in timing and other		25,652			(12,293	)		(3,868	)
Standardized measure of discounted future net cash flows, end of the year	$	891,313		$	1,533,733		$	1,098,361

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

134

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

(a)      Evaluation of Disclosure Controls and Procedures

We performed an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report.  Based on that evaluation, our principal executive officer and principal financial officer have concluded that as of December 31, 2012 our disclosure controls and procedures, as defined in Rule 13a-15(e), are effective to ensure that information we are required to disclose in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

(b)      Changes in Internal Control Over Financial Reporting

There was no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2012 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

(c)      Management’s Annual Report on Internal Control over Financial Reporting

Management of the Company, including our principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls are designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition.

Management conducted an evaluation of the effectiveness of our internal controls over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. We did not identify any material weaknesses in our internal controls as a result of this evaluation. Based on this evaluation, management has concluded that our internal controls over financial reporting were effective as of December 31, 2012.

BDO USA, LLP, the independent registered public accounting firm who also audited our consolidated financial statements, has issued an attestation report on our internal control over financial reporting as of December 31, 2012, which is set forth below under “Attestation Report.”

135

(d)      Attestation Report

Report of Independent Registered Public Accounting Firm

on Internal Control over Financial Reporting

To the Board of Directors and Stockholders

BPZ Resources, Inc. and Subsidiaries

Houston, Texas

     We have audited BPZ Resources, Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). BPZ Resources, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

     We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

     A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     In our opinion, BPZ Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the COSO criteria.

     We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of BPZ Resources, Inc. as of December 31, 2012 and 2011, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years ended December 31, 2012, and our report dated March 15, 2013 expressed an unqualified opinion thereon.

/s/ BDO USA, LLP

Houston, TX

March 15, 2013

136

ITEM 9B.  OTHER INFORMATION

None.

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Annual Report on Form 10-K.

ITEM 11.  EXECUTIVE COMPENSATION

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Annual Report on Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Annual Report on Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Annual Report on Form 10-K.

ITEM 14.  PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Annual Report on Form 10-K.

137

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this report:
1.	Financial Statements.
	Our consolidated financial statements are included in Part II, Item 8 of this report:	81
	Report of Independent Registered Public Accounting Firm	82
	Consolidated Balance Sheets	83
	Consolidated Statements of Operations	84
	Consolidated Statements of Stockholders’ Equity	85
	Consolidated Statements of Cash Flows	86
	Notes to Consolidated Financial Statements	87
	Supplemental Oil and Gas Disclosures (Unaudited)	125
	Management’s Annual Report on Internal Control Over Financial Reporting	135
	Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting	136
2.	Financial Statements Schedules and supplementary information required to be submitted:
	None.
3.	Exhibits
	A list of the exhibits filed or furnished with this report on Form 10-K (or incorporated by reference to exhibits previously filed or furnished by us) is provided in the Index of Exhibits of this report.  Those exhibits incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter.  Otherwise, the exhibits are filed herewith.

138

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry that are used in this report.

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent determined using the ratio of approximately six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Bopd. Barrels of oil per day.

BoepdBarrels of oil equivalent per day

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Exploitation. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet.

Mcfe. One thousand cubic feet equivalent, determined using the ratio of approximately six Mcf of natural gas to one Bbl of crude oil or other hydrocarbon.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBtu. One million British thermal units.

MMcf. One million cubic feet.

MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil condensate or natural gas liquids.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

Oil. Crude oil, condensate and natural gas liquids.

Productive well. A well that is found to be capable of producing hydrocarbons.

139

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. The SEC provides a complete definition of proved developed reserves in Rule 4-10(a)(3) of Regulation S-X.

Proved reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and cost as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions. The SEC provides a complete definition of proved reserves in Rule 4-10(a)(2) of Regulation S-X.

Proved undeveloped reserves. Proved oil and gas reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. The SEC provides a complete definition of proved undeveloped reserves in Rule 4-10(a)(4) of Regulation S-X.

Recompletion. The completion for production of an existing well bore in another formation from that which the well has been previously completed.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

Workover.  A remedial operation on a completed well to restore, maintain or improve the well’s production.

140

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 15, 2013.

BPZ Resources, Inc.
By:	/s/ Manuel Pablo Zúñiga-Pflücker
	Manuel Pablo Zúñiga-Pflücker
	President & Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

/s/  MANUEL PABLO ZÚÑIGA-PFLÜCKER	/s/  RICHARD S. MENNITI
Manuel Pablo Zúñiga-Pflücker	Richard S. Menniti
President, Chief Executive Officer and Director	Chief Financial Officer
March 15, 2013	(Principal Financial Officer and Principal Accounting Officer)
	March 15, 2013
/s/  JAMES B. TAYLOR	/s/  JERELYN EAGAN
James B. Taylor	Jerelyn Eagan
Director and Chairman of the Board	Director
March 15, 2013	March 15, 2013
/s/  STEPHEN C. BEASLEY	/s/  JOHN J. LENDRUM, III
Stephen C. Beasley	John J. Lendrum, III
Director	Director
March 15, 2013	March 15, 2013
/s/  STEPHEN R. BRAND	/s/  DENNIS G. STRAUCH
Stephen R. Brand	Dennis G. Strauch
Director	Director
March 15, 2013	March 15, 2013

141

INDEX OF EXHIBITS

2.1	Plan of Conversion for BPZ Energy, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on August 24, 2007).
3.1	Certificate of Formation of BPZ Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on August 24, 2007).
3.2	Bylaws of BPZ Resources, Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Form 8-K filed on August 17, 2007).
3.3	First Amendment to the Bylaws of BPZ Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on March 7, 2011).
4.2	Indenture for 6.5% Convertible Senior Notes due 2015 by and among BPZ Resources Inc. and Wells Fargo Bank National Association, as trustee, dated February 8, 2010 (incorporated by reference to exhibit 4.1 to the Company’s Form 8-K filed on February  9, 2010).
4.3	Form of 6.5% Convertible Senior Note due 2015 (included in Exhibit 4.2).
10.1*	BPZ Energy, Inc. 2005 Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form S-8 filed on July 5, 2005 (SEC File No. 333- 126388)).
10.2*	BPZ Energy, Inc. 2007 Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on August 24, 2007).
10.3*	BPZ Energy, Inc. 2007 Directors Compensation Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on August 24, 2007).
10.4	Merger Agreement between Navidec, Inc. and BPZ Energy, Inc. dated July 8, 2004 (incorporated by reference to Exhibit 10.1 from the Company’s Form 8-K filed on July 13, 2004).
10.5	Closing Agreement between Navidec, Inc. and BPZ, Inc. dated September 8, 2004(incorporated by reference to Exhibit 10.1 from the Company’s Form 8-K filed on September 14, 2004).
10.6	License Contract from the Government of Peru for Block Z-1 dated November 30, 2001 (incorporated by reference to Exhibit 10.5 to the Company’s Form SB-2 filed on February 14, 2005 (SEC File No. 333-122816)).
10.7	Amendment to License Contract from the Government of Peru for Block Z-1 dated February 3, 2005 (incorporated by reference to Exhibit 10.5 of the Company’s Annual Report on Form 10-KSB for the year ended December 31, 2004 filed on April 15, 2005).
10.8	License Contract from the Government of Peru for Block XIX dated December 12, 2003 (incorporated by reference to Exhibit 10.6 to the Company’s Form SB-2 filed on February 14, 2005 (SEC File No. 333-122816)).
10.9	License Contract from the Government of Peru for Block XXII dated November 21, 2007 (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-K filed on March 14, 2008).

142

10.10	License Contract from the Government of Peru for Block XXIII dated November 21, 2007 (incorporated by reference to Exhibit 10.10 to the Company’s Form 10-K filed on March 14, 2008).
10.11	Contract No. 001-2009-Mextipetroperu - Supply of 17,000,000 Barrels of Crude Oil for Talara Refinery dated January 8, 2009, by and among BPZ Exploración & Producción S.R.L., and Petroleos del Perú-PETROPERU S.A.(incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 14, 2009).
10.12	Contract for Sale of Equipment and Services dated September 26, 2008 (incorporated by reference to Exhibit 10.11 to BPZ Resources, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 filed on November 10, 2008).
10.13	Amendment dated January 23, 2009 to Contract for Sale of Equipment and Services dated September 26, 2008 by and among GE Packaged Power, Inc. GE International, Inc. Sucursal De Peru and Empresa Eléctrica Nueva Esperanza, SRL (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on January 29, 2009).
10.14	Loan Agreement between BPZ Exploracion & Produccion S.R.L and BPZ Marine Peru S.R.L  and International Finance Corporation dated as of August 15, 2008 (incorporated by reference to exhibit 10.15 to the Company’s Form 10-K filed on March 2, 2009).
10.15	Common Terms Agreement between BPZ Exploracion & Produccion S.R.L and BPZ Marine Peru S.R.L., as borrowers, and International Finance Corporation, as lender, and the Additional Secured Facility Lenders dated as of August 15, 2008 (incorporated by reference to exhibit 10.16 to the Company’s Form 10-K filed on March 2, 2009).
10.16	Subscription Agreement by and among BPZ Resources, Inc. and International Finance Corporation  dated December 18, 2006 (incorporated by reference to exhibit 10.1 to the Company’s Form 8-K filed on December 22, 2006).
10.17	Letter Agreement by and between the Consortium of GE Packaged Power, Inc. and GE International Inc. Sucursal de Peru (collectively, “Seller”) and Empresa Electrica Nueva Esperanza S.R.L. (“Buyer”) dated as of November 20, 2009 (incorporated by reference to exhibit 10.3 to the Company’s Form 8-K filed on November 27, 2009).
10.18	US $40,000,000 Credit Agreement by and among Empresa Electrica Nueva Esperanza S.R.L., as Borrower, and BPZ Resources,  Inc., and BPZ Exploración & Producción S.R.L., as Guarantors and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, and Credit SuisseInternational, as Arranger, dated as of January 27, 2011 (incorporated by reference to exhibit 10.21 to the Company’s Form 10-K filed on March 16, 2011).
10.19*	Amendment to the BPZ Energy, Inc. (a/k/a BPZ Resources, Inc.) 2007 Long-Term Incentive Compensation Plan (incorporated by reference to exhibit 10.22 to the Company’s Form 10-K filed on March 16, 2011).
10.20*	Amendment to the BPZ Energy, Inc. (a/k/a BPZ Resources, Inc.) 2007 Long-Term Incentive Compensation Plan, dated April 20, 2011 (incorporated by reference to exhibit 10.2 to the Company’s Form 10-Q filed on August 8, 2011).
10.21	BPZ Resources, Inc. Employee Stock Purchase Plan (incorporated by referenced to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2011 filed with the Commission on August 9, 2011).

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10.22	$75,000,000 Credit Agreement by and among BPZ Resources, Inc., and its subsidiaries BPZ Energy LLC, and BPZ Exploración & Producción S.R.L., as guarantors and Credit Suisse AG, Cayman Islands Branch, as administrative agent and lender, Standard Bank PLC, as lender and mandated lead arranger, and Credit Suisse International, as lead arranger, dated as of July 6, 2011 (incorporated by reference to exhibit 10.1 to the Company’s Form 10-Q filed on August 8, 2011).
10.23	First Amendment to $40,000,000 Credit Agreement by and among Empresa Electrica Nueva Esperanza S.R.L., as Borrower, and BPZ Resources,  Inc., and BPZ Exploración & Producción S.R.L., as Guarantors and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, and Credit Suisse International, as Arranger, dated as of January 27, 2011 (incorporated by reference to Exhibit 10.27 to the Company’s Form 10-K filed on March 14, 2012).
10.24	Second Amendment to $40,000,000 Credit Agreement by and among Empresa Electrica Nueva Esperanza S.R.L., as Borrower, and BPZ Resources,  Inc., and BPZ Exploración & Producción S.R.L., as Guarantors and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, and Credit Suisse International, as Arranger, dated as of January 27, 2011 (incorporated by reference to Exhibit 10.28 to the Company’s Form 10-K filed on March 14, 2012).
10.25	Third Amendment to $40,000,000 Credit Agreement by and among Empresa Electrica Nueva Esperanza S.R.L., as Borrower, and BPZ Resources,  Inc., and BPZ Exploración & Producción S.R.L., as Guarantors and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, and Credit Suisse International, as Arranger, dated as of January 27, 2011 (incorporated by reference to Exhibit 10.29 to the Company’s Form 10-K filed on March 14, 2012).
10.26	Fourth Amendment to $40,000,000 Credit Agreement by and among Empresa Electrica Nueva Esperanza S.R.L., as Borrower, and BPZ Resources, Inc., and BPZ Exploración & Producción S.R.L., as Guarantors and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, and Credit Suisse International, as Arranger, dated as of January 27, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q filed on May 10, 2012).
10.27	Waiver dated as of September 28, 2012, with respect to that certain $40,000,000.00 Credit Agreement, dated as of January 27, 2011 (as amended), by and among Empresa Eléctrica Nueva Esperanza S.R.L., as borrower, BPZ Resources, Inc. and BPZ Exploración & Producción S.R.L., as guarantors, and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, and Credit Suisse International, as Arranger, dated as of January 27, 2011 (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q filed on November  9, 2012).
10.28	Amendment to the Credit Agreement dated January 27, 2011 among Empresa Electrica Nueva Esperanza S.R.L.as borrower and Credit Suisse AG Cayman Island Branch as administrative agent (incorporated by reference to Exhibit 10.3 to the Company’s Form 8-K filed on January 2, 2013).
10.29	Waiver dated as of January 14, 2013, with respect to that certain $40,000,000.00 Credit Agreement, dated as of January 27, 2011 (as amended), by and among Empresa Eléctrica Nueva Esperanza S.R.L., as borrower, BPZ Resources, Inc. and BPZ Exploración & Producción S.R.L., as guarantors, and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, and Credit Suisse International, as Arranger, dated as of January 27, 2011, filed herewith.
10.30	Waiver dated as of March 8, 2013, with respect to that certain $40,000,000.00 Credit Agreement, dated as of January 27, 2011 (as amended), by and among Empresa Eléctrica Nueva Esperanza S.R.L., as borrower, BPZ Resources, Inc. and BPZ Exploración & Producción S.R.L., as guarantors, and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, and Credit Suisse International, as Arranger, dated as of January 27, 2011, filed herewith.
10.31	First Amendment to $75,000,000 Credit Agreement by and among BPZ Resources, Inc., and its subsidiaries BPZ Energy LLC, and BPZ Exploración & Producción S.R.L., as guarantors and Credit Suisse AG, Cayman Islands Branch, as administrative agent and lender, Standard Bank PLC, as lender and mandated lead arranger, and Credit Suisse International, as lead arranger, dated as of July 6, 2011 (incorporated by reference to Exhibit 10.30 to the Company’s Form 10-K filed on March 14, 2012).

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10.32	Second Amendment to $75,000,000 Credit Agreement by and among BPZ Resources, Inc., and its subsidiaries BPZ Energy LLC, and BPZ Exploración & Producción S.R.L., as guarantors and Credit Suisse AG, Cayman Islands Branch, as administrative agent and lender, Standard Bank PLC, as lender and mandated lead arranger, and Credit Suisse International, as lead arranger, dated as of July 6, 2011 (incorporated by reference to Exhibit 10.31 to the Company’s Form 10-K filed on March 14, 2012).
10.33	Third Amendment to $75,000,000 Credit Agreement by and among BPZ Resources, Inc., and its subsidiaries BPZ Energy LLC, and BPZ Exploración & Producción S.R.L., as guarantors and Credit Suisse AG, Cayman Islands Branch, as administrative agent and lender, Standard Bank PLC, as lender and mandated lead arranger, and Credit Suisse International, as lead arranger, dated as of July 6, 2011 (incorporated by reference to Exhibit 10.32 to the Company’s Form 10-K filed on March 14, 2012).
10.34	Fourth Amendment to $75,000,000 Credit Agreement by and among BPZ Resources, Inc., and its subsidiaries BPZ Energy LLC, and BPZ Exploración & Producción S.R.L., as guarantors and Credit Suisse AG, Cayman Islands Branch, as administrative agent and lender, Standard Bank PLC, as lender and mandated lead arranger, and Credit Suisse International, as lead arranger, dated as of July 6, 2011 (incorporated by reference to Exhibit 10.2 to the Company’s Form 10-Q filed on May 10, 2012).
10.35	Fifth Amendment to $75,000,000 Credit Agreement by and among BPZ Resources, Inc., and its subsidiaries BPZ Energy LLC, and BPZ Exploración & Producción S.R.L., as guarantors and Credit Suisse AG, Cayman Islands Branch, as administrative agent and lender, Standard Bank PLC, as lender and mandated lead arranger, and Credit Suisse International, as lead arranger, dated as of July 6, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q filed on August 9, 2012).
10.36	Waiver dated as of September 28, 2012, with respect to that certain $75,000,000.00 Credit Agreement, dated as of July 6, 2011 (as amended), by and among BPZ Exploración & Producción S.R.L., as borrower, BPZ Resources, Inc., BPZ Energy LLC, Soluciones Energéticas S.R.L., and BPZ Norte Oil S.R.L., as guarantors, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and lender, Standard Bank PLC, as lender and mandated lead arranger, and Credit Suisse International, as lead arranger, dated as of July 6, 2011 (incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q filed on November 9, 2012).
10.37	Amendment to the Credit Agreement dated July 6, 2011 among BPZ Exploracion & Produccion S.R.L.as borrower and Credit Suisse AG Cayman Island Branch as administrative agent (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on January 2, 2013).
10.38	Waiver dated as of January 14, 2013, with respect to that certain $75,000,000.00 Credit Agreement, dated as of July 6, 2011 (as amended), by and among BPZ Exploración & Producción S.R.L., as borrower, BPZ Resources, Inc., BPZ Energy LLC, and Soluciones Energéticas S.R.L., as guarantors, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and lender, Standard Bank PLC, as lender and mandated lead arranger, and Credit Suisse International, as lead arranger, dated as of July 6, 2011, filed herewith.
10.39	Waiver dated as of March 8, 2013, with respect to that certain $75,000,000.00 Credit Agreement, dated as of July 6, 2011 (as amended), by and among BPZ Exploración & Producción S.R.L., as borrower, BPZ Resources, Inc., BPZ Energy LLC, and Soluciones Energéticas S.R.L., as guarantors, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and lender, Standard Bank PLC, as lender and mandated lead arranger, and Credit Suisse International, as lead arranger, dated as of July 6, 2011, filed herewith.

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10.40	Stock Purchase Agreement Among BPZ Energy International Holdings, L.P. and BPZ Energy LLC, as Sellers, BPZ Resources, Inc., as Borrower, and Pacific Stratus Energy S.A., as Buyer, and Pacific Stratus International Energy Ltd., as Pre Lender, Concerning BPZ Norte Oil S.R.L., dated April 27, 2012 (incorporated by reference to Exhibit 10.3 to the Company’s Form 10-Q filed on May 10, 2012).
10.41	Joint Operating Agreement among BPZ Exploración & Producción S.R.L. and BPZ Norte S.R.L. for the Exploration - Exploitation License Block Z-1 Offshore, Peru, signed as of April 27, 2012 and effective as of the Effective Date (as defined therein) (incorporated by reference to Exhibit 10.4 to the Company’s Form 10-Q filed on May 10, 2012).
10.42	Carry Agreement made on April 27, 2012 and effective as of the Carry Start Date (as defined therein) between BPZ Exploración & Producción S.R.L. and BPZ Norte S.R.L. (incorporated by reference to Exhibit 10.5 to the Company’s Form 10-Q filed on May 10, 2012).
10.43	Amendment to the Stock Purchase Agreement Among BPZ Energy International Holdings, L.P. and BPZ Energy LLC, as Sellers, BPZ Resources, Inc., as Borrower, and Pacific Stratus Energy S.A., as Buyer, and Pacific Stratus International Energy Ltd., as PRE Lender, Closing Letter Concerning BPZ Norte Oil S.R.L., dated December 26, 2012 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 2, 2013).
14.1	Code of Ethics for Executive Officers (incorporated by reference to Exhibit 14.1 to Form 10-KSB/A filed on September 26, 2006).
21.1	Subsidiaries of the Registrant, filed herewith.
23.1	Consent of Independent Registered Public Accounting Firm, filed herewith.
23.2	Consent of Independent Petroleum Engineers and Geologists, filed herewith.
31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
32.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
99.1	Report of Netherland, Sewell & Associates, Inc., filed herewith.
101.INS	XBRL Instance Document.  (Furnished herewith)
101.SCH	XBRL Schema Document.  (Furnished herewith)
101.CAL	XBRL Calculation Linkbase Document.  (Furnished herewith)
101.LAB	XBRL Label Linkbase Document.  (Furnished herewith)

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101.PRE	XBRL Presentation Linkbase Document.  (Furnished herewith)
101.DEF	XBRL Definition Linkbase Document.  (Furnished herewith)

* - Management Contract or Compensatory Plan or Arrangement.

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