BPZ RESOURCES, INC. - FORM 10-K

Attached files

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EX-31.1 - EX-31.1 - BPZ RESOURCES, INC.	a09-35895_1ex31d1.htm
EX-31.2 - EX-31.2 - BPZ RESOURCES, INC.	a09-35895_1ex31d2.htm
EX-23.2 - EX-23.2 - BPZ RESOURCES, INC.	a09-35895_1ex23d2.htm
EX-32.2 - EX-32.2 - BPZ RESOURCES, INC.	a09-35895_1ex32d2.htm
EX-99.1 - EX-99.1 - BPZ RESOURCES, INC.	a09-35895_1ex99d1.htm
EX-32.1 - EX-32.1 - BPZ RESOURCES, INC.	a09-35895_1ex32d1.htm
EX-23.1 - EX-23.1 - BPZ RESOURCES, INC.	a09-35895_1ex23d1.htm
EX-21.1 - EX-21.1 - BPZ RESOURCES, INC.	a09-35895_1ex21d1.htm

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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, 2009

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 website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12-months (or for such shorter period that the registrant was required to submit and post such files). Yes o 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, 2009 was 64,700,845 shares, all of one class of common stock, no par value, having an aggregate market value of approximately $316,387,132 based upon the closing price of registrant’s common stock on such date of $4.89 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 March 26, 2010 there were 115, 223,926 shares of common stock, no par value, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

(1) Proxy Statement for 2010 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	Reserved	34

PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35
Item 6.	Selected Financial Data	37
Item 7.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	38
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	70
Item 8.	Financial Statements and Supplementary Data	72
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	118
Item 9A.	Controls and Procedures	118
Item 9B.	Other Information	119

PART III
Item 10.	Directors, Executive Officers and Corporate Governance	120
Item 11.	Executive Compensation	120
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	120
Item 13.	Certain Relationships and Related Transactions, and Director Independence	120
Item 14.	Principal Accountant Fees and Services	120

PART IV
Item 15.	Exhibits and Financial Statement Schedules	121

Glossary of Oil and Natural Gas Terms		122

Signatures		124

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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 exclusive rights and license contracts for oil and gas exploration and production covering a total of approximately 2.2 million acres, in four blocks, in northwest Peru. Our license contracts cover 100% ownership of the following properties: Block Z-1 (0.6 million acres), Block XIX (0.5 million acres), Block XXII (0.9 million acres) and Block XXIII (0.2 million 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”) 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, 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 exploration and production and up to 40 years for gas exploration and 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 exploration and 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 working interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). The license agreement covering the property extends through May 2016.

We are in the process of developing our oil and natural gas reserves. We have been producing and selling oil from the CX-11 platform in the Corvina field of Block Z-1 under a well testing program and are in the process of satisfying the conditions to transition to commercial production in Corvina. From the time we began producing from the CX-11 platform in the Corvina field in November 2007, through December 31, 2009, we have produced approximately 1.9 million barrels (“MMBbls”) of oil. We are also in the initial stages of appraising, exploring and developing our potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1 and have drilled and completed our first well in December 2009. Additionally, our activities in Peru include analysis and evaluation of technical data on our other properties, preparation of the development plans for the properties, refurbishment of and designs for platforms to perform our drilling campaigns in the Corvina and Albacora fields in Block Z-1, procuring machinery and equipment for an extended drilling campaign, obtaining all necessary environmental and operating permits, bringing additional production on-line, seismic

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acquisition, obtaining detailed engineering and design of the power plant and gas processing facilities, executing a contract to purchase three LM 6000 gas fired turbines and securing the required capital and financing to conduct the current plan of operation.

At December 31, 2009, we had estimated net proved oil reserves of 37.5 MMBbls, of which 27.5 MMBbls were in the Corvina field and 10.0 MMBbls were from the Albacora field; both fields being in Block Z-1, located offshore of northwest Peru. Of our total proved reserves, 9.9 MMBbls (26.4%) are classified as proved developed reserves consisting of 13 wells and 27.6 MMBbls (73.6%) are classified as proved undeveloped reserves consisting of 22 future wells. 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 starting on page 72 of this Annual Report on Form 10-K.

Our Business Plan

Our business plan is to enhance shareholder value primarily through application of our knowledge of our targeted areas in Peru and leveraging management’s experience with the local suppliers and regulatory authorities to effectively and efficiently (i) quantify the potential value of our oil and gas holdings in Peru; (ii) increase production and cash flows from our identified holdings; and (iii) create a revenue stream through implementation of our gas-to-power project.

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

Our focus is to re-appraise and develop properties in northwest Peru that have been explored by other companies and 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.

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 found oil in our first well in the Corvina field in offshore Block Z-1 in 2007, and oil in our first well in Albacora in December 2009, we are focusing on development of the proved oil reserves in the Corvina and Albacora fields.

In addition, our business plan includes a gas-to-power project, which entails the installation of a 10-mile gas pipeline from the CX-11 platform to shore, construction of gas processing facilities and an approximately 135 megawatt (“MW”) simple cycle electric generating plant using three LM 6000 gas fired turbines. 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 320 MW of power. The gas-to-power project will allow us to create a revenue stream by creating a market for the gas discovered in our Corvina field that is currently shut-in. We plan to utilize part of our future natural gas production as a supply source for the development of a gas-fired power generation facility in Peru, which we currently plan to wholly or partially own.

We will concentrate our efforts on areas we believe contain proven oil and gas reserves that can be economically developed and produced in commercial quantities and leverage our knowledge of oil and gas operations in the areas we operate. We believe this strategy will allow us to develop the oil and gas effectively and efficiently to enhance the profitability of the Company, and thus increase shareholder value.

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

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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 for 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-leased tracts exist within our target area, we believe these properties may be less attractive to other companies because it will be difficult for them to obtain a significant amount of contiguous mineral acres. This results in part from our significant holdings in the vicinity of these un-leased tracts. However, 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. We are adjusting our operating plans and timelines to adapt to this changing environment. However, increasing future demand for drillers and contractors may limit our ability to execute in a timely manner and may negatively impact our ability to grow.

Customers

To date, all of our sales of oil in Peru have been made under contract 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 internationally.

In January 2009, our wholly-owned subsidiary, BPZ E&P, entered into a long-term oil supply agreement with Petroperu. Under the terms of the contract, we agree to sell, and Petroperu agrees to purchase our crude oil production originating from the Corvina oilfield in Block Z-1. The contract term is for approximately seven years or until 17 million barrels of crude oil has been delivered to the Petroperu refinery located in Talara, whichever comes first. The price per barrel of oil under the agreement is determined on the date of delivery based on the previous 15-day average of crude oil prices consisting of Forties, Oman, and Suez blend, as quoted in the Spot Crude Prices Assessment published in Platt’s Crude Oilgram Price Report, minus $1 per barrel and other customary purchase price adjustments. We currently have approximately 16.0 million barrels of oil left to sell under this contract.

Additionally, we are currently negotiating a short-term oil sales contract for the oil produced from the Albacora field. The current contract being negotiated is expected to provide for the sale of up to 400,000 barrels of oil under similar terms to the short-term Corvina oil contract which was negotiated with Petroperu in late 2008.

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.

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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 ownership right to extract hydrocarbons to 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. Perupetro is empowered to enter into contracts for the exploration and exploitation of hydrocarbons on behalf of Peru, the nature of which are described further below. The Peruvian government also plays an active role in petroleum operations through the involvement of the Ministry of Energy and Mines, 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 all these sectors and supervising compliance with such policies and rules. Within the Ministry of Energy and Mines, Organismo Supervisor de la Inversión en Energía y Mineria (“OSINERGMIN”) is the governmental entity that supervises both legal and technical aspects of hydrocarbon activities in Peru, and 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. We are subject to the laws and regulations of all of these entities and agencies.

Perupetro, empowered by the Peruvian state as a contractual party, 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 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 limited liability company, 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 Energy, LLC (Texas) and its corresponding subsidiary in Peru has been qualified by Perupetro with respect to our current contracts as required by current regulation.

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, subject to a limitation in the case of natural emergencies where the law stipulates such manner.

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. 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. 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,

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such as lack of transportation facilities or 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 thirty to forty percent of the estimated value of the minimum work program.

Perupetro also grants technical evaluation agreements. These agreements give the contractor the right to conduct technical evaluations of the areas under such agreements with the possibility to enter into license contracts if the evaluations indicate the potential for profitable operations. The technical evaluation agreements terms depend upon the volume and nature of the work to be carried out.

We currently have four license contracts. As of March 31, 2010, we believe we were in compliance with all of the material requirements of each such contract. We have executed certain letters of guaranty in favor of Perupetro to insure our performance under the license contracts. At December 31, 2009, we had $5.3 million in bonds posted at various dates, to secure our obligation under the license contracts for Block XIX, Z-1, XXII and XXIII and a drilling service agreement. The license contract bonds are partially secured by the deposit of restricted cash in the amount of $3.1 million with the financial institutions which issued the bonds. Additionally, we have $1.6 million of restricted cash to collateralize insurance bonds for import duties related to the BPZ-01 barge and crane on board the BPZ-01. Should we fail to fulfill our obligations under any of our license contracts without technical justification or other good cause, Perupetro, and/or our service provider, could seek recourse to the bond or terminate the license and/or the service contract.

New legislation in Peru was passed by Supreme Decree 088-2009 on December 13, 2009 with respect to regulating well testing and gas flaring. The new 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, and can technically justify such need, a request for the well to enter into an extended well test period must be submitted to the DGH. The approval process for an extended well test permit requires that the DGH request the opinion of Perupetro on the technical justification for the extended well test. After the initial six-month period or after an approved extended well test 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.

The new regulation also provides for a transition period applicable to well tests taking place as of the date of the Supreme Decree, and provides that (i) within 30 business days of the enactment of the Supreme Decree (January 25, 2010), contractors conducting a well test lasting more than six months must request authorization from the DGH, and (ii) in the same 30 business day term, contractors flaring gas while testing wells must request authorization from the DGH for purposes of flaring the gas.

On December 29, 2009, we received approval, from Perupetro, of our proposed First Date of Commercial Production (“FDCP”), as set forth in the current Field Development Plan (“FDP”) for the Corvina field in Block Z-1, which is May 31, 2010.

On January 25, 2010, we applied for an extended well testing permit in Corvina for the first five wells (not including the CX11-19D and CX11-17D wells) as we believe it is necessary to continue gathering data to fully understand the drive mechanisms that are present in Corvina. On March 23, 2010, we received a decision from the DGH notifying us that they are approving us to continue extended well testing on our first five Corvina wells, until the FDCP date of May 31, 2010, subject to specific limits on the amount of natural gas flared from each of the first five Corvina wells. Based on the natural gas flaring limits set by the DGH, we expect to constrain the oil production from some or all of those five Corvina wells in order to comply with those limits. The actual future decrease in production from these five Corvina wells will not be known until we fully implement our gas mitigation strategy to optimize oil production while complying with the gas flaring limits, but production from these wells could decrease by as much as 400 to 800 bopd.

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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. Nevertheless, it is important to note that in Peru our License Contracts have fiscal stability.

License contracts are subject to royalty payments, which are usually a fixed percentage of the actual production which is verified by Perupetro. The taxing regulations stipulate a minimum royalty payment of five percent increasing incrementally to a maximum of twenty percent based on production. However, when a company bids for a license contract on a new area it can elect to voluntarily increase the royalty percentage to increase its chances to win a successful bid for a block.

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.

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 import goods tax-free for an additional two-year period.

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 over a period of five years 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, on a semi-annual basis, with a list of their personnel, indicating their nationality, specialty and position. These entities must also permanently train their workers on the application of safety measures in the operations, and control of disasters and emergencies. Each entity must keep detailed records of all accidents that occur in its operations and report all accidents to the OSINERGMIN. 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, which is our current phase of operations, are also contained in the regulations and include safety measures in camps, medical assistance, food conditions, and handling of explosives. Additional safety regulations may also apply as we expand and develop our operations.

The Constitution of Peru and Legislative Decree Nos. 677 and 892 gives employees working in private companies engaged in activities generating income classified as third category income by the Income Tax Law the right to share in the 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 following factors are taken into account regarding the profit sharing system: (1) calculation of profits to be distributed to each employee is based on two criteria (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;

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(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 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 electric power legislation. Our business plan envisions the generation of electricity and the sale of such electric power in Peru. The basic laws in 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, 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.

Peruvian environmental regulation. Our operations are subject to numerous and frequently 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 by the Ministry of Mines and Energy if a contractor fails to maintain such standards. The Ministry of Mines and Energy is charged with the responsibility of issuing the applicable standards. OSINERGMIN is responsible for ensuring compliance with applicable environmental rules covering hydrocarbon activities.

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. It was, however, subsequently modified to enable investors to prospect for hydrocarbons within protected areas, provided there is compliance with several obligations. 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 must annually file a report corresponding to the previous year describing the company’s compliance with the environmental legislation in force.

Companies involved in hydrocarbon activities must also prepare and file an Environmental Impact Study (“EIS”) with the General Hydrocarbons Bureau, which is part of the Ministry of Energy and Mines, in order for the relevant activities to comply 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 General Environmental Bureau, which is also part of the Ministry of Energy and Mines.

In addition, any party responsible for hydrocarbon activities must file an “Oil Spill and Emergency Contingency Plan” with the General Hydrocarbons Bureau. 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 State entities.

Peru has recently enacted amendments to its environmental law, imposing substantial 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 rules, the import of contaminated products, or failure to keep a monitoring register or send reports to the General Hydrocarbons Bureau in a timely fashion, could subject the company 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 can also be subject to a suspension of operations for a term of one, two or three months, or indefinitely. Furthermore, any contract signed with the Peruvian government, the implementation of which jeopardizes or endangers the protection or conservation of protected natural areas, can be terminated.

We are subject to all Peruvian environmental regulations applicable to the petroleum industry now in existence and those existing in the future. 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

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the waters offshore Peru where we intend to 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.

Although we believe our operations are in substantial compliance with existing environmental requirements, our ability to conduct continued operations is subject to complying with applicable regulations. Our current permits and authorizations and ability to obtain future permits and authorizations may be susceptible, on a going forward basis, to increased scrutiny, greater complexity resulting in increased costs, or delays in receiving appropriate authorizations. In particular, we may in the future experience delays in obtaining permits and authorizations in Peru necessary for our operations.

Compliance with Existing Legislation in Peru

Although we believe our operations are and will 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 principals have 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.

Ecuador

SMC Ecuador, Inc., our wholly-owned subsidiary, has held its 10% non-operating 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 an owner or lessee and operator of oil and gas properties in South America, in particular Peru, we are subject to various national, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the contractor under an oil and gas license agreement for the cost of pollution clean-up resulting from operations, subject the contractor 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 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, Corvina and Albacora fields and Block XIX for the years ended December 31, 2009, 2008, and 2007 were approximately $1.2 million, $0.5 million and $0.3 million, respectively. We are currently assessing what studies are necessary and the associated cost estimate for Blocks XXII and XXIII.

In January 2008, the T/V SUPE (“Supe”), a small tanker that one of our marine transportation contractors was chartering from the Peruvian Navy’s commercial branch sank after catching fire. The Supe was moored near the Corvina CX-11 platform and was being used to store oil produced from Corvina’s CX11-21XD and 14D wells. At the time of the incident the Supe contained approximately 1,300 barrels of oil, which burned in the fire. Subsequent assessments showed that environmental issues were adequately controlled.

There was no significant or material damage to our platform, barges, drilling and well testing equipment, or other facilities we own and the damage was limited mostly to the Supe. We contracted the services of Clean Caribbean and

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Americas (“CCA”) to assist us in response to this incident. As part of their assistance they conducted an oil pollution assessment in and around the area surrounding the incident. CCA concluded that the majority of the crude oil contained in the Navy tanker was consumed during the fire subsequent to the explosion. This was confirmed after divers inspected the sunken tanker, which is resting 200 feet underwater, and reported that no crude oil was detected in any of the tanks. Our environmental consultants, as well as several independent organizations, conducted additional lab tests on seawater and marine life within the potentially affected area and these lab test results indicated no contamination related to the incident. In March 2008, OSINERGMIN, the government regulatory agency in Peru responsible for monitoring industrial safety, cleared the Company to resume operations at the CX-11 platform in the offshore Z-1 Block in northwest Peru. We have not received any additional requests from any regulatory agency requiring us to perform additional services related to this incident in order for us to be in compliance with environmental regulation.

We do not believe compliance with national, state or local provisions regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, will have a material adverse effect upon the capital expenditures, earnings or competitive position of the Company or its subsidiaries. However, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not have such an impact.

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 premium 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 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 practical extent, particularly in the application of geophysical and exploration software. In certain cases, our collaboration has aided the development of these technologies. We do not believe we have incurred any quantifiable incremental costs in connection with research and development

Employees

As of December 31, 2009, we employed 27 full-time employees in our Houston office and 153 full-time employees in our Lima, Peru office. We had two full-time employees in the Quito, Ecuador office. BPZ believes that its relationship with its 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.

We have a limited operating history and have only engaged in start-up and development activities. We are in the initial stages of developing our oil and natural gas reserves and have begun producing and selling oil from our discoveries under a well test program. 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, in particular, not be able to profitably execute our plan of operation.

We must comply with Peruvian legal and regulatory requirements to be able to produce and sell oil after the expiration of production testing or approved extended well testing. If we do not obtain approval to continue our well testing on wells producing for more than six months, we would be required to suspend production from such wells and we would experience an interruption in production that would negatively impact the revenues and cash flow associated with those wells. Under new legislation regulating well testing in Peru, all new wells may be placed on production testing for up to six months. If we need additional time for testing a new well, we must submit a request for the well to enter into an extended well test period, together with technical justification for such need and duration, to the DGH, the agency of the Ministry of Energy and Mines responsible for regulating the optimum development of oil and gas fields. After the initial six-month period or before an approved extended well test period expires, we will be required to have the necessary gas and water reinjection equipment in place to continue producing the well according to existing environmental regulations.

We currently have five wells that have been under well testing for more than six months as permitted during the exploration phase of our Block Z-1 License Contract. Our current FDP for our Corvina field in Block Z-1 sets May 31, 2010 as the date to transition from exploration to commercial production in the Corvina field, at which time we will be required under our Block Z-1 License Contract to meet certain environmental and technical requirements in order to continue with commercial sales.

On January 25, 2010, we applied for an extended well testing permit in Corvina for the first five wells (not including the CX11-19D and CX11-17D wells) as we believe it is necessary to continue gathering data to fully understand the drive mechanisms that are present in Corvina. On March 23, 2010, we received a decision from the DGH notifying us that they are approving us to continue extended well testing on our first five Corvina wells until the FDCP date of May 31, 2010, subject to specific limits on the amount of natural gas flared from each of the first five Corvina wells. Based on the natural gas flaring limits set by the DGH, we expect to constrain the oil production from some or all of those five Corvina wells in order to comply with those limits. The actual future decrease in production from these five Corvina wells will not be known until we implement our gas flaring mitigation strategy to optimize oil production while complying with the gas flaring limits, but production from these wells could decrease by as much as 400 to 800 bopd.

In addition, we are in the initial stages of appraising, exploring and developing our potential oil and natural gas reserves in the Albacora field of Block Z-1. Our first well in Albacora has been, and all new wells drilled in Albacora will be, placed in the initial six-month production testing under the new legislation. As in Corvina, we will need to receive approval for all the pertinent environmental and technical permits and install the required gas and water reinjection facilities at the Albacora platform in order to transition from exploration to commercial production in Albacora, which as currently estimated could take up to two years. If we do not receive extended well testing permits on wells in Albacora beyond the

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original six-month test period, we will experience an interruption in production that would negatively impact any revenue and cash flow associated with those wells until the applicable requirements are satisfied for commercial production in Albacora.

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 present value of reserves shown or incorporated by reference 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.

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 present value of our reserves. In addition, our independent petroleum engineer 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 net present 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 net present 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 net present value estimate.

Except as required by applicable law, we undertake no duty to update this information and do not intend to update this information.

We have received comments from the SEC to our most recent annual report, quarterly report and proxy statement that are still pending and that may not be resolved in our favor. In connection with a registration statement filed on October 21, 2009 to register shares issued to an institutional investor in a private transaction, we received comments from the SEC pertaining to our registration statement, our most recent Form 10-K for the year ended December 31, 2008, our Definitive Proxy Statement filed on April 30, 2009, and our most recent Form 10-Q for the period ended September 30, 2009 and the related earnings press release. In general, the pending questions or comments from the SEC relate to: (i) clarifications in several of our disclosures; (ii) the basis for the assumptions underlying our SEC oil reserves reported for 2008 in light of our actual production performance in 2009; (iii) the reasons our 2009 production fell short of 2008 projections; (iv) the consideration we gave to the reasonable certainty of our assumptions underlying our SEC oil reserves and the related accounting reported in our financial statements; and (v) how we are taking into consideration certain items and uncertainties for our 2009 reserves report. The SEC is currently reviewing our responses, and could ask additional questions or request additional revisions to our filings, some of which could be material. In particular, the process of estimating oil and natural gas reserves is complex, requiring interpretations of available technical data and many assumptions, including assumptions relating to economic factors, and therefore are inherently imprecise. In its review of our responses and reserve data provided to them, the SEC could disagree with our independent petroleum engineer’s reserve estimates, including the underlying interpretations and assumptions or the reasonable certainty of our assumptions, and request a revision to our estimates of proved reserves and the related accounting of the reserves in our financial statements. Any restatement of our financial statements or our estimates of proved reserves could have a material adverse effect on the trading price of our common stock.

As of December 31, 2009, approximately 74% 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. There are 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 natural gas and 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 not been profitable since we commenced operations and have historically had significant working capital deficits. To date we have had limited revenue and limited earnings from operations. As of December 31, 2009, we had a working capital surplus of approximately $7 million. As of December 31, 2008, however, we had a working capital deficit of approximately $30 million, and we may incur working capital deficits in the future. The sources of our working capital surplus have generally been equity and debt financings rather than revenue from operations. We cannot provide any assurance that we will be profitable in the future or that we will be able to generate cash from operations or financings to fund working capital deficits.

We require additional financing for the exploration and development of our foreign oil and gas properties and the construction of our proposed power generation facility, pipeline and gas processing facility. Since the merger with Navidec, Inc. (“Navidec”) on September 10, 2004 (the “Merger”), we have funded our operations with the net proceeds of (i) approximately $288 million in various private placements of our common stock, (ii) $186.4 million in convertible debt financings, including $170.9 million of convertible debt 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, and (iii) $15.0 million in a reserve-based lending facility with IFC. We have recently begun to generate revenues from operations. With these funds we have begun to implement our plans to develop our existing oil and gas properties, but we will need significant additional financing to fully implement our plan of operation. If we are unable to timely obtain adequate funds to finance our exploration and development, our ability to develop our oil and natural gas reserves may be limited or substantially delayed. Such limitations or delays 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 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 foreign 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 adequate funding available to finance our future operations.

Any failure to meet our debt obligations or the occurrence of a continuing default under our debt facility would adversely affect our business and financial condition. Through our subsidiaries BPZ E&P and BPZ Marine Peru S.R.L., as borrowers, we entered into a $15.0 million senior revolving debt facility with IFC in August 2008, which funded in October 2008. The current facility is secured by a pledge of the shares of our BPZ E&P and BPZ Marine Peru subsidiaries.

The debt facility provides for events of default customary for agreements of this type, including, among other things:

· payment breaches under any of the finance documents for the first and second tranche of the senior debt;

· failure to comply with obligations under the finance documents;

· representation and warranty breaches;

· expropriation of the assets, business or operations of any borrower;

· insolvencies of any borrower;

· certain attachments against the assets of any borrower;

· abandonment or extended business interruption of the Corvina field or certain other petroleum assets for a period over 100 consecutive days or an aggregate of 120 days in any twelve month period;

· failure to maintain certain authorizations with respect to any financing documents with the IFC, the development and operation of the Corvina field in Block Z-1, any additional petroleum assets under license contracts with Perupetro or certain other key agreements;

· revocation of any financing or security documents with the IFC or certain key agreements;

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· defaults on certain liabilities;

· certain judgments against the borrower or any subsidiary;

· failure to make payment on any other liabilities in excess of $2 million;

· engagement in certain sanctionable, such as fraudulent, coercive or corrupt, practices; or

· restrictions enacted in Peru that could inhibit any payment a borrower is required to make under the financing documents with the IFC.

Upon the occurrence of an event of default or a specified change of control event, the IFC under our debt facility may: (i) terminate all or part of the relevant facility; (ii) declare all or part of the principal amount of the loan, together with accrued interest, immediately due and payable; (iii) declare all or part of the principal amount of the loan, together with accrued interest, payable on demand; or (iv) declare any and all of the security documents under the facility enforceable and exercise its rights under such documents, including rights of foreclosure against the collateral. In addition, if any borrower is liquidated or declared bankrupt, all loans and interest accrued on it or any other amounts due, will become immediately due and payable without notice.

The maximum amount available under this facility will be reduced by approximately $2.5 million beginning on December 16, 2010 and every six months thereafter during the term of the Agreement. The facility is subject to a semi-annual borrowing base re-determination based on the value of Corvina oil reserves. In the event the amount outstanding exceeds the re-determined borrowing base, we could be forced to repay a portion of our borrowings. We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings, we may be required to arrange new financing or sell a portion of our assets.

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.

Demand for oil and natural gas is highly volatile. A substantial or extended decline in oil or 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 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 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. For example, oil and natural gas prices increased to historical highs in 2008 and then declined significantly over the last two quarters of 2008. In early July 2008, commodity prices reached levels in excess of $140.00 per Bbl of crude oil and $13.00 per Mcf for natural gas. As of March 23, 2010, those prices were $79.45 per Bbl and $4.39 per MMBtu, respectively. These prices will likely continue to be volatile in the future. Oil and natural gas are commodities, and, therefore, 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:

· international political conditions (including wars and civil unrest);

· 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

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· 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. A continuation of low or a further 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. We 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.

Recent changes in the financial and credit market may impact economic growth, and combined with the recent volatility of oil and natural gas prices, may also affect our ability to obtain funding on acceptable terms or obtain funding under our proposed credit facilities. Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. Accordingly, the equity capital markets have become exceedingly distressed. These issues, along with significant asset write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions, have made, and will likely continue to 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 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 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 in the Company, 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.

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 and tsunamis and adverse weather conditions;

· pipe, cement, subsea well or pipeline failures;

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· 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 any drilling operations we may commence. 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 sales of oil 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, allisions, groundings and damage or loss from adverse weather conditions or interference from commercial fishing activities. These conditions can cause substantial damage to facilities, tankers and barges, 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 barges and tankers could temporarily impair our operations and delay delivery of our oil to be sold. We depend on our deck barges BPZ-01 and BPZ-02 to act as tender support vessels for our offshore drilling operations in our Corvina and Albacora fields in Block Z-1. In addition, we have two barges under capital lease to use in support of our offshore oil production operations. One barge is used as a floating production, storage and offloading facility (“FPSO”) and the other is currently being used as a floating storage and offloading facility (“FSO”). In addition, we have time chartered a double hull tank vessel to transport crude oil from our offshore production and storage facilities in Block Z-1 to the Talara refinery approximately 70 miles south of the platform where the oil is sold at market prices under a sales contract with the Peruvian national oil company Petroperu. Any disruption or delay of the services provided by our barges 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.

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.

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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.

Our management team has limited experience in the power generation business and we need additional funding to construct power generation and gas processing facilities and pipelines. Our plan of operation includes constructing power generation and gas processing facilities and pipelines in Peru and in the future potentially in Ecuador. However, the experience of our management team has been in the oil and natural gas exploration and production industry and we have limited experience in the power generation business. We are initially 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 and gas processing facilities, which may not be available when needed or available on favorable terms.

Construction and operation of power generation and gas processing facilities and pipelines involve significant risks and delays that cannot always be covered by insurance or contractual protections. The construction of power generation and gas processing facilities 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 necessary gas turbines;

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

· possible delays in connection with power plant construction;

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

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

The 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, as well as obtain warranties from vendors and obligate contractors to meet certain performance levels. However, the coverage

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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 expense and higher costs.

The success of our gas-to-power project depends, in part, on the existence and growth of markets for natural gas and electricity in Peru and Ecuador. Peru has a relatively well-developed and stable market for electricity, while the power market in Ecuador is not as well-developed or stable. Both countries rely on hydroelectric generating capacity for a significant portion of their power demand. 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. The majority of the non-hydroelectric or thermal power capacity in both countries consists of generating plants that utilize diesel or fuel oil, which are significantly more costly than natural gas at this time. Both countries have natural gas reserves and production, but neither has a well-developed natural gas infrastructure. Our immediate business plan relies on the continued stability of the power market in Peru (and Ecuador for the purpose of potential future gas sales to third-party power producers in Ecuador), and our longer-term plans depend on the further development of the electricity market in Ecuador. We currently do not expect to complete our power plant until 2011. Our assessment of the future power market and demand in Peru and Ecuador could be inaccurate. We are subject to the 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;

· potential disruptions or changes to regulations 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 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 also 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 plants.

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:

· 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.

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, specifically Peru and Ecuador. The success and profitability of our international operations may be adversely affected by risks associated with international activities, including:

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· 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 in 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 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 unrest. For example, in August 2008, Peru’s Congress repealed two presidential decrees that made it easier for companies and individuals to buy land belonging to indigenous peoples as a result of protests from a large number of indigenous people in Peru’s Amazon jungle. Beginning in April 2009, thousands of indigenous people again protested by blocking roads and waterways in eastern Peru to try to force the repeal of additional decrees facilitating oil exploration, commercial farming and logging in parts of the Amazon jungle, resulting in a violent clash between police officers and the protestors in June 2009. The violence led to the suspension of several of the decrees and the Peruvian President’s third reshuffle of his cabinet since he came to power in 2006.

Peru’s next municipal and regional political elections will be in November 2010, and the next Peruvian Presidential and Congressional election will be in April 2011. The campaigning leading up to the elections will likely cause heightened political risk and attention to various topics, including the regulation of oil and gas companies operating in Peru, and related environmental law compliance. As a result of these or similar events, 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.

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 when compared 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, 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 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.

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 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 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 current administration in Ecuador is likely to 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 ability to operate in that country. We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:

· work program guarantees and other financial responsibility requirements;

· taxation;

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· royalty requirements;

· customer requirements;

· operational reporting;

· environmental and safety requirements; and

· unitization requirements.

Under these laws and regulations, we could be liable for personal injuries, property and natural resource damages, governmental infringements and sanctions and unitization payments.

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 contracts with the government of Peru, including 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 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 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 limited compliance program designed to ensure that the Company, its 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.

We are subject to complex 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 are subject to extensive environmental 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 continue commercial sales of oil beyond May 31, 2010, the date under our current FDP to transition from exploration to commercial production in Corvina, unless an extension is obtained. Additionally, environmental laws and regulations promulgated in Peru impose substantial 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. The laws create additional monitoring and reporting obligations in the event of any spillage or unregulated discharge of 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 get future permits and authorizations may, over time, be susceptible to increased scrutiny, resulting in increased costs, or delays in receiving appropriate authorizations. In particular, we may experience delays in obtaining permits and authorizations in Peru necessary for our operations. Compliance with these laws and regulations may increase our costs of operations, as well as further restrict our foreign operations. Moreover, these laws and regulations could change in ways that substantially increase our costs. These laws and regulations have changed in the past and have generally imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated developments could cause us to make environmental expenditures that are significantly higher than those we currently anticipate, thereby increasing our overall costs. Any failure to comply with applicable regulations could cause us to suspend or terminate certain operations or subject

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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.

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 discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, 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, subject the owner or lessee to liability for pollution damages and other environmental damages, and require suspension or cessation of operations in affected areas or related sales of oil and gas.

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 the oil and gas 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.

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 leases uneconomical. Further, the quality of the extracted oil or gas could limit potential markets or could require expensive chemical treatment to make it marketable. This could result in a total loss of our investments made in our operations.

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 (a state company responsible for promoting and overseeing the investment of hydrocarbon exploration and exploitation activities in Peru) 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 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 divesting practices of other oil and natural gas companies, commodity prices, general economic conditions and other factors we cannot control or influence.

The loss of senior management or key technical personnel could adversely affect us. We have engaged certain members of management who have substantial experience and 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 upon 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

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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 personnel may adversely affect us.

Insurance does not cover all risks. Exploration for, and 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 damage to or destruction of wells or production facilities, formations, injury to persons, loss of life, or damage to property or the environment. 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 coverage includes certain physical damage to the Company’s 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 operations until such time as replacement capital is obtained, if ever, and this could have a material adverse impact on our financial position.

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 acquire 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 at economical exploration and development costs. 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.

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 from operations totaling $241.2 million through December 31, 2009. To date we have had limited revenue and no earnings from operations. There can be no assurances that sufficient revenue to cover total expenses can be achieved until, if at all, we fully implement our operational plan.

Additional infusions of capital may have a dilutive effect on existing shareholders. To finance our operations we may sell additional shares of our common stock. In February 2010 and March 2010, we issued $170.9 million of Convertible Notes due 2015 that, if converted to common stock, could potentially significantly increase the amount of our common shares outstanding by up to approximately 23 million shares currently. Our certificate of formation does not provide for preemptive rights. We currently have $134.6 million in common stock available under an effective shelf registration statement, which we may sell from time to time in one or more offerings pursuant to underwritten public offerings, negotiated transactions, block trades or a combination of these methods prior to the December 7, 2010 expiration date of our shelf registration statement. 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. 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

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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. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

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

· refinancing or restructuring our debt;

· selling assets;

· reducing or delaying capital investments; or

· seeking to raise additional capital.

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

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, 2009, we had 115,223,926 shares of common stock issued and outstanding. In addition, we have outstanding 4,545,332 shares of other potentially dilutive securities, which mainly consist of options granted under our 2005 Long-Term Incentive Compensation Plan, as amended and restated. We also have an additional 1,538,900 shares of common stock allocated under our 2007 Long-Term Incentive Compensation Plan, as amended and restated, and our 2007 Directors’ Compensation Incentive Plan. During the first quarter of 2010, we issued $170.9 million of Convertible Notes due 2015 that, if converted to common stock, could potentially increase the amount of our common shares outstanding, by up to approximately 23 million shares currently. 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 14.8% of our common stock, and several institutional investors own approximately another 34.4% of our common stock, issued as of December 31, 2009. These shareholders, if acting together and owning approximately 49.2%, will 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 to which we are subject may delay or prevent a change in control that some shareholders may favor. Our certificate of formation and bylaws contain provisions that, either alone or in combination with the provisions of Texas law described below, may have the effect of delaying or making it more difficult for another person to acquire us by means of a hostile tender offer, open market purchases, a proxy contest or otherwise. These provisions include:

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

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

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

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

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

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; or

· 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 in the past, and may in the future, experience extreme price and volume fluctuations. These market fluctuations may materially and adversely affect the trading price of our common stock, regardless of our actual operating performance.

ITEM 1B. UNRESOLVED STAFF COMMENTS

We have received no written comments regarding our periodic or current reports from the staff of the SEC that were issued 180 days or more preceding the end of our 2009 fiscal year that remain unresolved.

In connection with a registration statement filed on October 21, 2009 to register shares issued to IFC in a private transaction, we have received comments from the SEC pertaining to our registration statement, our Form 10-K for the year ended December 31, 2008, our Definitive Proxy Statement filed on April 30, 2009, and our Form 10-Q for the period ended September 30, 2009 and the related earnings press release. In general, the pending questions or comments from the SEC relate to: (i) clarifications in several of our disclosures; (ii) the basis for the assumptions underlying our SEC oil reserves reported for 2008 in light of our actual production performance in 2009; (iii) the reasons our 2009 production fell short of 2008 projections; (iv) the consideration we gave to the reasonable certainty of our assumptions underlying our SEC oil reserves and the related accounting reported in our financial statements; and (v) how we are taking into consideration certain items and uncertainties for our 2009 reserves report. We have promptly responded to the SEC’s requests and are currently waiting on requests for additional information, if any. In addition, where appropriate, we have proposed clarifications to our disclosures, none of which we believe are material in light of all of the disclosures and risk factors provided in our public filings to date. The SEC is currently reviewing our responses, and could ask additional questions or request additional revisions to our filings, some of which could be material. In particular, the process of estimating oil and natural gas reserves is complex, requiring interpretations of available technical data and many assumptions, including assumptions relating to economic factors, and therefore are inherently imprecise. In its review of our responses and reserve data provided to them, the SEC could disagree with our independent petroleum engineer’s reserve estimates, including the underlying interpretations and assumptions or the reasonable certainty of our assumptions, and request a revision to our estimates of proved reserves and the related accounting of the reserves in our financial statements. In addition, results of actual future production will depend on expected production levels that might not be achieved, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, which will most likely vary from our estimates, and those variances may be material.

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ITEM 2. PROPERTIES

Offices

Our corporate headquarters office is in Houston, Texas, where we lease approximately 20,400 square feet of office space under a lease agreement which expires in February 2016. We sublease approximately 4,400 square feet of our office space to a tenant under a sublease agreement which expires in December 2012. We also currently lease four administrative offices and a warehouse in Peru of approximately 12,100 square feet and 68,000 square feet, respectively. The current administrative offices in Lima, Peru and a warehouse in Piura, Peru are under month-to-month leasing arrangements until we are ready to move into our new consolidated administrative offices in Lima, Peru and new warehouse located in Caleta Cruz which is near our operations in Tumbes, Peru. The new administrative office and warehouse leased areas are approximately 22,500 square feet and 101,300 square feet, respectively, and both leases expire in December 2013. Additionally, we lease an administrative office in Quito, Ecuador of 829 square feet under a month-to-month lease.

Properties in Peru

We currently have exclusive rights to four properties in northwest Peru. We have a 100% working interest in license contracts for Block Z-1, Block XIX, Block XXII and 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 exploration and production and up to 40 years for gas exploration and production. In the event a block contains

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both oil and gas, as is the case in the Block Z-1 contract, the 40 year term may apply to oil exploration and 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, 2009 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)

Block Z-1	Tumbes/Talara	100	%	November 2001	554,300	700	7
Block XIX	Tumbes/Talara	100	%	December 2003	473,000
Block XXII	Lancones/Talara	100	%	November 2007	912,000
Block XXIII	Tumbes/Talara	100	%	November 2007	230,000
Total					2,169,300	700	7

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

Description of Block Z-1 and License Contract

Block Z-1, a coastal offshore area encompassing approximately 555,000 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. Wells drilled in each of these structures 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 economic 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 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 and are still in place in the Corvina field. The first platform is located in the East Corvina prospect field and we need to conduct an engineering study to determine the viability of repairing and refurbishing the platform or building 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, after repairs and refurbishment, 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, although only one of the wells, the CX11-16X, was completed and tested. At the time these wells were drilled, there was no commercial market for natural gas in the region. The CX11-16X ,when tested by Belco, produced natural gas at rates as high as 16.6 million cubic feet of gas per day during two separate tests over a period of approximately 20 days each. Following these tests, the well was shut-in. In June 2007, we successfully recompleted the CX11-16X well as a natural gas producing well and completed a total of four drill stem tests on various zones in the well including one in a formation previously untested in the entire basin. The tests produced quantities of gas we believe to be in commercial amounts. The CX11-16X well remains shut-in pending development of our planned gas-to-power project.

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 Belco during this period is still in place in the Albacora field and has been repaired and refurbished by us. The Albacora field is located in the northern part of our offshore Block Z-1. It consists of approximately 7,500 acres and is located in water depths of less than 200 feet.

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. The completed well in the Piedra Redonda field, the C18X, when tested by Belco, produced natural gas at rates as high as 8.3 MMcfe per day over a period of approximately 20 days during an extended test in 1979 and was also shut-in.

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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.

The license contract provides for an initial exploration phase of seven years, and can be extended under certain circumstances an additional six years up to thirteen 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 is currently in the fourth exploration period. This period was initially scheduled to expire in November 2010. However, due to receiving a statement from the Ministry of Energy and Mines to suspend our seismic data survey, the fourth period is currently under suspension until our revised Environmental Impact Study is approved by the DGAAE (“Dirección General de Asuntos Ambientales y Energéticos”), a division of the Ministry of Energy and Mines, who is responsible for environmental protection matters in Peru. The fourth and final exploration period requires the drilling of an additional exploratory well or other equivalent work commitments, such as conducting a seismic data survey. 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 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.

Under the terms of the Block Z-1 license contract, we are permitted to retain a portion of the license contract area that we would otherwise have to return to Perupetro as long as we carry out additional exploration activities after the end of the exploration period, in accordance with the requirements under the license contract. Our current plans are to carry out these additional exploration commitments and retain this area.

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. The commercial development period of the Corvina field will commence on May 31, 2010. In December 2009 Perupetro approved our proposed FDCP as set forth in the current FDP for our Corvina field. The FDP sets May 31, 2010 as the date to transition from exploration to commercial production in the Corvina field. Accordingly, on or before the FDCP we will be required to have installed and commissioned any equipment needed to process and transport all produced fluids, including reinjection facilities for any formation water and unused associated gas produced with the crude oil, unless an extension is obtained. Under the contract, oil exploration, development and production can continue for a total of up to 30 years from the effective date of the contract, and gas exploration, development and production can continue for up to 40 years. 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 exploration and 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.

After the third exploration period, we relinquished 25% of the least prospective acreage as stipulated under the terms of the Block Z-1 License Contract as we transitioned into the fourth exploration phase under the license contract. None of the mapped prospects identified by us were included within the acreage relinquished. At the end of the fourth exploration phase, we may keep the remaining contract area, provided we commit to certain exploration commitments every two years, for a maximum additional period of up to six years. 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 XIX and License Contract

Block XIX covers approximately 473,000 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.

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In February 2003, we entered into a Technical Evaluation Agreement with Perupetro for Block XIX. 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 exploration and production of oil for a period of 30 years from the effective date of the contract and the exploration and 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 exploration and 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 is divided into five periods of 18 months, 24 months, 15 months, 15 months and 12 months, respectively. We are currently in the third exploration period, which was scheduled to end in September of 2010. However, due to the fact the authorization for access is still in process by DGH, last February we asked Perupetro to declare force majeure. Once approved by Perupetro, the third exploration period requires us to drill and test one well or perform other equivalent work commitments. Once we complete the third exploration period we will reestablish timelines for the remaining exploration periods. In connection with the third exploration period, we posted a $585,000 performance bond for $292,500 in cash collateral. The fourth exploration period will require a performance bond of $585,000. The fifth and final exploration period is scheduled to begin in December 2011 and 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.

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 purse and implement an additional work program every two years, up to a maximum of four years. 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 such discoveries.

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 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 or 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 first exploration period which was originally scheduled to expire in July 2009. However, since our Environmental Impact Study took several months to be approved, the first exploration period time limit was on suspension until such approval was obtained from the DGAAE. We obtained the approval in March 2011 which extended the first exploration period up to September 2010. The first exploration period requires that we acquire, process and interpret 260 kms of two dimensional (“2-D”) seismic data and prepare a comprehensive geological and engineering study for the area. 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 exploration and production of oil for a period of 30 years from the effective date of the contract and the exploration and 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 exploration and production as well. Royalties under the contract vary from 15% to 30% based on production volumes. Royalties start at 15% if and when production is less than 5,000 boepd and are capped at 30% if and when production surpasses 100,000 boepd.

In connection with the first exploration period, we were required to obtain a cash collateralized $600,000 bond for cash collateral in the amount of $300,000. 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.

Under the Blocks 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

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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 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 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 in to two periods of 18 months and two periods of 24 months. We are in the first exploration period which was originally scheduled to expire in July 2009. However, since our Environmental Impact Study is still pending approval from DGAAE, the first exploration period time limit is on suspension until such approval is obtained. Once we complete the first exploration period we will reestablish timelines for the remaining exploration periods. The first exploration period requires that we acquire, process and interpret 360 kms of three dimensional (“3-D”) seismic data and 290 kms of 2-D seismic data and prepare an integrated geological, geochemical and reservoir engineering evaluation of the hydrocarbon prospects in the block. In each subsequent period after the first exploration period, we will be required to drill a certain number of wells and/or acquire certain amount of either 2-D or 3-D seismic data. If a commercial discovery is made during the exploration period, the contract will allow for the exploration and production of oil for a period of 30 years from the effective date of the contract and the exploration and 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 exploration and production as well. Royalties under the contract vary from 15% to 30% based on production volumes. Royalties start at 15% if and when production is less than 5,000 boepd and are capped at 30% if and when production surpasses 100,000 boepd.

In connection with the first exploration period, we were required to obtain performance bond of $3,075,000 bond for $1,537,500 in cash collateral. 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.

Under the Blocks 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 their 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” and , “We have received comments from the SEC to our most recent annual report, quarterly report and proxy statement that are still pending and that may not be resolved in our favor” 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. See further information about the basis of presentation of these amounts in “Supplemental Oil and Gas Disclosures (Unaudited)” to our consolidated financial statements provided herein.

As of December 31, 2009, we owned a 100% working interest in the Corvina and Albacora fields, subject to Peruvian government royalties of 5% to 20% net revenue interest 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 have 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.

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Net Proved Crude Oil Reserves and Future Net Cash Flows

As of December 31, 2009

Based on Average Fiscal-Year Prices

	Actual		Estimated Future Capital Expenditures
	(In MBbls)		(In thousands)
Proved Developed Producing	4,298		$	26,400
Proved Developed Not Producing	5,614		$	21,800
Proved Undeveloped	27,572		$	354,400
Total	37,484		$	402,600
Standardized Measure of Discounted Future Net Cash Flows, Discounted @ 10% (PV-10) (in thousands)	$	738,559

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 Disclosures.” 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 for 2009 requires the use of an average 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. For years prior to 2009, the SEC rules required the use of year-end prices.

All of our proved undeveloped reserves are scheduled for development within five years and at December 31, 2009, we did not have any proved undeveloped reserves greater than five years.

In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our properties, and the present value of the properties, are made using the twelve-month first day of the month historical average oil prices for the December 31, 2009 reserves and oil sales prices in effect as of the end of the period of such estimates for prior periods, and are held constant throughout the life of the properties, except where the guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Historically, the prices for oil have been volatile and are likely to continue to be volatile in the future.

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 petroleum engineer with over 20 years operating experience in international oil and gas projects. He holds an Advanced Degree in Mathematics from Ecole Centrale de Paris, France, a Master’s Degree and Ph.D. in Petroleum Engineering from Texas A&M University, as well as an MBA from the University of Colorado.

The technical personnel responsible for preparing the reserves estimates at NSAI meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI is an independent firm of petroleum engineers, geologists, geophysicists, and petrophysicists; it does not own an interest in our properties and is

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not employed on a contingent fee basis. NSAI’s President and Chief Operating Officer is a licensed professional engineer with more than 30 years of experience and the geoscientist charged with the audit is a licensed professional with 25 years of experience.

Reserve Technologies

The SEC’s new rules 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 has been field tested and has 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, including the material additions to the 2009 reserves estimates.

Development of Proved Reserves

As of December 31, 2009, we had proved reserves of 37.5 MMBbls, an increase of 20.3 MMBbls relative to December 31, 2008 of proved reserves of 17.2 MMBbls. Additions to proved developed non-producing reserves were 5.6 MMBbls at December 31, 2009. There were no proved developed non-producing wells at December 31, 2008. Additions to proved undeveloped reserves of 14.6 MMBbls resulted primarily from additional proved undeveloped locations in our Corvina field of 10.3 MMBbls, or 23.2 MMBbls total, and to a lesser extent to our Albacora field of approximately 4.3 MMBbls.

Production, Average Sales Price and Production Costs.

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

				Average
	Sales (1)	Average Sales		Production
	Volumes (MBbls)	Price		Cost (2)
2009	962.6	$	54.49	$	29.21
2008	825.8	$	76.23	$	14.11
2007	28.7	$	81.78	$	26.26

(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 includes the oil operating, workover and repair costs.

Acreage

The following table shows approximately the number of developed and undeveloped acres as of December 31, 2009:

		Acres
Developed		700
Undeveloped		2,169,300
Total acreage		2,170,000

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Drilling Activity

The number of productive development wells at December 31, 2009, 2008 and 2007 were 7.0, 4.0 and 2.0, respectively. The following table lists our successful exploratory and development wells that were drilled during the year ended December 31, 2009:

Corvina Field	Exploratory/Development	Drilling Depth (feet)	Date Objective Drilled/Tested
CX11-15D	Development	9,390	1st quarter
CX11-19D	Development	8,695	4th quarter

Albacora Field		Exploratory/Development		Drilling Depth (feet)		Date Objective Drilled/Tested
A-14D		Development		14,484		4th quarter

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

In the first quarter of 2010, we drilled and tested the CX11-17D well in the Corvina field. The development well was drilled to a total depth 9,830 feet.

Present Activities

Corvina Field

We are producing oil under a long-term testing program, at the CX-11 platform in Corvina and are in the process of satisfying the conditions to transition to commercial production in Corvina. Production for the three months ended December 31, 2009 was approximately 205,121 barrels of oil, or approximately 2,300 bopd.

In December 2009, the CX11-19D well was successfully completed into a proved undeveloped area of the Corvina field, targeting not only sands currently produced in other wells, but also lower untested oil sands that were found to be productive. During the drilling of this well, the Zorritos formation was encountered higher than previously mapped. The well has continued to produce consistently with its initial production rate (“IPR”), with an increase in its gas-oil-ratio as expected, indicative of the production mechanism predominant in the early life of the well. There has been no formation water reported to date.

Additionally, in February of 2010, the CX11-17D well, our seventh oil well in the Corvina field, was successfully completed and placed into production with normal gas-oil-ratio and no formation water. We first tested a set of lower sands that had not been tested before in prior wells before adding the second set of sands, thus allowing us to gather data to continue updating the Corvina geologic and reservoir models. While all wells decline over time, it is too early to model the decline rate in the Corvina field as we are still collecting data to determine the field’s drive mechanism.

We are currently drilling the CX11-22D in Corvina. This well will be drilled to approximately 10,000 feet measured depth. We expect this well to be online in the second quarter of 2010.

Albacora Field

In December 2009, we produced approximately 7,400 barrels of oil from the A-14XD well at the A platform in the Albacora field under a under a production testing program pursuant to the new regulations.

In January 2010, we commenced drilling the A-15D, the second Albacora well, which was to be drilled to approximately 13,000 feet vertical depth and aims to test prospective sands below the lowest known oil sands tested or produced to date in the field. In mid January 2010, the Company stopped oil production and drilling activities in order to install the permanent production equipment on the A platform. In February 2010, we resumed drilling of the A-15D well as

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well as resumed testing the A-14XD. The Company is in the process of negotiating an initial short-term oil sales contract with the Talara refinery or another third party, which is expected to be completed by the end of the first quarter.

In March 2010, while drilling the A-15D and preparing to run our 9 5/8” casing to the top of the Zorritos formation, we found that the 13 3/8” casing of the previous section had been damaged. After several unsuccessful attempts to recover that section of the well, we decided to abandon that wellbore and proceed to skid the rig and start the drilling of the A-16D well which, similar to the A-15D, will be drilled to approximately 13,000 feet vertical depth and will aim to test prospective sands below the lowest known oil sands tested or produced to date in the field. We are evaluating the possible courses of action to recover the slot that was used by the A-15D well. Our methodology for appraising and developing the Albacora field remains consistent with the methodology used to appraise and develop the Corvina field; we plan to take a step-by-step approach to find and delineate the generalized oil-water contact in the field based on prospective sands identified by the A-14XD well and the wells previously drilled in the field.

Additionally, while preparing to drill the A-16D well, we learned that one of the main beams of the upper platform deck was bent. It appears that the damage occurred during the drilling of the A-15D well. We are investigating this incident to confirm our initial assessment of the cause and structural integrity of the platform. At present, structural engineers are evaluating the overall condition of the platform to insure its structural integrity. Initial estimates to complete repairs are two weeks. On completion of all repairs we will begin drilling the A-16D well.

Marine Operations

Subsequent to December 31, 2009, we have upgraded our oil transportation capabilities by time chartering a double-hull tanker with a capacity of approximately 65,000 barrels. This vessel should allow us to optimize delivery of our oil to the Talara refinery. We have also leased a storage vessel with capacity of approximately 160,000 barrels and plan to place it near the Albacora platform. The additional transportation and storage capacity should provide needed operational flexibility to minimize future oil production restrictions due to possible delays at the Talara refinery’s terminal caused by high tanker traffic or adverse sea conditions.

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-operated working 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 is located west of the city of Guayaquil along the coast of Ecuador. The license contract provides for royalty payments equal to 23% of production. There have been almost 3,000 wells drilled in the field since production began in the 1920s. There are approximately 1,450 active wells which produce approximately 1,400 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 license agreement covering the property extends through May 2016.

ITEM 3. LEGAL PROCEEDINGS

Navy Tanker Litigation

The T/V SUPE, a small tanker owned and operated by the commercial division of the Peruvian Navy, caught fire and sank while under time charter to Tecnomarine, BPZ E&P’s marine contractor, resulting in two fatalities and numerous injuries. On December 18, 2008, a lawsuit was filed in the 152nd Judicial District Court of Harris County, Texas by two crewmembers and the family and estate of two of the deceased sailors of the T/V SUPE against BPZ Energy, Inc. and BPZ Resources, Inc. As none of the Peruvian government sanctioned investigations into the SUPE incident found fault on the part of Tecnomarine, BPZ or BPZ’s subsidiary, BPZ E&P, we do not currently believe, based upon the known facts relating to the incident, that the outcome of the legal proceeding will have a material adverse effect on our financial condition, results of operations or cash flows. Additionally, we believe the incident would be covered by our insurance policies, after a customary deductible.

ITEM 4. RESERVED

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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

Effective October 26, 2009, we transferred the listing of our Common Stock, no par value, from the NYSE Amex to the New York Stock Exchange (“NYSE”), where we continue to trade under the symbol “BPZ.”

From October 2008, following the acquisition of the American Stock Exchange by the NYSE Euronext, until our transfer to the NYSE, our Common Stock traded on the NYSE Alternext U.S. (later renamed NYSE Amex) under the ticker “BPZ”. From January 12, 2007 until the merger of the stock exchanges, our Common Stock was traded on the American Stock Exchange (“AMEX”) under the symbol “BZP”.

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, NYSE Amex , NYSE Alternext U.S., and AMEX for the applicable time periods.

	High		Low
2009
Fourth quarter	$	9.98	$	6.05
Third quarter	8.07		4.52
Second quarter	7.65		3.60
First quarter	9.18		2.25

2008
Fourth quarter	$	17.39	$	3.95
Third quarter	29.88		12.00
Second quarter	29.52		17.20
First quarter	23.20		10.51

Holders

As of March 23, 2010, we had approximately 165 shareholders of record, and an estimated 17,614 beneficial owners of our Common Stock.

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

Recent Sales of Unregistered Securities

The information on our recent sales of unregistered securities has been previously reported in the following reports filed with the SEC:

1) Form 8-K filed on February 24, 2009;

2) Form 10-Q, Part II, Item 2, filed on May 11, 2009;

3) Form 8-K filed on September 16, 2009;

4) Form 8-K filed on February 9, 2010;

5) Form 8-K filed on February 19, 2010; and

6) Form 8-K filed on March 15, 2010.

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Performance Graph

The following graph compares the cumulative total shareholder return for the Company’s Common Stock to that of (i) the Russell 2000 Stock Index, and (ii) a Company peer group of five independent oil and gas exploration companies selected by us, for the period indicated as prescribed by the SEC’s rules. The companies in our selected peer group are Toreador Resources Corp., Contango Oil & Gas, Co, Harvest Natural Resources, Inc., Far East Energy Corp, and Carrizo Oil & Co Inc. “Cumulative total return” is defined as the change in share price during the measurement period, plus cumulative dividends for the measurement period (assuming dividend reinvestment), divided by the share price at the beginning of the measurement period. The graph assumes $100 was invested on January 1, 2004 in our Common Stock, the Russell 2000 Stock Index and a Company peer group.

	2004		2005		2006		2007		2008		2009
BPZ Resources, Inc.	$	100	$	112	$	108	$	294	$	168	$	250
Russell 2000 Stock Index	100		104		121		117		76		96
Peer Group Composite	100		115		152		213		139		151

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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,
	2009			2008			2007 (Restated) (1)			2006 (Restated) (1)			2005 (Restated) (1)
	(In thousands, except per share and per barrel information)
Operating Results:
Revenue (net)	$	52,454		$	62,955		$	2,350		$	—		$	—

Operating and administrative expenses:
Lease operating expense	28,113			11,649			755			—			—
General and administrative expense	33,258			42,094			18,548			11,532			5,805
Geological, geophysical and engineering expense	7,768			794			4,045			2,048			998
Depreciation, depletion and amortization expense	25,803			16,062			793			214			30

Total operating expenses	94,942			70,599			24,141			13,794			6,833

Operating loss	(42,488		)	(7,644		)	(21,791		)	(13,794		)	(6,833		)

Other income (expense):
Income from investment in Ecuador property, net of amortization	1,208			718			264			1,403			469
Interest expense	—			—			—			(16		)	(11		)
Amortization of deferred financing costs	—			—			—			—			(68		)
Registration delay expense	—			—			—			(3,553		)	(516		)
Interest income	215			319			855			787			510
Miscellaneous income (expense)	(1,312		)	102			201			(314		)	42

Total other income (expense)	111			1,139			1,320			(1,693		)	426

Loss before income taxes	(42,377		)	(6,505		)	(20,471		)	(15,487		)	(6,407		)

Income taxes (benefit)	(6,575		)	3,141			39			—			—

Net loss	$	(35,802	)	$	(9,646	)	$	(20,510	)	$	(15,487	)	$	(6,407	)

Basic and diluted net loss per share	$	(0.35	)	$	(0.12	)	$	(0.33	)	$	(0.35	)	$	(0.23	)

Weighted average common shares outstanding	103,362			77,390			61,660			44,752			27,399

Oil sales price per barrel, net	$	54.49		$	76.23		$	81.78		$	—		$	—
Operating cost per barrel	$	29.21		$	14.11		$	26.26		$	—		$	—

Balance Sheet Data:
Working Capital/(Defecit)	$	7,385		$	(30,562	)	$	1,549		$	22,057		$	29,036
Property, equipment and construction in progress, net	262,517			193,934			100,366			38,727			4,365
Total assets	349,172			235,365			129,619			74,037			38,091
Total long-term debt	22,581			15,018			15,537			56			71
Stockholders’ equity	271,957			159,180			90,740			63,636			36,732

Cash Flow Data:
Cash flow provided by/(used in) operating activites	(30,785		)	48,722			(15,171		)	(6,682		)	(4,461		)
Cash flow used in investing activities	(90,005		)	(102,185		)	(58,464		)	(34,270		)	(5,745		)
Cash flow provided by financing activities	133,620			51,266			55,825			36,820			35,647

(1) For further information regarding the restated amounts, see Note 11 — “Restatement of Merger Earn-Out Shares”.

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

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

Overview

We are an independent oil and gas company focused on the exploration, development and production of oil and natural gas in Peru and Ecuador. We also intend to utilize part of our planned future natural gas production as a supply source for the development of a gas-fired power generation facility in Peru, which we currently plan to wholly or partially own. We have the exclusive rights and license agreements for oil and gas exploration and production covering approximately 2.2 million 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-operated working 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:

· Transition of the Corvina field in Block Z-1 from extended well testing to commercial production, which involves the installation of equipment necessary to comply with Peruvian environmental and other regulatory requirements.

· Development of the Albacora field in Block Z-1 where we have commenced drilling and begun initial production well testing. We will also need to install equipment in Albacora as necessary to comply with Peruvian environmental regulations and are planning on an approximately two-year period to transition to commercial production.

· Continued development of our gas-to-power project to monetize our natural gas reserves, which we have identified in Corvina, but for which no market has yet otherwise developed, preventing us from reporting volumes of gas reserves for SEC reporting purposes.

· Continued acquisition of seismic and well testing data to better understand the characteristic and potential of our license properties and build our reportable asset values.

· Commencement of an on-shore drilling campaign to develop our on-shore properties and meet our applicable license requirements.

Extended Well Testing Program

On December 13, 2009 new legislation regulating well testing in Peru became effective by means of a Supreme Decree. The new regulation provides that all new wells may be placed on production testing for up to six months. If the operator believes that 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 Extended Well Test (“EWT”) period must be submitted to the DGH, the agency of the Ministry of Energy and Mines responsible for regulating the optimum development of oil and gas fields. The approval process for an EWT permit requires that the DGH request Perupetro’s opinion on the technical justification for the EWT. 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. For wells that have been under testing for more than six months as of the date of publication of the Supreme Decree, the new regulation provides 30 business days to apply to the DGH for the corresponding EWT permit.

On December 29, 2009, we received approval, from Perupetro, of our proposed FDCP, as set forth in the current FDP for the Corvina field in Block Z-1, which is May 31, 2010.

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On January 25, 2010, we applied for an extended well testing permit in Corvina for the first five wells (not including the CX11-19D and CX11-17D wells) as we believe it is necessary to continue gathering data to fully understand the drive mechanisms that are present in Corvina. On March 23, 2010, we received a decision from the DGH notifying us that they are approving us to continue extended well testing on our first five Corvina wells, until the FDCP date of May 31, 2010, subject to specific limits on the amount of natural gas flared from each of the first five Corvina wells. Based on the natural gas flaring limits set by the DGH, we expect to constrain the oil production from some or all of those five Corvina wells in order to comply with those limits. The actual future decrease in production from these five Corvina wells will not be known until we fully implement our gas flaring mitigation strategy to optimize oil production while complying with the gas flaring limits, but production from these wells could decrease by as much as 400 to 800 bopd.

We initially planned to have the needed gas and water reinjection facilities at the CX-11 platform by May 31, 2010. However, this no longer appears to be reachable due to the delayed delivery of certain equipment. If we are unable to receive and install the necessary water and gas reinjection equipment and receive approval of the corresponding environmental permits by May 31, 2010, we may not be permitted to produce from some or all of the oil wells in Corvina until such installation is completed or an extension of the May 31, 2010 date is obtained. We will apply to the proper authorities for an extension of the May 31, 2010 date to be able to maintain testing the wells in Corvina; however, no assurance can be given that such extension will be awarded. Depending on the extent of the delay, we plan to use the additional time to drill one or two more wells from the CX-11 platform after the current well, the CX11-22D is completed. Further, we may not be able to produce any well drilled after December 13, 2009 for a period longer than the initial six month testing period. Our current view is that we may be able to produce our new wells CX11-17D, CX11-19D, CX11-22D, and any other well we may drill at the CX-11 platform for at least six months, as stated by the new well testing regulations. Testing these wells beyond the initial six month period will require a special application to the Ministry of Energy and Mines that may or may not be granted approval.

Oil Development

General

We will conduct our drilling and exploration activities based in part on an ongoing assessment of economic efficiencies, likely success and logistical issues such as license requirements, 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.

Seismic Data Acquisition

We are in the initial process of acquiring seismic data to assist us in exploring, appraising and developing certain areas of interest within our blocks located in northwest Peru. The purpose of the seismic survey is to improve the subsurface imaging of certain areas within the blocks in order to better define the position of future wells as well as to comply with our exploration commitments under our license contracts.

For Block Z-1, we intend to acquire approximately 1,500 square kilometers of 3-D seismic data. The 3-D seismic data survey will include areas of interest within the Corvina, Albacora, and Delfin fields as well as certain prospects and leads located within the Mero and Piedra Redonda regions and certain deep water leads located within Block Z-1. Additionally, the 3-D seismic survey will include data underneath four existing platforms in the Albacora, Corvina and Piedra Redonda fields. The seismic data survey will fulfill our commitments under the fourth exploration period of the Block Z-1 license contract if conducted within the allowed contractual time frame. We initially attempted to conduct this seismic survey in late 2009 but encountered opposition that led us to suspend the survey as directed by the Ministry of Energy and Mines. We are currently working on a new seismic environmental permit and we estimate the 3-D seismic data survey to be completed by 2011.

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For Block XXIII, we intend to acquire approximately 360 square kilometers of 3-D seismic data and 290 kilometers of 2-D seismic data which will include certain areas of interest within the PaloSanto region and four other prospects that are part of the Mancora gas play. We expect the 3-D and 2-D seismic data survey to be completed by the end of 2010.

For Block XXII, we intend to acquire approximately 260 kilometers of 2-D seismic data on four potential prospects. We expect the 2-D seismic data survey to be completed by the end of 2010.

Corvina Field

We are producing oil from the CX-11 platform, located in the Corvina field within the offshore Block Z-1, under a well testing program that started on November 1, 2007. The Corvina field consists of approximately 47,000 acres in water depths of less than 300 feet. We are currently concentrating our drilling efforts on West Corvina, which consists of 3,500 acres and have completed a total of seven oil producing wells, the CX11-17D, the CX11-19D, the CX11-15D, the CX11-21XD, the CX11-20XD, the CX11-18XD and the CX11-14D. The oil is delivered by tank vessel to the Petroperu refinery in Talara, located approximately 70 miles south of the platform. Produced oil is kept in production inventory until such time it is delivered to the refinery.

At December 31, 2008 we had four oil wells producing under a well testing program. These wells were the CX11-14D, the CX11-18XD, the CX11-21XD, and the CX11-20XD.

In November 2008, we commenced drilling on the CX11-15D well and reached total drilling depth in January 2009. However, during the testing it was confirmed that the deeper prospective sands were found lower than expected and were located below the estimated oil-water contact, thus testing formation water. Subsequently, we commenced sidetracking the CX11-15D well, targeting a location higher in the geological formation and reached total drilling depth of 9,390 feet in March 2009. We began testing the sands that previously tested water and found them to be oil-bearing. We added the CX11-15D well to the wells currently producing under our long-term well testing program in June 2009. The CX11-15D well was completed with a single production string in three of the oil sands that were successfully tested, leaving two accessible oil sands to be added at a later date and leaving the two uppermost oil sands isolated from the producing sands. Additionally, the CX11-15D well has six gas sands. The gas sands remain behind pipe until they are needed for the gas-to-power project. During the testing of the CX11-15D well, gas channeling was discovered. During the time needed to conduct additional testing and identify possible solutions, we moved the rig to the CX11-20XD well to perform a workover to correct gas channeling problems there, which were similar to the CX11-15D well.

In June 2009, we completed the workover of the CX11-20XD well and successfully upgraded both production flow lines from the CX-11 platform in Corvina to the FPSO. The new lines enhanced capacity to handle the combined production of oil, gas and water from the CX-11 platform in a safe and efficient manner.

In July 2009, we finished the completion of the first workover of the CX11-15D well and began the workover of the CX11-21XD well in order to reduce the amount of water being produced along with the oil. For the workover of the CX11-21XD well, we attempted to close off the area beneath the oil producing sands which we believed was the cause of the water content. In October, the workover of the CX11-21XD well was completed and the well had been placed back on production. In September 2009, we completed a second minor workover of the CX11-15D to correct certain mechanical difficulties that were not completely addressed during the first workover.

In October 2009, we commenced drilling on the CX11-19D well. The CX11-19D well is adjacent to the CX11-21XD well, our first oil discovery well completed in 2007. The CX11-19D is being drilled in a higher geological location that should also allow us to continue appraising the Corvina field. We plan to implement a well design on the CX11-19D to help alleviate previous gas channeling issues encountered on the CX11-15D and CX11-20XD wells.

In December 2009, we completed the CX11-19D well in the Corvina field in offshore Block Z-1 in northwest Peru. The CX11-19D well is the sixth oil well from the CX-11 platform and has been placed into the production well testing program.

The CX11-19D well was drilled and successfully completed into a proved undeveloped area of the Corvina field, targeting not only sands currently produced in other wells but also lower untested oil sands that turned out to be productive. The CX11-19D well is presently producing from these sands. During the drilling of this well, the Zorritos formation was encountered higher than previously mapped. The electric logs show approximately 148 feet of net oil pay plus an additional 34 feet of net gas pay. We selectively perforated approximately 100 feet of the total 148 feet of estimated net oil pay to test

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the lower sands that had not previously been included in the Corvina testing program. The initial performance of the well will be evaluated over a period of time before a decision is made whether to perforate any of the remaining net pay found in the upper oil zones.

The CX11-19D well was carefully evaluated prior to placing it into the ongoing production testing phase. Although each of the previous 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 all have initially shown typical solution gas drive behavior which can lead to significant declines during the first year of production before leveling off to sustainable rates. However, the representative rates of decline remain to be determined, as the effective production mechanism in the Corvina field has yet to be fully understood. Hence the need to continue testing these initial wells.

The CX11-19D well will be tested and produced under the new well testing regulation giving companies six months to evaluate a well before applying for the extended well testing program. We plan to have the needed gas and water reinjection facilities at the CX-11 platform as soon as possible. The initial estimated date of May 31, 2010, proposed by us and viewed as reasonable by Perupetro, no longer appears to be reachable due to the delayed delivery of certain equipment. We are currently assessing a revised date to have all equipment in place, as well as all other requirements complied with, at which time the CX11-19D would be placed into commercial production. Any delays in delivering or commissioning reinjection equipment or delays in other permitting aspects may force us to shut-in the CX11-19D well, and our other Corvina wells, until we are ready to transition from exploration to exploitation, unless we obtain an approval for extended well testing for each well as required by the regulations.

During the fourth quarter of 2009, after a sufficient evaluation period, we determined the workovers performed on the CX11-15D, CX11-20XD and the CX11-21XD did not achieve the desired results. Therefore, we will reduce the oil production from these wells in order to manage the water and gas produced along with the oil until we complete our water and gas injection facilities. Additionally, oil production from the CX11-14D well has been suspended since November 7, 2009 due to water issues in production that began in May 2009 that caused sand production and lifting issues.

The Corvina wells have seen initial declines of approximately 50% during the first year of production before stabilizing. We do not believe these results are indicative of the Corvina field generally, but are instead the result of technical/mechanical problems encountered with our initial wells; however, it is possible we will see similar production declines with new Corvina wells. Further, our ability to produce indicated reserves in Corvina depends on our ability to finance our continued operations, install the necessary water and gas reinjection equipment and get our produced oil to market. While we do not foresee difficulties in meeting these requirements, any failure to do so could negatively affect our indicated reserves as reported under SEC rules. As such, in the evaluation of its reserves, we attempt to account for all possible delays we are aware of and their impact on the production forecast and remaining reserves to be produced. When dealing with an issue with a future outcome that is uncertain, we attempt to take the most conservative scenario. As an example, we are assuming certain shut-in periods for wells that may not occur in reality.

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 a mapped structure closure of the target Zorritos formation of approximately 7,500 acres and is located in water depths of less than 200 feet.

In September 2009, we commenced drilling on the A-14XD well, our first new well in the Albacora field, from our recently renovated A platform. The A platform also has three shut-in oil wells that were drilled and produced for a short period of time by Belco Oil & Gas around 1980. At the time, each well showed different productive capacity and decline rates. The A-14XD well was drilled, cased, tested, completed, and put on production testing before year end. The top of the Upper Zorritos formation was found at approximately 9,300 feet measured depth, while the bottom of the Lower Zorritos formation was found at approximately 14,450 feet measured depth, resulting in approximately a 5,150 foot section of Upper and Lower Zorritos formation. The logs indicate the presence of multiple prospective sands throughout the entire section, as was also observed in the 8X2 discovery well drilled by Tenneco in 1972. The A-14XD and 8X2 wells are close together by field standards and can be considered twin wells.

We estimate from the mud log and electric logs that the A-14XD well has approximately 100 feet of net gas pay and approximately 150 feet of net oil pay, plus similar amounts of prospective pay that still require further evaluation. We selectively perforated one interval which accounts for approximately 80 feet of the total 150 feet of estimated net oil pay. The well was then completed and its initial performance will be evaluated over a period of time before a decision is made whether to perforate any of the additional net pay found in the upper oil zones.

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The well has initially maintained a stabilized IPR from an oil zone lower than any of the oil zones tested in the discovery well drilled by Tenneco in 1972. The well has continued to produce consistently, according to the various choke sizes being used, with no apparent increase in its gas-oil-ratio and with no formation water reported to date. Additionally, the mud log and the electric logs show in a preliminary evaluation that the A-14XD well contains gas sands that are likely to be rich in condensates, as demonstrated in the twin well 8X2 drilled by Tenneco in 1972. The only previous production history in Albacora is from the shut-in Belco wells drilled in the 1970’s that were produced for a very limited time, with each showing different productive capacity and decline rates. The ongoing testing program aims at determining the field’s drive mechanisms, as well as a representative decline rate for this and future wells. With the drilling of the A-14XD well we have complied with our previous exploration commitment under the Block Z-1 license contract and have now entered into the fourth exploration period. The fourth exploration period requires us to drill an exploratory well or acquire a certain amount of seismic data. We are installing the required production processing facilities for well testing at the platform and, as a result, stopped oil production from the A-14XD well, for approximately three weeks, during the offloading of the production equipment onto the platform. The installation and commissioning of these facilities are estimated to take approximately eight weeks. The A-14XD well has been re-opened using temporary well testing equipment, while the work on the permanent well testing equipment continues. We have re-opened the A-14XD with the availability of a large FSO vessel. We are currently negotiating an initial short-term oil sales contract with the Talara refinery, which is expected to be finalized by the end of the first quarter. Additionally, we are also evaluating the feasibility of having other buyers for our Albacora oil.

Consistently with our methodology for Corvina, we have requested our independent petroleum engineers, NSAI, to evaluate the reserves of the Albacora oil field using conservative estimates of known uncertainties. Similarly, when facing uncertain outcomes for future equipment projects or permitting issues, we have taken the most conservative route and simulated the shut-in of certain production over a period of time reasonably expected to occur while the issues under consideration are being resolved.

Gas-to-Power Project

The Corvina gas-to-power project entails the installation of a 10-mile gas pipeline from the CX-11 platform to shore, construction of gas processing facilities and 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, after the Peruvian government completes their expansion, are expected to be capable of handling up to 320 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 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 $135.0 million, excluding 19% value-added tax which will be recovered via early recovery and/or future revenue billings. The $135.0 million includes $115.0 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. After a private tender process, we commenced discussions with potential joint venture partners for the gas-to-power project in June 2009. The joint venture will be subject to the satisfactory negotiation of a joint venture agreement and related documents. To date, we have not entered into any definitive agreements and are not currently in ongoing negotiations with a potential partner. In the event we are able to reach agreement with a potential joint venture partner, we may only retain a minority position in the project. However, we expect to retain the responsibility for the construction of the pipeline as well as retain ownership of the pipeline. If we are unable to reach agreement with a potential partner, we are planning to continue moving the project forward to completion. Decisions regarding project financing will be determined as we move the project forward to completion.

Pending SEC Comments

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reported for 2008 in light of our actual production performance in 2009; (iii) the reasons our 2009 production fell short of 2008 projections; (iv) the consideration we gave to the reasonable certainty of our assumptions underlying our SEC oil reserves and the related accounting reported in our financial statements; and (v) how we are taking into consideration certain items and uncertainties for our 2009 reserves report. We have promptly responded to the SEC’s requests and are currently waiting on requests for additional information, if any. In addition, where appropriate, we have proposed clarifications to our disclosures, none of which we believe are material in light of all of the disclosures and risk factors provided in our public filings to date. The SEC is currently reviewing our responses, and could ask additional questions or request additional revisions to our filings, some of which could be material. In particular, the process of estimating oil and natural gas reserves is complex, requiring interpretations of available technical data and many assumptions, including assumptions relating to economic factors, and therefore are inherently imprecise. In its review of our responses and reserve data provided to them, the SEC could disagree with our independent petroleum engineer’s reserve estimates, including the underlying interpretations and assumptions or the reasonable certainty of our assumptions, and request a revision to our estimates of proved reserves and the related accounting of the reserves in our financial statements. In addition, results of actual future production will depend on expected production levels that might not be achieved, oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds, which will most likely vary from our estimates, and those variances may be material.

Restatement of Merger Earn-Out Shares

On September 10, 2004, BPZ Energy, Inc., a Texas corporation (“BPZ-Texas”), consummated a reverse merger with Navidec, Inc. (“Navidec”) whereby BPZ-Texas became a wholly owned subsidiary of Navidec (the “Merger”). As a result of the Merger, the shareholders of BPZ-Texas received the majority of the voting interest control of the Board of Directors and management of the combined entity and on February 4, 2005, Navidec changed its name to BPZ Energy, Inc. (now known as BPZ Resources, Inc.). For accounting purposes, BPZ-Texas was treated as the acquiring entity. The Merger Agreement provided for the immediate issuance by Navidec of 9,000,000 shares of its common stock to the shareholders of BPZ-Texas and the future issuance of additional merger consideration of 18,000,000 shares on an earn-out basis if the Company achieved certain reserve and production goals. The first 9,000,000 earn-out shares were contingent on achieving certain reserve targets, which were achieved in December 2004. However, the contingent earn-out shares could only be issued after the shareholders approved an increase in the number of authorized common shares of the Company. The shareholders approved an increase in the number of authorized shares from 20,000,000 to 250,000,000 at its 2005 Annual Meeting held on July 1, 2005 and the 9,000,000 shares were issued at that time. The closing price of BPZ common stock was $4.40 per share on that day. The remaining 9,000,000 earn-out shares were contingent on the Company becoming entitled to receive as its proportionate share from gross production from any oil and gas wells owned or operated by the Company not less than 2,000 barrels of oil per day or its equivalent (approximately 12 million cubic feet of gas per day) prior to December 28, 2007. On November 2, 2007 this production target was achieved, based on certification by an independent engineering firm that the Company’s production in Peru had met or exceeded the required level of production and the shares were issued. On November 2, 2007, the closing price of the Company’s common shares was $10.87 per share.

At the time of each earn-out, for accounting purposes, each earn-out was treated as a stock dividend because the earn-out was payable to the shareholders of the accounting acquirer, BPZ-Texas. Accordingly, we disclosed a retroactive increase in the number of common shares outstanding for all periods presented and no accounting entry was recorded upon the issuance of the earn-out shares. However, upon further analysis, we have determined that the presentation of the impact of the earn-outs should be changed to provide greater clarity concerning the associated re-allocation of value between the former BPZ-Texas shareholders and the other shareholders of the Company. Therefore, we have done the following:

(i) We recorded a distribution from our retained deficit to reflect the relative economic impact of the reallocation of shares and associated shareholder value at the fair value at the date of grant for each merger earn-out tranche. The effect of this transaction increased our cumulative retained deficit and common stock by $137.4 million.

(ii) We adjusted our presentation to show the merger earn-out shares when issued for each period presented without retroactively increasing the prior periods common shares outstanding. The effect of this transaction decreased the weighted average outstanding share count for the years ended December 31, 2005, 2006 and 2007 by 13.5 million shares, 9.0 million shares and 7.5 million shares, respectively.

The impact of this treatment was to increase the loss per share for all periods presented. We have adjusted our presentation in our five year tables in Item 6. — “Selected Financial Data” as well as our Consolidated Financial Statements to reflect this adjustment in presentation. For further information regarding the restated amounts and the impact on prior periods, see Note 11 — “Restatement of Merger Earn-Out Shares.”

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Financing Activities

$170.9 Million Convertible Notes due 2015

Subsequent to December 31, 2009, we closed on the private offering of $170.9 million convertible notes due 2015 (the “2015 Convertible Notes”). The 2015 Convertible Notes are comprised of the initial $140.0 million of 2015 Convertible Notes sold in the initial private offering, the exercise of a 30-day option to purchase an additional $21.0 million of 2015 Convertible Notes, and IFC’s election to participate in the offering for an additional $9.9 million of 2015 Convertible Notes, bringing the total proceeds of the private offering to $170.9 million. The convertible notes were sold to an initial purchaser who then sold the notes to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. The $170.9 million of convertible notes were issued pursuant to an indenture dated as of February 8, 2010, between us and Wells Fargo Bank, National Association, as trustee (“the Indenture”).

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 subordinated 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.

We will pay interest on 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. The initial conversion rate is 148.3856 shares per $1,000 principal amount of the 2015 Convertible Notes (equal to an initial conversion price of approximately $6.74 per share of common stock), subject to adjustment. Upon conversion, we must deliver, at our option, either (1) a number of shares of our common stock determined as set forth in the Indenture, (2) cash, or (3) a combination of cash and shares of our common stock (but not to exceed 19.99% of our outstanding shares at the time of such delivery).

The initial conversion rate may be adjusted on February 3, 2011 if the volume weighted average price of our common stock for each of the 30 trading days ending on February 3, 2011 is less than $5.6160 per share. In addition, following the occurrence of any one of certain corporate transactions that constitutes a fundamental change (as defined in the Indenture), we will increase the conversion rate, subject to certain limitations, for a holder who elects to convert the 2015 Convertible Notes in connection with such corporate transactions during the 30-day period after the effective date of such fundamental change.

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 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 specified corporate transactions. Holders may also convert the 2015 Convertible Notes at their option at any time beginning on February 1, 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 five 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 the 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

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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 contains customary terms and covenants and events of default. If an event of default (as defined therein) occurs and is continuing, the Trustee by notice to us, or the holders of at least 25% in aggregate principal amount of the 2015 Convertible Notes then outstanding by notice to us and the Trustee, may declare the principal of and accrued and unpaid interest (including additional interest or premium, if any) on the 2015 Convertible Notes 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 of and accrued and unpaid interest (including additional interest or premium, if any), on the notes will automatically become due and payable.

Net proceeds from the sale of the 2015 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by us, was approximately $165.4 million. The initial purchaser received commissions of approximately $5.5 million in connection with the sale of the Notes. We intend to use the net proceeds for general corporate purposes, including without limitation, capital expenditures and working capital, reduction or refinancing of debt, or other corporate obligations.

As a result of our adoption of the new accounting standard for convertible debt that may be settled in cash upon conversion, we are required to separately account for the liability and equity components in a manner that reflects our nonconvertible borrowing rate when interest cost is recognized in subsequent periods. 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 accounting standard requires retrospective restatement of all periods presented back to the date of debt issuance with a cumulative effect of the change in accounting principle on all prior periods being recognized as of the beginning of the first period.

We estimated our nonconvertible borrowing rate at the date of issuance of our 2015 Convertible Notes to be 12%. The 12% nonconvertible borrowing rate represents 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% nonconvertible borrowing rate, we estimate 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 will be amortized as non-cash interest expense into income over the life of the notes using the interest method. In addition, we plan to record approximately $4.4 million of the $5.5 million of fees and commissions as debt issue costs that will be amortized over time using the interest method as interest expense. The remaining $1.1 million of fees and commissions will be treated as an original issue discount against the value of the equity component. We estimate the cash payments related to the 2015 Convertible Notes, assuming no conversion, for the years ended 2010, 2011, 2012, 2013, 2014 and thereafter to be approximately $6.4 million, $11.1 million, $11.1 million, $11.1 million, $11.1 million and $176.5 million, respectively

September 2009 Private Placement of Common Stock

On September 15, 2009, we closed a private placement of approximately 1.6 million shares of common stock, no par value, to IFC pursuant to a Subscription Agreement dated September 15, 2009. This private placement was related to our registered direct offering of approximately 18.8 million shares of Common Stock at a price of $4.66 per share that closed on June 30, 2009. Pursuant to the Subscription Agreement dated December 16, 2006 (the “Subscription Agreement”) by and between IFC and us, IFC has the right, within 45 days of notice of the offering, to purchase shares of the our Common Stock for the same price and terms as the participants in an offering to retain its proportionate ownership in us. IFC exercised its pre-emptive right to purchase approximately 1.6 million shares of Common Stock at the offering price of $4.66 per share to which it was entitled under the Subscription Agreement, resulting in gross proceeds to us of approximately $7.6 million. The transaction was submitted to and approved by the shareholders of BPZ at a Special Meeting of Shareholders on August 24, 2009. No warrants or dilutive securities were issued to IFC in connection with the private placement. The shares were placed directly by us. We used the proceeds of this offering to develop our properties under our existing license contracts and other general corporate purposes consistent with our operating plans.

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Under the September 15, 2009 Subscription Agreement, we committed to file a registration statement with the SEC covering the shares no later than 45 days after the closing with respect to such shares, and will use our reasonable best efforts to obtain its effectiveness no later than the earlier of (i) 90 days after the closing with respect to such shares, or in the event of SEC review of the registration statement, 120 days after the closing and (ii) the third business day following the date on which BPZ is notified (orally or in writing, whichever is earlier) by the SEC that the registration statement will not be reviewed or is no longer subject to further review and comment unless, upon the advice of legal counsel, it is advisable not to accelerate the effectiveness of such registration statement. On October 21, 2009, we filed a registration statement with the SEC covering the shares. Subsequently, we received comments from the SEC pertaining to our registration statement, Form 10-K for the year ended December 31, 2008, Definitive Proxy Statement filed on April 30, 2009, Form 10-Q for the period ended September 30, 2009 and the related earnings press release. We promptly responded to the SEC’s requests and are currently waiting on requests for additional information, if any. In addition, where appropriate, we have proposed clarifications to our disclosures. Once we are notified by the SEC our responses are no longer subject to further review, we will use our reasonable best efforts to obtain the registration statement’s effectiveness. There are no penalty payments associated with the delay in obtaining effectiveness of the registration statement.

June 2009 Registered Direct Offering of Common Stock

On June 30, 2009, we closed the sale of approximately 18.8 million shares of our common stock, no par value, in a registered direct offering under an effective shelf registration statement. The shares of common stock were priced at $4.66 per share resulting in net proceeds to us, after placement agent fees and other fees, of approximately $82.9 million. In connection with the registered direct offering, we entered into a placement agency agreement with Canaccord Adams Inc. as lead placement agent for the offering along with Pritchard Capital Partners, LLC, and Raymond James and Associates, Inc. In addition, Rodman & Renshaw, LLC, and Wunderlich Securities, Inc. assisted as agents in the transaction. We paid approximately $4.4 million as a 5% placement agency fee of the gross proceeds received by us in accordance with the terms of the placement agency agreement. We used the proceeds of this offering to develop our properties under our existing license contracts and other general corporate purposes consistent with our operating plans.

February 2009 Private Placement of Common Stock

On February 23, 2009, we closed a private placement of approximately 14.3 million shares of common stock, no par value, to institutional and accredited investors pursuant to a Stock Purchase Agreement dated February 19, 2009. Additionally, in March 2009, IFC exercised its pre-emptive right to elect to participate in the private placement offering resulting in an additional 1.4 million shares of common stock which brought the total to approximately 15.7 million shares of common stock sold in the private placement offering. The common stock was priced at $3.05 per share resulting in net proceeds to us, after placement agent and financial advisory fees, of approximately $45.2 million. No warrants or dilutive securities were issued in connection with the private placement. A financial advisory fee of $0.7 million was paid to Morgan Keegan and Company, Inc. for investment services and consulting related to the offering. Additionally, a private placement fee of $2.2 million was paid to Pritchard Capital Partners, LLC, for placement services related to the offering. We used the proceeds of this offering to develop our properties under our existing license contracts and other general corporate purposes consistent with our operating plans.

Under the Stock Purchase Agreement, we committed to file a registration statement with the SEC and obtain the registration statement’s effectiveness within the time-frames outlined in the Stock Purchase Agreement. On April 27, 2009, we obtained effectiveness of the registration statement related to the Stock Purchase Agreement in compliance with such time-frames.

GE 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 $51.5 million contract (the “Agreement”) for the purchase of three LM6000 gas-fired turbines 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 will 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. We were still in negotiations with GE to modify the terms of the Agreement at the time the second progress payment was due on November 16, 2009, and GE agreed to a short extension of the deadline for the milestone payment in order to conclude ongoing negotiations with

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respect to new delivery dates, pricing, payment terms and payment security for the reinstatement of the Agreement. Amended terms were agreed with GE by Letter Agreement on November 20, 2009 (the “Letter Agreement”), at which time we made the $3.5 million progress payment. Under the terms of the Letter Agreement, GE and BPZ agreed to a variable monthly payment plan with a final $20.7 million payment due December 1, 2010 for the remaining $35.2 million due under the Agreement. Additionally, should we locate a joint venture partner and obtain financing for the three LM6000 gas-fired turbines and services prior to the December 1, 2010 deadline, we agreed to pay the final payment under the Letter Agreement within 7 days of obtaining the financing and funding.

Should we not make the payments in accordance with the terms of the Letter Agreement, this would result in immediate termination of the Agreement without any additional notice or cure period. As of December 31, 2009, we have made payments to GE totaling $16.5 million. Additionally, in March 2010, we made a $2.5 million payment and plan to meet the remaining payments due throughout 2010 by using proceeds from the recently completed convertible debt offering or subsequent project financing. Failure to make any of the remaining progress payments in full would result in a charge-off of all of the previously made progress payments.

Reserve-Based Credit Facility

In July 2009, we, through our subsidiary, BPZ E&P, had secured formal commitments for a $70.0 million reserve based credit facility, including $15.0 million previously received under the IFC Facility. The syndication of this facility was led by Natixis, a major French bank. The other institutions participating in the syndicate include IFC, Scotiabank and Banco de Crédito del Perú.

Subsequent to December 31, 2010, we, through our subsidiary, BPZ E&P, elected to terminate negotiations on the previously announced $55.0 million portion of the reserve based credit facility being arranged by Natixis. With the proceeds from the 2015 Convertible Notes offering, the termination of these negotiations is not expected to impact our ability to undertake our 2010 capital expenditures program, including drilling and continued development of the Corvina and Albacora fields as well as payments due under the GE turbine purchase agreement.

May 2008 $15.5 Million Debt Conversion to Equity

In May 2008, we elected to exercise our option to convert $15.5 million of existing convertible debt with the IFC into approximately 1.5 million shares of common stock. The terms of the Convertible Debt Agreement, dated November 19, 2007, stipulated a conversion price of $10.39 per share and included a forced conversion feature, exercisable at our option, if the closing price of the our common stock exceeds a price of $18.19 per share based on the average closing price over a period of twenty consecutive business days.

March 2008 Equity Offering

On March 25, 2008, we completed a public offering of 2.0 million shares of common stock. The offering was priced to the public at $20.00 per share and underwritten by Canaccord Adams, Inc. (“Canaccord”) on a firm commitment basis. We received proceeds after underwriting fees and discounts of approximately $37.5 million. In addition, we granted Canaccord a 30-day option to purchase up to 200,000 additional shares to cover any over-allotments. On April 18, 2008, the over-allotment option was executed and Canaccord bought an additional 200,000 shares resulting in proceeds to us after underwriting fees and discounts of approximately $3.6 million. A financial advisory fee of $150,000 was paid to Morgan Keegan for investment services and consulting related to the offering.

Contingent Incentive Earn-Out Shares

During 2005, the Company’s Board of Directors awarded a total of 485,000 shares of incentive stock awards to three of our officers. The incentive stock awards vest and the earn-out shares are issuable once BPZ is entitled to receive as its proportionate share from gross production from any oil and gas wells owned or operated by us not less than 2,000 barrels of oil per day or its equivalent (approximately 12 million cubic feet of gas per day) prior to December 28, 2007, the same target applicable to the Merger earn-out shares. However, one of our officers entitled to receive earn-out shares resigned from BPZ and its subsidiaries effective June 15, 2006, and as a result 225,000 of the unvested contingent incentive stock awards, representing $990,000 of future possible compensation expense, were forfeited. Subsequently, 190,000 shares of those 225,000 shares were awarded to the officer’s successor to supplement a previous award of 35,000 shares. The second earn-out target provided for in the original merger agreement related to its merger with Navidec, Inc. In November 2007, the production target in the Merger Agreement dated July 8, 2004 was achieved. The determination was made by our Board of Directors based on certification by the independent engineering firm that BPZ’s production in Peru met or exceeded the required level of production.

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The achievement of the required level of production resulted in the issuance of 450,000 shares. For accounting purposes, during the year ended December 31, 2007, $1,980,000 was recorded as compensation expense.

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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 future license contracts. The world economies are slowly recovering from a recession which began in 2008 and extended into 2009. Growth has resumed, but is modest. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. 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.

In response to the current environment, we have decided to focus on oil development in Block Z-1, specifically the Corvina and Albacora fields, for 2010, and reduce operating and general and administrative expenses in an effort to enhance shareholder value by optimizing profits.

From a production perspective, our goal is to continue to increase production during 2010, assuming we encounter minimal technical difficulties and successfully complete the gas and water injection facilities. In order to attain that goal we plan to commit a majority of our 2010 capital budget of approximately $200 million on further development of the Corvina field and the continued appraisal and development of oil in the Albacora field. Our drilling plans include drilling two additional oil development wells from the CX-11 platform in the Corvina field and drilling four new wells in the Albacora field from the Albacora platform using a recently contracted drilling rig.

Expected operational cash flow from Corvina and Albacora oil sales as well as the additional proceeds from the recent covertible debt offering should cover the capital expenditures necessary to complete our 2010 capital program. In addition, we are working to obtain the necessary financing for the gas-to-power project and 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 2010 performance, we relied on assumptions about the market for oil, our customers and suppliers, past results and operational and regulatory delays. We expect the average spot price for oil in 2010 to be approximately $71.00 or 30% more than the average price we received in 2009. With our planned oil production increases, we expect earnings for 2010 to exceed that of 2009. Our results could materially differ from what we anticipate if any of our assumptions, such as major technical or mechanical well issues, commodity pricing, production levels or our ability to raise additional capital, 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, 2009 Compared to Year Ended December 31, 2008

	Year Ended December 31,						Increase/
	2009			2008			(Decrease)
	(in thousands except per bbl information)
Net sales volume:
Oil and condensate (MBbls)	963			826			137

Net revenue:
Oil and condensate	$	52,454		$	62,955		$	(10,501	)

Average sales price (approximately):
Oil (per Bbl)	$	54.49		$	76.23		$	(21.74	)

Operating expenses
Lease operating expense	$	28,113		$	11,649		$	16,464
General and administrative expense	33,258			42,094			(8,836		)
Geological, geophysical and engineering expense	7,768			794			6,974
Depreciation, depletion and amortization expense	25,803			16,062			9,741
Total operating expenses	$	94,942		$	70,599		$	24,343

Operating loss	$	(42,488	)	$	(7,644	)	$	(34,844	)

Net Revenue

For both years ended December 31, 2009 and 2008, all oil sales were from oil produced from the CX-11 platform, located in the Corvina field within Block Z-1 in northwest Peru, under a well testing program.

For the year ended December 31, 2009, our net revenue decreased by $10.5 million to $52.5 million from $63.0 million for the same period in 2008. The decrease in net revenue is due to a decrease of $21.74, or 29% in the average per barrel sales price received which was partially offset by an increase in oil sales of 137 MBbls. Oil prices reached record levels during the third quarter of 2008 before sharply falling towards the end of the year. During 2009, oil prices rose steadily from the lows seen at the beginning of the year but the average price received for oil in 2009 was considerably less than the average oil price received during 2008.

During the year ended December 31, 2009 oil production from the CX11-21XD, CX11-20XD and the CX11-15D wells were at various times and intervals partially or fully suspended due to workovers and maintenance of the wells in order to perform routine maintenance activities and to attempt to resolve certain gas channeling and water production issues encountered in the operation of the wells. Additionally, oil production from the CX11-14D well was suspended since November 7, 2009 due to water issues in production that began in May 2009 that caused sand production and lifting issues. With respect to the CX11-14D, we have no plans in our 2010 budget to further workover this well.

The CX11-15D workover caused oil production from the well to be stopped intermittently for approximately one month during 2009 while we attempted to resolve certain gas channeling issues believed to be originating from the overlying gas sands. The workover was completed in September 2009; however, the workover did not achieve the desired results. Therefore, we had to temporarily shut-in the sands under consideration and complete the well solely in the bottom set of sands that was immune to this gas channeling problem. The CX11-15D well is currently producing only from these sands, at a reduced rate. Currently, we have no plans in our 2010 budget to further workover this well.

The CX11-20XD workover caused oil production from the well to be stopped intermittently for approximately two months during 2009 as the well developed a sustained high gas-oil-ratio in April 2009. Although the high gas production was partially resolved with the workover of the well, the production from this well has been restrained to maintain its gas production at a manageable level. Currently, we have no plans in our 2010 budget to further workover this well.

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The CX11-21XD workover caused oil production from the well to be stopped intermittently for approximately two and a half months during 2009 as the well began producing a significant amount of associated water during production. The workover was completed in October 2009; however the workover did not achieve the desired results. Therefore we reduced oil production from this well in order to manage the water produced along with the oil, in particular when running into fluid storage capacity limitations. Currently we have no plans in our 2010 budget to further workover this well.

At December 31, 2009, we had six producing wells, the A-14D, CX11-19D, CX11-15D, CX11-20XD, CX11-18XD and CX11-21XD , compared to four producing wells, the CX11-21XD, CX11-14D, CX11-20XD and the CX11-18XD, at the same period in 2008. However the A-14D oil production was stopped after placing it on production toward the end of 2009 in order to complete the installation of oil production equipment and to obtain an oil sales agreement, and as requested by the OSINERGMIN (the governmental entity overseeing hydrocarbon activities in Peru). Following the presentation of appropriate documentation to the OSINERGMIN by the Company, the well testing activities in well A-14XD were resumed. Accordingly, we did not realize any oil sales from the A-14D during 2009.

During 2009, we had oil production for approximately 10 of the 12 months for four of the seven wells. The CX11-15D began its initial production in June 2009. The CX11-19D and A-14D began their initial production in December 2009.

During the same period in 2008, oil production operations were suspended on January 30, 2008 and our oil sales did not resume until June 2008, due to an incident involving a small tanker leased by our marine transportation contractor from the Peruvian Navy. In July 2008 the CX11-18XD was placed on production. Subsequent to June 2008, we had full oil production for three of the four wells while the CX11-20XD well began its initial production toward the end of September 2008.

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 both the year ended December 31, 2009 and 2008, the revenues received by us are net of royalty costs of approximately 5% of gross revenues or $2.9 million and $3.3 million, respectively.

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, operator fees, processing fees, insurance and transportation. For the year ended December 31, 2009, lease operating expenses increased by $16.5 million to $28.1 million ($29.21 per Bbl) from $11.6 million ($14.11 per Bbl) for the same period in 2008. The increase in expense is due to the additional workover and maintenance expenses incurred in 2009 and additional production costs associated with increased production facilities. During the year ended December 31, 2009, we incurred $9.8 million of workover expenses related to the CX11-20XD, CX11-21XD and CX11-15D wells and $1.2 million of additional expense incurred for the replacement of underwater hoses and flow lines, respectively. The remaining increase in the per Bbl amount of lease operating expenses is comprised of increased oil transportation costs, processing fees, and insurance costs as a result of the increased production compared to the same period in 2008.

General and Administrative

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, 2009, general and administrative expenses decreased $8.8 million to $33.3 million from $42.1 million for the same period in 2008. Stock-based compensation expense, a subset of general and administrative expenses, decreased by $5.8 million to $12.6 million for the year ended December 31, 2009 from $18.5 million for the same period in 2008. The decrease in stock-based compensation expense is due to the decrease in fair market value of awards granted in 2009 as a result of the decline in the stock price of BPZ. Additionally the 2009 stock-based compensation expense includes approximately $0.7 million of stock-based compensation expense related to the accelerated vesting for certain restricted stock and stock option awards granted to a former member of the Board of Directors but excludes $0.4 million of compensation expense that is included in “Other income (expense)” on the Consolidated Statements of Operations. The $0.4 million relates to 100,000 stock options awarded to a former member of the Board of Directors. The grant date fair value of the award was recognized upon issuance of the award. Other general and administrative expenses decreased $3.0 million to $20.6 million from $23.6 million for the same period in 2008. The $3.0 million decrease is due to $2.3 million decrease of salary and salary related expenses, $1.2 million

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of decreased consulting and contract labor expense, $0.4 million of decreased legal expenses and $0.4 million decreased travel and travel related expenses partially offset by $0.4 million of increased bank fees and $0.8 million increased rent expenses. The reduction in salary and salary related expense is due to the voluntary salary reduction initiatives and timing of executive bonuses and employee salary increases. During the first half of 2009, certain executive and other key personnel agreed to a voluntary salary reduction of 5% to 15% of their base salaries and the Chairman of the Board of Directors agreed forgo his salary for 2009. Additionally, BPZ did not pay bonuses in 2009. In July 2009, employees who participated in the voluntary salary reduction, other than the Chairman of the Board of Directors, received a salary reinstatement. During 2008, executives and other key employees received bonuses and employees received salary increases that were retroactive to the beginning of the year. The reduction in contract labor, consulting and legal fees is due to the Shell joint venture negotiations and tax reorganization expenses for which we incurred significant fees in 2008 that were not repeated in 2009. The reduced travel and travel related an expense is due to less travel incurred by our personnel in 2009 compared to 2008. The increase in bank fees is due to higher fees charged by financial institutions in 2009 compared to 2008. The higher rent expense is due to increased office space rented by both our Houston and Peru offices in 2009 compared to 2008.

Geological, Geophysical and Engineering

Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses. For the year ended December 31, 2009, geological, geophysical and engineering expenses increased $7.0 million to $7.8 million compared to $0.8 million for the same period in 2008. During the fourth quarter of 2009, we incurred approximately $6.3 million for seismic acquisition expenses. At the end of the third quarter of 2009, we entered into a contract to acquire approximately 950 square kilometers of 3-D seismic data for Block Z-1 to assist us in exploring, appraising and developing certain areas of interest and to better define the position of future wells as well as to comply with our exploration commitments under our license contracts. As Block Z-1 is located offshore, the seismic activity was to be conducted by marine seismic vessels from a third party seismic contractor. Shortly after starting the seismic operations, and following protests from fisherman in the area where our third party contractor was performing seismic tests, we received a statement from the Peruvian Ministry of Energy and Mines to suspend our seismic testing. As a result of the suspension we incurred approximately $4.7 million in standby fees and mobilization and support costs as well as $1.5 million in contract extension costs of which approximately $0.8 million will be credited against the future cost of the seismic acquisition by the contractor. The contract extension guarantees the original seismic acquisition pricing as long as we are able to resume our seismic acquisition within the next two years. We are currently working with the Peruvian Ministry of Energy and Mines to resume conducting the seismic survey. The remaining increase of $0.7 million is due to increased laboratory and consulting costs as a result of more environmental impact studies performed on Blocks XIX, XXII and XXIII in the current year compared to the activities of the prior year.

Depreciation, Depletion and Amortization

For the year ended December 31, 2009, depreciation, depletion and amortization expense increased $9.7 million to $25.8 million from $16.1 million for the same period in 2008. The increase is due to increased production discussed above, increased average costs per well being depleted and a reduction in the reserve base from 2008 as a result of decreased oil prices at the end of 2008.

Other Income/(Expense)

For the year ended December 31, 2009, income from our investment in Ecuador property, net of investment amortization, increased $0.5 million to $1.2 million in 2009 from $0.7 million in 2008. The increase is due to receiving $1.4 million in payments during 2009 from our investment in the Santa Elena Property while receiving $0.9 million for the same periods in 2008. Income/(expense) from our investment in Ecuador is net of investment amortization expense. For both the years ended December 31, 2009 and 2008, investment income / (expense) includes amortization expense of approximately $0.2 million.

For the year ended December 31, 2009, we capitalized $4.4 million of interest expense to construction in progress. For the same period in 2008, we capitalized approximately $4.2 of interest expense to construction in progress.

For the years ended December 31, 2009 and 2008, we received interest income of $0.2 million and $0.3 million, respectively. The decrease in interest income is due to the decreased cash balances in 2009 and lower interest rates.

For the year ended December 31, 2009, other expense increased by $1.4 million to an expense of $1.3 million in 2009 from income of $0.1 million in 2008. The reason for the increase in expense is due to $0.4 million of stock compensation expense related to stock options awarded to a former member of the Board of Directors that was recognized

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upon issuance of the award and approximately $0.8 million of expense related to the settlement of a disputed contractual obligation with a former consultant of ours concerning services provided to both BPZ and its predecessor at the time BPZ became publicly traded. We were notified of this alleged dispute towards the end of the first quarter of 2009. The settlement was paid in April 2009. Additionally, for the year ended December 31, 2009, we recognized $0.1 million of foreign currency losses and for the same period in 2008 we recognized a $0.1 million foreign currency gain.

Income Taxes

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

	2009			2008			2007
United States	$	860		$	(28,122	)	$	(12,922	)
Foreign	(43,237		)	21,617			(7,549		)
Loss from continuing operations before income taxes	$	(42,377	)	$	(6,505	)	$	(20,471	)

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

	2009			2008			2007
Current Taxes
Federal	$	200		$	—		$	39
Foreign	6,709			7,536			—
Total Current Taxes	6,909			7,536			39

Deferred Taxes
Federal		—			—			—
Foreign	(13,484		)	(4,395		)	—
Total Deferred Taxes	(13,484		)	(4,395		)	—
Total Income Tax Provision (Benefit)	$	(6,575	)	$	3,141		$	39

The income tax expense (benefit) for the years ended December 31, 2009, 2008 and 2007 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):

	2009			2008			2007
Federal statutory income tax rate	$	(14,408	)	$	(2,212	)	$	(7,139	)
Increases (decreases) resulting from:	—			—			—
Peruvian income tax - rate difference less than 34% statutory	—			—			—
Non-deductible stock compensation expense	2,908			6,551			3,653
Non-deductible intercompany expenses and other	4,180			—			—
Tax effect of Peru conversion to permanent establishment status	—			7,642			—
Change in domestic valuation allowance	745			(8,840		)	3,525
Total Income Tax Provision (Benefit)	$	(6,575	)	$	3,141		$	39

The tax effects of the temporary differences that give rise to the significant portions of the deferred tax assets and liabilities at December 31, 2009 and 2008 are presented below (in thousands):

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	2009			2008
Deferred Tax:
Asset:
Net Operating Loss	$	16,546		$	19,941
Deferred Compensation	2,514			1,889
Foreign Tax AMT	1,647			—
Asset Basis Difference	—			—
Exploration Expense	7,256			2,080
Depreciation	—			12
Depletion	8,162			3,340
Asset Retirement Obligation	67			27
Overhead Allocaion to Foreign Locations	2,298			—
Other	119			666
Liability:	—			—
Preoperation Expenses	(295		)	(295		)
Depreciation	(18		)
Asset Basis Difference	(1,819		)	(1,298		)
Other	(1		)	(300		)
Net Deferred Tax Asset	$	36,476		$	26,062

Less Domestic Valuation Allowance	(19,548		)	(21,191		)
Deferred Tax Asset	$	16,928		$	4,871

As of December 31, 2009, we had a valuation allowance for the full amount of the domestic deferred tax asset 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 2028. Furthermore, because we have no operations within the U.S. taxing jurisdiction, it is likely that a sufficient generation of revenue to offset our deferred tax asset is remote. As a result, we have a full allowance on our deferred tax asset generated in the U.S. However, we are subject to Peruvian income tax on our earnings at a statutory rate, as defined in the Block Z-1 License Contract, of 22%. Because we are under a well testing program from which we will finalize a development plan for Block Z-1, we have not moved into the commercial phase of production as defined by the license contract. As such, certain deductions are disallowed by the Peruvian tax regime while we operate under the well testing program. In addition, the tax provision is based on taxable Peruvian income that excludes certain U.S. expenses that are not deductible at the Peruvian level. As a result, we recognized a total tax provision for the year ended December 31, 2009 of approximately $6.6 million.

We anticipate moving into commercial production in Block Z-1 under the license contract in 2010, at which time our full investment in our producing properties will be eligible to be amortized over five years. 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 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 benefits of the these deductible differences at December 31, 2009. As a result, we recognized a deferred tax asset of $16.9 million as of December 31, 2009.

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. As of the date of adoption of FIN 48, now codified under ASC Topic 740, “Income Taxes”, we did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the year. Additionally, the adoption had no effect on our financial position or results of operations. 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, 2009 or December 31, 2008.

For the year ended December 31, 2009, our net loss increased $26.2 million to a net loss of $35.8 million or ($0.35) per basic and diluted share from a net loss of $9.6 million or ($0.12) per basic and diluted share for the same period in 2008.

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Year Ended December 31, 2008 Compared to Year Ended December 31, 2007

	Year Ended December 31,						Increase/
	2008			2007			(Decrease)
	(in thousands except per bbl information)
Net sales volume:
Oil and condensate (MBbls)	826			28			798

Net revenue:
Oil and condensate	$	62,955		$	2,350		$	60,605

Average sales price (approximately):
Oil (per Bbl)	$	76.23		$	81.78		$	(5.55	)

Operating expenses
Lease operating expense	$	11,649		$	755		$	10,894
General and administrative expense	42,094			18,548			23,546
Geological, geophysical and engineering expense	794			4,045			(3,251		)
Depreciation, depletion and amortization expense	16,062			793			15,269
Total operating expenses	$	70,599		$	24,141		$	46,458

Operating loss	$	(7,644	)	$	(21,791	)	$	14,147

Net Revenue

Our 2008 net revenue increased by $60.6 million to $63.0 million from $2.4 million in 2007. The increase in net revenue is due to increased oil production of 797 MBbls from the CX-11 platform located in the Corvina field within Block Z-1 in northwest Peru. Oil production and revenues increased proportionately compared to 2007 due to the increase in number of wells producing in 2008 and the increase in production days. Partially offsetting the increase in production is an overall 7.0% decrease in the average per barrel sales price received, $76.23 versus $81.78, in the prior year. In 2007, we began producing oil on a limited basis in November 2007 from the CX11-21XD and CX11-14D wells in the Corvina field under a well testing program.

Although our production increased in 2008 compared to 2007, we were not able to produce fully during the year. During January 2008, we incurred production and transportation delays due to the incident involving one of the Peruvian Navy tankers being leased by our marine transportation contractor and used in our offshore oil production operation as part of our well testing program. As a result of the incident, our production was shut-in for approximately five months while we completed a series of safety and integrity tests on the facilities at the CX-11 Corvina platform and waited to receive the clearance needed to transport oil from the CX-11 platform to the nearby Talara refinery by the corresponding Peruvian environmental agencies.

Upon receiving clearance to resume production and transportation in June 2008, we began production from our existing CX11-21XD and CX11-14D oil wells, as well as bringing online the CX11-18XD oil well while only limiting production during certain periods by the drilling and testing of the CX11-20XD well. Production of the CX11-20XD well began in the early part of the fourth quarter of 2008. Production from all four oil wells was limited during certain periods by the drilling and testing of the CX11-15D oil well. On November 21, 2008, we began drilling operations on the CX11-15D well in the Corvina field. In January 2009, we reached total drilling depth and began testing the formation.

In 2008, we had oil production from four producing wells, the CX11-21XD, the CX11-14D, the CX11-18XD and the CX11-20XD. The CX11-21XD and the CX11-14D wells produced for the full year, except when production was voluntarily suspended, as noted above, and during certain periods by drilling and testing activity. The CX11-18XD well produced oil from June 2008 through December 2008, except when production was suspended during certain periods due to the drilling and testing of the CX11-20XD and CX11-15D wells. The CX11-20XD well produced oil from September 2008 through December 2008, except when production was suspended during certain periods due to the drilling and testing of the

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CX11-15D well. In 2007, we had limited production from two wells, the CX11-21XD and the CX11-14D wells, from November 2007 through December 2007.

The net revenues above are net of royalties owed to the government of Peru. Royalties are calculated by Perupetro as stipulated in the Block Z-1 license agreement based on a blend of crude prices as provided in the Northwest Oil Basket. However, the crude oil price calculation is based on the past two week average price before the crude oil delivery date, as opposed to the royalty calculation being based on the past five-day average price before the crude oil delivery date. For the year ended December 31, 2008 and 2007, the revenues received by BPZ are net of royalty costs of approximately 5% of gross revenues or $3.3 million and $0.1 million, respectively.

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, operator fees, processing fees, insurance and transportation. Lease operating expenses for 2008 increased $10.8 million to $11.6 million ($14.11 per Bbl) from $0.7 million ($26.26 per Bbl) in 2007. The increase was attributable to the production increases noted above. Additionally as we had limited oil production during 2007 we also incurred limited lease operating expense for the same period. Typically, as production increases, our lease operating expense per unit decreases as a result of fixed costs. Our 2008 lease operating expense includes approximately $38,000 related to the cost of the approximately 1,300 barrels of oil that was lost as a result of the tanker incident.

General and Administrative

General and administrative expenses are overhead-related expenses, including employee compensation, legal, consulting and accounting fees, insurance, and investor relations expenses. General and administrative expenses for 2008 increased $23.6 million to $42.1 million compared to $18.5 million in 2007. The increase in general and administrative expenses is due to additional employees in Peru and related increases in compensation expenses of $6.5 million, and increased legal and consulting fees of $2.4 million, and increased other expenses of $3.2 million, which include insurance, travel and travel related expenses, and contract labor, incurred in 2008. In the third quarter of 2008 we internalized our previously outsourced marine operations in order to better manage our long term growth initiatives and tripled the number of our employees in Peru. Additionally we incurred increased personnel and compensation expense in order to administer our growth and to support our increased operations. Further we incurred additional consulting and legal fees as part of our negotiations with Shell to explore jointly developing Blocks Z-1, XIX and XXIII in Northwest Peru into large-scale oil and gas ventures. A subset of compensation expense, stock-based compensation expense increased by $11.5 million to $18.5 million in 2008 from $7.0 million in 2007. The increase results from of additional awards granted in the current year at the time when the price of our Common Stock was relatively high and therefore fair value of the awards and related expense recognized increased as a result. Further, we recognized an additional $0.7 million of stock-based compensation expense, as compared to 2007, as a result of the accelerated vesting for certain stock option awards. The awards granted under our 2007 Long-Term Incentive Plan and 2007 Directors Compensation Incentive Plan allows us to attract and retain key personnel.

Geological, Geophysical and Engineering

Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses. Geological, geophysical and engineering expenses decreased $3.3 million to $0.8 million in 2008 compared to $4.0 million in 2007. The decrease is due to performing seismic acquisition activity in 2007 when we incurred 200 kilometers of 2-D seismic in Block XIX in order to comply with the provisions of the related License Contract.

Depreciation, Depletion and Amortization

Depreciation, Depletion and Amortization (“DD&A”) expense increased $15.3 million during 2008 to $16.1 million from $0.8 million for 2007. The DD&A expense increase was due to increased production discussed above. This amount includes approximately $24,000 related to the cost of the approximately 1,300 barrels of oil that was lost as a result of the tanker incident.

Other Income/(Expense)

Income from our investment in Ecuador property increased $0.4 million to $0.7 million in 2008 from $0.3 million in 2007. The increase is due to increased production and increased oil prices received in 2008. Since our investment consists of an interest in a producing oil and gas property, we are amortizing the investment on a straight-line basis over the remaining

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term of the license agreement covering the property. Accordingly, we recorded annual amortization expense of $0.2 million for both 2008 and 2007.

For the year ended December 31, 2008 and 2007, we capitalized interest expense of $4.2 million and $1.2 million, respectively. The increase in capitalized interest expense is related to our increased debt for the current year, which includes interest on our capital lease obligations, $15.5 million of IFC convertible debt and $15.0 million Senior Debt.

For the year ended December 31, 2008 and 2007, we received interest income of $0.3 million and $0.9 million, respectively. The decrease in interest income is due to the increased cash balances in 2007 due to lower operating expenses.

Other income decreased $0.1 million to $0.1 million in 2008 from $0.2 million in 2007. The decrease in other income is due to a reduction in realized foreign exchange rate gains of approximately $0.1 million in 2008. The exchange rate gain is related to the early recovery of IGV or Value Added Taxes in Peru. IGV under the early recovery program is denominated in the Peruvian Nuevo Sol currency. The decrease in the net foreign currency gain was due to the strengthening of the Nuevo Sol against the U.S. Dollar.

Taxes

We recognized a total tax provision for the year ended December 31, 2008 of approximately $3.1 million compared to $39,000 for the same period in 2007. The difference is due to oil sales from our production in Block Z-1 during the 2008. We are subject to Peruvian income tax on our earnings at a statutory rate, as defined in the Block Z-1 License Contract, of 22%. Because we are under a well testing program, from which we will finalize a development plan for Block Z-1, we have not moved into the commercial phase of production as defined by the license contract. As such, certain deductions are disallowed by the Peruvian tax regime while the Company operates under the well testing program. In addition, the tax provision amount is based on taxable Peruvian income that excludes certain U.S. expenses that are not deductible at the Peruvian level. The tax expense in 2007 is related to the revenues from our 10% non-operated working interest in the Santa Elena Property in southwestern Ecuador and its effect on our US non-consolidated returns. We were unable to offset the operating losses generated from our Peruvian branch with the revenues from our Ecuador branch.

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

	2008			2007
United States	$	(28,122	)	$	(12,922	)
Foreign	21,617			(7,549		)
Loss from continuing operations before income taxes	$	(6,505	)	$	(20,471	)

The income tax expense (benefit) for the year ended December 31, 2008, and 2007 differs from the amount computed by applying the U.S. statutory rate for the applicable year to consolidated net loss before taxes as follows (in thousands):

	2008			2007
Federal statutory income tax rate	$	(2,212	)	$	(7,139	)
Increases (decreases) resulting from:	—			—
Non-deductible stock compensation expense	6,551			3,653
Tax effect of Peru conversion to permanent establishment status	7,642			—
Change in domestic valuation allowance	(8,840		)	3,525
	$	3,141		$	39

Our net loss decreased $10.9 million to $9.6 million or ($0.12) per basic and diluted share in 2008 from a net loss of $20.5 million or ($0.33) per basic and diluted share during the same period in 2007. The decrease in net loss is due to the increase in oil revenues during 2008 compared with limited oil revenues in 2007.

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Liquidity, Capital Resources and Capital Expenditures

At December 31, 2009, we had cash and cash equivalents of $18.1 million and current accounts receivable related to our December oil sales of $2.9 million, all of which was collected in early January 2010. We also had $26.2 million in Value Added Tax receivable, which we will collect over time as we invoice our oil sales.

At December 31, 2009, we had trade accounts payable and accrued liabilities of $46.9 million.

At December 31, 2009 our outstanding long-term debt and short-term debt consisted of a $15.0 million IFC Facility bearing interest at LIBOR plus 2.75% due December 31, 2012, which we expect to refinance with the proceeds of our convertible debt, and $1.0 million short-term loan that was repaid in January 2010. At December 31, 2009 the current and long term portions of our capital lease obligations, primarily related to the barges used in our marine operations were $4.3 million and $7.6 million, respectively.

	For the Year Ended December 31,
Cash Flows	2009			2008			2007
	(in thousands)
Cash provided by (used in):
Operating activities	$	(30,785	)	$	48,722		$	(15,171	)
Investing activities	(90,005		)	(102,185		)	(58,464		)
Financing activities	133,620			51,266			55,825

Operating Activities

Cash used in operating activities increased by $79.5 million to a use of cash of $30.8 million in 2009 from a source of cash of $48.7 million in 2008. Cash flow before changes in operating assets and liabilities decreased by $29.1 million reflecting lower oil production revenues and higher lease operating costs and geological, geophysical, and engineering costs during 2009 compared to 2008, partially offset by lower general and administrative expenses. Changes in operating assets and liabilities provided a use of cash of $50.4 million. In 2009 the change in accounts payable provided a use of cash of $2.6 million and in 2008 provided a source of cash of $23.5 million, the change being a net use of cash of $26.1 million. The reason for the change in accounts payable is due to initiatives in 2009 taken by us to better manage our accounts payable balance. In 2009 the change in income taxes payable provided a use of cash of $6.5 million and in 2008 provided a source of cash of $6.9 million, the change being a net use of cash of $13.4 million. The reason for the change in income taxes payable is primarily due to the income tax cash payments made in 2009. In 2009 the change in value added tax receivable provided a use of cash of $14.0 million and in 2008 provided a use of cash of $4.6 million, the change being a net use of cash of $9.4 million. The reason for the change in the balance is due to lower oil revenues in the current year and increased costs. In 2009 the change in inventory provided a use of cash of $7.6 million and in 2008 provided a use of cash of $0.6 million, the change being a net use of cash of $7.0 million. The reason for the change is due to the increased purchase of casing and accessories for use in the Company’s current and future operations. In 2009 the change in accounts receivable provided a source of cash of $2.4 million and in 2008 provided a use of cash of $2.3 million, the change being an increase of cash of $4.7 million. The reason for the change is due to the timing and amount of our account receivable balances. The balance at the end of 2009 was lower than the balance at the end of 2008 by $2.4 million. The balance at the end of 2008 was higher than the balance at the end of 2007 by $2.3 million.

Cash provided by (used in) operating activities increased by $63.9 million to a source of cash of $48.7 million in 2008 from a use of cash of $15.2 million in 2007, respectively. Cash flow from operations increased due to higher oil production revenues during 2008 compared to 2007, partially offset by higher operating and overhead costs. Cash flow before changes in operating assets and liabilities increased by $32.7 million reflecting the increase in production activity and changes in operating assets and liabilities provided a source of cash of $31.2 million due to the increase in liabilities due to the incurring significant operating costs near year end for the drilling, exploration and development of our CX11-20XD and CX11-15D wells and the timing of payments for those costs.

Investing Activities

Net cash used in investing activities decreased by $12.2 million to cash used in investing activities of $90.0 million in 2009 from $102.2 million in 2008, respectively, and is primarily due to decreased capital expenditures in 2009.

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Net cash used in investing activities increased by $43.7 million to $102.2 million in 2008 from $58.8 million in 2007, respectively, and is primarily due to increased capital expenditures and an increase in restricted investments required in order to secure performance bonds under our license contracts.

2009 Equipment Activity

During the year ended December 31, 2009, we incurred capital expenditures of approximately $96.6 million associated with our development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of proprietary gas-fired power generation facility in Peru.

Of the incurred costs mentioned above, we incurred capital expenditures related to the drilling and testing of the CX11-15D, CX11-19D, CX11-17D and CX11-20XD in the Corvina field of approximately, $23.5 million, $12.8 million, $3.0 million and $1.0 million respectively, as well as for the A-14D well of approximately $20.6 million in the Albacora field during the year ended December 31, 2009 in addition to $5.1 million in standby, installation and mobilization costs during the same period.

We also incurred costs of approximately $7.9 million during the year ended December 31, 2009 for the design and refurbishment of the Albacora Platform. We began installing permanent production and testing facilities on the Albacora platform and incurred an additional $1.9 million in cost.

In 2009, we entered into a lease-purchase agreement to acquire the Don Fernando barge resulting in additional capital assets of approximately $7.2 million. The Don Fernando will serve as our construction lay barge as well as tender assist barge for drilling and construction operations and will eventually be fitted to lay subsea pipe for the gas-to-power project. Additional outfitting of the barge will cost approximately $1.5 million to $2.0 million.

For the development of a Company owned gas-fired power generation facility, we incurred costs of approximately $4.9 million as part of our agreement to purchase three LM6000 gas-fired turbines.

We also incurred costs for the purchase of machinery and equipment used in operations in Peru of approximately $2.9 million.

For the year ended December 31, 2009, in accordance with “successful efforts” method of accounting, we capitalized approximately $1.4 million of depreciation expense, mainly related to the tender assist barges serving as support equipment, and $4.4 million of interest expense to construction in progress.

2008 Equipment Activity

During the year ended December 31, 2008, we incurred capital expenditures of approximately $110.6 million associated with our development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of proprietary gas-fired power generation facility sale in Peru.

Of the incurred costs mentioned above, we incurred capital expenditures related to the drilling and testing of the CX11-18XD, CX11-20XD and CX11-15D of approximately $19.0 million, $31.2 million, and $11.2 million, respectively, during the year ended December 31, 2008.

We also incurred costs of approximately $12.4 million during the year ended December 31, 2008 for the installation of sea-bed pipelines and a new mooring system as a result of placing the FPSO into service and production equipment to support operations.

In preparation for our drilling campaign in Albacora field, we performed well control on the existing well heads located at the A platform. We incurred approximately $1.5 million in well control costs to provide a safe environment for its refurbishment.

Additionally in 2008, we entered into two lease-purchase agreements to acquire the BPZ-02 barge and to acquire the production equipment on board the FPSO Namoku resulting in additional capital assets of approximately $7.0 million and $2.4 million, respectively. Further we capitalized an additional $2.8 million of production equipment in order to have the FPSO ready to receive and treat oil received from the CX-11 platform.

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For the development of a Company owned gas-fired power generation facility, we incurred costs of approximately $3.6 million related to the drafting of certain design specifications for the power plant and capitalized an additional $9.0 million incurred as part of our agreement to purchase three LM6000 gas-fired turbines, including an initial down payment of $5.1 million.

We also incurred costs for office equipment and leasehold improvements for our offices in Houston, Peru and Ecuador of approximately $0.9 million and for the purchase of machinery and equipment used in operations in Peru of approximately $0.7 million.

For the year ended December 31, 2008, in accordance with “successful efforts” method of accounting, we capitalized approximately $1.0 million of depreciation expense, mainly related to the tender assist barges serving as support equipment, and $4.2 million of interest expense to construction in progress.

Financing Activities

Cash provided by financing activities increased by $82.4 million to $133.6 million in 2009 compared to $51.3 million in 2008. The increase in cash provided by financing activities reflects increased proceeds from sales of our common stock and proceeds from the exercise stock options and warrants of $91.4 million. Partially offsetting these proceeds are reduced borrowings, loan fees and reduced repayments of borrowings of $9.0 million.

Cash provided by financing activities decreased by $4.6 million to $51.3 million in 2008 compared to $55.8 million in 2007. This decrease in cash provided by financing activities reflects increased cash used on principal payments for capital lease obligations partially offset by additional cash proceeds from debt and proceeds received from the issuance of common stock.

Shelf Registration

To finance our operations we may sell additional shares of our common stock. 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 approximately $134.6 million in common stock available under an effective shelf registration statement, which we may sell from time to time in one or more offerings pursuant to underwritten public offerings, negotiated transactions, block trades or a combination of these methods. This registration statement will expire on December 7, 2010.

Long-Term Debt and Capital Lease Obligations

At December 31, 2009 and December 31, 2008, long-term debt and capital lease obligations consist of the following (in thousands):

	December 31, 2009		December 31, 2008
	(in thousands)

$15 million IFC Senior Note, Libor plus 2.75%, due 2012	$	15,000	$	15,000
Capital Lease Obligations	11,910		7,838
Other	1,023		—
	27,933		22,838
Less: Current Portion of Long-Term Debt and Capital Lease Obligations	5,352		7,820
	$	22,581	$	15,018

$15.0 Million IFC Reserve-Based Credit Facility

We have 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 reserve-based lending facility was to originally mature in December 2012, however, as result of the $170.9 million Convertible Debt issuance by us in February and March 2010, we expect to use a portion of the proceeds to repay the amount outstanding to the IFC in 2010. Therefore $2.5 million of the $15.0 million that was originally due at December 31, 2010 and that would have being classified as a

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current liability at December 31, 2009 is being classified as a long term liability, in accordance with Accounting Standard Codification (“ASC”) Topic 470, “Debt”, as we intend to refinance the obligation on a long-term basis.

The reserve-based lending facility bears interest at an approximate rate of LIBOR plus 2.75%, currently equivalent to 3.19% based on the six month LIBOR rate of 0.44% at December 31, 2009. The maximum amount available under this facility begins at $15.0 million and will 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 Loan Agreement is subject to a semi-annual borrowing base determination based on the value of oil reserves. In addition, we are 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. We requested and received a waiver and amendment from IFC which extended the period of time to assign a first priority lien on Empresa Electrica Nueva Esperanza S.R.L.’s interest in the Agreement with GE for three gas fired turbines to IFC until December 2010. Accordingly, we were in compliance with all material covenants of the Loan Agreement as of December 31, 2009.

The Loan Agreement provides for events of default customary for agreements of this type, including, among other things, payment breaches under any of the finance documents for the first and second tranche of the senior debt; failure to comply with obligations; representation and warranty breaches; expropriation of the assets, business or operations of any borrower; insolvencies of any borrower; certain attachments against the assets of any borrower; failure to maintain certain authorizations with respect to any financing documents with the IFC, the development and operation of the Corvina field in Block Z-1, any additional petroleum assets under license contracts with Perupetro or certain other key agreements; revocation of any financing or security documents with the IFC or certain key agreements; defaults on certain liabilities; certain judgments against the borrower or any subsidiary; abandonment or extended business interruption of the Corvina field or certain other petroleum assets; engagement in certain sanctionable practices; or restrictions are enacted in Peru that could inhibit any payment a borrower is required to make under the financing documents with the IFC.

If an event of default occurs, IFC and any additional facility agent may (i) terminate all or part of the relevant facility; (ii) declare all or part of the principal amount of the loan, together with accrued interest, immediately due and payable; (iii) declare all or part of the principal amount of the loan, together with accrued interest, payable on demand; or (iv) declare any and all of the security documents under the facility enforceable and exercise its rights under such documents. In addition, if any borrower is liquidated or declared bankrupt, all loans and interest accrued on it or any other amounts due, will become immediately due and payable without notice.

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 bears an annual interest rate of 5.45% and is to be 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 will be 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.

Note Payable

In January 2009, in exchange for receipt of $1.0 million from an individual (“Note Holder”), we signed a promissory note (the “Note”). The Note originally provided for maturity in July 2009 and bore an annual interest rate of 12.0%. However, in March 2009 we repaid the principal amount and accrued interest in full to the Note Holder.

Capital Leases

In November 2009, we entered into a capital lease agreement for a construction barge, the Don Fernando, to assist us in our offshore construction projects. The capital lease asset and corresponding liability was recorded at $7.0 million, which represents the present value of the minimum lease payments, or the aggregate fair market value of the assets. At the end of the two year lease the title to the barge transfers to us. We accounted for the lease agreement in accordance with ASC Topic 840, “Leases”, previously accounted for under Statement of Financial Accounting Standards (“SFAS”) No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement is 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 22.4%.

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In June 2007, we entered into a capital lease agreement, with an option to purchase, for two barges, Namoku and the Nu’uanu, to assist in the development of the Corvina oil. The capital lease assets were recorded at $6.2 million, which represents 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 barges currently under charter, the Namoku and the Nu’uanu. Under the terms of the amended lease agreement, the current charter, originally set to expire in November 2009, is 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 barges is fixed. Commencing on 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 us after November 2010 over the initial daily rate, as a result of the escalated tiered structure based on the price of WTI, will be considered contingent rental payments. 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”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. 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 FPSO ready to receive and treat oil received from the CX-11 platform. The FPSO lease contains two bargain purchase options; therefore, depreciation of these 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”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement is 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 March 2008, we entered into a lease-purchase agreement to acquire the BPZ-02 barge resulting in additional capital assets of approximately $7.0 million. In February 2009, we made the final lease payment on the BPZ-02 deck barge at which point title to the barge was transferred to us.

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.

Performance Bonds

As of December 31, 2009, we have restricted cash deposits of $5.7 million. In connection with our properties in Peru, we have obtained four performance bonds totaling $5.3 million that are partially collateralized by restricted cash deposits of $3.1 million to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally, we have $1.6 million of restricted cash to collateralize insurance bonds for import duties related to the BPZ-01 barge and crane on board the BPZ-01. We also have $1.0 million of restricted cash held in a trust account in order to secure financing to support our operations. In January 2010, the $1.0 million of restricted cash held in a trust account was released in order to make the final payment on our short-term loan agreement. Furthermore we have an unsecured performance bond of $0.1 million to guarantee our performance under our new office lease agreement in Peru.

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

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2010 Estimated Capital Expenditures Budget

We established a 2010 capital expenditures budget of approximately $200.0 million which includes $18.0 million in seismic costs that will be expensed under the Successful Efforts Method of Accounting, as well as $35 million in remaining contract payments to purchase the GE turbines for the gas-to-power project. We will continue to focus our efforts on oil production in Block Z-1 by committing a majority of our capital expenditures budget to continue to appraise and develop the oil in the Corvina and Albacora fields. Accordingly, we plan to complete our final two wells on the CX-11 platform in the Corvina field and drill approximately four new wells in Albacora from the A platform. We also plan to install permanent reinjection facilities in Albacora and complete our production and reinjection facilities to begin commercial production in the Corvina field. In accordance with our Block XIX 2010 exploration commitments, upon completion of the last Corvina well in 2010, we intend to mobilize the Corvina rig to Block XIX and drill a step out well to the 5215 in the Pampa de la Gallina field. The step out well will qualify as an exploration well under the Block XIX License Contract as it will target previously untested sands lower in the Heath formation.

We believe the increased production from both the Corvina and Albacora fields, combined with our recent convertible debt issuance, should allow us to be cash flow positive while drilling at the Corvina, Albacora and Pampa la Gallina fields and should cover the capital expenditures noted below.

	2010 Capital Budget
	($ in millions)
Corvina
Drilling and development	$	16.4
Platform construction and refurbishment	10.4
Other facilities and activities	13.6
	40.4
Albacora
Drilling and development	60.0
Platform construction and refurbishment	0.6
Other facilities and activities	3.7
	64.3
Other Drilling Areas and Activities
Block XIX	17.3
Block XXIII	11.7
Other facilities and activities	0.8
	29.8
Marine Support Operations
Barges and vessels	3.8
Infrastructure improvements and other facilities and activities	8.8
	12.5
Power Generation
Turbines	35.2

Total estimated capital budget	$	182.2

Seismic expenses*	$	18.0

Total	$	200.2

* Seismic costs are expensed under the successful efforts method of accounting

Note: The Estimated Capital Expenditures Budget for 2010 reflects our operational plans and goals for 2010. We cannot guarantee that these goals can be achieved and events may cause us to fall short of the goals reflected in this budget. See Item 1A. — “Risk Factors” and Item 7. — “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” to better understand the variables that might cause us to miss our goals. Further, for purposes of calculating our proved reserves, (see “Proved Reserves” below) we have made more conservative assumptions than reflected in the budget above about the possible results of our capital expenditures in light of our results in 2009.

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Liquidity Outlook

Our 2009 net revenue decreased by $10.5 million to $52.5 million from $63.0 million in 2008. The decrease in net revenue is primarily due to the depressed oil prices during the first half of 2009. Oil sales from the Corvina field during 2009 was approximately 963,000 barrels or approximately 137,000 barrels more than what was sold in 2008. However, average oil prices received from our oil sales to the Talara Refinery decreased by approximately 29% to approximately $54.49 per barrel compared to the 2008 average price of $76.23 per barrel.

Our major sources of funding to date have been through oil sales, equity raises, convertible debt issuances and, to a lesser extent, debt financing activities. With our current cash balance, current and prospective Corvina and Albacora Oil development cash flow, our recent convertible debt issuance, other potential third-party financing and potential financing from future equity raises, we believe we will have sufficient capital resources to execute our current Corvina and Albacora oil development projects as well as service our current debt obligations and plan to continue pursuing our gas-to-power project once project funding becomes available. However, the timing and execution of our project is dependent on a variety of factors, including the technical design of facilities, permitting approval, availability of equipment, time and costs required for delivery of materials and construction operations, performance by contractors and the success of planned financing, many of which factors are outside our control and cannot be assured.

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Off-Balance Sheet Arrangements

As of December 31, 2009, 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.

Contractual Obligations

	Payments Due by Period at December 31, 2009
	Total		Less Than One Year		One to Three Years		Three to Five Years		More Than Five Years
	(in thousands)
Contractual Obligations:
Operating lease obligation (1)	$	71,792	$	39,607	$	28,530	$	3,079	$	576
Capital lease obligation (2)	18,264		7,173		7,666		3,425		—
Debt obligation (3)	17,277		1,604		15,673		—		—
Purchase obligation (4)	35,219		35,219		—		—		—
Total	$	142,552	$	83,603	$	51,869	$	6,504	$	576

(1) Includes operating leases for our executive office in Houston, Texas, and our branch offices in Lima, Peru and warehouses in Peru, respectively, including the renting of current office space and warehouse space in Peru on a month-to-month basis through March 2010 and new office space and warehouse space in Peru through 2013, respectively. The operating lease amounts also exclude $0.2 million of sublease rentals from our Houston, Texas office due in the future under noncancelable subleases.

Includes the monthly lease expense for our two drilling rigs, one located at the Corvina platform and one located at the Albacora platform. The Corvina rig lease is set to expire in July 2011 and the Albacora rig lease is set to expire in July 2012.

Includes the monthly lease expense for one of our oil transportation vessels whose lease is set to expire in March 2010.

(2) Includes capital lease for a construction barge, the Don Fernando. The capital ease is set to expire in November 2011 at which point title to the barge transfers to us.

Includes capital lease for two production and storage barges, the Namoku and the Nu’uanu, whose lease was amended in May 2009 and is currently set to expire in April 2014. Lease payments are variable based on the working status of the barges. 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. Commencing on 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 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 will be considered contingent rental payments.

Includes the capital lease for production equipment used on board the Namoku that is currently set to expire in June 2010. The capital lease contains a bargain purchase option of $0.5 million at the end of the second year of the lease.

Includes the capital lease for office furniture in our executive office in Houston, Texas expiring in October 2010.

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(3) Includes the debt and interest payments related to the $15.0 million reserve-based lending facility agreement with IFC through our subsidiaries BPZ Exploracion & Produccion S.R.L and BPZ Marine Peru S.R.L as borrowers. The reserve-based lending facility bears interest at an approximate rate of LIBOR plus 2.75%, currently equivalent to 3.19% based on the six month LIBOR rate of 0.44% at December 31, 2009. The maximum amount available under this facility will begin at $15.0 million and will be reduced by $2.5 million beginning on December 16, 2010 and every six months thereafter during the term of the Loan Agreement. As we intend to refinance this facility with a long term obligation, the $2.5 million due December 16, 2010 has not been included in the 2010 payments.

Includes the remaining amount under a short-term loan agreement to finance the purchase of casing and accessories. In January 2010 the remaining principal amount along with the accrued interest due, was repaid.

(4) The amount relates to the remaining amounts due for purchase of three LM6000 gas-fired turbines from GE whose total purchase price is $51.5 million.

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:

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 will 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.

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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, geo-physical, 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 US as prescribed by the Society of Petroleum Engineers. Reserve estimates are independently evaluated at least annually by independent qualified reserves engineers, NSAI.

Our board of directors oversees the review of our 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 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 that are applied to each unit-of-production in calculating our depletion expense; and

· Assessing, when necessary, our oil and gas assets for impairment. Estimated future cash flows are determined using proved reserves. The critical estimates used to assess impairment, including the impact of changes in reserves 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 oil 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,

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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”, previously known as SFAS No. 143, “Accounting for Asset Retirement Obligation” (“ARO”), 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.

Our plan of operations includes the drilling of wells and the construction of an electric power generation plant. We will be required to plug and abandon those wells and restore the well sites and power generation site upon abandonment if they are abandoned prior to the end of the contract period. See Note 8 “Asset Retirement Obligation” to the consolidated financial statements provided herein for further detail.

Principles of Consolidation

Our consolidated financial statements include the accounts of BPZ and its wholly-owned subsidiaries and branch offices. All intercompany balances and transactions have been eliminated. Management has evaluated all subsequent events through March 31, 2010, the date the financial statements were available to be issued.

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 working interest owned by our consolidated subsidiary, SMC Ecuador, Inc. See Note 6 “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 our investment into income over the remaining term of the license agreement, which expires in May 2016.

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”), previously accounted for under SFAS 123(R), “Share—Based Payment”, which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employees. 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’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 years ended December 31, 2009, 2008 and 2007. We provide compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans.

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we are not able to use these tax deductions (see Note 14, “Income Taxes” for further information), we have no excess tax benefits to be classified as financing cash flows.

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”, previously SFAS No. 52, “Foreign Currency Translation,” 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 June 2009, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 168, now codified as ASC Topic 105, “Generally Accepted Accounting Principles” (“ASC Topic 105”). ASC Topic 105 provides the FASB ASC as the single source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. The FASB ASC changes GAAP from a standards based model, with thousands of standards, to a topically based model. Rules and interpretive releases of the Securities and Exchange Commission (“SEC”) under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of ASC Topic 105 the ASC supersedes all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the ASC will become nonauthoritative. The provisions of FASB ASC Topic 105 are effective for interim and annual periods ending after September 15, 2009 and, accordingly, are effective for us for the current fiscal reporting period. The adoption of the ASC did not have an impact on our financial position, results of operations or cash flows.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS No. 165”), now codified as ASC Topic 855, “Subsequent Events” (“ASC Topic 855”). This standard establishes the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. We adopted ASC Topic 855 in the second quarter of 2009. The adoption of ASC Topic 855 did not have a material impact on our consolidated financial position, results of operations or cash flows. See Note 1, “Basis of Presentation and Significant Accounting Policies”, to the accompanying consolidated financial statements for the related disclosure.

In December 31, 2008, the SEC adopted the final rules regarding amendments to current Oil and Gas reporting requirements. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology and include the following:

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

· Enabling companies to additionally disclose their probable and possible reserves;

· Requiring previously nontraditional resources, such as oil shales, to be classified as oil and gas reserves if the nontraditional resources are intended to be upgraded to synthetic oil and gas;

· 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

· Permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

The amendments are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10-K and for fiscal years ending on or after December 31, 2009. Early adoption is not permitted in either annual or quarterly reports before the first annual report in which the revised disclosures are required.

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We adopted the rules effective December 31, 2009. See Supplemental Oil and Gas Information (Unaudited) for impact of adoption on oil and gas reserves.

In addition, in January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures”, to provide consistency with the new SEC rules. The Update amends existing standards to align the reserves calculation and disclosure requirements under U.S. GAAP with the requirements in the SEC rules. We adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate. See also Supplemental Oil and Gas Information (Unaudited).

In May 2008, the FASB issued FASB Staff Position (“FSP”) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which is codified under ASC Topic 470, “Debt”. Under the accounting guidance, convertible debt instruments that may be settled entirely or partially in cash upon conversion will be required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The FSP is effective for fiscal years beginning after December 15, 2008. This rule requires retrospective application to all periods presented. The cumulative effect of the change in accounting principle on periods prior to those presented shall be recognized as of the beginning of the first period presented. However, the provisions of this FSP need not be applied to immaterial items. Subsequent to December 31, 2009, the Company issued $170.9 million of convertible debt due in 2015 that is impacted by this accounting standard. See Convertible Debt due 2015 under Financing Activities of ITEM 7., “Management’s Discussion and Analysis of Financial Conditions and Results of Operations”, for the expected impact of this accounting standard on the Company’s convertible debt issued in February 2010 and March 2010.

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 reasonable 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.

Interest Rate Risk.

As of December 31, 2009, we had long-term debt and capital lease obligations of approximately $22.6 million and current maturities of long-term debt and capital lease obligations of approximately $5.4 million, consisting of three capital lease obligations for two barges and production equipment and two loans for office furniture.

The $15.0 million reserve-based lending facility is variable rate debt and bears interest at an approximate rate of LIBOR plus 2.75%. The variable rate debt 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 December 2009 levels, interest expense would increase by approximately $0.2 million annually. The carrying value of the variable interest rate debt approximates fair value as it bears interest at current market rates.

The capital lease obligation for the FPSO and transportation barges began in August 2007 and is set to expire in May 2014. Lease payments are variable based on the working status of the barges, with a purchase option of $3.0 million in May 2012, $2.0 million in May 2013, and required to be purchased by us for $1.0 million in May 2014. The imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 34.9%. The capital lease obligation for the production equipment on board the FPSO barge, the Namoku, is set to expire in June 2010, and contains a purchase option at the end of twelve months and another at the end of 24 months and stipulates an interest rate of 18.0%. We have two additional loans for office equipment containing a term of 60 months and bearing fixed interest rates of 5.94% and 9.44%, respectively, with principal and interest payments due on a monthly basis. We do not expect a significant change in the market interest rate to impact the interest on our capital lease obligations. However, significant changes in market interest rates may significantly affect the level of financing IFC and Natixis will structure with respect to our project in Peru.

In November 2009, we entered into a capital lease agreement for a construction barge, the Don Fernando, to assist us in our offshore construction projects. The capital lease asset and corresponding liability was recorded at $7.0 million, which represents the present value of the minimum lease payments, or the aggregate fair market value of the assets. At the end of the two year lease the title to the barge transfers to us. We accounted for the lease agreement in accordance with ASC Topic 840, “Leases”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Under the

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guidance, the lease agreement is 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 22.4%.

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 we 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.

With respect to our planned electricity generation business, the price we can obtain for the sale of power may not rise at the same rate, or may not rise at all, to match a rise in the Company’s cost to produce and transport gas reserves to our initial 135MW power plant in Caleta Cruz. Prices for both electricity and natural gas have been very volatile in the past year and have increased significantly over the past two years. The profitability of this business depends in large part on the difference between the price of power and the price of fuel used to generate power, or “spark spread.”

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, 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, 2009, we recognized an exchange rate loss of approximately $0.1 million. During the year ended December 31, 2008, and 2007 we recognized exchange rate gains of approximately $0.1 million and $0.2 million, respectively.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

BPZ Resources, Inc. and Subsidiaries
Index to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm	73

Consolidated Balance Sheets as of December 31, 2009 and 2008	74

Consolidated Statements of Operations for the Years Ended December 31, 2009, 2008 and 2007	75

Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2009, 2008 and 2007	76

Consolidated Statements of Cash Flows for the Years Ended December 31, 2009, 2008 and 2007	77

Notes to Consolidated Financial Statements	78

Supplemental Oil and Gas Disclosures (Unaudited)	110

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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. and Subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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.

As discussed in Note 11 to the consolidated financial statements, the Company has restated its previously issued consolidated financial statements to reflect certain adjustments associated with the issuance of Merger Earn-Out Shares in 2007 and 2005.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BPZ Resources, Inc. and Subsidiaries at December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, 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. and Subsidiaries’ internal control over financial reporting as of December 31, 2009, 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 31, 2010, expressed an unqualified opinion thereon.

/s/ Johnson Miller & Co., CPA’s PC

Midland, Texas

March 31, 2010

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BPZ Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except share par value amounts)

	December 31,
	2009			2008
				(Restated) (1)
ASSETS

Current assets:
Cash and cash equivalents	$	18,147		$	5,317
Accounts receivable	2,867			5,276
Value added tax receivable	26,152			12,110
Inventory	12,507			4,054
Prepaid and other current assets	1,580			3,268

Total current assets	61,253			30,025

Property, equipment and construction in progress, net	262,517			193,934
Restricted cash	5,720			5,153
Other non-current assets	1,559			—
Investment in Ecuador property, net	1,195			1,382
Deferred tax asset	16,928			4,871

Total assets	$	349,172		$	235,365

LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable	$	32,698		$	35,286
Accrued liabilities	14,155			9,920
Other liabilities	1,235			720
Current income taxes payable	322			6,841
Accrued interest payable	106			—
Current maturity of long-term debt and capital lease obligations	5,352			7,820

Total current liabilities	53,868			60,587

Asset retirement obligation	766			580
Long-term debt and capital lease obligations	22,581			15,018

Total long-term liabilities	23,347			15,598

Commitments and contingencies (Note 16)

Stockholders’ equity:
Preferred stock, no par value, 25,000 authorized; none issued and outstanding	—			—
Common stock, no par value, 250,000 authorized; 115,224 and 78,748 shares issued and outstanding at December 31, 2009 and December 31, 2008, respectively	513,145			364,566
Accumulated deficit	(241,188		)	(205,386		)

Total stockholders’ equity	271,957			159,180

Total liabilities and stockholders’ equity	$	349,172		$	235,365

(1) For further information regarding the restated amounts, see “Restatement of Merger Earn-Out Shares” under Note 11 — “Restatement of Merger Earn-Out Shares”.

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

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BPZ Resources, Inc. and Subsidiaries

Consolidated Statements of Operations

(In thousands, except per share data)

	Year Ended December 31,
	2009			2008			2007
							(Restated) (1)
Revenue	$	52,454		$	62,955		$	2,350

Operating and administrative expenses:
Lease operating expense	28,113			11,649			755
General and administrative expense	33,258			42,094			18,548
Geological, geophysical and engineering expense	7,768			794			4,045
Depreciation, depletion and amortization expense	25,803			16,062			793

Total operating expenses	94,942			70,599			24,141

Operating loss	(42,488		)	(7,644		)	(21,791		)

Other income (expense):
Income from investment in Ecuador property, net of amortization	1,208			718			264
Interest income	215			319			855
Other income (expense)	(1,312		)	102			201

Total other income, net	111			1,139			1,320

Loss before income taxes	(42,377		)	(6,505		)	(20,471		)

Income tax expense (benefit)	(6,575		)	3,141			39

Net loss	$	(35,802	)	$	(9,646	)	$	(20,510	)

Basic and diluted net loss per share	$	(0.35	)	$	(0.12	)	$	(0.33	)
Weighted average common shares outstanding	103,362			77,390			61,660

(1) For further information regarding the restated amounts, see “Restatement of Merger Earn-Out Shares” under Note 11 — “Restatement of Merger Earn-Out Shares”.

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

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BPZ Resources, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity

Years Ended December 31, 2009, 2008 and 2007

(In thousands)

	Common Stock				Additional Paid- in			Stock Subscription			Accumulated
	Shares	Amount			Capital			Receivable			Deficit			Total

Balances at January 1, 2007 (1)	54,144	$	136,175		$	5,092		$	(231	)	$	(77,400	)	$	63,636

Stock-based compensation	5	19			(25		)	—			—			(6		)
Exercise of stock options assumed in merger	379	647			(647		)	—			—			—
Exercise of stock options	1,868	3,426			—			—			—			3,426
Long-term incentive compensation plan, net of forfeitures	1,348	12,020			(6,757		)	—			—			5,263
Incentive earn-out shares	—	—			1,782			—			—			1,782
Common stock sold for cash, net of offering costs	7,170	37,717			(799		)	231			—			37,149
Common stock dividend (merger earn-out shares) (1)	9,000	97,830			—			—			(97,830		)	—
Adjustment for negative APIC - deferred stock compensation	—	(1,354		)	1,354			—			—			—
Net loss	—	—			—			—			(20,510		)	(20,510		)

Balances at December 31, 2007	73,914	286,480			—			—			(195,740		)	90,740

Exercise of stock options assumed in merger	325	422			—			—			—			422
Exercise of stock options	567	2,046			—			—			—			2,046
Long-term incentive compensation plan, net of forfeitures	—	18,464			—			—			—			18,464
Common stock sold for cash, net of offering costs	2,200	40,904			—			—			—			40,904
IFC debt conversion (1)	1,492	15,500			—			—			—			15,500
Stock subscription agreement	250	750			—			—			—			750
Net loss	—	—			—			—			(9,646		)	(9,646		)

Balances at December 31, 2008	78,748	364,566			—			—			(205,386		)	159,180

Exercise of stock options assumed in merger	—	—			—			—			—			—
Exercise of stock options	164	602			—			—			—			602
Long-term incentive compensation plan, net of forfeitures	188	13,055			—			—			—			13,055
Common stock sold for cash, net of offering costs	36,124	134,922			—			—			—			134,922
Net loss	—	—			—			—			(35,802		)	(35,802		)

Balances at December 31, 2009	115,224	$	513,145		$	—		$	—		$	(241,188	)	$	271,957

(1) For further information regarding the restated amounts, see Note 11 — “Restatement of Merger Earn-Out Shares”.

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

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BPZ Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)

	For the Year Ended December 31,
	2009			2008			2007
							(Restated)
Cash flows from operating activities:
Net loss	$	(35,802	)	$	(9,646	)	$	(20,510	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Stock-based compensation	13,055			18,464			7,040
Depreciation, depletion and amortization	25,803			16,062			793
Amortization of investment in Ecuador property	187			188			188
Deferred income taxes	(12,057		)	(4,872		)	—
Net loss on the sale of asset	—			—			9
Amortization of deferred financing fees	—			—			2
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable	2,409			(2,326		)	(2,950		)
Increase in value added tax receivable	(14,042		)	(4,613		)	(4,337		)
Increase in inventory	(7,619		)	(661		)	(1,200		)
Decrease (increase) in other assets	1,531			240			(299		)
(Decrease) increase in accounts payable	(2,588		)	23,512			4,398
Increase in accrued liabilities	4,341			5,078			1,535
(Decrease) increase in income taxes payable	(6,519		)	6,841			—
Increase in other liabilities	516			455			160
Net cash provided by (used in) operating activities	(30,785		)	48,722			(15,171		)

Cash flows from investing activities:
Property and equipment additions	(89,438		)	(99,867		)	(55,766		)
Increase in restricted cash	(567		)	(2,318		)	(2,698		)
Net cash used in investing activities	(90,005		)	(102,185		)	(58,464		)

Cash flows from financing activities:
Borrowings	6,533			17,819			15,500
Repayments of borrowings	(8,437		)	(10,451		)	(17		)
Deferred loan fees	—			(225		)	(233		)
Proceeds from exercise of warrants, net	—			750			—
Proceeds from exercise of stock options, net	602			2,469			3,426
Proceeds from sale of common stock, net	134,922			40,904			37,149
Net cash provided by financing activities	133,620			51,266			55,825

Net increase (decrease) in cash and cash equivalents	12,830			(2,197		)	(17,810		)
Cash and cash equivalents at beginning of period	5,317			7,514			25,324
Cash and cash equivalents at end of period	$	18,147		$	5,317		$	7,514

Supplemental cash flow information:
Cash paid for:
Interest	$	4,259		$	4,678		$	470
Income tax	12,525			1,165			39
Non — cash items:
Purchase and additions to equipment with the issuance of a capital lease obligation	$	7,000		$	9,243		$	6,170
Conversion of long-term debt to common stock	—			15,500			458
Accrued interest capitalized to construction in progress	54			230			458
Depletion allocated to production inventory	834			19			227
Depreciation on support equipment capitalized to construction in progress	1,415			977			474
Asset retirement obligation capitalized to property and equipment	112			269			269
Property and equipment transferred to other non-current assets	(1,456		)	—			—
Recapitalization of Merger Earn-out Shares. See Note 11							97,830

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

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BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

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, formerly BPZ Energy, Inc., and its subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership. Currently, the Company, through BPZ E&P, has exclusive rights and license contracts for oil and gas exploration and production covering a total of approximately 2.2 million acres, in four blocks, in northwest Peru. The Company’s license contracts cover 100% ownership of the following properties: Block Z-1 (0.6 million acres), Block XIX (0.5 million acres), Block XXII (0.9 million acres) and Block XXIII (0.2 million 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”) 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, specific provisions of each license contract can vary the exploration phase of the contract as established by the 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 exploration and production and up to 40 years for gas exploration and 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 exploration and 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-operated working interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). The license agreement covering the property extends through May 2016.

The Company is in the process of developing its oil and natural gas reserves. The Company has been producing and selling oil from the CX-11 platform in the Corvina field of Block Z-1 under a well testing program and is in the process of satisfying the conditions to transition to commercial production in Corvina. From the time the Company first began producing from the CX-11 platform in the Corvina field in November of 2007, through December 31, 2009, it has produced approximately 1.9 MMBbls of oil. The Company is also in the initial stages of appraising, exploring and developing the potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1, and has drilled and completed its first well in December 2009. Additionally, the Company’s activities in Peru include analysis and evaluation of technical data on its other properties, preparation of the development plans for the properties, refurbishment of and designs for platforms, procuring machinery and equipment for an extended drilling campaign, obtaining all necessary environmental and operating permits, bringing additional production on-line, seismic acquisition, obtaining detailed engineering and design of the power plant and gas processing facilities, executing a contract to purchase three LM 6000 gas fired turbines and securing the required capital and financing to conduct the current plan of operation.

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. Management has evaluated all subsequent events through March 31, 2010, the date the financial statements were available to be issued.

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 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-operated

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BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

working interest owned by its consolidated subsidiary, SMC Ecuador Inc. See Note 6 “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.

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 in this Form 10-K 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 obligation 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 management’s estimates.

Restatement and Reclassification

The Form 10-K includes a restatement of the Company’s previously issued consolidated financial statements as of and for the years ended December 31, 2007, 2006, and 2005. This restatement was required to adjust the consolidated financial statements presentation for the issuance of the merger earn-out shares issued in conjunction with the Company’s recapitalization. See Note 11, “Restatement of Merger Earn-out Shares” for further information.

Certain reclassifications have been made to the 2008 and 2007 consolidated financial statements to conform to the 2009 presentation. These reclassifications were not material to the 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 oil 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.

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”, previously Statement of Financial Accounting Standards (“SFAS”) No. 52, “Foreign Currency Translation,” which requires that the translation of the applicable

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BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

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, a translation loss of approximately $0.1 million was recognized during the year ended December 31, 2009 and a translation gain of approximately $0.1 million and $0.2 million was recognized during the year ended December 31, 2008 and 2007, respectively.

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

As discussed in Note 7, “Restricted Cash”, 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.

Allowance for Doubtful Accounts

Currently, the Company’s contract terms regarding oil sales have a relatively short settlement period. However, the Company regularly reviews all aged accounts receivables for collectability and establishes an allowance as necessary for balances greater than 90 days outstanding. Currently 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, 2009 and December 31, 2008, respectively.

Property, Equipment and Construction in Progress

The Company follows the “successful efforts” method of accounting of 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. 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.

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, 2009, 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. Barges and related equipment are depreciated on a straight-line basis over the estimated useful life of the asset which is between five and fifteen years.

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

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.

Oil and Gas Accounting Reserves Determination

The successful efforts method of accounting depends on the estimated reserves the Company believes 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, 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 investment activities;

· 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 prepare 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 U.S. 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 Company’s Board of Directors oversees the review of our 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 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 that are applied to each unit-of-production in calculating our depletion expense; and

Impairment of Long-Lived Assets

The Company periodically evaluates the recoverability of the carrying value of its long-lived assets, goodwill 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 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

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

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 years ended December 31, 2009, 2008 and 2007, there was 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”), previously accounted for under SFAS 123(R), “Share—Based Payment”, which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employees. 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’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 years ended December 31, 2009, 2008 and 2007. The Company provides compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans. See Note 10, “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 14, “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, 2009, 2008 and 2007 was $4.4 million, $4.2 million and $0.9 million, respectively.

Fair Value of Financial Instruments

The Company’s financial instruments consist of cash, trade receivables, trade payables and debt. 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. The fair value of debt at December 31, 2009 and 2008 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 can currently borrow.

Income Taxes

The Company accounts for income taxes in accordance with SFAS 109, “Accounting for Income Taxes, which was codified into 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

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 these studies and assistance related to the Company’s properties for the year ended December 31, 2009, 2008 and 2007 were approximately $1.2 million, $0.5 million and $0.3 million, respectively.

Loss per Common Share

In accordance with provisions of ASC Topic 260, “Earnings per Share”, previously known as SFAS No. 128, “Earnings per Share”, basic earnings 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 earnings per share equals basic earnings per share for the periods presented because the effects of potentially dilutive securities are antidilutive.

Recent Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 168, now codified as ASC Topic 105, “Generally Accepted Accounting Principles” (“ASC Topic 105”). ASC Topic 105 provides the FASB ASC as the single source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. The FASB ASC changes GAAP from a standards based model, with thousands of standards, to a topically based model. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. On the effective date of ASC Topic 105 the ASC supersedes all then-existing non-SEC accounting and reporting standards. All other nongrandfathered non-SEC accounting literature not included in the ASC will become nonauthoritative. The provisions of FASB ASC Topic 105 are effective for interim and annual periods ending after September 15, 2009 and, accordingly, are effective for the Company for the current fiscal reporting period. The adoption of the ASC did not have an impact on the Company’s financial position, results of operations or cash flows.

In May 2009, the FASB issued SFAS No. 165, “Subsequent Events” (“SFAS No. 165”), now codified as ASC Topic 855, “Subsequent Events” (“ASC Topic 855”). This standard establishes the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events and the basis for that date, that is, whether that date represents the date the financial statements were issued or were available to be issued. The Company adopted ASC Topic 855 in the second quarter of 2009. The adoption of ASC Topic 855 did not have a material impact on the Company’s consolidated financial position, results of operations or cash flows. See Note 1, “Basis of Presentation and Significant Accounting Policies”, to the accompanying consolidated financial statements for the related disclosure.

On December 31, 2008 the SEC adopted the final rules regarding amendments to current oil and gas reporting requirements. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology and include the following:

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

· Enabling companies to additionally disclose their probable and possible reserves;

· Requiring previously nontraditional resources, such as oil shales, to be classified as oil and gas reserves if the nontraditional resources are intended to be upgraded to synthetic oil and gas;

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

· 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

· Permitting the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

The amendments are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and for fiscal years ending on or after December 31, 2009. Early adoption is not permitted in either annual or quarterly reports before the first annual report in which the revised disclosures are required. The Company adopted the rules effective December 31, 2009. See Supplemental Oil and Gas Information (Unaudited) for impact of adoption on oil and gas reserves.

In addition, in January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures” (“ASU 2010-3”), to provide consistency with the December 2008 SEC rules regarding Oil and Gas Disclosures. ASU 2010-3 amends existing FASB standards to align the reserves calculation and disclosure requirements under U.S. GAAP with the requirements in the SEC rules. The Company adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate. See Supplemental Oil and Gas Information (Unaudited) for further information.

In May 2008, the FASB issued FASB Staff Position (“FSP”) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which is codified under ASC Topic 470, “Debt”. Under the accounting guidance, convertible debt instruments that may be settled entirely or partially in cash upon conversion will be required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The FSP is effective for fiscal years beginning after December 15, 2008. This rule requires retrospective application to all periods presented. The cumulative effect of the change in accounting principle on periods prior to those presented shall be recognized as of the beginning of the first period presented. However, the provisions of this FSP need not be applied to immaterial items. Subsequent to December 31, 2009, the Company issued $170.9 million of convertible debt due in 2015 that is impacted by this accounting standard. See $170.9 Million Convertible Debt due 2015 under Note 9, “Long-Term Debt and Capital Lease Obligations” for the expected impact of this accounting standard on the Company’s convertible debt issued in February 2010 and March 2010.

Note 2 — Value Added Tax Receivable

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

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 under a well testing program, 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.

The Company’s value-added tax receivable balance as of December 31, 2009 and December 31, 2008 was $26.2 million and $12.1 million, respectively. For the year ended December 31, 2009 and December 31, 2008, the Company accrued approximately $31.1 million and $19.6 million, respectively, for IGV related to expenditures, reduced by approximately $17.0 million and $11.2 million, respectively, for IGV related to the sale of oil for the same periods.

Note 3 — 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 balance of inventory at December 31, 2009 and December 31, 2008 was $12.5 million and $4.1 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

Inventory associated with tubular goods, accessories and spare parts inventory at December 31, 2009 and December 31, 2008 was $10.5 million and $3.6 million, respectively.

The Company maintains crude oil inventories in storage barges until the inventory quantities are at a sufficient level that the refinery in Talara will accept delivery. These inventories are also 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 at December 31, 2009 consisted of approximately 40,108 barrels at an estimated cost of $2.0 million or $50.55 per barrel. The crude oil inventory at December 31, 2008 consisted of approximately 11,656 barrels at an estimated cost of $0.4 million or $37.56 per barrel.

Note 4 — Prepaid and Other Current Assets

Below is a summary of other current assets as of December 31, 2009 and 2008:

	2009		2008
	(in thousands)
Prepaid expenses and other	$	296	$	1,981
Deposits	92		86
Prepaid insurance	580		590
Insurance receivable	612		611
	$	1,580	$	3,268

Prepaid expenses and other are primarily related to prepayments for drilling services, equipment rental and material procurement. Deposits 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 officer’s insurance policies. Insurance receivable is related to the barge incident which occurred in early August 2006. The Company incurred an operational delay of approximately three weeks resulting from a navigation incident which caused the BPZ-01 barge to be grounded on a sand bank in Talara Bay in northwest Peru during the second mobilization trip to the Corvina platform. As of December 31, 2009, the Company has an insurance receivable of approximately $0.7 million for the estimated insurance repair claims of $0.8 million expected to be filed with the insurance carrier. A deductible of $75,000 will be applied to this insurance claim when reimbursed. The hull claim will be finalized upon the dry docking of the vessel, which is expected to occur during the third quarter of 2010.

Note 5 — Property, Equipment and Construction in Progress

Below is a summary of property, equipment and construction in progress as of December 31, 2009 and 2008:

	2009			2008
	(in thousands)
Construction in progress:
Power plant and related equipment	$	23,144		$	17,484
Platforms and wells	20,899			34,768
Pipelines and processing facilities	5,373			5,108
Producing properties	200,647			110,230
Producing equipment	18,057			18,399
Barge and related equipment	30,852			24,927
Office equipment, leasehold improvements and vehicles	10,466			1,960
Accumulated depletion, depreciation and amortization	(46,921		)	(18,942		)

Net property, equipment and construction in process	$	262,517		$	193,934

During the year ended December 31, 2009 and 2008, the Company incurred capital expenditures of approximately $96.6 million and $110.6 million, respectively, associated with its development initiatives for the exploration and production

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

of oil and natural gas reserves and the complementary development of proprietary gas-fired power generation facility in Peru.

Of the incurred costs mentioned above, the Company incurred capital expenditures related to the drilling and testing of the CX11-15D, CX11-19D, CX11-17D and CX11-20XD in the Corvina field of approximately, $23.5 million, $12.8 million, $3.0 million and $1.0 million respectively, as well as for the A-14D well of approximately $20.6 million in the Albacora field during the year ended December 31, 2009 in addition to $5.1 million in standby, installation and mobilization costs during the same period. For the year ended December 31, 2008 the Company incurred capital expenditures related to the drilling and testing of the CX11-18XD, the CX11-20XD, CX11-15D wells of approximately $19.0 million, $31.2 million, and $11.2 million, respectively. Approximately $86.6 million and $52.3 million was transferred from construction in progress to producing properties for the year ended December 31, 2009 and 2008, respectively.

The Company also incurred costs of approximately $7.9 million during the year ended December 31, 2009 for the design and refurbishment of the Albacora Platform. In addition, the Company began installing permanent production and testing facilities on the Albacora platform and incurred an additional $1.9 million in project costs.

The Company incurred costs of $12.4 million during the year ended December 31, 2008 for the installation of sea-bed pipelines and a new mooring system as a result of placing the floating production, storage and offloading facility (“FPSO”) into service and production equipment to support operations. In addition, in 2008, in preparation for the Company’s drilling campaign in Albacora, it performed well control on the three existing well heads located at the platform. The Company incurred approximately $1.5 million in well control costs to provide a safe environment to begin the refurbishment of the A platform.

In 2009, the Company entered into a lease-purchase agreement to acquire the Don Fernando barge resulting in additional capital assets of approximately $7.2 million. The Don Fernando will serve as the Company’s construction lay barge as well as tender assist barge for drilling and construction operations and will eventually be fitted to lay subsea pipe for the gas-to-power project. Additional outfitting of the barge will cost approximately $1.5 million to $2.0 million. In 2008, the Company entered into two lease-purchase agreements to acquire the BPZ-02 barge and to acquire the production equipment used on board the Namoku resulting in additional capital assets of approximately $7.0 million and $2.4 million, respectively. Both leasing transactions were accounted for in accordance with ASC Topic 840, “Leases”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Further, in 2008, the Company capitalized an additional $2.8 million of production equipment in order to have the FPSO ready to receive and treat oil received from the CX-11 platform.

For the development of a Company owned gas-fired power generation facility, BPZ incurred costs of approximately $4.9 million as part of its agreement to purchase three LM6000 gas-fired turbines for the year ended December 31, 2009. The Company incurred approximately $3.6 million related to the drafting of certain design specifications for the power plant and capitalized an additional $9.0 million incurred as part of its agreement to purchase three LM6000 gas-fired turbines, including an initial down payment of $5.1 million during the year ended December 31, 2008.

In 2009 the Company also incurred costs for the purchase of machinery and equipment used in operations in Peru of approximately $2.9 million. In 2008 the Company incurred costs for office equipment and leasehold improvements for its offices in Houston, Peru and Ecuador of approximately $0.9 million and for the purchase of machinery and equipment used in operations in Peru of approximately $0.7 million.

For the year ended December 31, 2009, in accordance with “successful efforts” method of accounting, the Company capitalized approximately $1.4 million of depreciation expense, mainly related to the tender assist barges serving as support equipment, and $4.4 million of interest expense to construction in progress. For the year ended December 31, 2008, the Company capitalized approximately $1.0 million of depreciation expense and $4.2 million of interest expense to construction in progress.

For the years ended December 31, 2009, 2008 and 2007, the Company recognized $25.8 million, $16.1 million and $0.8 million of depreciation, depletion and amortization expense, respectively.

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

Note 6 — Investment in Ecuador Property

The Company has a 10% net investment interest in an oil and gas property in Ecuador (the “Santa Elena Property”) totaling $1.2 million and $1.4 million as of December 31, 2009 and December 31, 2008, respectively. 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 license agreement which expires in May 2016. Investment income from the Company’s investment in Ecuador property was $1.2 million, $0.7 million and $0.3 million for each of the years ended December 31, 2009, 2008 and 2007, respectively. For the years ended December 31, 2009, 2008 and 2007, the Company received $1.4 million, $0.9 million and $0.5 million of cash, respectively, from its investment in Ecuador property and recorded amortization expense of $0.2 million in each of the three years, respectively.

Note 7 — Restricted Cash

As of December 31, 2009, the Company has restricted cash deposits of $5.7 million. In connection with the Company’s properties in Peru, it obtained four performance bonds totaling $5.3 million that are partially collateralized by restricted cash deposits of $3.1 million to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally, the Company has $1.6 million of restricted cash to collateralize insurance bonds for import duties related to the BPZ-01 barge and crane on board the BPZ-01. The Company also has $1.0 million of restricted cash held in a trust account in order to secure financing to support our operations. In January 2010, the $1.0 million of restricted cash held in a trust account was released in order to make the final payment on the Company’s short-term loan agreement. Furthermore the Company has an unsecured performance bond of $0.1 million to guarantee its performance under its new office lease agreement in Peru.

As of December 31, 2008, the Company had restricted cash deposits of $5.2 million, which partially collateralized insurance bonds and four performance bonds. The four performance bonds totaling $5.3 million, that were partially collateralized by restricted cash deposits of $2.9 million, are to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally, the Company had $2.3 million of restricted cash to collateralize insurance bonds for import duties related to the FPSO and transport tanker.

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

Note 8 —Asset Retirement Obligation

An obligation was recorded for the future plug and abandonment of the producing oil wells, the A-14D, CX11-19D, CX11-21XD, CX11-14D, CX11-20XD, CX11-18XD and the CX11-15D, in accordance with the provisions of ASC Topic 410, “Asset Retirement and Environmental Obligations”, previously accounted for in accordance with SFAS No 143 “Accounting for Asset Retirement Obligations”.

Activity related to the Company’s asset retirement obligation (“ARO”) for December 31, 2009 and December 31, 2008 is as follows:

	2009			2008
	(in thousands)
ARO as of the beginning of the period	$	580		$	273
Liabilities incurred during period	296			268
Accretion expense	74			39
Revisions in estimates during period	(184		)	—
ARO as of the end of the period	$	766		$	580

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

The 2009 revision in estimate is due to the shift in timing of cash flows associated with expected payment of the ARO liabilities. As the expected timing to settle the liabilities was extended in the current year, the present value of the liabilities was decreased and, as a result, the Company reduced both the liability and capitalized asset by approximately $0.2 million in accordance with of ASC Topic 410.

Note 9 — Long-Term Debt and Capital Lease Obligations

At December 31, 2009 and 2008 long-term debt and capital lease obligations consist of the following:

	December 31, 2009		December 31, 2008
	(in thousands)

$15 million IFC Senior Note, Libor plus 2.75%, due 2012	$	15,000	$	15,000
Capital Lease Obligations	11,910		7,838
Other	1,023		—
	27,933		22,838
Less: Current Portion of Long-Term Debt and Capital Lease Obligations	5,352		7,820
	$	22,581	$	15,018

The following is a summary of scheduled long-term debt and other debt maturities by year (in thousands):

2010	$	1,023
2011	7,500
2012	7,500
2013	—
2014	—
Therafter	—
	$	16,023

The following is a summary of scheduled minimum lease payments under capital lease obligations by year (in thousands):

2010	$	7,173
2011	5,835
2012	1,830
2013	1,825
2014	1,600
Therafter	—
Total Minimum Lease Payments	18,263
Less: Amounts Representing Interest	6,353
Present Value of Minimum Lease Payments	11,910
Less: Current Portion of Obligations Under Capital Lease	4,329
Long-Term Portion of Obligations Under Capital Lease	$	7,581

$170.9 Million Convertible Notes due 2015

Subsequent to December 31, 2009, the Company closed on the private offering of $170.9 million convertible notes due 2015 (the “2015 Convertible Notes”). The 2015 Convertible Notes are comprised of the initial $140.0 million of 2015 Convertible Notes sold in the initial private offering, the exercise of a 30- day option to purchase an additional $21.0 million

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

of 2015 Convertible Notes, and International Finance Corporation’s (“IFC”) election to participate in the offering for an additional $9.9 million of 2015 Convertible Notes, bringing the total proceeds of the private offering to $170.9 million. The convertible notes were sold to an initial purchaser who then sold the notes to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. The $170.9 million of convertible notes were issued pursuant to an indenture dated as of February 8, 2010, between the Company and Wells Fargo Bank, National Association, as trustee (“the Indenture”).

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 subordinated 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 Company will pay interest on 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. The initial conversion rate is 148.3856 shares per $1,000 principal amount of the 2015 Convertible Notes (equal to an initial conversion price of approximately $6.74 per share of common stock), subject to adjustment. Upon 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 (but not to exceed 19.99% of the Company’s outstanding shares at the time of such delivery).

The initial conversion rate may be adjusted on February 3, 2011 if the volume weighted average price of the Company’s common stock for each of the 30 trading days ending on February 3, 2011 is less than $5.6160 per share. In addition, following the occurrence of any one of certain corporate transactions that constitutes a fundamental change (as defined in the Indenture), the Company will increase the conversion rate, subject to certain limitations, for a holder who elects to convert the 2015 Convertible Notes in connection with such corporate transactions during the 30-day period after the effective date of such fundamental change.

(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 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

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.

If the Company experiences any one of the 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.

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

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 the Company, or the holders of at least 25% in aggregate principal amount of the 2015 Convertible Notes then outstanding by notice to the Company and the Trustee, may declare the principal of and accrued and unpaid interest (including additional interest or premium, if any) on the 2015 Convertible Notes 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 of and accrued and unpaid interest (including additional interest or premium, if any), on the notes will automatically become due and payable.

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 $165.4 million. The initial purchaser received commissions of approximately $5.5 million in connection with the sale of the Notes. The Company intends to use the net proceeds for general corporate purposes, including without limitation, capital expenditures and working capital, reduction or refinancing of debt, or other corporate obligations.

As a result of the Company’s adoption of the new accounting standard for convertible debt that may be settled in cash upon conversion, it is required to separately account for the liability and equity components in a manner that reflects the Company’s nonconvertible borrowing rate when interest cost is recognized in subsequent periods. 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 accounting standard requires retrospective restatement of all periods presented back to the date of debt issuance with a cumulative effect of the change in accounting principle on all prior periods being recognized as of the beginning of the first period.

The Company estimates its nonconvertible borrowing rate at the date of issuance of its 2015 Convertible Notes to be 12%. The 12% nonconvertible borrowing rate represents 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% nonconvertible borrowing rate, the Company estimates 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 will be amortized as non-cash interest expense into income over the life of the notes using the interest method. In addition, the Company plans to record approximately $4.4 million of the $5.5 million of fees and commissions as debt issue costs that will be amortized over time using the interest method as interest expense. The remaining $1.1 million of fees and commissions will be treated as an original issue discount against the value of the equity component. The Company estimates the cash payments related to the 2015 Convertible Notes, assuming no conversion, for the years ended 2010, 2011, 2012, 2013, 2014 and thereafter to be approximately $6.4 million, $11.1 million, $11.1million, $11.1million, $11.1million and $176.5 million, respectively

$15.0 Million IFC Reserve-Based Credit Facility

On August 15, 2008, the Company entered into 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 co-borrowers. The reserve-based lending facility was to originally mature in December 2012, however, as result of the $170.9 million Convertible Debt issuance by the Company in February and March 2010 , the Company expects to use a portion of the proceeds to repay the amount outstanding to the IFC in 2010. Therefore $2.5 million of the $15.0 million that was originally due at December 31, 2010 and that would have been classified as a current liability at December 31, 2009 is being classified as a long term liability, in accordance with ASC Topic 470, “Debt”, as the Company intends to refinance the obligation on a long-term basis.

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

thereafter during the term of the Loan Agreement. The amount available under the Loan Agreement is subject to a semi-annual borrowing base determination based on the value of oil reserves. In addition, the Company is 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. Additionally, the Company requested and received a waiver and amendment from IFC which extended the period of time to assign a first priority lien on Empresa Electrica Nueva Esperanza S.R.L.’s interest in the Agreement with GE to purchase three gas fired turbines to IFC until December 2010. Accordingly, the Company was in compliance with all material covenants of the Loan Agreement as of December 31, 2009.

The Loan Agreement provides for events of default customary for agreements of this type, including, among other things, payment breaches under any of the finance documents for the first and second tranche of the senior debt; failure to comply with obligations; representation and warranty breaches; expropriation of the assets, business or operations of any borrower; insolvencies of any borrower; certain attachments against the assets of any borrower; failure to maintain certain authorizations with respect to any financing documents with the IFC, the development and operation of the Corvina field in Block Z-1, any additional petroleum assets under license contracts 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. Perupetro is empowered to enter into contracts for the exploration and exploitation of hydrocarbons on behalf of Peru, or certain other key agreements; revocation of any financing or security documents with the IFC or certain key agreements; defaults on certain liabilities; certain judgments against the borrower or any subsidiary; abandonment or extended business interruption of the Corvina field or certain other petroleum assets; engagement in certain sanctionable practices; or restrictions are enacted in Peru that could inhibit any payment a borrower is required to make under the financing documents with the IFC.

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 bears an annual interest rate of 5.45% and is to be 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 will be 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.

Note Payable

In January 2009, in exchange for receipt of $1.0 million from an individual (“Note Holder”), the Company signed a promissory note (the “Note”). The Note originally provided for maturity in July 2009 and bore an annual interest rate of 12.0%. However, in March 2009 the Company repaid the principal amount and accrued interest in full to the Note Holder.

Capital Leases

In November 2009, the Company entered into a capital lease agreement for a construction barge, the Don Fernando, to assist it in its offshore construction projects. The capital lease asset and corresponding liability was recorded at $7.0 million, which represents the present value of the minimum lease payments, or the aggregate fair market value of the assets. At the end of the two year lease, the title to the barge transfers to the Company. The Company accounted for the lease agreement in accordance with ASC Topic 840, “Leases”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement is 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 22.4%.

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

In June 2007, the Company entered into a capital lease agreement, with an option to purchase, for two barges, the Namoku and the Nu’uanu, to assist in the development of the Corvina oil. The capital lease assets were recorded at $6.2 million, which represents 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 two barges currently under charter, the Namoku and the Nu’uanu. Under the terms of the amended lease agreement, the current charter, originally set to expire in November 2009, is 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 barges is fixed. Commencing on 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, will be considered contingent rental payments. 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”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. 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 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”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement is 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 March 2008, the Company entered into a lease-purchase agreement to acquire the BPZ-02 barge resulting in additional capital assets of approximately $7.0 million. In February 2009, the Company made the final lease payment on the BPZ-02 deck barge at which point title to the barge was transferred to it.

Note 10 — 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.

September 2009 Private Placement of Common Stock

On September 15, 2009, the Company closed a private placement of approximately 1.6 million shares of common stock, no par value, to IFC pursuant to a Subscription Agreement dated September 15, 2009. This private placement was related to the Company’s registered direct offering of approximately 18.8 million shares of Common Stock at a price of $4.66 per share that closed on June 30, 2009. Pursuant to the Subscription Agreement dated December 16, 2006 (the “Subscription Agreement”) by and between IFC and the Company, IFC has the right, within 45 days of notice of the offering, to purchase shares of the Company’s Common Stock for the same price and terms as the participants in an offering to retain its proportionate ownership in the Company. IFC exercised its pre-emptive right to purchase approximately 1.6 million shares of Common Stock at the offering price of $4.66 per share to which it was entitled under the Subscription Agreement, resulting in gross proceeds to the Company of approximately $7.6 million. The transaction was submitted to and approved by the shareholders of the Company at a Special Meeting of Shareholders on August 24, 2009. No warrants or dilutive securities were issued to IFC in connection with the private placement. The shares were placed directly by the Company. The Company

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

used the proceeds of this offering to develop its properties under its existing license contracts and other general corporate purposes consistent with the Company’s operating plans.

Under the September 15, 2009 Subscription Agreement, the Company committed to file a registration statement with the SEC covering the shares no later than 45 days after the closing with respect to such shares, and will use its reasonable best efforts to obtain its effectiveness no later than the earlier of (i) 90 days after the closing with respect to such shares, or in the event of SEC review of the registration statement, 120 days after the closing and (ii) the third business day following the date on which the Company is notified (orally or in writing, whichever is earlier) by the SEC that the registration statement will not be reviewed or is no longer subject to further review and comment unless, upon the advice of legal counsel, it is advisable not to accelerate the effectiveness of such registration statement. On October 21, 2009, the Company filed a registration statement with the SEC covering the shares.

Subsequently, the Company received comments from the SEC pertaining to its registration statement, Form 10-K for the year ended December 31, 2008, Definitive Proxy Statement filed on April 30, 2009, Form 10-Q for the period ended September 30, 2009 and the related earnings press release. The Company promptly responded to the SEC’s requests and is currently waiting on requests for additional information, if any. In addition, where appropriate, the Company has proposed clarifications to its disclosures. Once the Company is notified by the SEC that the Company’s responses are no longer subject to further review, the Company will use its reasonable best efforts to obtain the registration statement’s effectiveness. There are no penalty payments associated with the delay in obtaining effectiveness of the registration statement.

June 2009 Registered Direct Offering of Common Stock

On June 30, 2009, the Company closed its sale of approximately 18.8 million shares of its common stock, no par value, in a registered direct offering under an effective shelf registration statement. The shares of common stock were priced at $4.66 per share resulting in net proceeds to the Company, after placement agent fees and other fees, of approximately $82.9 million. In connection with the registered direct offering, the Company entered into a placement agency agreement with Canaccord Adams Inc. as lead placement agent for the offering along with Pritchard Capital Partners, LLC, and Raymond James and Associates, Inc. In addition, Rodman & Renshaw, LLC, and Wunderlich Securities, Inc. assisted as agents in the transaction. The Company paid approximately $4.4 million as a 5% placement agency fee of the gross proceeds received by the Company in accordance with the terms of the placement agency agreement. The Company used the proceeds of this offering to develop its properties under its existing license contracts and other general corporate purposes consistent with the Company’s operating plans.

February 2009 Private Placement of Common Stock

On February 23, 2009, the Company closed a private placement of approximately14.3 million shares of common stock, no par value, to institutional and accredited investors pursuant to a Stock Purchase Agreement dated February 19, 2009. Additionally, in March 2009, IFC exercised its pre-emptive right to elect to participate in the private placement offering resulting in an additional 1.4 million shares of common stock which brought the total to approximately 15.7 million shares of common stock sold in the private placement offering. The common stock was priced at $3.05 per share resulting in net proceeds to the Company, after placement agent and financial advisory fees, of approximately $45.2 million. No warrants or dilutive securities were issued in connection with the private placement. A financial advisory fee of $0.7 million was paid to Morgan Keegan and Company, Inc. for investment services and consulting related to the offering. Additionally a private placement fee of $2.2 million was paid to Pritchard Capital Partners, LLC for placement services related to the offering. The Company used the proceeds of this offering to develop its properties under its existing license contracts and other general corporate purposes consistent with the Company’s operating plans.

Under the Stock Purchase Agreement, the Company committed to file a registration statement with the SEC and obtain the registration statement’s effectiveness within the time-frames outlined in the Stock Purchase Agreement. On April 27, 2009, the Company obtained effectiveness of the registration statement related to the Stock Purchase Agreement in compliance with such time-frames.

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

March 2008 Public Offering of Common Stock

On March 25, 2008 the Company completed an offering of 2.0 million shares of its common stock, no par value, under an effective registration statement, with an additional 0.2 million share over-allotment purchase of common stock that closed on April 21, 2008. The shares of common stock for the offering, including shares of common stock for the over-allotment, was priced at $20.00 per share resulting in net proceeds to the Company, after underwriting fees and discounts, of approximately $41.3 million. No warrants or dilutive securities were issued in connection with the offering. A financial advisory fee of $150,000 was paid to Morgan Keegan for investment services and consulting related to the offering.

Contingent Incentive Earn-Out Shares

During 2005, the Company’s Board of Directors awarded a total of 485,000 shares of incentive stock awards to three of the Company’s officers. The incentive stock awards vest and the earn-out shares are issuable once the Company is entitled to receive as its proportionate share from gross production from any oil and gas wells owned or operated by the Company not less than 2,000 barrels of oil per day or its equivalent (approximately 12 million cubic feet of gas per day) prior to December 28, 2007, the same target applicable to the Merger earn-out shares. However, one of the Company’s officers entitled to receive earn-out shares resigned from the Company and its subsidiaries effective June 15, 2006, and as a result 225,000 of the unvested contingent incentive stock awards, representing $990,000 of future possible compensation expense, were forfeited. Subsequently, 190,000 shares of those 225,000 shares were awarded to the officer’s successor to supplement a previous award of 35,000 shares. The second earn-out target provided for in the original merger agreement related to its merger with Navidec, Inc. In November 2007, the production target in the Merger Agreement dated July 8, 2004 was achieved. The determination was made by the Company’s Board of Directors based on certification by the independent engineering firm that the Company’s production in Peru has met or exceeded the required level of production.

November 2007 Convertible Debt

In November of 2007, the Company issued a $15.5 million convertible note to the IFC. The convertible debt had a 10 year term with a variable interest rate of 2% per annum above 6-month LIBOR, 6.9% at December 31, 2007. Pursuant to the terms of the Convertible Debt Agreement, dated November 19, 2007, the convertible note had a conversion price of $10.39 per share and included a forced conversion, exercisable at the Company’s option, if the closing price of the Company’s common stock exceeds a price of $18.19 per share based on the average closing price over a period of twenty consecutive business days. In May 2008, the Company elected to exercise its option to convert $15.5 million of debt with the IFC into approximately1.5 million shares of common stock.

Potentially Dilutive Securities

In addition to the shares issued and outstanding, the Company has the following potentially dilutive securities at December 31, 2009 and 2008. None of these potentially dilutive shares have been included in the calculation of earnings per share as the effect would be anti-dilutive.

	2009	2008
	(in thousands)
Stock options outstanding	4,545	3,894
Warrants outstanding	—	—
Total potentially dilutive securities issued	4,545	3,894
Shares available pursuant to Long-Term Incentive Compensation Plans	1,539	2,541

The following table summarizes stock-based compensation costs recognized under ASC Topic 718, “Stock Compensation”, previously recognized under SFAS 123(R), for the years ended December 31, 2009, 2008, and 2007,

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

respectively, and is generally included in “General and administrative expense” on the Consolidated Statements of Operations :

	For the Year Ended December 31,
	2009		2008		2007
	(in thousands)
Employee stock—based compensation costs (a)	$	7,786	$	12,698	$	5,592
Director stock—based compensation costs (b) (c)	5,269		5,766		1,448
	$	13,055	$	18,464	$	7,040

(a) For the year ended December 31, 2008, additional compensation expense of $0.7 million was recognized for the year related to accelerated vesting for certain stock option awards.

(b) For the year ended December 31, 2009, additional stock-based compensation of approximately $0.7 million was recognized primarily related to the accelerated vesting for certain restricted stock and stock option awards granted to a former member of the Board of Directors.

(c) For the year ended December 31, 2009 approximately $0.4 million of stock-based compensation is included in “Other income (expense)” on the Consolidated Statements of Operations. The amount relates to 100,000 stock options awarded to a former member of the Board of Directors to purchase the Company’s common stock. The grant date fair value of the award was recognized upon issuance of the award.

Stock Option and Restricted Stock Plans

The Company has in effect the 2007 Long-Term Incentive Compensation Plan (the “2007 LTIP”) and the 2007 Directors’ Compensation Incentive Plan (the “Directors’ Plan”). The 2007 LTIP and Directors’ Plan provides 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 2007 LTIP and Directors’ Plan is 4.0 million and 2.5 million, respectively. As of December 31, 2009, 163,900 shares remain available for future grants under the 2007 LTIP and 1,375,000 shares remain available for future grants under the Directors’ Plan.

Restricted Stock Awards and Performance Shares

At December 31, 2009, there were approximately 787,900 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, 2009 and related information is presented below:

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

			Weighted—
	Number of		Average
	Restricted		Fair Value
	Shares		Per Share
Outstanding at the begining of the year	865,350		$	10.95
Granted	187,900			5.33
Vested	(265,350	)		8.85
Forfeited	—			—
Outstanding at the end of the year	787,900		$	10.32

The weighted average grant-date fair value of restricted stock awards granted for the year ended December 31, 2007 was $8.73. There were no restricted stock awards granted in 2008. The fair value of restricted stock awards that vested during the years ended December 31, 2009, 2008 and 2007 was $1.6 million, $6.7 million, and $5.9 million, respectively. As of December 31, 2009, there was $0.8 million of total unrecognized compensation cost related to nonvested restricted stock awards, which is expected to be recognized over a weighted-average period of 0.6 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.

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

	2009			2008			2007
Expected life (years) (a)	4.5			4.6			6
Risk-free interest rate (c)	2.5		%	3.6		%	4		%
Volatility (b)	91.9		%	81.0		%	82.31		%
Dividend yield (d)	—			—			—
Weighted-average fair value per share at grant date	$	3.75		$	14.48		$	7.07

(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.

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YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

A summary of the Company’s stock option activity for the year ended December 31, 2009 and related information is presented below:

					Weighted
			Weighted—		Average
			Average		Remaining	Aggregate
	Number of		Exercise Price		Contractual	Intrinsic
	Options		Per Option		Term	Value
Outstanding at the begining of the year	3,894,348		$	10.03
Granted	814,650			5.46
Exercised	(163,666	)		3.68
Forfeited	—			—
Outstanding at the end of the year	4,545,332		$	9.44	7.55	$	12,106,245
Exercisable at the end of the year	2,504,131		$	8.12	7.23	$	8,751,098

As of December 31, 2009, there was $4.5 million of unrecognized compensation cost related to non-vested stock options that is expected to be recognized over a weighted average period of 1.1 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 years ended December 31, 2009, 2008 and 2007 was $0.7 million, $16.0 million and $9.7 million, respectively. Cash received from stock option exercises for the years ended December 31, 2009, 2008 and 2007 was $0.6 million, $2.4 million and $3.4 million, respectively.

The following table summarizes information about stock options outstanding as of December 31, 2009:

			Outstanding				Exercisable
				Weighted-
				Average
				Remaining				Weighted-
				Contractual				Average
			Number of	Life	Weighted		Number of	Exercise Price
Range of Exercise Prices			Options(1)	(In years)	Exercise Price		Options	Per Option
Below	to	$2.12	99,248	4.7	$	1.30	99,248	$	1.30
$2.13	to	$4.23	800,000	6.4		3.40	800,000		3.40
$4.24	to	$6.35	1,323,650	8.6		5.14	556,338		4.93
$6.36	to	$8.47	209,234	5.9		6.48	168,410		6.47
$8.48	to	$10.58	251,200	8.0		10.22	154,133		10.32
$10.59	to	$25.53	1,862,000	7.6		15.75	726,002		16.60
Total			4,545,332	7.5	$	9.44	2,504,131	$	8.12

Note 11— Restatement of Merger Earn-Out Shares

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

remaining 9,000,000 earn-out shares were contingent on the Company becoming entitled to receive as its proportionate share from gross production from any oil and gas wells owned or operated by the Company not less than 2,000 barrels of oil per day or its equivalent (approximately 12 million cubic feet of gas per day) prior to December 28, 2007. On November 2, 2007 this production target was achieved, based on certification by an independent engineering firm that the Company’s production in Peru had met or exceeded the required level of production and the shares were issued. On November 2, 2007, the closing price of the Company’s common shares was $10.87 per share.

At the time of each earn-out, for accounting purposes, each earn-out was treated as a stock dividend because the earn-out was payable to the shareholders of the accounting acquirer, BPZ-Texas. Accordingly, we disclosed a retroactive increase in the number of common shares outstanding for all periods presented and no accounting entry was recorded upon the issuance of the earn-out shares. However, upon further analysis, the Company has determined that the presentation of the impact of the earn-outs should be changed to provide greater clarity concerning the associated re-allocation of value between the former BPZ-Texas shareholders and the other shareholders of the Company. Therefore, the Company has done the following:

(i) The Company recorded a distribution from its retained deficit to reflect the relative economic impact of the reallocation of shares and associated shareholder value at the fair value at the date of grant for each merger earn-out tranche. The effect of this transaction increased the Company’s cumulative retained deficit and common stock by $137.4 million.

(ii) The Company adjusted its presentation to show the merger earn-out shares when issued for each period presented without retroactively increasing the prior periods common shares outstanding. The issuance of the 2005 earn-out shares is therefore reflected in the beginning balance of the 2007 Consolidated Statement of Stockholders’ Equity and the issuance of the 2007 earn-out shares is reflected in 2007. The effect of this transaction decreased the weighted average outstanding share count for the years ended December 31, 2005, 2006 and 2007 by 13.5 million shares, 9.0 million shares and 7.5 million shares, respectively.

The following table shows the adjustment to Stockholders’ Equity in each period presented to reflect the fair value of the merger earn-out shares granted at each issuance date:

As Originally Reported (in thousands):

	December 31,
Stockholders’ Equity	2008			2007			2006			2005
Stockholders’ equity:
Preferred stock, no par value, 25,000,000 authorized; none issued and outstanding	$	—		$	—		$	—		$	—
Common stock, no par value, 250,000,000 authorized; 78,748,390, 73,914,471, 54,143,717 and 40,347,979 shares issued and outstanding at December 31, 2008, 2007, 2006 and 2005, respectively	227,136			149,050			96,575			56,874
Additional paid in capital	—			—			5,092			2,401
Stock subscription receivable	—			—			(231		)	(231		)
Accumulated deficit	(67,956		)	(58,310		)	(37,800		)	(22,312		)

Total stockholders’ equity	$	159,180		$	90,740		$	63,636		$	36,732

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As Adjusted (in thousands):

	December 31,
Stockholders’ Equity	2008			2007			2006			2005
Stockholders’ equity:
Preferred stock, no par value, 25,000,000 authorized; none issued and outstanding	$	—		$	—		$	—		$	—
Common stock, no par value, 250,000,000 authorized; 78,748,390, 73,914,471, 54,143,717 and 40,347,979 shares issued and outstanding at December 31, 2008, 2007, 2006 and 2005, respectively	364,566			286,480			136,175			96,474
Additional paid in capital	—			—			5,092			2,401
Stock subscription receivable	—			—			(231		)	(231		)
Accumulated deficit	(205,386		)	(195,740		)	(77,400		)	(61,912		)

Total stockholders’ equity	$	159,180		$	90,740		$	63,636		$	36,732

The following table shows the adjustment to the Stockholders’ Equity in each of the 2009 and 2008 quarterly periods presented to reflect the fair value of the merger earn-out shares outstanding:

2009 As Originally Reported (In thousands except share data):

Stockholders’ Equity	March 31,			June 30,			September 30,
	(Unaudited)			(Unaudited)			(Unaudited)
Stockholders’ equity:
Preferred stock, no par value, 25,000,000 authorized; none issued and outstanding	$	—		$	—		$	—
Common stock, no par value, 250,000,000 authorized; 94,486,094, 113,399,234 and 115,079,760 shares issued and outstanding at March 31, 2009, June 30, 2009 and September 30, 2009, respectively	275,271			362,235			372,622
Accumulated deficit	(75,004		)	(84,818		)	(93,780		)

Total stockholders’ equity	$	200,267		$	277,417		$	278,842

2009 As Adjusted (In thousands except share data):

Stockholders’ Equity	March 31,			June 30,			September 30,
	(Unaudited)			(Unaudited)			(Unaudited)
Stockholders’ equity:
Preferred stock, no par value, 25,000,000 authorized; none issued and outstanding	$	—		$	—		$	—
Common stock, no par value, 250,000,000 authorized; 94,486,094, 113,399,234 and 115,079,760 shares issued and outstanding at March 31, 2009, June 30, 2009 and September 30, 2009, respectively	412,701			499,665			510,052
Accumulated deficit	(212,434		)	(222,248		)	(231,210		)

Total stockholders’ equity	$	200,267		$	277,417		$	278,842

2008 As Originally Reported (In thousands except share data):

Stockholders’ Equity	March 31,			June 30,			September 30,
	(Unaudited)			(Unaudited)			(Unaudited)
Stockholders’ equity:
Preferred stock, no par value, 25,000,000 authorized; none issued and outstanding	$	—		$	—		$	—
Common stock, no par value, 250,000,000 authorized; 76,438,471, 78,251,890 and 78,745,890 shares issued and outstanding at March 31, 2008, June 30, 2008 and September 30, 2008, respectively	192,360			215,783			222,103
Accumulated deficit	(65,732		)	(70,388		)	(61,777		)

Total stockholders’ equity	$	126,628		$	145,395		$	160,326

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2008 As Adjusted (In thousands except share data):

Stockholders’ Equity	March 31,			June 30,			September 30,
	(Unaudited)			(Unaudited)			(Unaudited)
Stockholders’ equity:
Preferred stock, no par value, 25,000,000 authorized; none issued and outstanding	$	—		$	—		$	—
Common stock, no par value, 250,000,000 authorized; 76,438,471, 78,251,890 and 78,745,890 shares issued and outstanding at March 31, 2008, June 30, 2008 and September 30, 2008, respectively	329,790			353,213			359,533
Accumulated deficit	(203,162		)	(207,818		)	(199,207		)

Total stockholders’ equity	$	126,628		$	145,395		$	160,326

The following table shows the adjustment to earnings per share for each annual period presented to reflect the increase in shares outstanding when issued without retroactively increasing the prior periods common shares outstanding:

As Originally Reported (in thousands except per share data):

	For the Year Ended December 31,
Operating Results:	2007			2006			2005

Net loss	$	(20,510	)	$	(15,487	)	$	(6,407	)

Basic and diluted net loss per share	$	(0.30	)	$	(0.29	)	$	(0.16	)

Weighted average common shares outstanding	69,156			53,752			40,899

As Adjusted (in thousands except per share data):

	For the Year Ended December 31,
Operating Results:	2007			2006			2005

Net loss	$	(20,510	)	$	(15,487	)	$	(6,407	)

Basic and diluted net loss per share	$	(0.33	)	$	(0.35	)	$	(0.23	)

Weighted average common shares outstanding	61,660			44,752			27,399

Note 12 — Affiliate and Related Party Transactions

For the years ended December 31, 2009, 2008 and 2007, the Company had not entered into any transactions with affiliates or related parties.

Note 13 — Revenue

At December 31, 2009, the Company is currently producing oil from five wells in the Corvina field and one well in the Albacora field under a well testing program. At December 31, 2008, the Company was producing oil from four wells in the Corvina field under a well testing program.

The Company began producing oil on a limited basis in November 2007 from the CX11-21XD and CX11-14D wells in the Corvina field under a well testing program. During the second and fourth quarter of 2008, it added production from the

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CX11-18XD and CX20-20XD wells under the well testing program. In the second quarter of 2009, the Company added the CX11-15D well in the Corvina field and during the fourth quarter of 2009 the Company added CX11-19D well in the Corvina field and the A-14D well in the Albacora field to its well testing program.

The oil is delivered by barge to the Petroleos del Peru - PETROPERU S.A. ((“Petroperu”) a private law state company engaged in the refining, transportation, distribution and trading of petroleum products to meet Peru’s domestic energy needs) refinery in Talara, located approximately 70 miles south of the platform. Produced oil is kept in production inventory until the Company increases the inventory quantities to a sufficient level that the refinery in Talara will accept delivery.

In January 2009, the Company, through its wholly-owned subsidiary BPZ E&P, entered into a long-term oil supply agreement with Petroperu. Under the terms of the contract, the Company agrees to sell, and Petroperu agrees to purchase the Company’s crude oil production originating from the Corvina oilfield in Block Z-1. The contract term is for approximately seven years or until 17 million barrels of crude oil has been delivered to the Petroperu refinery located in Talara, whichever comes first. The price per barrel of oil under the agreement is determined using a basket of crude oils based on a 15-day average of Forties, Oman, and Suez blend crude oil prices, as quoted in the Spot Crude Prices Assessment published in Platt’s Crude Oilgram Price Report, minus $1 per barrel and other customary purchase price adjustments. The Company is currently in negotiations with Petroperu to finalize a short term oil sales contract for up to 400,000 barrels of oil originating from the Albacora field.

In 2007 and 2008, the Company had two short-term contracts for the sale of oil with Petroperu since it began oil production in November 2007. The first contract was for the sale of up to 200,000 barrels of oil to the refinery in Talara. The contract was fulfilled in June 2008. During the second half of 2008, the Company’s sales agreement with Petroperu was for the delivery of up to 400,000 barrels of oil to the Talara refinery whose per barrel sales price was based on Northwest Oil Basket pricing which is comprised of Oman, Fortes and Suez Blend pricing. The unadjusted sales price was based on the past five day average before the crude oil delivery date. The price was then discounted for the quality of the oil delivered. The determination of quality was based on the gravity of the oil expressed in degrees, as determined under standards established by the American Petroleum Institute (“API”). The price was discounted at a rate of 0.53% of the basket price per one degree API lower than the benchmark of 33 degrees API as stipulated in the contract. In addition, a fixed premium of $0.75 per barrel was added to the price as a result of the high diesel content of the crude oil.

During the years ended December 31, 2009, 2008 and 2007, the Company produced approximately 991,003, 826,534 and 40,989 barrels of oil, respectively. For the years ended December 31, 2009, 2008 and 2007, the Company sold 962,551, 825,845 and 28,741 barrels of oil at an average per barrel price, net of royalties, of approximately $54.49, $76.23 and $81.78, respectively.

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. However their calculation is based on the past five-day average basket of crude oils prices, as discussed above, before the crude oil delivery date. For the years ended December 31, 2009, 2008 and 2007, the revenues received by the Company are net of royalty costs of approximately 5% of gross revenues or $2.9 million, $3.3 million and $0.1 million, respectively.

Note 14 — Income Taxes

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

	2009			2008			2007
United States	$	860		$	(28,122	)	$	(12,922	)
Foreign	(43,237		)	21,617			(7,549		)
Loss from continuing operations before income taxes	$	(42,377	)	$	(6,505	)	$	(20,471	)

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

	2009			2008			2007
Current Taxes
Federal	$	200		$	—		$	39
Foreign	6,709			7,536			—
Total Current Taxes	6,909			7,536			39

Deferred Taxes
Federal		—			—			—
Foreign	(13,484		)	(4,395		)	—
Total Deferred Taxes	(13,484		)	(4,395		)	—
Total Income Tax Provision (Benefit)	$	(6,575	)	$	3,141		$	39

The income tax expense (benefit) for the year ended December 31, 2009, 2008 and 2007 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):

	2009			2008			2007
Federal statutory income tax rate	$	(14,408	)	$	(2,212	)	$	(7,139	)
Increases (decreases) resulting from:	—			—			—
Peruvian income tax - rate difference less than 34% statutory	—			—			—
Non-deductible stock compensation expense	2,908			6,551			3,653
Non-deductible intercompany expenses and other	4,180			—			—
Tax effect of Peru conversion to permanent establishment status	—			7,642			—
Change in domestic valuation allowance	745			(8,840		)	3,525
Total Income Tax Provision (Benefit)	$	(6,575	)	$	3,141		$	39

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The tax effects of the temporary differences that give rise to the significant portions of the deferred tax assets and liabilities at December 31, 2009 and 2008 are presented below (in thousands):

	2009			2008
Deferred Tax:
Asset:
Net Operating Loss	$	16,546		$	19,941
Deferred Compensation	2,514			1,889
Foreign Tax AMT	1,647			—
Asset Basis Difference	—			—
Exploration Expense	7,256			2,080
Depreciation	—			12
Depletion	8,162			3,340
Asset Retirement Obligation	67			27
Overhead Allocaion to Foreign Locations	2,298			—
Other	119			666
Liability:	—			—
Preoperation Expenses	(295		)	(295		)
Depreciation	(18		)
Asset Basis Difference	(1,819		)	(1,298		)
Other	(1		)	(300		)
Net Deferred Tax Asset	$	36,476		$	26,062

Less Domestic Valuation Allowance	(19,548		)	(21,191		)
Deferred Tax Asset	$	16,928		$	4,871

As of December 31, 2009, the Company had a valuation allowance for the full amount of the domestic deferred tax asset 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 2028. Furthermore, because the Company has no operations within the U.S. taxing jurisdiction, it is likely that a sufficient generation of revenue to offset the Company’s deferred tax asset is remote. As a result, the Company has a full allowance on its deferred tax asset generated in the U.S. However, 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%. Because the Company is under a well testing program from which it will finalize a development plan for Block Z-1, it has not moved into the commercial phase of production as defined by the license contract. As such, certain deductions are disallowed by the Peruvian tax regime while the Company operates under the well testing program. In addition, the tax provision is based on taxable Peruvian income that excludes certain U.S. expenses that are not deductible at the Peruvian level. As a result, the Company recognized a total tax provision for the year ended December 31, 2009 of approximately $6.6 million.

The Company anticipates moving into commercial production in Block Z-1 under the license contract in 2010, at which time its full investment in its producing properties will be eligible to be amortized over five years. The Company assessed the realizability of the deferred tax asset generated in Peru. It 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 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 benefits of the these deductible differences at December 31, 2009. As a result, the Company recognized a deferred tax asset of $16.9 million as of December 31, 2009.

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unrecognized tax benefits, nor was any interest expense recognized during the year. Additionally, the adoption had no effect on the Company’s financial position or results of operations. 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, 2009 or December 31, 2008.

Note 15 — Business Segment Information

The Company determines and discloses its segments in accordance with ASC Topic 280, “Segment Reporting” (“ASC Topic 280”) , previously in accordance with SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information”, 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 parlance 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 years ended December 31, 2009, 2008 and 2007 and 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.

Note 16 — Commitments and Contingencies

Extended Well Testing Program

On December 13, 2009 new legislation regulating extended well testing in Peru became effective by means of a Supreme Decree. The new regulation provides that all new wells may be placed on production testing for up to six months. If the operator believes that 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 Extended Well Test (“EWT”) period must be submitted to the DGH, the agency of the Ministry of Energy and Mines responsible for regulating the optimum development of oil and gas fields. The approval process for an EWT permit requires that the DGH request Perupetro’s opinion on the technical justification for the EWT. 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. For wells that have been under testing for more than six months as of the date of publication of the Supreme Decree, the new regulation provides 30 business days to apply to the DGH for the corresponding EWT permit.

On December 29, 2009, the Company received approval, from Perupetro, of its proposed First Date of Commercial Production (“FDCP”), as set forth in the current Field Development Plan (“FDP”) for the Corvina field in Block Z-1, which is May 31, 2010.

On January 25, 2010, the Company applied for an extended well testing permit in Corvina for the first five wells (not including the CX11-19D and CX11-17D wells) as it believes it is necessary to continue gathering data to fully understand the drive mechanisms that are present in Corvina. On March 23, 2010, the Company received a decision from the DGH notifying it that they are approving BPZ to continue extended well testing on its first five Corvina wells until the FDCP date of May 31, 2010, subject to specific limits on the amount of natural gas flared from each of the first five Corvina wells. Based on the natural gas flaring limits set by the DGH, the Company expects to constrain the oil production from some or all of those five Corvina wells in order to comply with those limits. The actual future decrease in production from these five Corvina wells will not be known until the Company fully implements its gas flaring mitigation strategy to optimize oil production while complying with the gas flaring limits, but production from these wells could decrease by as much as 400 to 800 bopd.

The Company initially planned to have the needed gas and water re-injection facilities at the CX-11 platform by May 31, 2010. However, this no longer appears to be reachable due to the delayed delivery of certain equipment. If the Company is unable to receive and install the necessary water and gas reinjection equipment and receive approval of the corresponding environmental permits by May 31, 2010, it may not be permitted to produce from some or all of the oil wells in Corvina until such installation is completed or an extension of the May 31, 2010 date is obtained. The Company will apply to the proper authorities for an extension of the May 31, 2010 date to be able to maintain testing the wells in Corvina; however, no assurance can be given that such extension will be awarded. Depending on the extent of the delay, the Company plans to use the additional time to drill one or two more wells from the CX-11 platform after the current well, the

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CX11-22D is completed. Further, the Company may not be able to produce any well drilled after December 13, 2009 for a period longer than the initial six month testing period. The Company’s current view is that it may be able to produce its new wells CX11-17D, CX11-19D, CX11-22D, and any other well drilled at the CX-11 platform for at least six months, as stated by the new well testing regulations. Testing these wells beyond the initial six month period will require a special application to the Ministry of Energy and Mines that may or may not be granted approval.

In addition, the Company is in the initial stages of appraising, exploring and developing its potential oil and natural gas reserves in the Albacora field of Block Z-1. The Company’s first well in Albacora has been, and all new wells drilled in Albacora will be, placed in the initial six-month production testing under the new legislation. As in Corvina, the Company will need to receive approval for all the pertinent environmental and technical permits and install the required gas and water reinjection facilities at the Albacora platform in order to transition from exploration to commercial production, which as currently estimated could take up to two years. If the Company does not receive EWT permits on wells in Albacora beyond the original six-month test period, it will experience an interruption in production that would negatively impact any revenue and cash flow associated with those wells until the applicable requirements are satisfied for commercial production.

Profit Sharing

The Constitution of Peru and Legislative Decree Nos. 677 and 892 gives Peru employees working in private companies engaged in activities generating income classified as third category income by the Income Tax Law the right to share in the Company’s Peruvian subsidiaries 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 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 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 years ended December 31, 2009 and 2008, approximately $1.3 million and $1.9 million of expense related to profit sharing is included in “General and administrative expense” in the Consolidated Statement of Operations as the Company’s Peruvian subsidiaries have “income subject to taxation” per the Peruvian tax code. No profit sharing was incurred by the Company for 2007 as the Company’s Peruvian subsidiaries did not have “income subject to taxation” per the Peruvian tax code during this period. The Company will be subject to profit sharing expense each year its Peruvian subsidiaries are considered profitable under the Peruvian tax code.

Barge Incident

In August 2006, the Company incurred an operational delay resulting from a navigation incident which caused the BPZ-01 barge to be grounded on a sand bar in Talara Bay in northwest Peru. The Company expects to file an insurance claim after the dry docking of the vessel. The dry dock of the BPZ-01 is scheduled during the third quarter of 2010. As of December 31, 2009, the Company has not presented a final claim to its insurance carrier for the barge repairs.

The Company believes the majority of the costs associated with the grounding incident will be reimbursed through insurance or through a third party. No assurances can be given, however, that any such recoveries will be sufficient to cover all costs associated with the incident or to the timing of any such recoveries. The Company intends to file an insurance claim with its underwriters after it has fully assessed the damages and estimated repair costs as well as finalized the reimbursement agreement with the third party.

Peru Properties

As of December 31, 2009, the Company has restricted cash deposits of $5.7 million. In connection with the Company’s properties in Peru, it has obtained four performance bonds totaling $5.3 million that are partially collateralized by restricted cash deposits of $3.1 million to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally, the Company has $1.6 million of restricted cash to collateralize insurance bonds for import duties related to the BPZ-01 barge and the crane on board the BPZ-01. The Company also has $1.0 million of restricted cash held in a trust account in order to secure financing to support our operations. In

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January 2010, the $1.0 million of restricted cash held in a trust account was released in order to make the final payment on the Company’s short-term loan agreement. Furthermore the Company has an unsecured performance bond of $0.1 million to guarantee its performance under its new office lease agreement in Peru.

GE Turbine Purchase Agreement, Amendment and Letter Agreement

On September 26, 2008, the Company, through its subsidiary Empresa Electrica Nueva Esperanza S.R.L., entered into a $51.5 million contract (the “Agreement”) for the purchase of three LM6000 gas-fired turbines 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 will give rise to a breach of contract or the right to terminate the contract, provided the Company 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, the Company paid the first progress payment of $3.4 million. The Company was still in negotiations with GE to modify the terms of the Agreement at the time the second progress payment was due on November 16, 2009, and GE agreed to a short extension of the deadline for the milestone payment in order to conclude ongoing negotiations with respect to new delivery dates, pricing, payment terms and payment security for the reinstatement of the Agreement. Amended terms were agreed with GE by Letter Agreement on November 20, 2009, at which time the Company made the $3.5 million progress payment. Under the terms of the Letter Agreement, GE and BPZ agreed to a variable monthly payment plan with a final $20.7 million payment due December 1, 2010 for the remaining $35.2 million due under the Agreement. Additionally, should the Company locate a joint venture partner and obtain financing for the three LM6000 gas-fired turbines and services prior to the December 1, 2010 deadline, the Company agrees to pay the final payment under the Letter Agreement within 7 days of obtaining the financing and funding.

Should the Company not make the payments in accordance with the terms of the Letter Agreement, this would result in immediate termination of the Agreement without any additional notice or cure period. As of December 31, 2009, the Company has made payments to GE totaling $16.5 million. Additionally in March 2010 the Company made a $2.5 million payment and plans to meet the remaining payments due throughout 2010 by using proceeds of the recent convertible debt offering or subsequent project financing. Failure to make any of the remaining progress payments in full would result in a charge-off of all of the previously made progress payments.

Reserve-Based Credit Facility

In July 2009, the Company, through its subsidiary, BPZ E&P, had secured formal commitments for a $70.0 million reserve based credit facility, including $15.0 million previously received under the IFC Facility. The syndication of this facility was led by Natixis, a major French bank. The other institutions participating in the syndicate include IFC, Scotiabank and Banco de Crédito del Perú.

Subsequent to December 31, 2010, the Company, through its subsidiary, BPZ E&P, elected to terminate negotiations on the previously announced $55.0 million portion of the reserve based credit facility being arranged by Natixis. With the proceeds from the 2015 Convertible Notes offering, the termination of these negotiations is not expected to impact the Company’s ability to undertake its 2010 capital expenditures program, including drilling and continued development of the Corvina and Albacora fields as well as payments due under the GE turbine purchase agreement.

Gas-to-Power Project Financing

The Company currently estimates the gas-to-power project will cost approximately $135.0 million, excluding 19% value-added tax which will be recovered via early recovery and/or future revenue billings. The $135.0 million includes $115.0 million for the estimated cost of the power plant and $20.0 million for the estimated cost of the construction of the

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BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

natural gas pipeline. Accordingly, the Company commenced discussions with potential joint venture partners for the gas-to-power project in an attempt to secure additional equity for the project. After receiving proposals for the Corvina gas-to-power project, management selected a potential joint venture partner in June 2009. The joint venture will be subject to the satisfactory negotiation of a joint venture agreement and related documents. To date, the Company has not entered into any definitive agreements and is not currently in ongoing negotiations with a potential partner. In the event the Company is able to reach agreement with a potential joint venture partner, it may only retain a minority position in the project. However, the Company expects to retain the responsibility for the construction of the pipeline as well as retain ownership of the pipeline. If the Company is unable to reach agreement with a potential partner, it is planning to continue moving the project forward to completion. Decisions regarding project financing will be determined as the Company moves the project forward to completion.

Note 17 — 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 commercial division of the Peruvian Navy 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 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 the BPZ Resources, Inc. and BPZ Energy LLC., parent entities of BPZ E&P that were not parties to the charter operation. Based on the Company’s assessment of the available facts including the fact that none of the Peruvian government-sanctioned investigations into the Supe incident found fault on the part of Tecnomarine or BPZ E&P, the Company does not believe the outcome of the legal proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. The Company intends to vigorously defend this action but cautions that there is inherent risk in litigation, which is difficult to quantify, especially at the early stage of litigation proceedings. The Company believes in any event that any monetary damages arising from the incident would be adequately covered by its insurance policies, after a customary deductible.

Disputed Contract Settlement

Towards the end of the first quarter of 2009, the Company was notified of an alleged breach of a contractual obligation to a former consultant of the Company related to services provided to both the Company and its predecessor at the time the Company became publicly traded. The Company has settled this dispute and, as a result of the settlement, the Company agreed to pay $0.8 million in exchange for a release of all claims against the Company for damages related to the disputed contract obligation. The payment is included in “Other income/(expense)” in the Consolidated Statements of Operations. The Company paid the $0.8 million settlement in April 2009.

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BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

Note 18 — Operating Leases and Purchase Obligations

The Company is committed under various operating leases, which primarily relate to office space, warehouse rental, drilling rig equipment, and marine support vessels. Total rent expense incurred for the years ended December 31, 2009, 2008 and 2007 was approximately $1.4 million, $0.5 million and $0.3 million, respectively.

Minimum non-cancelable lease and purchase commitments are as follows (in thousands):

For Year Ending December 31,

2010	$	74,826
2011	20,376
2012	8,154
2013	1,661
2014	1,418
Thereafter	576
Total minimum lease and purchase commitments	$	107,011

Includes operating leases for our executive office in Houston, Texas, and our branch offices in Lima, Peru and warehouses in Peru, respectively, including the renting of current office space and warehouse space in Peru on a month-to-month basis through March 2010 and new office space and warehouse space in Peru through 2013, respectively. The operating lease amounts also exclude $0.2 million of sublease rentals from our Houston, Texas office due in the future under noncancelable subleases.

Includes the monthly lease expense for two drilling rigs, one located at the Corvina platform and one located at the Albacora platform. The Corvina rig lease is set to expire in July 2011 and the Albacora rig lease is set to expire in July 2012.

Includes the monthly lease expense for one of our oil transportation vessels whose lease is set to expire in March 2010.

Includes the remaining amounts due for purchase of three LM6000 gas-fired turbines from GE whose total purchase price is $51.5 million.

Note 19 — Subsequent Events

Subsequent to December 31, 2009, the Company issued approximately $170.9 million of convertible debt described in Note 9 “Long-Term Debt and Capital Lease Obligations.

Subsequent to December 31, 2009, the Company announced the termination of negotiations with Natixis for its reserve based lending facility. See Note 16, “Commitments and Contingencies” for further information.

Subsequent to December 31, 2009, the Company made a $2.5 million progress payment under the GE contract. See Note 16, “Commitments and Contingencies” for further information.

Subsequent to December 31, 2009, the Company received communication from DGH regarding its application for extended well testing for its first five Corvina wells. See Note 16, “Commitments and Contingencies” for further information.

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BPZ RESOURCES, INC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

Note 20 — Quarterly Results of Operations (Unaudited)

	Three Months Ended
	March 31,			June 30,			September 30,			December 31,
	(in thousands except per share data)
2009
Revenue, net	$	13,225		$	11,049		$	13,088		$	15,092
Operating loss	(7,462		)	(10,885		)	(11,155		)	(12,986		)
Other income (expense)	(794		)	(584		)	401			1,088
Net loss	$	(7,048	)	$	(9,813	)	$	(8,963	)	$	(9,978	)

Basic net income (loss) per share	$	(0.08	)	$	(0.10	)	$	(0.08	)	$	(0.09	)
Diluted net income (loss) per share

Basic and diluted weighted average common shares outstanding	88,620			95,347			113,929			115,135

	Three Months Ended
	March 31,			June 30,			September 30,		December 31,
	(in thousands except per share data)
2008
Revenue, net	$	4,367		$	7,035		$	33,440	$	18,113
Operating loss	(7,539		)	(5,225		)	13,567		(8,447		)
Other income (expense)	209			717			95		118
Net income (loss)	$	(7,422	)	$	(4,656	)	$	8,611	$	(6,179	)

Basic net income (loss) per share	$	(0.10	)	$	(0.06	)	$	0.11	$	(0.08	)
Diluted net income (loss) per share	$	(0.10	)	$	(0.06	)	$	0.11	$	(0.08	)

Basic weighted average common shares outstanding	74,525			77,681			78,575		78,748
Diluted weighted average common shares outstanding	74,525			77,681			80,323		78,748

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BPZ RESOURCES, INC AND SUBSIDIARIES
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

YEARS ENDED DECEMBER 31, 2009, 2008 and 2007

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.

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 average first-day-of the month 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

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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.

The Company’s 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; and

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

In 2009, an average of the first-day-of-the month price based upon the prior 12-month period will be used for future sales of natural gas, crude oil and natural gas liquids. Future operating costs, production taxes and capital costs will be 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 risk.

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, 2009 and 2008:

	2009			2008
	(in thousands)
Proved properties	$	226,299		$	154,827
Unproved properties	13,304			15,343
Total	239,603			170,170
Less: Accumulated depreciation, depletion and amortization	(38,991		)	(15,946		)
Net capitalized cost	200,612			154,224

Company’s share of cost method investees’ costs of property acquisition, exploration and development (1)	$	—		$	—

(1) BPZ Energy purchased the Investment in Ecuador Property in 2004.

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Pursuant to ASC Topic 410, “Asset Retirement and Environmental Obligations”, previously accounted for in accordance with SFAS No 143 “Accounting for Asset Retirement Obligations”, net capitalized cost includes asset retirement costs of $0.8 million and $0.6 million as of December 31, 2009 and December 31, 2008, respectively.

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, 2009 and 2008 (in thousands):

	Total
Year Ended December 31, 2009:
Acquisition costs of properties
Proved	$	—
Unproved	—

Total acquisition costs	—
Exploration costs	9,546
Development costs	78,782

Total	$	88,328

Company’s share of cost method investees’ costs of property acquisition, exploration and development (1)	$	—

Year Ended December 31, 2008:
Acquisition costs of properties
Proved	$	—
Unproved	—

Total acquisition costs	—
Exploration costs	795
Development costs	82,845

Total	$	83,640

Company’s share of cost method investees’ costs of property acquisition, exploration and development (1)	$	—

(1) BPZ Energy purchased the Investment in Ecuador Property in 2004.

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Results of Operations for Oil and Natural Gas Producing Activities

The results of operations for oil and natural gas producing activities exclude interest charges and general and administrative expenses. Sales are based on market prices.

	Year Ended December 31,
	2009			2008		2007
				(in thousands)
Oil and natural gas production revenues
Third-party	$	52,454		$	62,955	$	2,350
Affiliate	—			—		—

Total revenues	52,454			62,955		2,350
Exploration expenses	7,768			794		4,045
Production costs	28,113			11,649		755
Depreciation, depletion and amortization	22,224			15,141		538
Oil and natural gas impairment	—			—		—

Income (loss) before income taxes	(5,651		)	35,371		(2,988		)
Income tax provision (benefit)	(1,243		)	3,141		—

Results of continuing operations	$	(4,408	)	$	32,230	$	(2,988	)

Company’s share of cost method investees’ results of operations for producing activities(1)	$	1,396		$	905	$	452

(1) Investment in Ecuador Property

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Net Proved Reserve Summary

The following table sets forth the Company’s net proved developed and undeveloped reserves at December 31, 2009, 2008, 2007 and 2006, and the changes in the net proved reserves for each of the three years in the period then ended. 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.

	Natural gas (MMcf)(4)	Natural gas liquids and crude oil (MBbls)(1)		(MBbls) equivalents(2)

Net proved reserves at December 31, 2006	—	—		—

Revisions of previous estimates	—	—		—
Purchases of minerals in place	—	—		—
Extensions, discoveries and other additions (6)	—	11,981		11,981
Sales in place	—	—		—
Production (8)	—	(41	)	(41	)
Other	—	—		—

Net proved reserves at December 31, 2007	—	11,940		11,940

Revisions of previous estimates (7)	—	(1,699	)	(1,699	)
Purchases of minerals in place	—	—		—
Extensions, discoveries and other additions (6)	—	7,740		7,740
Sales in place	—	—		—
Production (8)	—	(827	)	(827	)
Other	—	—		—

Net proved reserves at December 31, 2008	—	17,154		17,154

Revisions of previous estimates (7)	—	(1,552	)	(1,552	)
Purchases of minerals in place	—	—		—
Extensions, discoveries and other additions (6)	—	22,873		22,873
Sales in place	—	—		—
Production (8)	—	(991	)	(991	)
Other	—	—		—

Net proved reserves at December 31, 2009	—	37,484		37,484

Company’s proportional interest in reserves of investees accounted for by the cost method—December 31, 2009 (3)	—	219		219

Proved Developed Reserves as of:
December 31, 2006 (5)	—	—		—

December 31, 2007	—	2,977		2,977

December 31, 2008	—	4,223		4,223

December 31, 2009	—	9,912		9,912

Proved Undeveloped Reserves as of:
December 31, 2006 (5)	—	—		—

December 31, 2007	—	8,963		8,963

December 31, 2008	—	12,930		12,930

December 31, 2009	—	27,573		27,573

(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

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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 disclosed amounts of proved 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 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 Company did not have the financial capacity or commitments for a development program of this magnitude. Accordingly, the Company did not disclose amounts of proved reserves in its SEC filings for the year ended December 31, 2006.

(6) The 2007 balance represents the initial oil reserves as a result of completing the two initial wells drilled and completed by the Company toward the end of 2007. The 2008 additions to the extensions, discoveries and additions of 7.8 MMBbls were due to additional wells drilled in 2008. The 2009 additions to the extensions, discoveries and additions of 22.8 MMBbls were due to additional wells drilled in the Corvina field (12. 8 MMBbls) and the discoveries of the Albacora field (10.1 MMBbls).

(7) The 2008 negatives revisions were due to price. The 2007 reserve analysis as prepared by NSAI used $85.49 per barrel price while the 2008 reserve analysis as prepared by NSAI used a $37.80 per barrel price, resulting in a negative revision of 1.7 MMBbls in 2008. The 2009 reserve analysis as prepared by NSAI included negatives revisions due to performance. The negative revision was due to the lower than expected performance of the CX11-14D, CX11-18XD, and CX11-20XD wells and corresponding revisions of other wells resulting in a negative revision of 1.6 MMBbls.

(8) The 2007 and 2008 oil production was from the Corvina field. The 2009 oil production of 991 MBbls includes 984MBbls from the Corvina field and 7 MBbls from the Albacora field.

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.

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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 years ended December 31, 2009, 2008 and 2007 (in thousands):

December 31, 2009
Future cash inflows (3)	$	2,147,862
Future production costs	(402,673		)
Future development costs	(402,600		)
Future income tax expenses	(256,746		)
Future net cash flows	1,085,843
Discount to present value at 10% annual rate	(347,284		)

Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	738,559

Company’s share of cost method investees’ standardized measure of discounted future net cash flows (1)	$	6,898

December 31, 2008
Future cash inflows (3)	$	648,414
Future production costs	(103,999		)
Future development costs	(127,300		)
Future income tax expenses	(62,240		)
Future net cash flows	354,875
Discount to present value at 10% annual rate	(55,948		)

Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	298,927

Company’s share of cost method investees’ standardized measure of discounted future net cash flows (1)(2)	$	2,756


December 31, 2007
Future cash inflows (3)	$	1,020,728
Future production costs	(135,263		)
Future development costs	(79,400		)
Future income tax expenses	(155,081		)
Future net cash flows	650,984
Discount to present value at 10% annual rate	(94,302		)

Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	556,682

Company’s share of cost method investees’ standardized measure of discounted future net cash flows (1)(2)	$	3,400

(1) Investment in Ecuador Property

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

(3) The per barrel price used in determining future cash inflows for the year ended December 31, 2009, 2008 and 2007 were $57.30, $37.80 and $85.49, respectively.

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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. As 2008 is the first year subsequent to the Company’s initial development and production of its proved oil reserves, the required information is presented only for the years ended December 31, 2009 and 2008 as follows:

	Year Ended December 31,
	2009			2008
	(in thousands)
Standardized measure of discounted future net cash flows, beginnning of the year	$	298,927		$	556,682
Sales and transfers of natural gas, natural gas liquids and crude oil produced, net of production costs	(24,341		)	(51,306		)
Change in estimated future developemnt costs	(303,666		)	—
Net changes in prices and production costs	221,655			(368,287		)
Extensions, discoveries, additions and improved recovery, net of related costs	624,402			160,831
Development costs incurred	78,782			82,845
Revisions of previous quantity estimates and development costs	(58,805		)	(42,462		)
Accretion of discount	24,559			30,501
Net change in income taxes	(119,579		)	(64,330		)
Changes in timing and other	(3,375		)	(5,547		)
Standardized measure of discounted future net cash flows, end of the year	$	738,559		$	298,927

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

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, 2009 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 Securities and Exchange 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, 2009 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

(c) Management’s Report on Internal Control over Financial Reporting and Report of Independent Registered Public Accounting Firm 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, 2009.

Johnson Miller & Co., CPA’s PC, 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, 2009, which is set forth below under “Attestation Report”.

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(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. and Subsidiaries’ internal control over financial reporting as of December 31, 2009, 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, 2009, 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. and Subsidiaries as of December 31, 2009 and 2008, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009, and our report dated March 31, 2010, expressed an unqualified opinion thereon.

/s/ Johnson Miller & Co., CPA’s PC
Midland, Texas

March 31, 2010

ITEM 9B. OTHER INFORMATION

None.

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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

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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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:	72

	Report of Independent Registered Public Accounting Firm	73

	Consolidated Balance Sheets	74

	Consolidated Statements of Operations	75

	Consolidated Statements of Stockholders’ Equity	76

	Consolidated Statements of Cash Flows	77

	Notes to Consolidated Financial Statements	78

	Supplemental Oil and Gas Disclosures (Unaudited)	110

	Management’s Report on Internal Control Over Financial Reporting	118

	Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting	119

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 Exhibit Index beginning on page 125 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.

121

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.

Boepd. Barrels 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.

Drill Stem Test. A test of the flow rates of a formation through the drill pipe to determine the fluid and gas content, pressure and estimated production rates of the reservoir.

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.

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

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.

PV-10 value. The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.

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.

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

123

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 31, 2010.

	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/ EDWARD G. CAMINOS
Manuel Pablo Zúñiga-Pflücker		Edward G. Caminos
President, Chief Executive Officer and Director		Chief Financial Officer
March 31, 2010		(Principal Financial Officer)
		March 31, 2010


/s/ HEATH W. CLEAVER		/s/ DR. FERNANDO ZÚÑIGA Y RIVERO
Heath W. Cleaver		Dr. Fernando Zúñiga y Rivero
Vice President — Chief Accounting Officer		Director and Chairman of the Board
(Principal Accounting Officer)		March 31, 2010
March 31, 2010


/s/ GORDON GRAY		/s/ DENNIS G. STRAUCH
Gordon Gray		Dennis G. Strauch
Director		Director
March 31, 2010		March 31, 2010


/s/ JOHN J. LENDRUM, III		/s/ JAMES B. TAYLOR
John J. Lendrum, III		James B. Taylor
Director		Director
March 31, 2010		March 31, 2010


/s/ STEPHEN C. BEASLEY
Stephen C. Beasley
Director
March 31, 2010

124

Table of Contents

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).

4.1		Form of Certificate for Common Stock of BPZ Resources, Inc., a Texas corporation (incorporated by reference to Exhibit 99.1 to the Company’s Form 10-Q filed on November 8, 2007).

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)

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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		C Loan Agreement between BPZ Resources, Inc. (formerly BPZ Energy, Inc.) and International Finance Corporation, dated November 17, 2007 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on November 26, 2007).

10.15		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).

10.16		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).

10.17		Stock Purchase Agreement by and among BPZ Resources, Inc. and Investors (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on February 24, 2009).

10.18		Placement Agency Agreement and form of the Subscription Agreement by and among BPZ Resources, Inc. and Investors with Placement Agents dated as of June 25, 2009 (incorporated by reference to exhibit 1.1 to the Company’s Form 8-K filed on June 29, 2009)

10.19		Subscription Agreement by and among BPZ Resources Inc. and International Finance Corporation , as Investor, to purchase 1,630,776 shares of common stock dated September 15, 2009 (incorporated by reference to exhibit 10.1 to the Company’s Form 8-K filed on September 16, 2009)

10.20		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)

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.

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Table of Contents

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.

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.

99.1		Report of Netherland, Sewell & Associates, Inc., filed herewith.

* - Management Contract or Compensatory Plan or Arrangement.

127

Attached files

BPZ RESOURCES, INC. Reports

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