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, 2008

Or

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

For the transition period from                to               

Commission File Number: 001-12697

BPZ Resources, Inc.

(Exact name of registrant as specified in its charter)

Texas	33-0502730
(State or other jurisdiction of incorporation)	(I.R.S. Employer Identification Number)

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

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

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

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, no par value	New York Stock Exchange Alternext U.S.

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 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  x	Accelerated filer                    o
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, 2008 was 52,728,868 shares, all of one class of common stock, no par value, having an aggregate market value of approximately $1,550,228,719 based upon the closing price of registrant’s common stock on such date of $29.40 per share as quoted on the New York Stock Exchange Alternext U.S. For purposes of the foregoing calculation, all directors, executive officers, and 5% beneficial owners have been deemed affiliated.

As of February 23, 2009 there were 93,054,150 shares of common stock, no par value, outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

(1) Proxy Statement for 2009 Annual Meeting of Stockholders — Part III

TABLE OF CONTENTS

PART I
Item 1.	Business	3
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	22
Item 2.	Properties	23
Item 3.	Legal Proceedings	28
Item 4.	Submission of Matters to a Vote of Security Holders	28
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	28
Item 6.	Selected Financial Data	31
Item 7.	Management’s Discussion and Analysis of Financial Conditions and Results of Operations	32
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 8.	Financial Statements and Supplementary Data	53
Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	96
Item 9A.	Controls and Procedures	96
Item 9B.	Other Information	97
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	98
Item 11.	Executive Compensation	98
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	98
Item 13.	Certain Relationships and Related Transactions, and Director Independence	98
Item 14.	Principal Accountant Fees and Services	98
PART IV
Item 15.	Exhibits and Financial Statement Schedules	99
Glossary of Oil and Natural Gas Terms		100
Signatures		102

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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 Ecuador. We also intend to utilize part of our planned future natural gas production as a supply source for the complementary development of a Company owned gas-fired power generation facility in Peru.

We maintain a subsidiary registered in Peru through our wholly-owned subsidiary BPZ Energy, LLC, a Texas limited liability company, formerly BPZ Energy, Inc. (“BPZ — Texas”) and its subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership. Currently, we have exclusive rights and license agreements for oil and gas exploration and production covering a total of approximately 2.4 million acres, in four blocks, in northwest Peru. Our license contracts cover 100% ownership of Block Z-1 (739,205 acres), Block XIX (472,860 acres), Block XXII (948,000 acres) and Block XXIII (248,000 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. Our license contracts provide for an initial exploration period of seven and potentially up to thirteen years for Block Z-1 and seven and potentially up ten years for Blocks XIX, XXII and XXIII. In addition, they require that we conduct specified activities on the Blocks during this period. If the exploration activities are successful, 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 applies 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-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.

We are in the initial stages of developing our oil and natural gas reserves and have begun producing and selling oil from the CX11 platform in the Corvina field of Block Z-1 under an extended well testing program. Additionally our activities in Peru include analysis and evaluation of technical data on our Blocks, preparation of the development plans for the Blocks, including detailed engineering and design of the power plant and gas processing facilities, refurbishment of and designs for platforms to carry 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 and securing the required capital and financing to conduct the current plan of operation.

At December 31, 2008, we had estimated net proved oil reserves of 17.2 MMBbls all of which were in the Corvina field in Block Z-1 located offshore northwest Peru. Of our total proved reserves, 4.2 MMBbls (25%) are classified as proved developed producing reserves and approximately 12.9 MMBbls (75%) are classified as proved undeveloped reserves. See “Supplemental Oil and Gas Disclosures (Unaudited)” to our consolidated financial statements provided herein for further information.

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We have determined our reporting structure provides for only one operating segment as we only operate in Peru and 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 53 of this Annual Report on Form 10-K.

Our Business Plan

Our business plan is to enhance shareholder value primarily through our unique knowledge of our targeted areas in Peru and leveraging management’s relationship with the local suppliers and regulatory authorities to effectively and efficiently operate the oil and gas exploration and development process in 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 which we currently have exclusive rights and license agreements for oil and gas exploration and production, contain structures which were 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 the hydrocarbons in the fields.  The Company, having found oil in its first well in the Corvina field in offshore Block Z-1 in 2007, has turned its focus to development of the proved reserves in Corvina, as well as to re-developing the Albacora oil field which has a platform in place with three shut in oil wells drilled and produced by Belco in the 1980’s.

In addition, our business plan includes a gas-to-power project, which entails the installation of a 10-mile gas pipe from the CX-11 platform to shore, construction of gas process 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, with certain upgrades, are expected to be capable of handling up to 360 MW of power.

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

We will concentrate our energies 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.

Reincorporation, Name Change and Internal Restructuring

On October 11, 2007, BPZ Energy, Inc., a Colorado corporation, formerly named Navidec, Inc., completed a reincorporation from Colorado to the State of Texas pursuant to the Plan of Conversion as approved by the shareholders at the 2007 annual meeting of shareholders held on August 17, 2007. The related filings with the Secretary of State of Texas also included a change of the Company’s name from BPZ Energy, Inc. to BPZ Resources Inc., in connection with an ongoing review of certain internal reorganization matters related to our international tax planning and corporate structure. The Company continues to do business under the name BPZ Energy in its regular business operations.

No changes to the members of the Board of Directors, the management, or the operations of the Company were made in connection with the conversion from a Colorado corporation to a Texas corporation. The Company remains as the same business entity following the reincorporation to Texas, with all of the assets, rights, privileges and powers of, and all property owned by, all debts due to, as well as any causes of action belonging to the predecessor Colorado entity. As part of the reincorporation, a new Certificate of Formation and new Bylaws were adopted, which now govern the rights of holders of the Company’s common stock. At the effective time of the reincorporation, each outstanding share of the Colorado entity prior to the reincorporation was automatically converted into one share of the Texas entity.

Available Information

The Company maintains a website (http://www.bpzenergy.com), on which we make available, free of charge, all of the Company’s above mentioned filings with the Security and Exchange Commission (“SEC” or “Commission”), including Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Securities Act of 1934. These filings will be available as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

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Our Competition

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 unique knowledge of our targeted areas have 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 a short-term contract to the Peruvian national oil company, 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.

Subsequent to December 31, 2008, our wholly-owned subsidiary, BPZ Exploración & Producción S.R.L., 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, all of 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.

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. Although we believe our operations are and will be in substantial compliance with existing legislation and requirements of 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 unique 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.

Peru

Peruvian hydrocarbon legislation. Peru’s hydrocarbon legislation, which includes the Organic Hydrocarbon Law No. 26221 and the regulations thereunder (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 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

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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 environment 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 extracted hydrocarbons to Perupetro, a state company responsible for promoting and overseeing the investment of hydrocarbon exploration and exploitation 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, the specialized government department 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 agency charged with economic and technical supervision. We are subject to the laws and regulations of all of these entities and agencies.

Perupetro generally enters into either license contracts or service contracts for hydrocarbon exploration and exploitation. Peru’s laws also allow for other contract models, but the investor must propose contract terms compatible with Peru’s interests. We only operate under license contracts and do not foresee operating under any services contracts. 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 based 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 is jointly and severally liable at all times for the technical, legal, economic and financial capacity of its Peruvian subsidiary or branch. 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, and pays royalties which are collected by 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 Hydrocarbons Bureau (“Direccion General de Hidrocarburos”). Licensees must also submit a monthly economic report to the Central Bank 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 contract duration for crude oil is thirty years, while the contract duration for natural gas and condensates is forty years. The periods commence on an agreed date and are determined based on location of the contract area, season of the year in which exploration commences, and other similar factors. 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, 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 and to enter into license contracts if the evaluations indicate the potential for profitable operations. The technical evaluation agreement is generally for a period of twenty-four months, depending upon the volume and nature of the work to be carried out.

We currently have four license contracts. As of February 23, 2009, 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

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performance under the license contracts. At December 31, 2008, 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 with the financial institutions which issued the bonds in the amount of $2.9 million. Additionally we have $2.2 million of restricted cash to collateralize insurance bonds for import duties related to the floating production, storage and offloading facility (“FPSO”) and transport tanker. 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.

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.

License contracts are subject to royalty payments, which are usually a fixed percentage of the actual production sold. The taxing regulations stipulate a minimum royalty payment of five percent increasing incrementally to a maximum of twenty percent based on production. However, the bidding company can choose to increase the royalty payout percentage 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 Unified 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 the 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.

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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; (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 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

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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 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 satisfying 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. As noted above, 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.

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, 2008, 2007 and 2006 were approximately $0.5 million, $0.3 million and $0.5 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 primary marine transportation contractors was chartering from the Peruvian Navy’s commercial branch sank after catching fire. The 7,500 barrel capacity Supe, which was moored near the Corvina CX-11 platform and was being used to store oil produced from Corvina’s CX11-21XD and 14D wells, caught fire and later sank approximately one mile from the platform. At the time of the incident the Supe

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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 Americas (“CCA”) to conduct an environmental damage 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 activities.

Employees

As of December 31, 2008, we employed 27 full-time employees (of which four are executive officers) in our Houston office and 145 full-time employees (of which one is an executive officer) in our Lima, Peru office. We had three 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.

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 recently begun producing and selling oil from our recent discoveries under an extended 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

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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 have not been profitable since we commenced operations and have a significant working capital deficit. To date we have had limited revenue and limited earnings from operations. As of December 31, 2008, we had a working capital deficit of approximately $30 million, and we may incur working capital deficits in the future. We cannot provide any assurance that we will be profitable in the future or that we will be able to generate cash from operations or financings to fund working capital deficits.

We must comply with Peruvian legal and regulatory requirements to be able to produce and sell oil beyond the period of the current well test program. Our current well test program in the Corvina Field will likely end no later than May 31, 2010.  In particular, we are required to meet certain environmental and technical requirements before the end of the well test program in order to continue with commercial sales.  If we fail to meet these requirements before the end of the well test period, we could be required to cease production and discontinue commercial sales, which would have a materially adverse impact on our financial condition, our operations and our ability to execute our business plan.

As of December 31, 2008, approximately 75% 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.

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 approximately $197 million in various private placements of our common stock, $15.5 million in convertible debt financing from the International Finance Corporation (“IFC”), and $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 Exploración & Producción S.R.L. 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. This is the first tranche of the proposed overall debt package with the IFC, and a commercial bank, which is expected to be a total of approximately $90.0 million once the second tranche has been finalized with the commercial bank.  Once the second tranche is closed, we expect the initial available borrowing capacity to be approximately $60.0 million, inclusive of the $15.0 million already closed and funded by the IFC. The current facility (and the additional senior debt, when and if closed) will be secured by the current proved oil reserves in our Corvina field in Block Z-1.

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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;

· 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, each lender 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 $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 determination based on the value of 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 and current worldwide demand appears to be declining. 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. The worsening global economy has weakened oil demand. A continued

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slowing of global economic growth will likely reduce demand for oil and natural gas, increase spare productive capacity and result in lower oil and natural gas prices, which will reduce our cash flow from operations.

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. Oil and natural gas prices have declined significantly over the last two quarters of 2008 and may continue to decline. 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 January 31, 2009, those prices were respectively $41.68 per Bbl and $4.40 per Mcf. 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

· 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.

In addition, we may be unable to close or obtain adequate funding under our proposed credit facilities because (i) our lending counterparties may be unwilling or unable to meet their funding obligations or (ii) our borrowing base under the proposed credit facilities is decreased as the result of a re-determination, reducing it due to lower oil or natural gas prices, operating difficulties, declines in reserves, lending requirements or regulations, or for any other reason.

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.

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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 typhoons and other adverse weather conditions;

· pipe, cement, subsea well or pipeline failures;

· casing collapses;

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

· abnormally pressured formations; or

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

Experiencing any of these operating risks could lead to problems with any well bores, platforms, gathering systems and processing facilities, which could adversely affect 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.

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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 barge BPZ-01 to act as a tender for our offshore drilling operations in our Corvina field 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 FPSO and the other is currently being used as a floating oil storage facility (“FSO”). In addition, we have time chartered a double hull tanker barge to transport crude oil from our offshore production and storage facilities in Corvina Field to the Talara refinery approximately 70 miles south of the platform where the oil is sold at current market prices under our current oil contract with Petroperu. See Item 1,- “Business — Customers” for further information. These vessels are an important element in our strategy to control drilling, storage and transportation costs by allowing the use of existing platforms and avoiding the use of high-priced ships. Any disruption or delay of the services to be 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.

Our reserve estimates depend on many assumptions that may turn out to be inaccurate.  Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the estimated quantities and present value of our reserves.  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 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 Commission guidelines referred to in this Annual 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 the date of estimate.  Actual future prices, costs, taxes and the volume of produced reserves may differ materially from those used in the net present value estimate.

The Commission currently permits oil and natural gas companies, in their public filings with the Commission, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The Commission’s guidelines strictly prohibit us from including “probable reserves” and “possible reserves” in such filings, although we may disclose such reserves in other disclosures not filed with the Commission. We also caution you that the Commission views such “probable” and “possible” reserves estimates as inherently unreliable and these estimates may be seen as misleading to investors unless the reader is an expert in the oil or natural gas industry. Unless you have such expertise, you should not place undue reliance on these estimates. Potential investors should also be aware that such “probable” and “possible” reserve estimates will not be contained in any “resale” or other registration statement filed by us that offers or sells shares on behalf of purchasers of our

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common stock and may have an impact on the valuation of the resale of the shares. Except as required by applicable law, we undertake no duty to update this information and do not intend to update this information.

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

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

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

Our management team has limited experience in the power generation business. Our plan of operation includes constructing power generation and gas processing facilities and pipelines in Peru and Ecuador. However, the experience of our management team has primarily been in the oil and natural gas exploration and production industry and we have limited experience in the power generation business. We 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. In addition we are currently searching for a prospective joint venture partner to participate in our gas-to-power project.

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 connection with power plant construction;

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

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

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

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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:

·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.

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. 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;

·royalty requirements;

·customer requirements;

·operational reporting; and

·safety requirements.

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

·personal injuries;

·property and natural resource damages; and

·governmental infringements and sanctions.

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 the well test period currently in effect in Block Z-1, which will likely be required to be concluded by or before May 31, 2010. 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 and Ecuador necessary for our operations, including those required to continue commercial sales of oil beyond the well test period, which will likely be required to be concluded by or before May 31, 2010. 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. Failure to comply with new regulations could cause us to suspend or terminate certain operations or subject us to administrative, civil or criminal penalties. Any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and our ability to implement our plan of operation.

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

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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. 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 and unique 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 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

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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 of operations totaling $67.9 million through December 31, 2008. 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. Our certificate of formation does not provide for preemptive rights. We currently have $222 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.  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.

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, 2008, we had 78,748,390 shares of common stock issued and outstanding. In addition, we have outstanding 3,894,348 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 2,514,450 shares of common stock allocated under our 2007 Long-Term Incentive Compensation Plan, as amended and restated, and our 2007 Directors’ Compensation Incentive Plan.  The possibility that substantial amounts of shares of our common stock may be sold in the public market may cause prevailing market prices for our common stock to decrease and thus could impair our ability to raise capital through the sale of our equity securities.

We are controlled by our officers, directors and entities affiliated with them. In the aggregate, our management and directors own or control approximately 22.2% of our common stock issued as of December 31, 2008. These

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shareholders, if acting together, 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 of us that some shareholders may favor. Our certificate of formation and bylaws contain provisions that, either alone or in combination with the provisions of Texas law described below, may have the effect of delaying or making it more difficult for another person to acquire us by means of a hostile tender offer, open market purchases, a proxy contest or otherwise. These provisions include:

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

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

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

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

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

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ITEM 2. PROPERTIES

Offices

Our corporate headquarters office is located in Houston, Texas. In November 2008, we entered into a coterminous lease for the existing office space extending the current leased space of approximately 7,770 square feet of office space and 2,580 square feet of adjacent office space. This new lease extends the old lease terms seven-years and expires on January 31, 2016. Under this new lease agreement, we are obligated to lease an additional 7,070 square feet of office space with lease payments commencing in March of 2009. We also currently lease four administrative offices and a warehouse in Peru of approximately 12,100 square feet and 57,000 square feet, respectively. The leases expire at various times in 2009 and 2010. In 2008, our Lima, office entered into a lease agreement, beginning in March of 2009 and expiring in fourth quarter of 2013, to lease a consolidated office space of approximately 22,500 square feet. 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 and potentially up to ten years (seven and potentially up to thirteen for Block Z-1), and, if exploration efforts are successful, provide a total contract term of up to 30 years for oil exploration and production and up to 40 years for gas exploration and production. These four blocks cover a combined area of approximately 2.4 million acres.

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The following table is a summary of our properties in northwest Peru. As of December 31, 2008 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	738,996	209	4
Block XIX	Tumbes/Talara	100	%	December 2003	472,860
Block XXII	Lancones/Talara	100	%	November 2007	948,000
Block XXIII	Tumbes/Talara	100	%	November 2007	248,000
Total					2,407,856	209	4

(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 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 739,205 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 platforms need to be repaired and refurbished, but are structurally sound, and we believe suitable for our future operations. All five 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 produced natural gas at rates as high as 16.6 million cubic feet of gas per day (“MMcf/d”) during two separate tests over a period of approximately 20 days each. The well was shut-in. In June 2007, we successfully recompleted the Corvina 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.

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, produced natural gas at rates as high as 8.3 MMcf/d over a period of approximately 20 days during an extended test in 1979 and was also shut-in.

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, which is divided into four periods, and can be extended under certain circumstances up to an additional six years. Each period has a commitment for exploration

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activities and requires a financial guarantee to secure the performance of the work commitment during such period. Block Z-1 is currently in the third exploration period. This period was originally scheduled to expire in November 2008.  However, since Albacora Drilling Environmental Impact Study is still pending for approval from DGAAE (Dirección General de Asuntos Ambientales y Energéticos), who is responsible for environmental protection matters in Peru, the third exploration period time limit is on suspension until such approval is obtained from the DGAAE. The fourth and final exploration period will begin as soon as the third period expires. It will also require the drilling of an additional exploratory well or other equivalent work commitments and will require a performance bond of $1.0 million. A performance bond of $1.0 million was posted for cash collateral of $750,000 related to the third exploration period. The performance bond amounts are not cumulative, and are 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 of $50,000 per year.

On November 21, 2007, we submitted a letter to Perupetro declaring a commercial discovery in the Block Z-1 field. On May 19, 2008 we filed the field development plan with Perupertro.  The commercial development period of the contract will commence on the First Date of Commercial production (“FDCP”). The date of beginning of commercial extraction is currently under revision with Perupetro. 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. 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 barrels of oil equivalent per day (boepd) and are capped at 20% if and when production surpasses 100,000 boepd.

Description of Block XIX and License Contract

Block XIX covers approximately 472,860 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 show from the Heath Formation. The sections of the Tumbes and Talara Basins in Block XIX are primarily exploratory areas and have had limited drilling and seismic activity. However, the Mancora formation is expected to continue from offshore in Block Z-1 in Piedra Redonda through Block XXIII, also under license to us, and into Block XIX an area which spans approximately fifty miles.

In 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 three 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. 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 barrels of oil equivalent per day (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. As of December 31, 2008, we had a $585,000 bond posted for $292,500 in cash collateral. We are currently in the third exploration period, which was scheduled to end in May of 2009. However, in accordance with the terms of the license contract, we intend to postpone the third exploration period of Block XIX to 2010. During the third exploration period, we will be required to drill and test one well. In connection with the third exploration period, which began in February 2008, the performance bond associated with the second exploration period was released. Once we complete the third exploration period we will reestablish timelines for the fourth and fifth exploration periods. Both the fourth and fifth exploration periods will require a performance bond of $585,000 for each respective period. 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. The exploitation, or development, period of the contract will commence as soon as the Company declares a commercial discovery and receives approval for a field development plan. We must declare a commercial discovery no later than the end of the last exploration period, including any extensions or deferments.

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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 948,000 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 requires that we acquire, process and interpret 200 kms of 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. 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. 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 barrels of oil equivalent per day (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.

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 248,000 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. In addition, it commits the Company to drill a certain number of wells, acquire certain amount of either 2-D or 3-D seismic data and prepare an integrated geological, geochemical and reservoir engineering evaluation of the hydrocarbon prospects in the block. In connection with this block we posted a performance bond to guarantee our various obligations and 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. 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 barrels of oil equivalent per day (“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 $3,075,000 bond in the amount of $1,537,500. 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.

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 in Northern Peru. Our actual reserves, future rates of production and timing of development expenditures may vary substantially from these estimates. All of our proved reserves are in the Corvina Field. 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 theses amount in “Supplemental Oil and Gas Disclosures (Unaudited)” to our consolidated financial statements provided herein.

As of December 31, 2008, we owned a 100% working interest in the Corvina Field, subject to Peruvian government royalties of 5% to 20% net revenue interest depending on the level of production. The effect of these royalty interest deductions 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 expected 30-year term for oil and 40-year term for 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, 2008

(Reserves Quantities in barrels)

	Actual
Proved Developed Producing	4,223,398
Proved Undeveloped	12,930,405
Total Proved Reserves	17,153,803
Standardized Measure of Discounted Future Net Cash Flows, Discounted @ 10% (PV-10)	$	298,926,934

Acreage

The following table shows the number of developed and undeveloped acres as of December 31, 2008:

	Acres
Developed	209
Undeveloped	2,407,647
Total acreage	2,407,856

Drilling Activity

The following lists our successful exploratory and development wells that were drilled during the year ended December 31, 2008:

Corvina Field	Exploratory/Development	Drilling Depth (feet)	Date Objective Drilled/Tested
CX11-18XD	Development	8,792	1st quarter
CX11-20XD	Development	9,800	3rd 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 permanent equipment for the production of oil or natural gas.

Present Activities

In November 2008, we commenced drilling on the CX11-15D well and reached total drilling depth in January 2009. The CX11-15D targeted the known oil and gas sands higher in the geological formation with the main objective of proving up a portion of the probable oil and gas reserves and giving us another oil producing well. 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. The tests in the upper oil zones resulted in no flow due to the quality of the sands in this location. However, the gas sands in the gas zone were encountered higher than expected, which should allow us to prove up some of the probable gas reserves. Operations have commenced to sidetrack the CX11-15D well, targeting a location higher in the geological formation. Once the sidetrack is complete, which we estimate to be by the end of the first quarter, we will test the prospective oil sands which, in this location, should be above the oil-water contact and of better quality. As part of the extended well testing program, the well will then be placed on production if commercial amounts of oil are tested. We anticipate production increases in the field based on the CX11-15D well being completed in late March. Management does not expect the results of this well to have a material impact on oil-in-place in Corvina.

Following the completion of the CX11-15D well in Corvina, we intend to work over the CX11-20XD well to maximize oil production from the oil producing zone in the reservoir. The work over should be completed in approximately one month or less.

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We are producing oil under a long-term testing program, at the CX-11 platform in Corvina. Production for November and December 2008 was approximately 140,000 and 148,000 barrels of oil, respectively, or approximately 4,600 and 4,800 bopd, respectively. We were drilling the CX11-15D well in November and December 2008, which caused us to limit production during certain periods for safety reasons. In January 2009 production has averaged approximately 4,600 bopd. We expect to continue increase production when the CX11-15D well and future wells come online.

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. Currently, there are approximately 1,250 active wells which produce approximately 1,600 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 Exploración & Producción S.R.L’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 Exploración & Producción S.R.L., 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of stockholders during the fourth quarter of the fiscal year covered by this Form 10-K.

PART II

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

Market Information

In October 2008, following the acquisition of the American Stock Exchange by the NYSE Euronext, our Common Stock began trading on the NYSE Alternext U.S. and our ticker symbol changed to “BPZ”. From January 12, 2007 until the merger, our Common Stock was traded on the American Stock Exchange (“AMEX”) under the symbol “BZP”. Between December 27, 2005 and January 12, 2007, our common stock was traded on the Pink Sheets under the symbol “BPZI.PK”.

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 Alternext U.S., AMEX and the Pink Sheets for the applicable time periods. The quotations provided for the over the counter market reflects interdealer prices without retail mark-up, mark-down or commissions, and may not represent actual transactions.

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	High		Low
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
2007
Fourth quarter	$	13.08	$	8.11
Third quarter	7.84		4.14
Second quarter	7.55		5.58
First quarter	6.00		3.61

Holders

As of February 23, 2009, we had approximately 168 shareholders of record, and an estimated 14,790 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.

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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 Transmeridian Exploration, Inc., 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, 2003 in our Common Stock, the Russell 2000 Stock Index and a Company peer group.

	2003		2004		2005		2006		2007		2008
BPZ Resources, Inc.	$	100	$	330	$	370	$	357	$	972	$	557
Russell 2000 Stock Index	100		116		120		140		136		89
Peer Group Composite	100		138		188		240		429		272

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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,
	2008			2007			2006			2005			2004
Operating Results:
Revenue (net)	$	62,954,901		$	2,350,388		$	—		$	—		$	—
Operating and administrative expenses:
Lease operating expense	11,648,877			754,833			—			—			—
General and administrative	42,093,616			18,548,465			11,531,864			5,805,226			8,915,192
Geological, geophysical and engineering	794,925			4,045,381			2,048,742			998,131			360,965
Depreciation, depletion and amortization	16,061,540			792,531			213,815			29,638			157
Total operating expenses	70,598,958			24,141,210			13,794,421			6,832,995			9,276,314
Operating loss	(7,644,057		)	(21,790,822		)	(13,794,421		)	(6,832,995		)	(9,276,314		)
Other income (expense):
Income from investment in Ecuador property, net of amortization	717,571			264,031			1,403,298			468,726			147,861
Interest expense	—			—			(15,815		)	(11,149		)	(66,959		)
Amortization of deferred financing costs	—			—			—			(67,561		)	(360,439		)
Registration delay expense	—			—			(3,552,513		)	(515,967		)	—
Interest income	319,424			854,905			787,455			509,808			—
Merger costs	—			—			—			—			(5,470,455		)
Miscellaneous income (expense)	102,425			200,904			(315,463		)	42,149			13,129
Total other income (expense)	1,139,420			1,319,840			(1,693,038		)	426,006			(5,736,863		)
Loss before income taxes	(6,504,637		)	(20,470,982		)	(15,487,459		)	(6,406,989		)	(15,013,177		)
Income taxes	3,141,851			39,001			—			—			—
Net loss	$	(9,646,488	)	$	(20,509,983	)	$	(15,487,459	)	$	(6,406,989	)	$	(15,013,177	)
Basic and diluted net loss per share	$	(0.12	)	$	(0.30	)	$	(0.29	)	$	(0.16	)	$	(0.62	)
Weighted average common shares outstanding	77,389,536			69,156,404			53,751,761			40,899,291			24,169,823
Oil sales price per barrel, net	$	76.23		$	81.78		$	—		$	—		$	—
Operating cost per barrel produced	$	14.11		$	26.26		$	—		$	—		$	—
Balance Sheet Data:
Working Capital/(Defecit)	$	(30,562,123	)	$	1,549,390		$	22,057,206		$	29,036,304		$	3,611,410
Property, equipment and construction in progress, net	193,933,635			100,366,091			38,726,910			4,365,040			5,505
Total assets	235,365,419			129,619,204			74,036,726			38,090,980			5,161,095
Total long-term debt	15,017,511			15,537,293			55,815			70,908			—
Stockholders’ equity	159,180,191			90,740,112			63,635,905			36,731,577			4,586,155
Cash Flow Data:
Cash flow provided by/(used in) operating activites	48,721,975			(15,170,838		)	(6,681,722		)	(4,461,328		)	(1,473,800		)
Cash flow used in investing activities	(102,185,451		)	(58,463,949		)	(34,269,582		)	(5,745,130		)	(1,305,662		)
Cash flow provided by financing activities	51,266,098			55,824,742			36,820,407			35,647,397			6,785,497

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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 complementary development of a Company owned gas-fired power generation facility in Peru. We have the exclusive rights and license agreements for oil and gas exploration and production covering approximately 2.4 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”).

We are in the initial stages of developing our oil and natural gas reserves and have begun producing oil and selling oil from the CX11 platform in the Corvina field of Block Z-1 under an extended well testing program. Additionally, our activities in Peru include analysis and evaluation of technical data on our properties, preparation of the development plans for the properties, including detailed engineering and design of the power plant and gas processing facilities, refurbishment of and designs for platforms to be used under an extended well testing program, procuring machinery and equipment for an extended drilling campaign, obtaining all necessary environmental and operating permits, bringing additional production on-line and securing the required capital and financing to conduct the current plan of operation.

Corvina Field

We are producing oil from our recent discoveries at the CX-11 platform, located in the Corvina Field within the offshore Block Z-1, under an extended well testing program that started on November 1, 2007.  The Corvina field consists of approximately 47,000 acres in water depths of less than 200 feet.  We are currently concentrating our drilling efforts on West Corvina, which consists of 3,500 acres and have completed a total of four oil producing wells, the CX11-21XD, CX11-20XD, the CX11-18XD and the CX11-14D.  The oil is delivered by barge 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.

On October 24, 2007, Tecnomarine, our former primary marine transportation contractor, entered into two short-term time charters with the commercial division of the Peruvian Navy to lease two small tankers for use in our offshore oil production operation.  On January 30, 2008, one of the tankers, the Supe, sank after catching fire.  At the time of the incident, the tanker contained approximately 1,300 barrels of oil, most of which burned in the fire. Official environmental impact assessments concluded that environmental issues have been adequately controlled. On December 18, 2008, a lawsuit was filed by two crewmembers and the family and estate of two of the deceased crewmembers of the Supe against BPZ. As none of the Peruvian government sanctioned investigations into the Supe incident found fault on the part of Tecnomarine, BPZ or the BPZ’s subsidiary, BPZ Exploración & Producción S.R.L., we do not currently believe based upon the known facts relating to the incident that the claims asserted against us are meritorious and intend to vigorously defend ourself. Additionally we believe the incident would be covered by our insurance policies, after a customary deductible. As a result of the incident, our operations were voluntarily suspended at the CX-11 platform. For further information regarding the civil claims asserted against us see Item 3. — “Legal Proceedings”.

On March 14, 2008, we were notified by the OSINERGMIN, the government regulatory agency in Peru responsible for monitoring industrial safety, that we could resume drilling and testing operations at the CX-11 platform allowing us to begin testing the CX11-18XD well.  Three drill stem tests were conducted in the Upper Zorritos formation.  The first two drill stem tests targeted the lower sands in zones that had not previously been tested.  The third drill stem test targeted sands that had tested oil in our CX11-21XD well.  We began producing from the CX11-18XD well in May 2008 and, on June 9, 2008 we received the clearance needed to transport oil from the CX-11 platform to the nearby Talara refinery by the corresponding Peruvian environmental agency.  In addition, our FPSO vessel was placed into service in the Corvina field and is currently being used in our extended well testing program to process produced crude oil.

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Upon completion of the CX11-18XD well, we began drilling operations on the CX11-20XD well in May 2008.  The CX11-20XD well is positioned higher up in the geologic structure from the CX11-21XD well.  The well has been positioned to further develop the top gas sands found in the previously drilled CX11-21XD well, the oil sands currently producing in the CX11-21XD and CX11-18XD wells, the oil sands encountered and briefly tested in the CX11-18XD well during the initial drill-stem test number one, as well as sands found in the CX11-14D well.  The well tested positive for oil in quantities that we believe to be commercially producible.  We completed two drill stem tests on four sets of oil sands in the well.  On November 1, 2008 we completed the CX11-20XD well as an oil-producing well under an extended well testing program currently ongoing at the Corvina field. However, because the well crosses sands which tested positive for what we believe to be economic quantities of gas, during the drilling and testing of both the CX11-21XD and CX11-18XD wells, we intend to re-complete the CX11-20XD well, with dual production strings, when gas is needed for the gas-to-power project, to allow the well to produce gas as well as oil.

On November 21, 2008, we began drilling operations on the CX11-15D well located in the Corvina field within the offshore Block Z-1 in northwest Peru. The CX11-15D targeted the known oil and gas sands higher in the geological formation with the main objective of proving up a portion of the probable oil and gas reserves and giving us another oil producing well. 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. The tests in the upper oil zones resulted in no flow due to the quality of the sands in this location. However, the gas sands in the gas zone were encountered higher than expected, which should allow us to prove up some of the probable gas reserves. Operations have commenced to sidetrack the CX11-15D well, targeting a location higher in the geological formation. Once the sidetrack is complete, in approximately one month, we will test the prospective oil sands which, in this location, should be above the oil-water contact and of better quality. As part of the extended well testing program, the well will then be placed on production if commercial amounts of oil are tested. We anticipate increased production based on the CX11-15D well being completed in late March.

As of December 31, 2008, we had four oil producing wells, the CX11-21XD, CX11-20XD, the CX11-18XD and the CX11-14D under an extended well testing program. For 2009 we intend to keep the drilling rig at the CX-11 platform to focus on oil development in the offshore Block Z-1 and to drill three additional oil development wells to maximize cash flow.

Albacora Field

The Albacora field is located in the northern part of the offshore Block Z-1.  Based on our internal models, we believe the Albacora field consists of approximately 6,000 acres and, like the Corvina field, is located in water depths of less than 200 feet. In 2009, once our second contracted drilling rig (the PTX18) has been mobilized to the Albacora A-1 platform, which is currently being refurbished, we plan to drill the A-14XD well, a twin well to Albacora’s 8-X-2 discovery well. The PTX18 rig is contracted with Petrex, our current drilling contractor, for a period of three years. This rig will be capable of drilling to approximately 14,000 feet, and will be modified to drill from an offshore platform. This first well in Albacora will qualify as an exploratory well as we plan on testing the prospective Lower Zorritos formation sands.  The 8-X-2 discovery well, drilled 35 years ago, tested oil and gas in the upper Zorritos formation sands at quantities we believe to be commercially producible.  Our drilling plans in Albacora field are to drill two new wells in 2009.

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, with certain upgrades, are expected to be capable of handling up to 360 MW of power. 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. As a result of factors outside our control, as further discussed below, we have postponed development of the gas-to power project until such time as we are able to obtain the necessary financing, personnel and equipment to continue the project, including finding a joint venture partner to assist us in the gas-to-power project.

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GE Turbine Purchase Agreement

On September 26, 2008, we, through our power generation subsidiary, Empresa Eléctrica Nueva Esperanza, SRL, entered into a $51.5 million contract for the purchase of equipment and services (the “Agreement”) with GE Packaged Power, Inc. and GE International, Inc. Sucursal de Peru (collectively “GE”), which are part of GE Energy’s aeroderivative business.  The Agreement obligates us to purchase three LM6000 gas-fired turbines. Each turbine will have a generation capacity of 45 megawatts, with excess capacity of approximately 5%.  Delivery of the three units was initially scheduled for the fourth quarter 2009.

In January 2009, as a result of our decision to focus on increasing oil production, cash flow and reserves from the Corvina and Albacora fields during 2009, we entered into an amendment to the Agreement with GE. Under the terms of the amendment, both GE and BPZ, agree 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 give right to terminate the contract provided that we make milestone payment number four to GE in the amount of $3.4 million no later than February 25, 2009. As of February 24, 2009, we paid $3.4 million related to milestone payment four to GE. In addition we agreed to make milestone payment five in the amount of $3.5 million to GE no later than November 16, 2009. Any failure to make these payments in full will result in immediate termination of the Agreement with no cure period or time to correct the breach.

Once we decide to bring the Agreement out of the suspension period, we will provide evidence that payment security has been established and new delivery dates, pricing and payment terms will be determined by the BPZ and GE. All previous payments made by us on the Agreement will be applied to the new price.

Financing Activities

2009 Private Placement of Common Stock

On February 13, 2009, we announced our intent to sell approximately 15.7 million shares of our common stock to institutional investors at a price of $3.05 per share for gross proceeds of approximately $48 million. On February 23, 2009, we 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, the IFC holds a right to elect to participate in the offering resulting in the possible sale of an additional 1.4 million shares of common stock for a total of up to approximately 15.7 million shares of common stock sold in this private offering. The common stock was priced at $3.05 per share resulting in gross proceeds to us of approximately $43.6 million ($48.0 million if the IFC elects to participate in the offering). No warrants or other dilutive securities were issued to the investors in connection with the private placement. The shares were placed directly by Pritchard Capital Partners, LLC and we have agreed to a 5% cash placement fee of the gross proceeds at each closing.  Additionally, we retained Morgan Keegan & Company, Inc., as our financial advisor, in connection with the offering.  In return for its services, Morgan Keegan & Company, Inc. will receive an advisory fee of 1.5% of the gross proceeds of this transaction at each closing.

Under the Stock Purchase 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 the registration statements 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 we are 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.  We are subject to a potential maximum aggregate penalty of 13% of the gross proceeds of the offering or approximately $5.7 million, excluding the IFC’s participation, if the registration statement related to the offering is not filed or declared effective within the time-frames outlined above.  At our option, any penalties would be payable in cash or our common stock.

Following the closing of this private placement, we have 93,054,150 shares of common stock issued and outstanding, with fully diluted shares of 96,948,498, excluding the 1.4 million shares the IFC may elect to purchase as part of the offering, respectively. The fully diluted shares include the potential effect of vested and unvested options and restricted stock outstanding.

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$15.0 Million IFC Reserve-Based Credit Facility

 On August 15, 2008, we entered into a $15.0 million reserve-based lending facility (the “$15.0 million Senior Debt”) with IFC through our subsidiaries BPZ Exploración & Producción S.R.L and BPZ Marine Peru S.R.L as borrowers.  The $15.0 million Senior Debt represents the first tranche of an expected overall lending package of approximately $90.0 million.  We have primarily used the proceeds from the offering for our initial $5.1 million down payment and subsequent monthly progress payments for the GE turbines (discussed above). For further information regarding the terms of the $15.0 million Senior Debt see “Liquidity and Capital Resources - $15 million IFC Reserve-Based Credit Facility” below.

Reserve-Based Credit Facility

In August 2008, we signed a Mandate Letter and Facility Term Sheet with Natixis to underwrite and structure, on an exclusive basis, a $200.0 million reserve-based credit facility. The $200.0 million reserve-based credit facility was approved by the Natixis Credit Committee in September 2008. We originally planned to receive funding under the Natixis reserve-based credit facility at the end of 2008 and planned to finance our ongoing oil development operations and certain gas-to-power project costs with the proceeds until the receipt of the proceeds of the approximately $90.0 million lending package with the IFC (discussed below). We also planned to repay any advances from the $200.0 million reserve-based credit facility used for the gas-to-power project from the IFC lending package once the project financing closed.

Subsequent to December 31, 2008, we finalized a revised Mandate Letter and Facility Term Sheet with Natixis. Based on current credit and commodity market conditions, Natixis has now resized the facility to approximately $90.0 million inclusive of the $15.0 million tranche previously closed and funded with the IFC, bringing the facility in line with the expected borrowing base supported by our certified reserves. Once the facility is closed, we expect the initial available borrowing capacity to be approximately $60.0 million, inclusive of the $15.0 million already closed and funded by IFC as described above”. The existing Natixis Credit Committee approval remains in effect. The terms of the resized facility are expected to be aligned with recent transactions in the market.

We expect to complete this financing in the first part of the second quarter of 2009. However, the closing of this tranche of the credit facility is dependent upon the successful syndication of approximately 50% of the facility and successful negotiation of the related loan documents, and funding is predicated on the satisfaction of certain conditions precedent as specified in the loan documents. We cannot assure that the financing will occur early in the second quarter of 2009 or at all. If we are unable to secure the financing with Natixis we will need to find other funding sources to continue our operations. For further information regarding the expected terms of the reserve-based credit facility see “Liquidity and Capital Resources” below.

Gas-to-Power Project Financing

On November 29, 2006, a $120.0 million financing package was approved by the Credit Committee of the IFC for the development of our gas-to-power project.  Originally, IFC intended to loan $50.0 million, of which $19.5 million was invested in our common stock in December 2006, with the remaining $70.0 million to be syndicated to other financial institutions.

However, the discovery of oil in the Corvina field in early 2007 resulted in the gas-to-power project being deferred and our decision to focus on accelerating oil production.  As a result, the $30.5 million balance of the IFC commitment was transferred to the oil development project and funded as follows:  $15.5 million of convertible debt funded in November, 2007 and converted into common stock in May, 2008 and $15.0 million was funded in October, 2008 with the reserve based facility. See below for further information on $15.0 million credit facility.

We currently estimate the gas-to-power project will cost approximately $130.0 million.  The IFC has advised that approximately 65% of the project’s costs can be expected to be financed with traditional project financing, given current market conditions.  Accordingly, we have commenced discussions with potential joint venture partners for the gas-to-power project in an attempt to secure additional equity for the project.  Following the identification and selection of a partner and consummation of project contracts, we will enter into negotiations with the IFC regarding restructuring the gas-to-power financing. We are expecting terms to include an eight year amortization of principal with interest rates to reflect the current market conditions at the time of closing along with typical covenants for this type of financing.  The closing of this financing, which is targeted for late 2009, will be subject to the satisfactory negotiation of loan and security documents.

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$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.

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.

Conversion of Warrants

At December 31, 2007, we had 250,000 warrants outstanding to Morgan Keegan & Company, Inc. for their role as placement agent in connection with the private placement of common stock in 2005 and for their financial advisory services in connection with the private placement of common stock in 2006. During the year ended December 31, 2008, Morgan Keegan exercised the warrants to purchase 250,000 shares of our common stock at an exercise price of $3.00.  As a result, we received proceeds of $0.8 million. The 2006 and 2005 warrants were valued at $0.2 million, and $0.3 million, respectively, using the Black-Scholes model, which was treated as additional non-cash stock offering costs. At December 31, 2008, we had no outstanding warrants.

Note Payable

In January 2009 in exchange of receipt of $1.0 million from an individual (“Note Holder”), we signed a promissory note (the “Note”). The Note matures in July 2009 and bears an annual interest rate of 12.0%. Interest payments are due monthly on the first day of each month the principal is outstanding. Additionally the terms of the Note include a conversion feature, at our option, to deliver and exchange as consideration and payment of the Note; shares of our common stock. The number of shares will be determined by applying a 12% discount to the closing price of our Common Stock on the day prior to settlement. Further the Note Holder has the right to participate in any equity offering during the period the principal is outstanding by tendering the Note for shares of common stock. The number of shares will be determined by dividing the total outstanding indebtedness by the share price of the offering on the same terms as other participants in the offering. Should we default on any terms of the Note, BPZ agrees to deliver our common stock, as consideration and payment of the Note, within 30 days the date of default.

Memorandum of Understanding with Shell Exploration Company (West) B.V.

On June 26, 2008, we entered into a Memorandum of Understanding (“MOU”) with Shell Exploration Company (West) B.V. (“Shell”). This non-binding MOU established the basis for both parties to move forward with negotiations for a possible joint venture agreement with the ultimate goal of jointly developing Blocks Z-1, XIX and XXIII in Northwest Peru into large-scale oil and gas ventures, including regional power generation, gas supply for local and regional industry, and liquefied natural gas (“LNG”). Our purpose in considering forming a joint venture was to complement BPZ’s assets, local knowledge and experience, stakeholder relationships, and vision with Shell’s technology, equipment, manpower and leadership, especially in gas marketing.

On January 9, 2009, BPZ and Shell mutually agreed to discontinue negotiations for a possible joint venture agreement as contemplated by the MOU as certain complexities within the MOU could not be mutually agreed upon by both parties. BPZ will maintain its 100% working interest in Blocks Z-1, XIX, and XXIII, as well as Block XXII, which was not part of the proposed transaction.

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BPZ-02 Equipment Lease-Purchase

In February 2008, we entered into a lease-purchase agreement to acquire the BPZ-02 for approximately $7.0 million which represents the lesser of the present value of the minimum lease payments or the fair market value of the asset at inception of the lease.  The BPZ-02 is a deck barge approximately 330 feet in length.  It will assist in the platform refurbishment and drilling activities in the Albacora field as well as to assist in future offshore drilling and development activities.  The acquisition of the BPZ-02 allows us better asset maintenance scheduling and will aid in the support of increased offshore exploration and development activities.  The terms of the lease-purchase stipulate a 19% rate of interest (33% effective rate of interest) over a one-year term at which point, title to the BPZ-02 will transfer to us upon final payment of the lease.  We are accounting for the transaction as a capital lease in accordance to SFAS 13, “Accounting for Leases (As Amended)” (“SFAS 13”) and, as a result, depreciation will be recognized over the economic life of the asset.

Production Equipment Lease

We entered into a capital lease agreement for the production equipment used on board the FPSO.  The FPSO, the Namoku, as well as the storage barge, the Nu’uanu, are under a separate capital lease agreements.  The capital lease for the production equipment commenced in June 2008, the date the equipment was put into service.  The lease bears an interest rate of 18% based on our incremental borrowing rate for similar equipment.  In accordance with the terms of the lease, a bargain purchase option exists at the end of the lease.  As a result, depreciation will be recognized over the economic life of the asset.  We recorded the capital lease at $2.4 million, which represents the lesser of the present value of the minimum lease payments or the fair market value of the asset at inception of the lease, in accordance with the provisions of SFAS 13.

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Future Market Trends and Expectations

Our business depends primarily on the level of current and future oil and gas prices and 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. Currently markets for oil are depressed with spot oil prices at or near a five year low. Additionally the U.S. banking sector is in disarray prompting the federal government’s intervention to support the sector. Further, the economic slowdown in the U.S., combined with other factors, is negatively influencing lending practices worldwide.

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 2009, and reduce operating and general and administrative expenses in an effort to enhance shareholder value by optimizing profits and positioning ourselves for financing opportunities while continuing to work on raising additional capital to fund our existing and future oil and gas opportunities.

From a cost restructuring perspective, in December 2008, we implemented a cost restructuring initiative aimed at reducing general and administrative expenses for Houston and Peru by 15% to 20% and overall operating costs by as much as $1 million per month. Our initiative includes reducing personnel in Houston and Lima and senior management accepting salary reductions up to 15% and foregoing year-end 2008 cash bonuses.

From a production perspective, our goal is to double our current daily production to 10,000 bopd at December 31, 2009. In order to attain that goal we plan to commit a majority of our 2009 capital budget on appraising and developing oil in the Corvina and Albacora fields. Our drilling plans include drilling three additional oil development wells from the CX-11 platform in the Corvina field and drilling two new wells in the Albacora field from a recently contracted rig that will be mobilized to the Albacora platform.

We believe the increased production from Corvina, combined with the cost restructuring, should allow us to be cash flow positive while drilling at Corvina and Albacora in 2010 while continuing to work closely with IFC and Natixis on the reserve based revolvers, which are expected to have a sufficient borrowing base that, when added to cash flows from expected Corvina and Albacora oil sales and the additional proceeds from the recent sale of our common stock, should cover the capital expenditures necessary to meet our 2009 capital needs. By focusing our efforts on oil development and production, implementing and executing our cost reduction initiative, while continuing to work on additional financing, BPZ should succeed in a difficult credit and volatile commodity pricing environment.

We anticipate future results will be based on our production levels and current and future oil prices. When forecasting our 2009 performance, we relied on assumptions about the market for oil, our customers and suppliers, and past results. We expect the average spot price for oil in 2009 to be approximately $51.00 or 33% less than the average price we received in 2008. With our planned oil production increases, we expect earnings for 2009 to slightly exceed that of 2008. Our results could materially differ from what we anticipate if any of our assumptions, such as 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, 2008 Compared to Year Ended December 31, 2007

	2008			2007			Increase/ (Decrease)
Net sales volume:
Oil and condensate (Bbls)	825,845			28,741			797,104
Net revenue:
Oil and condensate	$	62,954,901		$	2,350,388		$	60,604,513
Average sales price:
Oil (per Bbl)	$	76.23		$	81.78		$	(5.55	)
Operating expenses
Lease operating expense	$	11,648,877		$	754,833		$	10,894,044
General and administrative	42,093,616			18,548,465			23,545,151
Geological, geophysical and engineering	794,925			4,045,381			(3,250,456		)
Depreciation, depletion and amortization	16,061,540			792,531			15,269,009
Total operating expenses	$	70,598,958		$	24,141,210		$	46,457,748
Operating loss	$	(7,644,057	)	$	(21,790,822	)	$	14,146,765

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 primarily due to increased oil production 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 primarily 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 average sales price received. 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 an extended 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 used in our offshore oil production operation as part of our extended well testing program (see “Overview - Corvina Field” above for a more detailed discussion of the incident).   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 located in the offshore Block Z-1 in northwest Peru. In January 2009, we reach total drilling depth and began testing the formation. During the testing it was confirmed that the deeper prospective sands that were found lower than expected were located below the estimated oil-water contact, thus testing formation water. Operations have commenced to sidetrack the CX11-15D well, targeting a location higher in the geological formation. Once the sidetrack is complete, which we expect to be by the end of the first quarter, we will test the prospective oil sands which, in this location, should be above the oil-water contact and of better quality. As part of the extended well testing program, the well will then be placed on production if commercial amounts of oil are tested. We anticipate production increases in the field based on the CX11-15D well being completed in late March.

The net revenues above exclude the cost of royalties owed to the government of Peru. Royalties are calculated by Perupetro as stipulated in the Block Z-1 license agreement based on the same Northwest Oil Basket.  However, their

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calculation is based on the past two week average price before the crude oil delivery date, as opposed to 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 primarily 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 primarily due to additional employees in Peru and increases in compensation expenses and legal fees 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 primarily 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. See Item 7. — “Memorandum of Understanding with Shell Exploration Company (West) B.V.” above for further information. 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 is primarily a result of additional awards granted in the current year at the time when the price of our Common Stock was high and therefore fair value of the awards and 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 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 primarily due to performing seismic 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 primarily 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 primarily 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 term of the license agreement covering the property.  Accordingly, we recorded annual amortization expense of $0.2 million for both 2008 and 2007.

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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 primarily 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 primarily 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 primarily due to a reduction in realized foreign exchange rate gains of approximately $0.1 million in 2008. The exchange rate gain is primarily 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 US Dollar. See Item 7A. — “Quantitative and Qualitative Disclosures About Market Risk, Foreign Currency Exchange Rate Risk”, for a more detailed discussion.

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 primarily 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 an extended 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 extended 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 affect 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 income (loss) before income tax expense/ (benefit) for the year ended December 31, is as follows:

	2008			2007			2006
United States	$	(28,121,651	)	$	(12,922,310	)	$	(11,627,018	)
Foreign	21,617,014			(7,548,671		)	(3,860,441		)
Loss from continuing operations before income taxes	$	(6,504,637	)	$	(20,470,981	)	$	(15,487,459	)

The income tax expense/(benefit) for the year ended December 31, 2008, 2007 and 2006 differs from the amount computed by applying the U.S. statutory rate for the applicable year to consolidated net loss before taxes as follows:

	2008			2007			2006
Federal statutory income tax rate	$	(2,211,576	)	$	(7,139,493	)	$	(5,242,737	)
Increases (decreases) resulting from:
Non-deductible stock compensation expense	6,550,722			3,653,338			—
Tax effect of Peru conversion to permanent establishment status	7,642,249			—			—
Change in domestic valuation allowance	(8,839,544		)	3,525,156			5,242,737
	$	3,141,851		$	39,001		$	—

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 ($0.30) per basic and diluted share during the same period in 2007. The decrease in net loss is primarily due to the increase in oil revenues during 2008 compared with limited oil revenues in 2007.

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Year Ended December 31, 2007 Compared to Year Ended December 31, 2006

	2007		2006		Increase/ (Decrease)
Lease operating expense	$	754,833	$	—	$		754,833
General and administrative	18,548,465		11,531,864		7,016,601
Geological, geophysical and engineering	4,045,381		2,048,742		1,996,639
Depreciation, depletion and amortization	792,531		213,815		578,716
Total operating expenses	$	24,141,210	$	13,794,421	$	10,346,789

Our operating and administrative expenses consisted principally of general and administrative costs as well as geological, geophysical and engineering costs.

Due to commencement of production from the CX-11 platform, we have incurred lease operating expense of $0.7 million during the year ended December 31, 2007 compared to no operating expenses incurred during the year ended December 31, 2006. General and administrative costs have increased significantly from $11.5 million during the year ended December 31, 2006 to $18.5 million during the year ended December 31, 2007 as a result of our increased activity levels, necessary additional personnel and costs associated with being a public company listed on the American Stock Exchange. Included in general and administrative expense is stock-based compensation expense. Stock-based compensation expense for year ended December 31, 2007 was approximately $7.0 million compared to $3.2 million during the year ended December 31, 2006. Stock based compensation expense is primarily related to our restricted stock grants, accrued stock-based compensation under our 2007 Long-Term Incentive Plan and the recognition of Incentive Earn-out Stock Compensation for two of our executive officers, in the third quarter of 2007 due to the achievement of the entitlement to the right to production of 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 overall increase was partially offset by a reduction associated with unvested restricted stock grants forfeited by certain employees who resigned from the Company during the year ended 2007. We incurred $4.0 million of geological, geophysical and engineering costs during the year ended December 31, 2007 primarily related to the oil discovery in Corvina and to the continued development of our Corvina gas-to-power project and 2-D seismic expense on Block XIX, compared to $2.0 million during the year ended December 31, 2006 primarily as a result of the commencement of our Corvina gas-to-power project.

We received net cash distributions from our investment in Ecuador property of $0.5 million during the year ended December 31, 2007, compared to net cash distributions of $1.3 million during the year ended December 31, 2006. The decrease in income primarily relates to capacity problems at the local refinery in Ecuador. As a result, oil sales for the year ended December 31, 2007 were significantly less than for the year ended December 31, 2006. 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 term of the license agreement covering the property. Accordingly, we recorded $0.2 million of amortization expense during each of the years ended December 31, 2007 and December 31, 2006.

We incurred interest expense of $0.9 million during the year ended December 31, 2007, all of which was capitalized to construction in progress, compared with $15,815 for the year ended December 31, 2006. The difference is primarily due to interest associated with the purchase of two vessels under capital lease obligation in 2007 compared to other debt related to acquiring furniture and fixtures during 2006.

We did not incur any registration delay expense for the year ended December 31, 2007. During the year ended December 31, 2006 we recorded registration delay expense totaling $3.6 million of which approximately $1.2 million was paid in cash and $2.3 million was settled by the issuance of 865,238 shares of common stock. In connection with the private placement of 11,466,000 common shares in July 2005, we were obligated to prepare and file with the SEC a Registration Statement on Form S-1 and to use our best efforts to cause the Registration Statement to be declared effective by the SEC no later than ninety days from closing. The Registration Statement had not been declared effective by the required date and we were liable to the investors for liquidated damages in an amount equal to 1.0% of the purchase price of the shares, approximately $343,000, for each thirty day period until the Registration Statement is declared effective by the SEC. In addition, in connection with the private placement of 4,482,000 common shares in March 2006, we were obligated to prepare and file with the SEC a Registration Statement on Form S-1 within ninety days from closing, and to use our best efforts to cause the Registration Statement to be declared effective by the SEC no later than ninety days, from March 8, 2006. The Registration Statement was not filed or declared effective by the required dates and we were liable to the investors for liquidated damages in an amount equal to 1.0% of the purchase price of the shares, approximately $50,010, for each thirty

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day period until the Registration Statement is declared effective by the SEC. On November 8, 2006, the SEC declared effective the Registration Statement on Form S-1 covering the common shares issued in connection with the July 19, 2005, March 10, 2006, and June 30, 2006, private placements. As a result, we were no longer subject to the liquidated damages described above.

As a result of our cash balances from the various private placements of our common stock during 2005, 2006 and 2007, we received interest income of $0.9 million during the year ended December 31, 2007 and $0.8 million during the twelve months ended December 31, 2006.

We realized federal income tax expense of $39,001 during the year ended December 31, 2007. The tax is related to the revenues from our 10% non-operated working interest in the Santa Elena Property in southwestern Ecuador. No tax expense was incurred during the year ended December 31, 2006.

During the year ended December 31, 2007, we recognized a foreign exchange gain of approximately $0.2 million compared to approximately $0.1 million during the year ended December 31, 2006. This is primarily as a result of our collection of Value Added Tax in Peru (“IGV”) under the early recovery program. IGV is denominated in local currency and the Peruvian Nuevo Sol has become stronger against the U. S. Dollar over the past year.

We realized a net loss of $20.5 million or $(0.30) per share during the year ended December 31, 2007, compared to a net loss of $15.5 million or $(0.29) per share for the year ended December 31, 2006.

Liquidity, Capital Resources and Capital Expenditures

At December 31, 2008, we had cash and cash equivalents of $5.3 million and current accounts receivable related to our December oil sales of $5.3 million, all of which was collected in early January 2009. We also had $12.1 million in Value Added Tax receivable which we will collect over time as we invoice our oil sales.

At December 31, 2008, we had trade accounts payable and accrued liabilities of $45.0 million. Of this amount, approximately $10.0 million is over 60 days past due. In addition we have $6.8 million in income tax and $1.9 million of profit sharing, as required under Peruvian law, due in April 2009. We also have capital lease obligations primarily related to the barges used in our marine operations of $7.8 million, all of which matures by end of 2009.

Our outstanding long-term debt at December 31, 2008 consisted of a $15.0 million Reserve-Based Lending Facility bearing interest at LIBOR plus 2.75% due December 31, 2012.

	Year Ended December 31,
Cash Flows	2008			2007			2006
Cash provided by (used in):
Operating activities	$	48,721,975		$	(15,170,838	)	$	(6,681,722	)
Investing activities	(102,185,451		)	(58,463,949		)	(34,269,582		)
Financing activities	51,266,098			55,824,742			36,820,407

Operating Activities

Cash provided by (used in) operating activities increased by $63.9 million to $48.7 million in 2008 from $(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 primarily 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.

Cash used in operating activities increased by ($8.5) million to ($15.2) million in 2007 from $(6.7) million in 2006, respectively. Cash used in operations increased primarily due to higher operating costs of our first wells, the CX11-21XD and CX11-14D, which began producing oil on a limited basis in November 2007. Cash flow before changes in operating assets and liabilities decreased by ($2.9) million reflecting the increase operating activity and changes in operating assets and

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liabilities provided a use of cash of ($5.5) million primarily due to the increase in accounts receivable and decrease in accounts payable as a result of our initial oil sales in the last two months of 2007.

Investing Activities

Net cash used in investing activities increased by ($43.7) million to ($102.2) million in 2008 from $(58.5) million in 2007, respectively, and is primarily due to increased capital expenditures in 2008. Net cash used in investing activities increased by ($24.2) million to ($58.5) million in 2007 from $(34.3) million in 2006, 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.

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 of electricity for 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.  This new program should enable us to initiate production in a more efficient manner which will allow for a better understanding of the behavior and characteristics of the Corvina oil field.

In preparation for our drilling campaign in Albacora field, we performed well control on the existing well heads located at the A-1 platform.  We incurred approximately $1.5 million in well control costs to provide a safe environment to 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 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.

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.

2007 Equipment Activity

In August 2006, we 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 CX-11 platform. No injuries were sustained by any of our employees, nor to any of the tug boat operator’s crew members. The BPZ-01 is a U.S. flagged vessel and as such was inspected after the incident by the U.S. Coast Guard, to its satisfaction. The barge resumed normal operations immediately thereafter. Based upon information currently available, we estimated that total expenditures related to this incident would be approximately $1.1 million. As of December 31, 2006, approximately $0.4 million had been incurred for barge recovery and temporary repairs to the vessel. In addition, we expect to incur approximately $0.3 million in permanent repairs to the barge and approximately $0.4 million of

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consequential damages, primarily stand-by charges. As of December 31, 2008, a claim of approximately $0.8 million for repairs is expected to be filed with the insurance carrier. A deductible of $75,000 will be applied to this insurance claim when reimbursed.  We received proceeds from the underwriter to cover a related claim regarding third party cargo that was damaged in the grounding incident. During the year ended December 31, 2008, approximately $80,000 of insurance proceeds was received in connection with this claim.  A deductible of $25,000 was offset against the insurance proceeds received.  This amount is unrelated to the $0.8 million hull claim described above as the proceeds from the cargo claim were passed on to the third party owner of the cargo that was damaged.  The hull claim will be finalized upon the dry docking of the vessel.  Because of the delays caused by the drilling of the highly deviated CX11-20XD well during the third quarter 2008, the dry dock of the BPZ-01 is scheduled during the last quarter of 2009.

In connection with the Block XIX license contract, we completed shooting 200 kilometers of 2-D seismic in 2007. The cost to acquire this seismic data was approximately $3.6 million. Processing and interpretation of the data was completed in late January 2008. Due to the flexibility under the license contract and as a result of our decision in 2008 to focus on developing the Corvina and Albacora fields during 2009, we have postponed our initial exploration of Block XIX to 2010.

On June 13, 2007, we entered into a capital lease agreement, with an option to purchase, for two barges to assist in the development of the Corvina oil. The two barges were towed to Peru where one barge, the Nu’uanu, is being used to transport oil between the CX11 platform and the refinery in Talara, approximately 70 miles south. The Nomoku is currently fitted with the required equipment for its intended use as a FPSO and moored next to the CX11 platform.

Financing Activities

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.

Cash provided by financing activities increased by $19.0 million to $55.8 million in 2007 compared to $36.8 million in 2006. This increase in cash provided by financing activities reflects additional proceeds from the $15.5 million issuance of debt and proceeds received from the exercise of stock options.

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. We currently have approximately $222 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.

$15.0 Million IFC Reserve-Based Credit Facility

On August 15, 2008, we entered into a $15.0 million reserve-based lending facility (“$15.0 million Senior Debt”) agreement (the “Loan Agreement”) with IFC through our subsidiaries BPZ Exploración & Producción S.R.L and BPZ Marine Peru S.R.L as borrowers.   The reserve-based lending facility matures in December 2012 and bears interest at an approximate rate of LIBOR plus 2.75%, currently equivalent to 4.56% based on the current six month LIBOR rate of 1.81%.  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.  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 cover ratio. We were in compliance with all applicable covenants of the Loan Agreement as of December 31, 2008.  Funding for the initial amounts available under the Loan Agreement was subject to satisfying certain conditions precedent which were fulfilled on October 17, 2008 and subsequently BPZ borrowed the entire $15.0 million available under the Loan Agreement.

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

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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.

Performance Bonds

As of December 31, 2008, we had restricted cash deposits of $5.1 million, which partially collateralizes the insurance and performance bonds. 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 $2.9 million to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally we have $2.2 million of restricted cash to collateralize insurance bonds for import duties related to the FPSO and transport tanker.

During the year ended December 31, 2008, we were refunded $0.8 million from a performance bond related to the second exploration phase under the Block XIX license contract and approximately $1.0 million related to a performance commitment under a drilling services contract.

All of the performance bonds are issued by Peruvian banks and their terms are governed by the corresponding license contract.

2009 Project Capital Budget

We established a 2009 capital expenditures budget of approximately $86.0 million and intend to focus our efforts on oil production in Block Z-1 by committing a majority of our capital expenditures budget to appraise and develop the oil in the Corvina and Albacora fields. Accordingly, we have decided to keep the rig currently drilling at the CX-11 platform in place to drill three additional oil development wells in 2009 to maximize cash flow. Additionally, the recently contracted rig scheduled for onshore Block XIX, will instead be mobilized to the platform near the Albacora field to drill two new wells beginning in the third quarter of 2009. The goal under this development plan is to increase total production at the end of 2009 to 10,000 barrels of oil per day (bopd).

Due to the flexibility of the license contracts in Peru, we intend to delay the exploration of Block XIX to 2010. We believe the increased production from the Corvina field, combined with cost restructuring, will allow us to be cash flow positive while drilling at the Corvina and Albacora fields. Additionally we are continuing to work with the IFC and Natixis on the reserve based credit facility which is expected to have a borrowing base sufficient that, when added to cash flow from expected Corvina and Albacora field oil sales and recent sale of our common stock, should cover the capital expenditures noted below.

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	2009 Capital Budget
	($ in millions)
Corvina
CX11-15D drillling and testing	$	11.0
CX11-19D development and production	10.0
CX11-22D development and production	10.0
CX11-23D initial drilling	5.0
Other facilities and activities	7.0
	43.0
Albacora
A-14XD exploration and development	15.0
A-15XD exploration and development	15.0
Other facilities and activities	11.0
	41.0
Other activities	2.0
Total estimated capital budget	$	86.0

Liquidity Outlook

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 primarily due to increased oil production from the CX-11 platform located in the Corvina field in Block Z-1 in northwest Peru. Oil production and revenues increased proportionately compared to 2007 primarily due to the increase in number of wells producing in 2008 and the increase in production days.

Our major sources of funding to date have been through oil sales, equity raises and, to a lesser extent, debt financing activities. With our current cash balance, proceeds from the expected IFC and Natixis debt facilities, current and prospective Corvina and Albacora Oil development cash flow, 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, 2008, 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, 2008
			Less Than		One to		Three to		More Than
	Total		One Year		Three Years		Five Years		Five Years
Contractual Obligations:
Operating lease obligation (1)	$	5,855,320	$	950,847	$	1,934,376	$	2,069,974	$	900,123
Capital lease obligation (2)	$	10,513,061	$	10,495,013	$	18,048	$	—	$	—
Debt obligation (3)	$	17,166,950	$	684,300	$	8,697,525	$	7,785,125	$	—
Purchase obligation (4)	$	42,887,500	$	6,939,143	$	35,948,357	$	—	$	—
Total	$	76,422,831	$	19,069,303	$	46,598,306	$	9,855,099	$	900,123

(1)Includes operating leases for our executive office in Houston, Texas, and our branch offices in Lima, Peru. In 2008, both our Houston office and Lima offices entered into agreements for additional offices space of 7,070 square feet and 22,500 square feet expiring 2016 and 2013, respectively.

(2)Includes capital lease for two production and storage barges which began in August 2007 and is set to expire in November 2009. Lease payments are variable based on the working status of the barges, with a purchase option of $5,000,000 after the first year of the lease and $4,000,000 after the maturity date of the lease. Also, includes lease-purchase of the BPZ-02 which stipulates a 19% rate of interest (33% effective rate of interest) over a one-year term at a fixed rate of payment of $694,167. At the end of the term, title to the BPZ-02 will transfer to us upon final payment of the lease. In addition, includes the $2.4 million capital lease of the production equipment onboard the Floating Production Storage and Offload Facility, the Namoku. The lease terms are variable and bear an interest rate of 18% based on our incremental borrowing rate for similar equipment. In accordance with the terms of the lease, a bargain purchase option exists at the end of the lease. Finally, includes the capital lease for office furniture in our executive office in Houston, Texas expiring in 2010.

(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 MarinePeru S.R.L as borrowers.  The interest used is an approximate rate of LIBOR plus 2.75%, currently equivalent to 4.56% based on the current six month LIBOR rate of 1.81%.  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.

(4)The amount relates to the purchase of three LM6000 gas-fired turbines from GE for $51.5 million.  Due to the amendment, the lease payments include the required payments due in 2009 and the remaining balance under the original lease agreement in 2010.  However, both GE and BPZ have agreed to determine new delivery dates, pricing and payment terms when we decide to bring the lease-purchase out of the suspension period.

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”). Management uses estimates and assumptions in preparing the consolidated financial statements in accordance with GAAP. Those estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses in the consolidated financial statements, and the disclosure of contingent assets and liabilities. We have identified the following as critical accounting policies directly related to our business and operations, and the understanding of our financial statements.

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Successful Efforts Method of Accounting

We follow the successful efforts method of accounting for our investments in oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Certain costs of exploratory wells are capitalized pending determinations that proved reserves have been found. If the determination is dependent upon the results of planned additional wells and required capital expenditures to produce the reserves found, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well and additional wells are underway or firmly planned to complete the evaluation of the well. All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive or at the one year anniversary of completion of the well if proved reserves have not been attributed and capital expenditures as described in the preceding sentence are not required. We assess our capitalized exploratory wells pending evaluation each quarter to determine whether costs should remain capitalized or should be charged to earnings. Other exploration costs, including geological and geophysical costs, are expensed as incurred. We 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.

Revenue Recognition

The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

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

Impairment of Long-Lived Assets

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

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

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Future Dismantlement, Restoration, and Abandonment Costs

The accounting for future development and abandonment costs changed on January 1, 2003, with the issuance of Statement of Financial Accounting Standards (“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 the Company and its wholly-owned subsidiaries and branch offices. All intercompany balances and transactions have been eliminated.

Our accounting policy regarding partnership or joint venture interests in oil and gas properties is to consolidate such interests on a pro-rata basis in accordance with accepted practice in the oil and gas industry. However, we have not been able to receive timely information to allow us to proportionately consolidate the minority non-operated 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.

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 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

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 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.

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·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 is currently evaluating the impact of the amendments on its consolidated financial position, results of operations and cash flows.

In addition, in May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles”, which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America. This statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” The Company does not expect the adoption of SFAS No. 162 to have a material impact on its consolidated financial position, results of operations or cash flows.

Also in June 2008, the FASB issued Financial Staff Position (“FSP”) No. FSP EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” (“FSP EITF 03-6-1”), which provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share under the two class method. FSP EITF 03-6-1 is effective for us on January 1, 2009 and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) will be adjusted retroactively to conform to its provisions. Early application of FSP EITF 03-6-1 is not permitted. On January 1, 2009, we adopted the provisions of FSP EITF 03-6-1 and the adoption, although our restricted stock awards meet this definition, did not have a significant impact on our reported earnings per share.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary 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, 2008, we had long-term debt and capital lease obligations of approximately $15.0 million and current maturities of long-term debt and capital lease obligations of approximately $7.8 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 2008 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 first capital lease obligation is for the FPSO barges which began in August 2007 and is set to expire in November 2009. Lease payments are variable based on the working status of the barges, with a purchase option of $5,000,000 after the first year of the lease and $4,000,000 after the maturity date of the lease.  The capital lease obligation has an imputed interest rate of 18.00% over a lease term.  The second capital lease obligation contains a lease-purchase option and stipulates a 19% rate of interest (33% effective rate of interest) over a one year term, at which point title to the BPZ-02 will transfer to us upon final payment of the lease.  The third capital lease obligation is for the production equipment on board the FPSO barge, the Namoku, and contains a purchase option at the end of twelve 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.

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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 the IFC will structure 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, 2008, 2007 and 2006 we recognized exchange rate gains of approximately $0.1 million, $0.2 million and $0.1 million, respectively.  The exchange rate gains are primarily 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.  However, the total gain during 2008 was partially offset by Nuevo Sol denominated accounts payable being settled.

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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	54
Consolidated Balance Sheets as of December 31, 2008 and 2007	55
Consolidated Statements of Operations for the Years Ended December 31, 2008, 2007 and 2006	56
Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2008, 2007 and 2006	57
Consolidated Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	58
Notes to Consolidated Financial Statements	59
Supplemental Oil and Gas Disclosures (Unaudited)	88

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Report of Independent Registered Public Accounting Firm

To the Board of Directors
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, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2008. 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.

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, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, 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, 2008, 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 February 27, 2009, expressed an unqualified opinion thereon.

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

February 27, 2009

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BPZ Resources, Inc. and Subsidiaries
Consolidated Balance Sheets

	December 31,
	2008			2007
ASSETS
Current assets:
Cash and cash equivalents	$	5,316,810		$	7,514,188
Restricted cash	—			1,013,152
Accounts receivable	5,275,647			2,950,089
Value added tax receivable	12,109,605			7,496,547
Inventory	4,053,536			3,372,883
Prepaid and other current assets	3,269,210			2,271,282
Total current assets	30,024,808			24,618,141
Property, equipment and construction in progress, net	193,933,635			100,366,091
Restricted cash	5,153,000			2,834,519
Prepaid and other non-current assets	—			230,433
Investment in Ecuador property, net	1,382,436			1,570,020
Deferred tax asset	4,871,540			—
Total assets	$	235,365,419		$	129,619,204
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	35,285,874		$	11,774,316
Accrued liabilities	9,920,211			4,384,049
Other liabilities	719,663			263,439
Current income taxes payable	6,841,275			—
Accrued interest payable	—			458,279
Current maturity of long-term debt and capital lease obligation	7,819,908			6,188,668
Total current liabilities	60,586,931			23,068,751
Asset retirement obligation	580,786			273,048
Long-term debt	15,017,511			15,537,293
Total long-term liabilities	15,598,297			15,810,341
Commitments and contingencies (Note 15)
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 and 73,914,471 shares issued and outstanding at December 31, 2008 and December 31, 2007, respectively	227,136,599			149,050,032
Accumulated deficit	(67,956,408		)	(58,309,920		)
Total stockholders’ equity	159,180,191			90,740,112
Total liabilities and stockholders’ equity	$	235,365,419		$	129,619,204

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

55

BPZ Resources, Inc. and Subsidiaries
Consolidated Statements of Operations

	Year Ended December 31,
	2008			2007			2006
Revenue	$	62,954,901		$	2,350,388		$	—
Operating and administrative expenses:
Lease operating expense	11,648,877			754,833			—
General and administrative	42,093,616			18,548,465			11,531,864
Geological, geophysical and engineering	794,925			4,045,381			2,048,742
Depreciation, depletion and amortization	16,061,540			792,531			213,815
Total operating expenses	70,598,958			24,141,210			13,794,421
Operating loss	(7,644,057		)	(21,790,822		)	(13,794,421		)
Other income (expense):
Income from investment in Ecuador property, net of amortization	717,571			264,031			1,403,298
Interest expense	—			—			(15,815		)
Registration delay expense	—			—			(3,552,513		)
Interest income	319,424			854,905			787,455
Other income/(expense)	102,425			200,904			(315,463		)
Total other income (expense)	1,139,420			1,319,840			(1,693,038		)
Loss before income taxes	(6,504,637		)	(20,470,982		)	(15,487,459		)
Income taxes	3,141,851			39,001			—
Net loss	$	(9,646,488	)	$	(20,509,983	)	$	(15,487,459	)
Basic and diluted net loss per share	$	(0.12	)	$	(0.30	)	$	(0.29	)
Weighted average common shares outstanding	77,389,536			69,156,404			53,751,761

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

56

BPZ Resources, Inc. and Subsidiaries
Consolidated Statements of Stockholders’ Equity (Deficit)
Years Ended December 31, 2008, 2007 and 2006

	Common Stock					Additional Paid- in			Stock Subscription			Accumulated
	Shares		Amount			Capital			Receivable			Deficit			Total
Balances at January 1, 2006	40,349,979		$	56,873,641		$	2,401,239		$	(230,825	)	$	(22,312,478	)	$	36,731,577
Stock-based compensation	10,000		43,900			318,281			—			—			362,181
Exercise of stock options assumed in acquisition	275,000		882,750			(882,750		)	—			—			—
Long-term incentive compensation plan, net of forfeitures	(8,500	)	(143,599		)	3,006,926			—			—			2,863,327
Common stock sold for cash, net of offering costs	12,652,000		36,835,500			—			—			—			36,835,500
Warrants issued in connection with sale of common stock	—		(248,645		)	248,645			—			—			—
Common stock issued for registration delay expenses	865,238		2,330,779			—			—			—			2,330,779
Net loss	—		—			—			—			(15,487,459		)	(15,487,459		)
Balances at December 31, 2006	54,143,717		96,574,326			5,092,341			(230,825		)	(37,799,937		)	63,635,905
Stock-based compensation	5,000		19,000			(24,891		)	—			—			(5,891		)
Exercise of stock options assumed in merger	378,652		647,035			(647,035		)	—			—			—
Exercise of stock options	1,868,752		3,425,616			—			—			—			3,425,616
Long-term incentive compensation plan, net of forfeitures	1,348,350		12,020,140			(6,756,646		)	—			—			5,263,494
Incentive earn-out shares	—		—			1,782,000			—			—			1,782,000
Common stock sold for cash, net of offering costs	7,170,000		37,717,497			(799,351		)	230,825			—			37,148,971
Common stock dividend (merger earn-out shares)	9,000,000		—			—			—			—			—
Adjustment for negative APIC - deferred stock compensation	—		(1,353,582		)	1,353,582			—			—			—
Net loss	—		—			—			—			(20,509,983		)	(20,509,983		)
Balances at December 31, 2007	73,914,471		149,050,032			—			—			(58,309,920		)	90,740,112
Exercise of stock options assumed in merger	325,000		422,500			—			—			—			422,500
Exercise of stock options	567,100		2,046,342			—			—			—			2,046,342
Long-term incentive compensation plan, net of forfeitures	—		18,463,765			—			—			—			18,463,765
Common stock sold for cash, net of offering costs	2,200,000		40,903,960			—			—			—			40,903,960
IFC debt conversion	1,491,819		15,500,000			—			—			—			15,500,000
Stock subscription agreement	250,000		750,000			—			—			—			750,000
Net loss	—		—			—			—			(9,646,488		)	(9,646,488		)
Balances at December 31, 2008	78,748,390		$	227,136,599		$	—		$	—		$	(67,956,408	)	$	159,180,191

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

57

BPZ Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows

	For the Year Ended December 31,
	2008			2007			2006
Cash flows from operating activities:
Net loss	$	(9,646,488	)	$	(20,509,983	)	$	(15,487,459	)
Adjustments to reconcile net loss to net cash used by operating activities:
Stock-based compensation	18,463,765			7,039,603			3,225,508
Stock issued for registration delay expenses	—			—			2,330,779
Depreciation, depletion and amortization	16,061,540			792,531			213,815
Amortization of investment in Ecuador property	187,584			187,584			187,584
Deferred income taxes	(4,871,540		)	—			—
Net gain (loss) on the sale of asset	—			9,207			(150		)
Amortization of deferred financing fees	—			2,067			—
Changes in operating assets and liabilities:
Increase in accounts receivable	(2,325,558		)	(2,950,089		)	—
Increase in value added tax receivable	(4,613,058		)	(4,336,849		)	(2,797,143		)
Increase in inventory	(661,434		)	(1,200,269		)	(1,945,781		)
Decrease in other assets	240,224			(298,783		)	(1,465,386		)
Increase in accounts payable	23,511,558			4,398,006			6,628,963
Increase in accrued liabilities	5,077,883			1,534,673			2,378,744
Increase in other income taxes payable	6,841,275			—			—
Increase in other liabilities	456,224			161,464			48,804
Net cash provided by (used in) operating activities	48,721,975			(15,170,838		)	(6,681,722		)
Cash flows from investing activities:
Property and equipment additions	(99,866,970		)	(55,766,279		)	(34,575,535		)
Restricted cash	(2,318,481		)	(2,697,670		)	305,953
Net cash used in investing activities	(102,185,451		)	(58,463,949		)	(34,269,582		)
Cash flows from financing activities:
Borrowings	17,819,080			15,500,000			—
Repayments of borrowings	(10,450,784		)	(17,345		)	(15,093		)
Deferred loan fees	(225,000		)	(232,500		)	—
Proceeds from exercise of warrants, net	750,000			—			—
Proceeds from exercise of stock options, net	2,468,842			3,425,616			—
Proceeds from sale of common stock, net	40,903,960			37,148,971			36,835,500
Net cash provided by financing activities	51,266,098			55,824,742			36,820,407
Net decrease in cash and cash equivalents	(2,197,378		)	(17,810,045		)	(4,130,897		)
Cash and cash equivalents at beginning of period	7,514,188			25,324,233			29,455,130
Cash and cash equivalents at end of period	$	5,316,810		$	7,514,188		$	25,324,233
Supplemental cash flow information:
Cash paid for:
Interest	$	4,678,454		$	470,440		$	15,815
Income tax	1,165,210			39,001			—
Non — cash items:
Purchase and additions to equipment with the issuance of a capital lease obligation	$	9,243,162		$	6,170,146		$	—
Accrued interest capitalized to construction in progress	230,433			458,279			—
Depletion allocated to production inventory	19,219			226,831			—
Depreciation on support equipment capitalized to construction in progress	976,967			474,421			195,755
Asset retirement obligation capitalized to property and equipment	268,574			268,572			—

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

58

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Note 1 — Basis of Presentation and Significant Accounting Policies

Organization

BPZ Resources, Inc., (the “Company” or “BPZ”) 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 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 Company owned gas-fired power generation facility.

The Company maintains a subsidiary registered in Peru through our wholly-owned subsidiary BPZ Energy, Inc., a Texas limited liability company, formerly BPZ Energy, Inc. (“BPZ — Texas”) and its subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership.. Currently, BPZ Energy has exclusive rights and license agreements for oil and gas exploration and production covering a total of approximately 2.4 million acres, in four blocks, in northwest Peru. The Company’s license contracts cover 100% ownership of Block Z-1 (739,205 acres), Block XIX (472,860 acres), Block XXII (948,000 acres) and Block XXIII (248,000 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. The Company’s license contracts provide for an initial exploration period of seven and potentially up to thirteen years for Block Z-1and seven and potentially up to ten years for Blocks XIX, XXII and XXIII. In addition, they require that the Company conduct specified activities on the properties during this period. If the exploration activities are successful, 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 applies to oil exploration and production as well.

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 initial stages of developing its oil and natural gas reserves and has begun producing oil and selling oil from the CX-11 platform in the Corvina field of Block Z-1 under an extended well testing program. Additionally, the Company’s activities in Peru include analysis and evaluation of technical data on its properties, preparation of the development plans for the properties, including detailed engineering and design of the power plant and gas processing facilities, refurbishment of and designs for platforms to be used under an extended well testing program, procuring machinery and equipment for an extended drilling campaign, obtaining all necessary environmental and operating permits, bringing additional production on-line and securing the required capital and financing to conduct the current plan of operation.

Corvina Field

The Company is producing oil from its recent discoveries at the CX-11 platform, located in the Corvina Field within the offshore Block Z-1, under an extended well testing program which began on November 1, 2007.  The Corvina field consists of 47,000 acres in water depths of less than 200 feet.  The Company is currently concentrating its drilling efforts on West Corvina, which consists of 3,500 acres and have completed a total of four oil producing wells, the CX11-21XD, CX11-20XD, the CX11-18XD and the CX11-14D.  The oil is delivered by barge to the Petroleos del Perú-PETROPERU S.A. (“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.

On October 24, 2007, Tecnomarine, the Company’s former primary marine transportation contractor, entered into two short-term agreements with the commercial division of the Peruvian Navy to lease two small tankers to for use in its offshore oil production operation.  On January 30, 2008, one of the tankers, the T/V SUPE (“Supe”), sank after catching fire.  At the time of the incident, the tanker contained approximately 1,300 barrels of oil, most of which burned in the fire. Official environmental impact assessments concluded that environmental issues have been adequately controlled. On December 18, 2008, a lawsuit was filed by two crewmembers and the family and estate of two of the deceased crewmembers of the Supe against the Company. As none of the Peruvian government sanctioned investigations into the Supe incident found fault on the part of Tecnomarine, the Company or the Company’s subsidiary, BPZ Exploración & Producción S.R.L., the Company does not currently believe based upon the known facts relating to the incident that the claims asserted against BPZ are

59

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

meritorious and intends to vigorously defend itself. The Company believes the incident would be covered by its insurance policies, after a customary deductible. As a result of the incident, operations were voluntarily suspended at the CX-11 platform. For further information regarding the civil claims asserted against us see Note 15, “Commitment and Contingencies” and Note-16, “Legal Proceedings”.

On March 14, 2008, The Company was notified by the Organismo Supervisor de la Inversión en Energía y Mineria (“OSINERGMIN”)  the government regulatory agency in Peru responsible for monitoring industrial safety, that it could resume drilling and testing operations at the CX-11 platform allowing the Company to begin testing the CX11-18XD well.  Three drill stem tests were conducted in the Upper Zorritos formation.  The first two drill stem tests targeted the lower sands in zones that had not previously been tested.  The third drill stem test targeted sands that had tested oil in the Company’s CX11-21XD well.  The Company began producing from the CX11-18XD well in May 2008 and, on June 9, 2008; it received the clearance needed to transport oil from the CX-11 platform to the nearby Talara refinery by the corresponding Peruvian environmental agency.  In addition, the Company’s floating production storage and offloading (“FPSO”) vessel was placed into service in the Corvina field and is currently being used in the extended well testing program to process produced crude oil.

Upon completion of the CX11-18XD well, the Company began drilling operations on the CX11-20XD well in May 2008.  The CX11-20XD well is positioned higher up in the geologic structure from the CX11-21XD well.  The well has been positioned to further develop the top gas sands found in the previously drilled CX11-21XD well, the oil sands currently producing in the CX11-21XD and CX11-18XD wells, the oil sands encountered and briefly tested in the CX11-18XD well during the initial drill-stem test number one, as well as sands found in the CX11-14D well.  The well tested positive for oil in quantities that the Company believes to be commercially producible.  The Company has completed two drill stem tests on four sets of oil sands in the well.  On November 1, 2008, the Company completed the CX11-20XD well as an oil-producing well under an extended well testing program currently ongoing at the Corvina field. However, because the well crosses sands which tested positive for what it believe to be economic quantities of gas, during the drilling and testing of both the CX11-21XD and CX11-18XD wells, it intends to re-complete the CX11-20XD well, with dual production strings, when gas is needed for the gas-to-power project, to allow the well to produce gas as well as oil.

On November 21, 2008, the Company began drilling operations on the CX11-15D well in the Corvina field located within the offshore Block Z-1 in northwest Peru. The CX11-15D targeted the known oil and gas sands higher in the geological formation with the main objective of proving up a portion of the probable oil and gas reserves and giving the Company another oil producing well. 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. The tests in the upper oil zones resulted in no flow due to the quality of the sands in this location. However, the gas sands in the gas zone were encountered higher than expected, which should allow the Company to prove up some of the probable gas reserves. Operations have commenced to sidetrack the CX11-15D well, targeting a location higher in the geological formation. Once the sidetrack is complete, in approximately one month, the Company will test the prospective oil sands which, in this location, should be above the oil-water contact and of better quality. As part of the extended well testing program, the well will then be placed on production if commercial amounts of oil are tested. The Company anticipates production increases in the field based on the CX11-15D well being completed in late March.

As of December 31, 2008, the Company has four oil producing wells, the CX11-21XD, CX11-20XD, the CX11-18XD and the CX11-14D under an extended well testing program. For 2009 the Company intends to keep the drilling rig currently at the CX-11 platform to focus on oil development in the offshore Block Z-1 and to drill three additional oil development wells to maximize cash flow.

Albacora Field

The Albacora Field is located in the northern part of the offshore Block Z-1.  Based on the Company’s internally developed models, the Albacora field consist of approximately 6,000 acres and, like the Corvina field, is located in water depths of less than 200 feet. In 2009, once the contracted drilling rig (the PTX18) has been mobilized to the Albacora A-1 platform, which is currently being refurbished, the Company plans to drill the A-14XD well, a twin well to Albacora’s 8-X-2 discovery well. The PTX18 rig is contracted with Petrex, the Company’s current drilling contractor, for a period of three years. This rig will be capable of drilling to approximately 14,000 feet, and will be modified to drill from an offshore platform. This first well in Albacora will qualify as an exploratory well as the Company plans on testing the prospective

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BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Lower Zorritos formation sands.  The 8-X-2 discovery well, drilled 35 years ago, tested oil and gas in the upper Zorritos formation sands at quantities the Company believes to be commercially producible.  The Company’s drilling plans in Albacora are to drill two new wells in 2009.

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, with certain upgrades, are expected to be capable of handling up to 360 MW of power. In order to support the Company’s proposed electric generation project, it 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, the Company believes it 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 the Company 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. As a result of factors outside the Company’s control, as further discussed below, it has postponed development of the gas-to power project until such time as the necessary financing, personnel and equipment becomes available to continue the project, including finding a joint venture partner to assist in the gas-to-power project.

GE Turbine Purchase Agreement

On September 26, 2008, the Company through its power generation subsidiary, Empresa Eléctrica Nueva Esperanza, SRL, entered into a $51.5 million contract for purchase of equipment and services (the “Agreement”) with GE Packaged Power, Inc. and GE International, Inc. Sucursal de Peru (collectively “GE”), which are part of GE Energy’s aeroderivative business.  The Agreement obligates the Company to purchase three LM6000 gas-fired turbines. Each turbine will have a generation capacity of 45 megawatts, with excess capacity of approximately 5%.  Delivery of the three units was initially scheduled for the fourth quarter 2009.

In January 2009, as a result of the Company’s decision to focus on increasing oil production, cash flow and reserves from the Corvina and Albacora fields during 2009, BPZ and GE entered into an amendment of the Agreement. Under the terms of the amendment, both GE and BPZ, agree 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 give right to terminate the contract, provided that the Company makes a payment to GE in the amount of $3.4 million no later than February 25, 2009. As of February 24, 2009, we paid $3.4 million related to milestone payment four to GE. In addition the Company agrees to make a payment in the amount of $3.5 million to GE no later than November 16, 2009. Any failure to make these payments in full will result in immediate termination of the Agreement with no cure period or time to correct the breach.

Once the Company decides to bring the Agreement out of the suspension period, it will provide evidence that payment security has been established and new delivery dates, pricing and payment terms will be determined by the BPZ and GE. All previous payments made by the Company on the Agreement will be applied to the new price.

Reincorporation, Name Change and Internal Restructuring

On October 11, 2007, BPZ Energy, Inc., a Colorado corporation, formerly named Navidec, Inc., (“Navidec”), completed a reincorporation from the State of Colorado to the State of Texas pursuant to the Plan of Conversion as approved by the shareholders at the 2007 annual meeting of shareholders held on August 17, 2007. The related filings with the Secretary of State of Texas also included a change of the company’s name from BPZ Energy, Inc. to BPZ Resources, Inc., in connection with an ongoing review of certain internal reorganization matters related to our international tax planning and corporate structure. The Company continues to do business under the name BPZ Energy in its regular business operations.

No changes to the members of the Board of Directors, the management, or the operations of the Company were made in connection with the reincorporation from a Colorado corporation to a Texas corporation. The Company remains the same business entity following the reincorporation to Texas, with all of the assets, rights, privileges and powers of, and all

61

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

property owned by, all debts due to, as well as any other causes of action belonging to the predecessor Colorado entity. As part of the reincorporation, a new Certificate of Formation and new Bylaws were adopted, and now govern the rights of holders of the Company’s common stock. At the effective time of the reincorporation, each outstanding share of the Colorado entity prior to the reincorporation was automatically converted into one share of the Texas entity.

Basis of Presentation and Principles of Consolidation

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

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 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.

Revenue Recognition

The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

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

Reporting and Functional Currency

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 foreign currency gains and losses. We have adopted Statement of Financial Accounting Standards (“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. Due to the relatively low level of activity to-date and the relatively steady exchange rate in Peru, a translation gain of approximately $0.1 million, $0.2 million and $0.1 million was recognized during the year ended December 31, 2008, 2007 and 2006, respectively. The primary reason for the translation difference related to the early recovery of Value Added Tax in Peru (“IGV”), which by Peruvian law must be transacted and accounted for in the local currency. However, the total gain during 2008 was partially offset by Nuevo Sol denominated accounts payable being settled.

Use of Estimates

The preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles 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.

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

62

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

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” contained herein under notes to the consolidated financial statements, the Company has secured various performance bonds, collateralized primarily 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, 2008 and December 31, 2007, 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 we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and interest. As of December 31, 2008, 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 is ranges between three and five 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 fifteen and twenty years. Maintenance and repairs are expensed as incurred. Replacements, upgrades or expenditures which improve and extend the life of the assets are capitalized. When assets are sold, retired or otherwise disposed, the applicable costs and accumulated depreciation and amortization are removed from the appropriate accounts and the resulting gain or loss is recorded.

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

63

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

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, 2008, 2007 and 2006, there was no impairment losses recognized by the Company.

Stock Based Compensation

On January 1, 2006, the Company adopted SFAS No. 123 — Revised 2004, “Share—Based Payment” (“SFAS No. 123(R)”), which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employees. SFAS No. 123(R) is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation”, and supersedes APB No. 25, “Accounting for Stock Issued to Employees”. Under the provisions of SFAS No. 123(R), 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. 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.

The Company adopted SFAS No. 123(R) using the modified prospective application method and, accordingly, no prior periods have been restated as a result of the adoption of this pronouncement. The modified prospective method requires recognition of compensation expense for stock-based payment awards that are granted, modified, repurchased or cancelled after 2005. Compensation expense for unvested stock options outstanding as of January 1, 2006 for which the requisite service has not been rendered is being recognized over the remaining service period using the compensation cost previously calculated for pro forma disclosure purposes under SFAS No. 123. See Note 10, “Stockholders’ Equity” for further discussion of the Company’s stock-based compensation plans.

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, 2008 and 2007 was $4.2 million and $0.9 million, respectively. No interest was capitalized during the year ended December 31, 2006 due to the lack of operational debt during that period.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily 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, 2008 and 2007 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” (“SFAS 109”). Under SFAS 109, 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.

64

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

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 Block Z-1 Corvina and Albacora fields and Block XIX for the year ended December 31, 2008, 2007 and 2006 were approximately $0.5 million, $0.3 million and $0.5 million, respectively.

Loss per Common Share

In accordance with provisions of 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

SEC Amendments to Oil and Gas Reporting Requirements

On December 31, 2008 the Securities and Exchange Commission (“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 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.

·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 is currently evaluating the impact of the amendments on its consolidated financial position, results of operations and cash flows.

Business Combinations

In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141 (revised 2007), “Business Combinations” (“SFAS No. 141(R)”), which replaces FASB Statement No. 141. SFAS No. 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired.  SFAS No. 141(R) also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the

65

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

business combination.  SFAS No. 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008, which will be the Company’s fiscal year 2009.  The Company adopted the provisions of SFAS No. 141(R) on January 1, 2009 and the adoption did not have a material impact on its financial statements.

Share Based Payments

On December 21, 2007, the SEC released Staff Accounting Bulletin, (“SAB 110”) “Share-Based Payment” which will no longer allow the use of the “simplified” method to estimate the expected terms as on the variables to determine the fair value of share-based payments.  With a limited number of exceptions, companies can continue to use the simplified method.  However, doing so requires the types of grants for which the simplified method is used if not for all grants, and the periods for which the simplified method is being used.  The adoption of this Staff Accounting Bulletin had no material impact on our consolidated financial position, results of operations, or cash flows.

Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurement” (“SFAS No. 157”).  SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and expands disclosures about fair value measurements.  SFAS No. 157 is effective for financial statements issued for periods beginning after November 15, 2007.  SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute.  Accordingly, SFAS No. 157 does not require any new fair value measurements.  However, for some entities, the application of this SFAS No. 157 will change current practice.  The definition of fair value focuses on the price that would be received to sell the asset or paid to transfer the liability (an exit price), not the price that would be paid to acquire the asset or received to assume the liability (an entry price).  SFAS No. 157 emphasizes that fair value is a market-based measurement, not an entity-specific measurement.  In February 2008, the FASB issued FASB Staff Position (“FSP”) SFAS 157-2 (“SFAS 157-2”) which defers the effective date of SFAS No. 157 for non-financial assets and liabilities that are not recorded at fair value on a recurring basis until periods beginning after November 15, 2008.  The Company adopted SFAS No. 157 effective January 1, 2008, except for those provisions permitted to be delayed by SFAS 157-2.  Accordingly, the Company has not applied the provisions of SFAS No. 157 to non-financial assets and liabilities initially measured at fair value.  In general, fair value measurements and disclosures are made in accordance with the provisions of SFAS No. 157.  The adoption of SFAS No. 157 had no impact on its consolidated financial position, results of operations or cash flows. The Company adopted the provisions of SFAS 157-2 on January 1, 2009 and the adoption did not have a material impact on its financial statements consolidated financial position, results of operations or cash flows.

The Fair Value Option for Financial Assets and Financial Liabilities

In February 2007, FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities—Including an Amendment of FASB Statement No. 115” (“SFAS No. 159”).  This standard permits an entity to choose to measure many financial instruments and certain other items at fair value.  Most of the provisions in SFAS No. 159 are elective; however, the amendment to FASB Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities, applies to all entities with available-for-sale and trading securities.  SFAS No. 159 is effective for fiscal years beginning after November 15, 2007.  On January 1, 2008, the Company adopted SFAS No. 159 and elected not to measure any of its currently eligible assets and liabilities at fair value.

Hierarchy of Generally Accepted Accounting Principles

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles,” which identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States of America. This statement is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board amendments to AU Section 411, “The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.” The Company does not expect the adoption of SFAS No. 162 to have a material impact on its consolidated financial position, results of operations or cash flows.

66

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Participating Securities

In June 2008, the FASB issued FSP EITF 03-6-1 “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities,” (“FSP EITF 03-6-1”) which provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share under the two class method. FSP EITF 03-6-1 is effective for us on January 1, 2009 and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) will be adjusted retroactively to conform to its provisions. Early application of FSP EITF 03-6-1 is not permitted. The Company adopted the provisions of FSP EITF 03-6-1 on January 1, 2009 and the adoption, although restricted stock awards meet this definition, did not have a significant material impact on its reported earnings per share.

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 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 production and revenue billings begin. Because the Company has oil sales, it is no longer eligible for the IGV early recovery program.

The Company’s value added tax receivable balance as of December 31, 2008 was $12.1 million. In 2008, the Company received approximately $3.8 million under the IGV early recovery program for claims previously filed with the Peruvian tax authority in 2007. During the year ended, December 31, 2008 the Company accrued approximately $19.6 million for IGV related to expenditures during the year and offset IGV by approximately $11.2 million related to the sale of oil in 2008.

The Company’s value added tax receivable balance as of December 31, 2007 was $7.5 million. Of this balance, the Company has filed claims with the Peruvian tax authority to recover approximately $2.9 million under the IGV early recovery program. During the year ended, December 31, 2007 the Company accrued approximately $11.4 million for IGV related to expenditures during the year and offset IGV by approximately $0.5 million related to the sale of oil in December 2007. Approximately $6.6 million of IGV was collected during the year ended December 31, 2007.

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, 2008 and 2007 was $4.1 million and $3.4 million, respectively. Inventory associated with tubular goods, accessories and spare parts inventory at December 31, 2008 and 2007 was $3.6 million and $2.8 million, respectfully.

The Company also maintains crude oil inventories in storage barges. 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 product inventory at December 31, 2008 consisted of approximately 11,656 barrels of crude oil at an estimated cost of $437,765 or $37.56 per barrel. The product inventory at December 31, 2007 consisted of approximately 12,248 barrels of crude oil at an estimated cost of $548,391 or $44.77 per barrel.

67

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Note 4 — Prepaid and Other Current Assets

Below is a summary of other current assets as of December 31, 2008 and 2007:

	2008		2007
Prepaid expenses and other	$	1,980,599	$	590,784
Deposits	86,390		51,964
Prepaid insurance	590,189		1,015,676
Insurance receivable	612,032		612,033
Interest receivable	—		825
	$	3,269,210	$	2,271,282

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, 2008, a claim of approximately $0.8 million for repairs is expected to be filed with the insurance carrier. A deductible of $75,000 will be applied to this insurance claim when reimbursed.  The Company received proceeds from the underwriter to cover a related claim regarding third party cargo that was damaged in the grounding incident. During the year ended December 31, 2008, approximately $80,000 of insurance proceeds was received in connection with this claim.  A deductible of $25,000 was offset against the insurance proceeds received.  This amount is unrelated to the $0.8 million hull claim described above as the proceeds from the cargo claim were passed on to the third party owner of the cargo that was damaged.  The hull claim will be finalized upon the dry docking of the vessel.  Because of the delays caused by the drilling of the highly deviated CX11-20XD well during the third quarter 2008, the dry dock of the BPZ-01 is scheduled during the last quarter of 2009.

Note 5 — Property, Equipment and Construction in Progress

Below is a summary of property, equipment and construction in progress as of December 31, 2008 and 2007:

	2008			2007
Construction in progress:
Power plant and related equipment	$	17,483,626		$	3,486,309
Platforms and wells	34,768,367			25,220,425
Pipelines and processing facilities	5,108,387			4,412,677
Producing properties	110,229,530			56,159,488
Producing equipment	18,399,383			—
Barge and related equipment	24,926,842			11,970,171
Office equipment, leasehold improvements, and vehicles	1,959,656			1,040,613
Accumulated depreciation and amortization	(18,942,156		)	(1,923,592		)
Net property, equipment and construction in process	$	193,933,635		$	100,366,091

During the year ended December 31, 2008 and 2007, the Company incurred capital expenditures of approximately $110.6 million and $63.1 million, respectively, 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 of electricity for sale in Peru.

Of the incurred costs mentioned above, 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, during the year ended December 31, 2008.  For the year ended December 31, 2007 the Company incurred

68

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

capital expenditures related to the drilling and testing of the CX11-21XD and the CX11-14D wells of $29.4 million and $22.8 million, respectively. Approximately $52.3 million and $55.9 million and was transferred from construction in progress to producing properties for the year ended December 31, 2008 and 2007, respectively.

In 2008, the Company also 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 FPSO into service and production equipment to support operations. This new program should enable BPZ to initiate production in a more efficient manner which will allow for a better understanding of the behavior and characteristics of the Corvina oil field.

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-1 platform.

Additionally 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. The leasing transactions are accounted for in accordance with SFAS 13, “Accounting for Leases (As Amended)” (“SFAS 13”). Title to the BPZ-02 transfers to the Company at the end of the lease and the FPSO lease contains a bargain purchase option; therefore, depreciation of both of these leased assets will be over their useful life, in accordance with SFAS 13. 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.

For the development of a Company owned gas-fired power generation facility, BPZ 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 its agreement to purchase three LM6000 gas-fired turbines, including an initial down payment of $5.1 million.

In 2007, the Company entered into a capital lease agreement, with an option to purchase, for two barges 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. Lease payments are variable based on the working status of the barges with a purchase option of $5.0 million after the first year of the lease and $4.0 million after the maturity date of the lease. The lease transaction is accounted for in accordance with SFAS 13. The lease contains a bargain purchase option; therefore, depreciation of these leased assets will be over their useful life, in accordance with SFAS 13.

In 2008 the Company 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. In 2007 the Company incurred costs for office equipment and leasehold improvements for our offices in Houston, Peru and Ecuador of approximately $0.1 million and for the purchase of machinery and equipment used in operations in Peru of approximately $0.2 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. For the year ended December 31, 2007, we capitalized approximately $0.5 million of depreciation expense and $0.9 million of interest expense to construction in progress.

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 $1.4 million and $1.6 million as of December 31, 2008 and 2007, 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. Accordingly, the Company recorded amortization expense of $0.2 million in each of the years ended December 31, 2008 and 2007, respectively. Investment income from the Company’s investment in Ecuador property was $0.7 million, $0.3 million and $1.4 million for each of the years ending December 31, 2008, 2007 and 2006, respectively.

69

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Note 7 — Restricted Cash

As of December 31, 2008, the Company has restricted cash deposits of $5.1 million, which partially collateralizes the insurance and performance bonds. 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 $2.9 million to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally the Company has $2.2 million of restricted cash to collateralize insurance bonds for import duties related to the FPSO and transport tanker.

During the year ended December 31, 2008, the Company was refunded $0.8 million related to the second exploration phase under the Block XIX license contract and approximately $1.0 million related to a performance commitment under a drilling services contract.

All of the performance bonds are issued by Peruvian banks and their terms are governed by the corresponding license contract.

In 2007, the Company had five performance bonds totaling $6.0 million to insure certain obligations and commitments, of which one relates to a guarantee under a service contract and four relate to performance obligations under the license contracts for Blocks Z-1, XIX, XXII and XXIII.

As of December 31, 2007, the Company secured a $1.0 million performance bond to guarantee payment under a service agreement. The bond expired in January 2008 at which time the cash was refunded. Accordingly the amount was recorded as a current asset at December 31, 2007.

Additionally, as of December 31, 2007, the Company had restricted cash deposits of $2.8 million, which partially collateralizes the performance bonds under the License Contracts. In addition to the cash collateral posted by the Company, an individual shareholder of the Company had provided a guarantee in the amount of $200,000 to the financial institution that issued one of the bonds to secure the Company’s performance. During 2004, the Company issued 236,528 shares to that individual investor for $119,175 of cash proceeds and a subscription receivable of $230,825 for the guarantee. During the year ended December 31, 2007, the guarantee was replaced by a deposit of an additional $95,000 by the Company to the same financial institution and the Company received the $230,825 cash proceeds related to the subscription receivable. See, Note 15 “Commitment and Contingencies” below for further details of our performance bonds obligation.

All of the performance bonds were issued by Peruvian banks and their terms are governed by the corresponding license contract or technical evaluation agreement.

Note 8 —Asset Retirement Obligation

An obligation was recorded for the plug and abandonment of the producing oil wells, the CX11-21XD, CX11-14D, CX11-20XD and the CX11-18XD, in accordance with the provisions of SFAS No 143 “Accounting for Asset Retirement Obligations” (“ARO”).

Activity related to the Company’s asset retirement obligation (“ARO”) for December 31, 2008 and 2007 is as follows:

70

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

	2008		2007
ARO as of the beginning of the period	$	273,048	$	—
Liabilities incurred during period	268,574		268,572
Liabilities settled during period	—		—
Accretion expense	39,164		4,476
ARO as of the end of the period	$	580,786	$	273,048

Note 9 — Long-Term Debt and Capital Lease Obligations

At December 31, 2008 and 2007 long-term debt and capital lease obligations consist of the following:

	2008		2007
$15 million IFC Senior Note, Libor plus 2.75%, due 2012	$	15,000,000	$	—
$15 million IFC Senior Convertible Notes, Libor plus 2.0%, due 2017	—		15,500,000
Capital Lease Obligations	7,837,419		6,225,961
	22,837,419		21,725,961
Less: Current Portion of Long-Term Debt	7,819,908		6,188,668
	$	15,017,511	$	15,537,293

The following is a summary of scheduled long-term debt maturities by year:

2009	$	—
2010	2,500,000
2011	5,000,000
2012	7,500,000
2013	—
Therafter	—
	$	15,000,000

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

2009	$	10,495,012
2010	18,048
2011	—
2012	—
2013	—
Therafter	—
Total Minimum Lease Payments	10,513,060
Less: Amounts representing interest	2,675,641
Present Value of Minimum Lease Payments	7,837,419
Less: Current Portion of Obligations Under Capital Lease	7,819,908
Long-Term Portion of Obligations Under Capital Lease	$	17,511

71

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

$15.0 Million IFC Reserve-Based Credit Facility

On August 15, 2008, the Company entered into a $15.0 million reserve-based lending facility (“$15.0 million Senior Note”) agreement (the “Loan Agreement”) with International Finance Corporation (“IFC”) through our subsidiaries BPZ Exploración & Producción S.R.L and BPZ Marine Peru S.R.L as borrowers.   The $15.0 million Senior Note represents the first tranche of an expected overall lending package of approximately $90.0 million.  The Company used a portion of the proceeds from the Senior Note for its initial $5.1 million down payment and subsequent monthly progress payments for the GE turbines (see Note 1 — “Basis of Presentation and Significant Accounting Policies” for further information) The reserve-based lending facility matures in December 2012 and bears interest at an approximate rate of LIBOR plus 2.75%, currently equivalent to 4.56% based on the current six month LIBOR rate of 1.81%.  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, 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 cover ratio. The Company was in compliance with all applicable covenants of the Loan Agreement as of December 31, 2008.  Funding for the initial amounts available under the Loan Agreement was subject to satisfying certain conditions precedent which were fulfilled on October 17, 2008 and subsequently BPZ borrowed the entire $15.0 million available under the Loan Agreement.

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.

$15.5 Million Debt Conversion to Equity

On November 19, 2007, a Convertible Debt Agreement between IFC and the Company was entered into for approximately $15.5 million.  The terms of the loan agreement stipulate a conversion price of $10.39 per share and include a forced convert price of $18.19 per share, based on the average closing price over twenty consecutive business days. The instrument had a 10 year term with a variable interest rate of 2.0% per annum above 6-month LIBOR. In May 2008, the Company elected to exercise its option to convert $15.5 million of convertible debt with the IFC into approximately 1.5 million shares of common stock.

Note Payable

In January 2009, in exchange of receipt of $1.0 million from an individual (“Note Holder”), the Company signed a promissory note (the “Note”). The Note matures in July 2009 and bears an annual interest rate of 12.0%. Interest payments are due monthly on the first day of each month the principal is outstanding. Additionally the terms of the Note include a conversion feature, at the Company’s option, to deliver and exchange as consideration and payment of the Note; shares of the Company’s common stock. The number of shares will be determined by applying a 12% discount to the closing price of its Common Stock on the day prior to settlement. Further the Note Holder has the right to participate in any equity offering during the period the principal is outstanding by tendering the Note for shares of common stock. The number of shares will

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BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

be determined by dividing the total outstanding indebtedness by the share price of the offering on the same terms as other participants in the offering. Should the Company default on any terms of the Note, it agrees deliver its common stock, as consideration and payment of the Note, within 30 days the date of default.

Capital Leases

In February 2008, the Company entered into a lease-purchase agreement to acquire the deck barge BPZ-02 to assist in the platform refurbishment and drilling activities in the Albacora field as well as to assist in future offshore drilling and development activities.  See Note 5 “Property, Equipment and Construction in Progress”, included herein, for further discussion.  The terms of the lease-purchase stipulate a 19% rate of interest (33% effective rate of interest) over a one-year term ending March 2009 at which point, title to the BPZ-02 will transfer to the Company upon final payment of the lease.  The Company accounted for the transaction as a capital lease in accordance to SFAS No. 13, “Accounting for Leases (As Amended)” under the applicable criteria, title to the barge will transfer at the end of the lease period and, as a result, depreciation will be calculated over the economic life of the asset.  Lease payments are fixed at $694,167 per month.  The capital lease asset was recorded at approximately $7.0 million, which represents the lesser of the present value of the minimum lease payments, or the fair market value of the asset.

In 2007 the Company entered into a capital lease agreement, with an option to purchase, for two barges (the Namoku, as well as the storage barge, the Nu’uanu ) to assist in the development of the Corvina oil.  The capital lease for the two barges began in August 2007 and expires in November 2009.  Lease payments are variable, based on the working status of the barges, with a purchase option of $5,000,000 after the first year of the lease and $4,000,000 after the maturity date of the lease.  The capital lease obligation was recorded at the present value of the minimum lease payments at an imputed discount rate of 18%, which reflects the Company’s incremental borrowing rate for this transaction.  The capital lease obligation was recorded at approximately $6.2 million, which represents lesser of the present value of the minimum lease payments, or the fair market value of the asset. As of December 31, 2008, the Company has not elected to purchase the barges under the terms of the first year purchase option.

In connection with the Namoku lease, the Company entered into a separate capital lease agreement for the production equipment used on board the Namoku for the FPSO. The capital lease for the production equipment commenced in June 2008, the date the equipment was put into service.  The lease terms are variable and bears an interest rate of 18% based on the Company’s incremental borrowing rate for similar equipment.  In accordance with the terms of the lease, a bargain purchase option exists at the end of the lease.  As a result, depreciation will be calculated over the economic life of the asset.  The Company recorded the capital lease at $2.4 million, which represents the lesser of the present value of the minimum lease payments, or the fair market value of the asset.

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.

In March 2008, the Company entered into two loan agreements with Peruvian banks to borrow approximately $2.8 million.  The loans were collateralized by IGV receivables and bore interest rates of approximately 8% each.  The Company repaid the remaining outstanding balance in August 2008.

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.

2009 Private Placement of Common Stock

On February 13, 2009, the Company announced its intent to sell approximately 15.7 million of its common stock shares to institutional investors at a price of $3.05 per share for gross proceeds of approximately $48 million. On February 23, 2009, the Company closed the 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, the IFC holds a right to elect to participate in the offering resulting in the possible sale of an additional 1.4 million shares of common stock for a total of up to approximately 15.7 million shares of common stock sold in this private offering. The common stock

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BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

was priced at $3.05 per share resulting in gross proceeds to the Company of approximately $43.6 million ($48.0 million if the IFC elects to participate in the offering). No warrants or other dilutive securities were issued to the investors in connection with the private placement.

The shares were placed directly by Pritchard Capital Partners, LLC and the Company has agreed to a 5% cash placement fee of the gross proceeds at each closing.  Additionally, the Company retained Morgan Keegan & Company, Inc., as its financial advisor, in connection with the offering.  In return for its services, Morgan Keegan & Company, Inc. will receive an advisory fee of 1.5% of the gross proceeds of this transaction at each closing.

Under the Stock Purchase 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.  The Company is subject to a potential maximum aggregate penalty of 13% of the gross proceeds of the offering or approximately $5.7 million, excluding the IFC’s participation, if the registration statement related to the offering is not filed or declared effective within the time-frames outlined above.  At the Company’s option, any penalties would be payable in cash or common stock of the Company.

Following the closing of this private placement, the Company has 93,054,150 shares of common stock issued and outstanding, with fully diluted shares of 96,948,498, excluding the 1.4 million shares the IFC may elect to purchase as part of the offering, respectively. The fully diluted shares include the potential effect of vested and unvested options and restricted stock outstanding.

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.

Conversion of Debt to Equity

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. The terms of the Convertible Debt Agreement, dated November 19, 2007, stipulate a conversion price of $10.39 per share and include 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. See Note 9, “Long-Term Debt and Capital Lease Obligations” for further information.

Warrants

In 2007, the Company had 250,000 warrants outstanding. For their role as placement agent, in connection with the private placement of 11,466,000 shares of common stock in July 2005, Morgan Keegan & Company, Inc. received fully vested warrants to purchase 100,000 shares of the Company’s common stock at an exercise price of $3.00 per share. Such warrants expire on July 19, 2010. These warrants were valued at $325,000 using the Black-Scholes model, which amount was treated as additional non-cash stock offering costs.

Additionally, for their financial advisory services, in connection with the private placement of 4,482,000 shares of common stock in June 2006, Morgan Keegan & Company, Inc. received fully vested warrants to purchase 150,000 shares of the Company’s common stock at an exercise price of $3.00 per share. Such warrants expire on June 30, 2011. These warrants were valued at $248,645 using the Black-Scholes model, which amount was treated as additional non-cash stock offering costs.

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BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

During the year ended December 31, 2008, Morgan Keegan exercised warrants to purchase 250,000 shares of the Company’s common stock at an exercise price of $3.00.  As a result, the Company received proceeds of $750,000.

Potentially Dilutive Securities

In addition to the shares issued and outstanding, the Company has the following potentially dilutive securities at December 31, 2008, 2007 and 2006. None of these potentially dilutive shares have been included in the calculation of earnings per share as the effect would be anti-dilutive.

	2008	2007	2006
Stock options outstanding	3,894,348	4,175,448	4,306,152
Warrants outstanding	—	250,000	250,000
Contingent incentive earn-out shares	—	—	450,000
Contingent Merger earn-out shares	—	—	9,000,000
Shares issuable under IFC convertible debt agreement	—	1,491,819	—
Total potentially dilutive securities issued	3,894,348	5,917,267	14,006,152
Shares available pursuant to Long-Term Incentive Compensation Plan	2,541,450	3,152,450	1,156,000

On January 1, 2006, the Company adopted SFAS No. 123 (R),”Share Based Payment” (“SFAS No. 123(R)”), which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employees. SFAS No. 123(R) is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation”, and supersedes APB No. 25, “Accounting for Stock Issued to Employees”. Under the provisions of SFAS No. 123(R), 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. 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.

The Company adopted SFAS No. 123(R) using the modified prospective application method and, accordingly, no prior periods have been restated as a result of the adoption of this pronouncement. The modified prospective method requires recognition of compensation expense for stock-based payment awards that are granted, modified, repurchased or cancelled after 2005. Compensation expense for unvested stock options outstanding as of January 1, 2006 for which the requisite service has not been rendered is being recognized over the remaining service period using the compensation cost previously calculated for pro forma disclosure purposes under SFAS No. 123.

Prior to the adoption of SFAS 123(R), the Company presented all tax benefits of deductions resulting from the exercise of options as operating cash flows in the Statement of Consolidated Cash Flows. SFAS 123(R) requires the cash flows resulting from tax deductions in excess of the compensation cost recognized for those options (excess tax benefits) to be classified as financing cash flows. However, as the Company is not able to use these tax deductions (see Note 13, “Income Taxes” for further information), it has no excess tax benefits to be classified as financing cash flows.

SFAS No. 123(R) requires all stock-based compensation related to unvested stock awards, including stock options, to be recognized by the Company as an operating expense. Stock-based compensation expense for all share-based arrangements is primarily recorded in “General and Administrative” expenses in the accompanying Consolidated Statements of Operations. Additionally, no stock-based compensation costs were capitalized for the year ended December 31, 2008, 2007 and 2006. The Company provides compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans.

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BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

The following table summarizes stock-based compensation costs recognized under SFAS 123(R) for year ended December 31:

	2008		2007		2006
Employee stock—based compensation costs	$	12,697,861	$	5,592,473	$	2,657,149
Director stock-based compensation	5,765,902		1,447,130		568,359
	$	18,463,763	$	7,039,603	$	3,225,508

Stock Option and Restricted Stock Plans

The Company has in effect the 2007 Long-Term Incentive Compensation Plan (the “2007 LTIP”), which is an amendment and restatement of the BPZ Energy, Inc. 2005 Long-Term Incentive Compensation Plan (the “2005 LTIP”). The 2007 LTIP 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, consultant and the employees of certain of the Company’s affiliates The provisions of each award will vary based on the type of award granted and will be specified by the Compensation Committee of the Board of Directors. The aggregate number of shares of Common Stock authorized for grant under the 2007 LTIP is 4.0 million. The Company normally issues new shares of its Common Stock in satisfaction of these awards. As of December 31, 2008, 916,450 shares remain available for future grants under the Plan,

The Company also has in effect the separate 2007 Directors’ Compensation Incentive Plan (the “Directors’ Plan”), which is an amendment and restatement of the BPZ Energy, Inc. 2005 Long-Term Incentive Compensation Plan (the “2005 LTIP”) applicable to directors. The 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 non-employee director. The provisions of each award will vary based on the type of award granted and will be specified by the Compensation Committee of the Board of Directors. The aggregate number of shares of Common Stock authorized for grant under the Directors’ Plan is 2.5 million. The Company normally issues new shares of its Common Stock in satisfaction of these awards. As of December 31, 2008, 1,625,000 shares remain available for future grants under the Plan,

Restricted Stock Awards and Performance Shares

At December 31, 2008, there were approximately 865,350 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, 2008 and related information is presented below:

			Weighted—
	Number of		Average
	Restricted		Fair Value
	Shares		Per Share
Outstanding at the begining of the year	1,284,850		$	8.82
Granted	—		$	—
Vested	(408,500	)	$	4.42
Forfeited	(11,000	)	$	4.10
Outstanding at the end of the year	865,350		$	10.95

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BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

The weighted average grant-date fair value of restricted stock awards granted for the years ended December 31, 2007 and 2006 was $8.73 and $3.44, respectively. The fair value of restricted stock awards that vested during the years ended December 31, 2008, 2007 and 2006 was $6.7 million, $5.9 million and $1.1 million, respectively. As of December 31, 2008, there was $6.0 million of total unrecognized compensation cost related to nonvested restricted stock awards, which is expected to be recognized over a weighted-average period of 1.2 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:

	2008			2007			2006
Expected life (years) (a)	5			6			6
Risk-free interest rate (c)	4		%	4		%	5		%
Volatility (b)	80.97		%	82.31		%	72.27		%
Dividend yield (d)	0		%	0		%	0		%
Weighted-average fair value per share at grant date	$	14.48		$	7.07		$	2.37

(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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BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

A summary of our stock option activity for the year ended December 31, 2008 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	4,175,448		$	8.14
Granted	634,500		$	22.69
Exercised	(903,100	)	$	2.73
Forfeited	(12,500	)	$	7.30
Outstanding at the end of the year	3,894,348		$	10.03	8.23	$	4,242,225.00
Exercisable at the end of the year	1,545,055		$	4.89	8.03	$	3,843,975.00

As of December 31, 2008, there was $10.3 million of unrecognized compensation cost related to non-vested stock options that is expected to be recognized over a weighted average period of 1.3 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, 2008 and 2007 was $16.0 million, $9.7 million, respectively. Cash received from stock option exercises for the years ended December 31, 2008 and 2007 was $2.4 million and $3.4 million, respectively. No options were exercised in 2006.

Additional compensation expense of $0.7 million was recognized for the year ended December 31, 2008 primarily related to accelerated vesting for certain stock option awards.

The following table summarizes information about stock options outstanding as of December 31, 2008:

			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	5.7	$	1.30	99,248	$	1.30
$2.13	to	$4.23	950,000	7.4	$	3.41	950,000	$	3.41
$4.24	to	$6.35	611,000	8.5	$	4.94	318,169	$	4.84
$6.36	to	$8.47	120,900	8.3	$	6.50	39,238	$	6.50
$8.48	to	$10.58	251,200	9.0	$	10.22	70,400	$	10.43
$10.59	to	$11.88	1,862,000	8.6	$	15.75	68,000	$	24.36
Total			3,894,348	8.2	$	10.03	1,545,055	$	4.89

Private Placements of Common Stock

On May 4, 2007, with an over-allotment purchase that closed on June 15, 2007, the Company completed a private placement of 7,170,000 shares of common stock, no par value, to accredited investors pursuant to a Subscription Agreement. The common stock was priced at $5.25 per share and the over-allotment was priced at $5.40 per share resulting in proceeds to the Company of approximately $37.7 million. No warrants or dilutive securities were issued in connection with the offering. The offering was placed directly by the Company. A placement fee of 2% of the gross proceeds of this transaction was paid to Morgan Keegan for investment services and consulting related to the offering. The registration statement was declared effective by the Securities and Exchange Commission on June 20, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Stock Subscription Receivable

During 2004, the Company issued 236,528 shares to an individual investor for $119,175 of cash proceeds and a subscription receivable of $230,825 for a guarantee letter. The guarantee letter was associated with the first exploration phase of Block Z-1. During the year ended December 31, 2007, the guarantee was replaced by a deposit of an additional $95,000 by the Company to the same financial institution. Additionally, during 2007 the Company received the $230,825 cash proceeds related to the subscription receivable. See Note 7 “Restricted Cash”, included herein, for further discussion.

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 (see immediately below). 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.

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.

Merger Earn-Out Shares — Stock Dividend

Under the terms of the Merger Agreement, the Company committed to issue 18,000,000 shares to the former shareholders of BPZ-Texas on a contingent earn-out basis if the Company achieved certain reserve and production goals. The first earn-out target relating to reserves was achieved in December 2004 and 9,000,000 of the earn-out shares were issued. 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. As mentioned above, in November 2007 the production target was achieved based on certification by an independent engineering firm that the Company’s production in Peru has met or exceeded the required level of production.

For accounting purposes, the earn-out arrangement is treated as a stock dividend because the earn-out is payable to the shareholders of the accounting acquirer, BPZ-Texas. Accordingly, except for a retroactive increase in the number of common shares outstanding for all periods presented, no accounting entry is required upon the issuance of the earn-out shares.

Note 11 — Affiliate and Related Party Transactions

As of December 31, 2008 and December 31, 2007, the Company had not entered into any transactions with affiliates or related parties.

Note 12 — Revenue

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 an extended well testing program.  During the second and fourth quarter of 2008, it added production from the CX11-18XD and CX20-20XD wells under the extended well testing program.  The oil is delivered by barge to the Petroperu 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.  The Company has entered into two contracts for the sale of oil to Petroperu since it began oil production in

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BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

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.  The current sales contract with Petroperu is for the delivery of up to 400,000 barrels of oil to the Talara refinery.  Similar to the first sales contract, the current sales contract is based on Northwest Oil Basket pricing which is comprised of Oman, Fortes and Suez Blend pricing.  The unadjusted sales price is based on the past five day average before the crude oil delivery date.  The price is then discounted for the quality of the oil delivered.  The determination of quality is based on the gravity of the oil expressed in degrees, as determined under standards established by the American Petroleum Institute (“API”).  The price is 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 is added to the price as a result of the high diesel content of the crude oil.

Subsequent to December 31, 2008, the Company, through its wholly-owned subsidiary BPZ Exploración & Producción S.R.L., 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, all of 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.

 During the year ended December 31, 2008 and 2007 the Company sold approximately 825,845 barrels and 28,741 barrels at an average price, net of royalties, of approximately $76.23 per barrel and $81.78, respectively.  The Company had no oil sales during the year ended December 31, 2006. In January 2008, BPZ incurred production and transportation delays due to the incident involving one of the Peruvian Navy tankers used in its oil production process. See Note 1, “Basis of Presentation and Significant Accounting Policies — Corvina” above for a more detailed discussion of the incident.   Approximately 1,300 barrels of oil were lost in the fire aboard the tanker.  The cost of the crude oil lost was approximately $62,000 and was expensed through lease operating expense and depreciation, depletion and amortization.

The Company’s net revenues exclude the cost of royalties owed to the government of Peru. Royalties are calculated by Perupetro as stipulated in the Block Z-1 license agreement based on the same Northwest Oil Basket discussed above, however, their calculation is based on the past two week average price before the crude oil delivery date, as opposed to 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 the Company are net of royalty costs of approximately 5% of gross revenues or $3.3 million and $0.1 million, respectively.

Note 13 — Income Taxes

As of December 31, 2008, 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 2027.  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 an extended 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 extended 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, 2008 of approximately $3,141,851.

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, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the year.

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BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

The source of income (loss) before income tax expense/(benefit)  for the years ended December 31, 2008, 2007 and 2006 is as follows:

	2008			2007			2006
United States	$	(28,121,651	)	$	(12,922,310	)	$	(11,627,018	)
Foreign	21,617,014			(7,548,671		)	(3,860,441		)
Loss from continuing operations before income taxes	$	(6,504,637	)	$	(20,470,981	)	$	(15,487,459	)

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

	2008			2007			2006
Federal statutory income tax rate	$	(2,211,576	)	$	(7,139,493	)	$	(5,242,737	)
Increases (decreases) resulting from:
Non-deductible stock compensation expense	6,550,722			3,653,338			—
Tax effect of Peru conversion to permanent establishment status	7,642,249			—			—
Change in domestic valuation allowance	(8,839,544		)	3,525,156			5,242,737
	$	3,141,851		$	39,001		$	—

81

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

The tax effects of the temporary differences that give rise to the significant portion of the deferred tax assets and liabilities at December 31, 2008, 2007 and 2006 are presented below:

	2008			2007			2006
Deferred Tax:
Asset:
Net Operating Loss	$	19,941,250		$	12,088,891		$	8,885,175
Deferred Compensation	1,889,109			6,360,268			3,966,804
Asset Basis Difference	—			709,140			—
Exploration Expense	2,079,853			—			—
Depreciation	12,409			—			—
Depletion	3,339,664			—			—
Asset Retirement Obligation	26,869			—			—
Other	665,527			—			—
Liability:
Preoperation Expenses	(294,607		)	—			—
Asset Basis Difference	(1,297,609		)	—			—
Other	(300,859		)	—			—
Net Deferred Tax Asset	$	26,061,606		$	19,158,299		$	12,851,979
Less Domestic Valuation Allowance	(21,190,066		)	(19,158,299		)	(12,851,979		)
Deferred Tax Asset	$	4,871,540		$	—		$	—

Note 14 — Business Segment Information

The Company determines and discloses its segments 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. SFAS No. 131 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, 2008, 2007 and 2006 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. The majority of our long-lived assets are located in Peru.

Note 15 — Commitments and Contingencies

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. The rate set for oil and gas companies is 5% of net income subject to taxation. The 5% of net 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 the “income subject to taxation” per the Peruvian tax code and not the reported net accounting of income of companies. For the year ended December 31, 2008, approximately $1.9 million of expense related to profit sharing is included in “General and administrative expenses” in the Consolidated

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BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Statement of Operations and is due to the Company’s Peru employees in April 2009. No profit sharing was incurred by the Company for 2007 or 2006. The Company will be subject to profit sharing expense each year its Peruvian subsidiaries are profitable.

Barge Incident

In early 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 bank in Talara Bay in northwest Peru.  As of December 31, 2008, the Company recorded approximately $0.7 million in insurance receivable pending the submission of an insurance claim estimated to be approximately $0.8 million.  A deductible of $75,000 will be applied to this insurance claim when reimbursed.

The Company received proceeds from its underwriter to cover a related claim regarding third party cargo that had been damaged in the grounding incident mentioned above.  During the year ended December 31, 2008, approximately $80,000 of insurance proceeds were received in connection with this claim.  A deductible of $25,000 was offset against the insurance proceeds received.  This amount is unrelated to the $0.8 million hull claim described above as the proceeds from the cargo claim was to the third party owner of the cargo that was damaged.  The hull claim will be finalized upon the dry docking of the vessel.  Because of the delays caused by the drilling of the highly deviated CX11-20XD well during the third quarter 2008, the dry dock of the BPZ-01 is scheduled during the last quarter of 2009.  As of December 31, 2008, the Company has not presented a final claim to its insurance carrier for the barge repairs.

The Company believes that 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 our 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

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 $2.9 million to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally, we have $2.2 million of restricted cash to collateralize insurance bonds for import duties related to the FPSO and transport tanker. As of December 31, 2008, we had restricted cash deposits of $5.1 million, which partially collateralizes the insurance and performance bonds. See Note 8, “Restricted Cash and Performance Bonds” for further discussion.

Capital Lease of Barge and Production Equipment

In February 2008, the Company entered into a lease-purchase agreement to acquire a deck barge (“BPZ-02”) to assist in the platform refurbishment and drilling activities in the Albacora field as well as to assist in future offshore drilling and development activities.  In the near term, the BPZ-02 will be used to act as a tender assist for the Albacora platform refurbishment and support for the Albacora drilling operations.  The acquisition of the BPZ-02 allows the Company better asset maintenance scheduling and will aid in the support of increased offshore exploration and development activities.  The terms of the lease-purchase stipulate a 19% rate of interest (33% effective rate of interest) over a one-year term at which point, title to the BPZ-02 will transfer to the Company upon final payment of the lease.  The Company has accounted for the transaction as a capital lease in accordance to SFAS No. 13, “Accounting For Leases (As Amended)” under the criteria the barge will transfer title at the end of the lease period and, as a result, depreciation will be calculated over the economic life of the asset.

The production equipment used on board the FPSO was financed through a separate capital lease that commenced when the Company began utilizing the production equipment on board the FPSO in June 2008.  The lease terms are variable and bears an interest rate of 18% based on our incremental borrowing rate for similar equipment.  In accordance with the terms of the lease, a bargain purchase option exists at the end of the lease.  As a result, depreciation will be calculated over the economic life of the asset.  The Company recorded the capital lease at $2.4 million, which represents the lesser of the present value of the minimum lease payments or the fair market value of the asset at the inception of the lease.

83

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

See Note 9 “Long-Term Debt and Capital Lease Obligations” for further discussion of both leases referred to above.

GE Turbine Purchase Agreement and Amendment

On September 26, 2008, the Company, through its subsidiary, entered into a $51.5 million contract for purchase of equipment and services with GE Packaged Power, Inc. and GE International, Inc. Sucursal de Peru, which are part of GE Energy’s aeroderivative business.  Subsequent to December 31, 2008, the Company and GE entered into an amendment of the contract. For further information regarding the original and amended contract see Note 1, “Basis of Presentation and Significant Accounting Policies — Gas-to Power” for further information.

Reserve-Based Credit Facility

In August 2008, the Company signed a Mandate Letter and Facility Term Sheet with Natixis, a major French bank, to underwrite and structure, on an exclusive basis, a $200.0 million reserve-based credit facility. The $200.0 million reserve-based credit facility was approved by the Natixis Credit Committee in September 2008.  Subsequent to December 31, 2008 the Company finalized a revised Mandate Letter and Facility Term Sheet with Natixis. Based on current credit and commodity market conditions, Natixis has now resized the facility to approximately $90.0 million including the $15.0 million received under the $15.0 million Senior Note. See Note 9 “Long-Term Debt and Capital Lease Obligations” for further information. Once the facility is closed, the Company expects the initial available borrowing capacity to be approximately $60.0 million, inclusive of the $15 million already closed and funded by IFC as described in Note 9, “Long-Term Debt and Capital Lease Obligations - $15.0 Million IFC Reserve-Based Credit Facility” above”. The existing Natixis credit committee approval remains in effect and both the Natixis and IFC facilities will be governed by a Common Terms Agreement (“CTA”). Terms of the resized facility are expected to be aligned with recent transactions in the market.

The Company expects to complete this financing in the first part of the second quarter of 2009. However, the closing of the credit facility is dependent upon the successful syndication of approximately 50% of the facility and successful negotiation of the related loan documents and funding is predicated on the satisfaction of certain conditions precedent as specified in the loan documents.

Gas-to-Power Project Financing

On November 29, 2006, a $120.0 million financing package was approved by the Credit Committee of the IFC for the development of the Company’s gas-to-power project.  Originally, IFC intended to loan $50.0 million, of which $19.5 million was invested in the Company’s common stock in December 2006, with the remaining $70.0 million to be syndicated to other financial institutions.

However, the discovery of oil in the Corvina field in early 2007 resulted in the gas-to-power project being deferred and the Company’s decision to focus on accelerating oil production.  As a result, the $30.5 million balance of the IFC commitment was transferred to the oil development project and funded as follows:  $15.5 million of convertible debt funded in November, 2007 and converted into common stock in May, 2008 and $15.0 million was funded in October, 2008 with the reserve based facility. See “Note 9, “Long-Term Debt and Capital Lease Obligations” for further information on $15.0 million credit facility.

The Company currently estimates the gas-to-power project will cost approximately $130.0 million.  The IFC has advised it that approximately 65% of the project’s costs can be expected to be financed with traditional project financing, given current market conditions.  Accordingly, the Company has commenced discussions with potential joint venture partners for the gas-to-power project in an attempt to secure additional equity for the project.  Following the identification and selection of a partner and consummation of project contracts, the Company will enter into negotiations with the IFC regarding restructuring the gas-to-power financing. The Company is expecting terms to include an eight year amortization of principal with interest rates to reflect the current market conditions at the time of closing along with typical covenants for this type of financing.  The closing of this financing, which is targeted for late 2009, will be subject to the satisfactory negotiation of loan and security documents.

84

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Note 16 — Legal Proceedings

Navy Tanker Litigation

On October 24, 2007, Tecnomarine, the Company’s former primary marine transportation contractor, 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. Although neither of the governmental agencies charged with investigating the incident found fault with the Company or the Company’s marine contractor, a lawsuit was filed against the Company in Houston, Texas by two crewmembers and the family and estate of two of the deceased sailors injured in the incident claiming negligence and gross negligence on the part of the Company.  As none of the Peruvian government sanctioned investigations into the Supe incident found fault on the part of Tecnomarine, the Company or the Company’s subsidiary, BPZ Exploración and Producción S.R.L., the Company does 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 its financial condition, results of operations or cash flows. Additionally, the Company believes the incident would be covered by its insurance policies, after a customary deductible.

Claim by Former Employee of Breach of Contract

In the fourth quarter of 2008, a former employee of the Company filed a lawsuit against the company claiming a breach of contract under the terms of the Company’s Long Term Incentive Compensation Plan.  Based upon the known facts relating to the legal proceeding, the Company does not believe that the outcome of the legal proceeding will have a material adverse effect on its financial condition, results of operations or cash flows.

Note 17 — Lease and Purchase Obligations

The Company leases office space in Houston, Texas under an operating lease that expires in 2016. The Company also leases five offices and a warehouse in Lima, Peru under an operating lease expiring in 2013. Additionally, the Company leases an administrative office Quito, Ecuador under a month-to-month lease. Total rent expense incurred for the years ended December 31, 2008, 2007 and 2006 was approximately $0.5 million, $0.3million and $0.3 million, respectively.

Minimum non-cancelable lease and purchase commitments are as follows:

For Year Ending December 31,

2009	$	7,889,990
2010	36,905,585
2011	977,148
2012	1,015,215
2013	1,054,759
Thereafter	900,123
Total minimum lease and purchase commitments	$	48,742,820

Includes operating leases for our executive office in Houston, Texas, and our branch offices in Lima, Peru. In 2008, both our Houston office and Lima offices entered into agreements for additional office space of 7,070 square feet and 22,500 square feet expiring 2016 and 2013, respectively.

Includes remaining amounts due to the purchase of three LM6000 gas-fired turbines from GE for $51.5 million.  Due to the amendment, the lease payments include the required payments due in 2009 and the remaining balance under the original lease agreement in 2010.  However, both GE and BPZ have agreed to determine new delivery dates, pricing and payment terms when the Company decides to bring the lease-purchase out of the suspension period.

85

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Note 18 — Subsequent Events

Subsequent to December 31, 2008, the Company borrowed $1,000,000 from an individual described in Note 9 “Long-Term Debt and Capital Lease Obligations — Note Payable”.

Subsequent to December 31, 2008, the Company entered into an amendment of its Agreement for the purchase of three LM6000 gas-fired turbine turbines with GE described in Note 1 “Basis of Presentation and Significant Accounting Policies — Gas-to-Power”.

Subsequent to December 31, 2008, the Company entered into a long-term oil supply agreement with Petroperu described in Note 12 “Revenue”.

Subsequent to December 31, 2008, the Company closed a private placement to sell stock to certain institutional investors as described in Note 10 “Stockholders’ Equity”.

Subsequent to December 31, 2008, the Company finalized a revised Mandate Letter and Facility Term Sheet with Natixis as described in Note 15 “Commitments and Contingencies”.

86

BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Note 19 — Quarterly Results of Operations

	Three Months Ended
	March 31,			June 30,			September 30,			December 31,
2008
Revenue, net	$	4,367,262		$	7,035,454		$	33,440,330		$	18,111,855
Operating loss	(7,539,040		)	(5,225,413		)	13,567,190			(8,446,794		)
Other income (expense)	209,247			717,448			94,963			117,762
Net loss	$	(7,422,194	)	$	(4,656,144	)	$	8,611,332		$	(6,179,482	)
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 share outstanding	74,525,279			77,680,924			78,574,955			78,748,390
Diluted weighted average common share outstanding	74,525,279			77,680,924			80,323,207			78,748,390
	Three Months Ended
	March 31,			June 30,			September 30,			December 31,
2007
Revenue, net	$	—		$	—		$	—		$	2,350,388
Operating loss	(3,251,880		)	(5,687,688		)	(7,586,791		)	(5,264,463		)
Other income (expense)	52,862			248,685			416,270			602,023
Net loss	$	(3,205,392	)	$	(5,482,931	)	$	(7,159,220	)	$	(4,662,440	)
Basic and diluted net loss per share	$	(0.05	)	$	(0.08	)	$	(0.10	)	$	(0.06	)
Weighted average common share outstanding	63,309,294			67,685,317			72,222,433			73,265,471

As restated for retroactive stock dividend, see Note 10, “Stockholders’ Equity —Merger Earn-out Shares — Stock Dividend” above for additional information.

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

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Supplemental Oil and Gas Disclosures (Unaudited)

Oil and Natural Gas Producing Activities

The following disclosures for the Company are made in accordance with SFAS No. 69, “Disclosures About Oil and Natural Gas Producing Activities (an amendment of FASB Statements 19, 25, 33 and 39)”. 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.

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

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

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

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

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

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

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

Market prices as of each year-end 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.

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

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

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, 2008 and 2007:

	2008			2007
Proved properties	$	154,826,919		$	73,447,919
Unproved properties	15,343,284			23,780,837
Total	170,170,203			97,228,756
Less: Accumulated depreciation, depletion and amorization	(15,946,183		)	(764,724		)
Net capitalized cost	154,224,020			96,464,032
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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BPZ RESOURCES, INC AND SUBSIDIARIES
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Pursuant to SFAS No. 143 “Accounting for Asset Retirement Obligations”, net capitalized cost includes asset retirement cost of $0.6 million and $0.3 million as of December 31, 2008 and December 31, 2007, 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, 2008 and 2007:

	Total
Year Ended December 31, 2008:
Acquisition costs of properties
Proved	$	—
Unproved	—
Subtotal	—
Exploration costs	794,925
Development costs	82,844,977
Total	$	83,639,902
Company’s share of cost method investees’ costs of property acquisition, exploration and development (1)	$	—
Year Ended December 31, 2007:
Acquisition costs of properties
Proved	$	—
Unproved	10,964
Subtotal	10,964
Exploration costs	19,122,831
Development costs	47,733,574
Total	$	66,867,369
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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BPZ RESOURCES, INC AND SUBSIDIARIES
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

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,
	2008		2007			2006
Oil and natural gas production revenues
Third-party	$	62,954,901	$	2,350,388		$	—
Affiliate	—		—			—
Total revenues	62,954,901		2,350,388			—
Exploration expenses	794,925		4,045,381			2,048,742
Production costs	11,648,877		754,833			—
Depreciation, depletion and amortization	15,141,181		537,892			—
Oil and natural gas impairment	—		—			—
Income (loss) before income taxes	35,369,918		(2,987,718		)	(2,048,742		)
Income tax provision (benefit)	3,141,851		—			—
Results of continuing operations	$	32,228,067	$	(2,987,718	)	$	(2,048,742	)
Company’s share of cost method investees’ results of operations for producing activities(1)	$	905,155	$	451,615		$	1,590,882

(1)    Investment in Ecuador Property

91

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

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

Net Proved and Proved Developed Reserve Summary

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

	Natural gas (Mcf)(1)(7)	Natural gas liquids and crude oil (Bbl)(2)(3)		(Bbl)(2) equivalents(4)
Net proved reserves at December 31, 2006	—	—		—
Revisions of previous estimates	—	—		—
Purchases in place	—	—		—
Extensions, discoveries and other additions	—	11,980,822		11,980,822
Sales in place	—	—		—
Production	—	(41,090	)	(41,090	)
Other	—	—		—
Net proved reserves at December 31, 2007	—	11,939,732		11,939,732
Revisions of previous estimates	—	(1,699,481	)	(1,699,481	)
Purchases in place	—	—		—
Extensions, discoveries and other additions	—	7,740,086		7,740,086
Sales in place	—	—		—
Production	—	(826,534	)	(826,534	)
Other	—	—		—
Net proved reserves at December 31, 2008	—	17,153,803		17,153,803
Company’s proportional interest in reserves of investees accounted for by the cost method—December 31, 2008 (6)	—	198,398		198,398

Net Proved Developed Reserves Summary

	Natural gas (Bcf) (7)	Natural gas liquids and crude oil (Bbl)	Bcf equivalents (5)
December 31, 2006 (8)	—	—	—
December 31, 2007	—	2,976,868	17.9
December 31, 2008	—	4,223,398	25.3

(1)Thousands of cubic feet.

(2)Barrels.

(3)Includes crude oil, condensate and natural gas liquids.

(4)Natural gas volumes have been converted to equivalent natural gas liquids and crude oil volumes using a conversion factor of six thousand cubic feet of natural gas to one barrel of natural gas liquids and crude oil.

(5)Billion cubic feet or billion cubic feet equivalent, as applicable

92

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

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

(6)Based on a rollforward of the independent reservoir engineer’s report provided by the operator of the Santa Elena property.

(7)We do not currently have the financial capacity or commitments for a development program of this magnitude for our gas reserves. Accordingly, the Company has not disclosed amounts of proved gas reserves in its SEC filings. At such time as we obtain 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, we expect to record SEC proved gas reserves as permitted under SEC rules and disclose such reserves in future SEC filings.

(8)We 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.

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 SFAS No. 69 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.

93

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

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s natural gas and crude oil reserves for the years ended December 31, 2008, 2007 and 2006:

December 31, 2008
Future cash inflows	$	648,413,900
Future production costs	(103,999,100		)
Future development costs	(127,300,000		)
Future income tax expenses	(62,240,029		)
Future net cash flows	354,874,771
Discount to present value at 10% annual rate	(55,947,837		)
Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	298,926,934
Company’s share of cost method investees’ standardized measure of discounted future net cash flows (1)(2)	$	2,755,897
December 31, 2007
Future cash inflows	$	1,020,728,000
Future production costs	(135,262,500		)
Future development costs	(79,400,000		)
Future income tax expenses	(155,081,716		)
Future net cash flows	650,983,784
Discount to present value at 10% annual rate	(94,301,509		)
Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	556,682,275
Company’s share of cost method investees’ standardized measure of discounted future net cash flows (1)(2)	$	3,400,241
December 31, 2006
Future cash inflows	$	—
Future production costs	—
Future development costs	—
Future income tax expenses	—
Future net cash flows	—
Discount to present value at 10% annual rate	—
Standardized measure of discounted future net cash flows relating to proved natural gas, natural gas liquids and crude oil reserves	$	—
Company’s share of cost method investees’ standardized measure of discounted future net cash flows (1)(2)	$	4,191,079

(1)Investment in Ecuador Property

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

94

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

YEARS ENDED DECEMBER 31, 2008, 2007 and 2006

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

Standardized measure of discounted future net cash flows, December 31, 2007	$	556,682,275
Sales and transfers of natural gas, natural gas liquids and crude oil produced, net of production costs	(51,306,024		)
Net changes in prices and production costs	(368,286,619		)
Extensions, discoveries, additions and improved recovery, net of related costs	160,830,600
Development costs incurred	82,844,977
Revisions of previous quantity estimates and development costs	(42,462,399		)
Accretion of discount	30,501,206
Net change in income taxes	(64,329,634		)
Changes in timing and other	(5,547,448		)
Standardized measure of discounted future net cash flows, December 31, 2008	$	298,926,934

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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, 2008 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, 2008 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, 2008.

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, 2008, 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 Shareholders
BPZ Resources, Inc. and Subsidiaries

Houston, Texas

We have audited BPZ Resources, Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2008, 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, 2008, 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, 2008 and 2007, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2008 and our report dated February 27, 2009 expressed an unqualified opinion thereon.

Johnson Miller & Co., CPA’s PC
Midland, Texas
February 27, 2009

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

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

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

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

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

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

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

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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:	53
	Report of Independent Registered Public Accounting Firm	54
	Consolidated Balance Sheets	55
	Consolidated Statements of Operations	56
	Consolidated Statements of Stockholders’ Equity (Deficit)	57
	Consolidated Statements of Cash Flows	58
	Notes to the Consolidated Financial Statements	59
	Supplemental Oil and Gas Disclosures (Unaudited)	88
	Management’s Report on Internal Control Over Financial Reporting	96
	Report of Independent Registered Public Accounting Firm on Internal Control over Financial Reporting	97
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 103 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.

99

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.

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 thru 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.

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

100

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.

101

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 2, 2009.

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 2, 2009	(Principal Financial Officer)
	March 2, 2009
/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 2, 2009
March 2, 2009
/s/  E. BARGER MILLER III	/s/  GORDON GRAY
E. Barger Miller III	Gordon Gray
Director	Director
March 2, 2009	March 2, 2009
/s/  DENNIS G. STRAUCH	/s/  JOHN J. LENDRUM, III
Dennis G. Strauch	John J. Lendrum, III
Director	Director
March 2, 2009	March 2, 2009

102

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).
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)
10.1	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).

103

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.
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.
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).
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.
23.1	Consent of Independent Registered Public Accounting Firm.
23.2	Consent of Independent Petroleum Engineers and Geologists.
31.1	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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.

* - Management Contract or Compensatory Plan or Arrangement.

104