**Table of Contents**

** **

** **

** **

**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington, DC 20549**

** **

**Form 10-K**

** **

**x**      ANNUAL REPORT PURSUANT TOSECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

** **

**For the fiscal year ended December 31, 2009**

** **

**or**

** **

**o**         TRANSITION REPORTPURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934

** **

**For the transition period from              to              **

** **

**Commission File Number: 001-12697**

** **

**BPZ Resources, Inc.**

(Exactname 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 525Houston, Texas 77079**(Addressof principal executive office)

** **

Registrant’stelephone number, including area code:  **(281)556-6200**

 

Securities registeredpursuant to Section 12(b) of the Act:

 
| **Title of  Each Class**    | ** ** | **Name of  Each Exchange on Which Registered** |
|-----------------------------|------------|------------------------------------------------|
| Common  Stock, no par value |       | New  York Stock Exchange                       |

 

Securities registeredpursuant to Section 12(g) of the Act:** None**

 

Indicate by check mark ifthe registrant is a well-known seasoned issuer, as defined in Rule 405 ofthe Securities Act.  Yes  o  No  x

 

Indicate by check mark ifthe registrant is not required to file reports pursuant to Section 13 or15(d) of the Act.  Yes  o  No  x

 

**Note** — Checking the box above will notrelieve any registrant required to file reports pursuant to Section 13 or15(d) of the Exchange Act from their obligations under those Sections.

 

Indicate by check markwhether the registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days.  Yes  x  No  o

 

Indicate by check markwhether the registrant has submitted electronically and posted on its corporatewebsite, if any, every Interactive Data File required to be submitted andposted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter)during the preceding 12-months (or for such shorter period that the registrantwas required to submit and post such files).  Yes  o  No  o

 

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K is notcontained herein, and will not be contained, to the best of registrant’sknowledge, in definitive proxy or information statements incorporated by referencein Part III of this Form 10-K or any amendment to this Form 10-K.  o

 

Indicate by check markwhether the registrant is a large accelerated filer, an accelerated filer, anon-accelerated filer or a smaller reporting company.  See the definitions of “large acceleratedfiler,” “accelerated filer” and “smaller reporting company” in Rule 12b-2of the Exchange Act.

 

| Large  accelerated filer  o |   | Accelerated  filer  x          |
|---------------------------------------|--------|------------------------------------------|
|                                  |   |                                     |
| Non-Accelerated  filer  o   |   | Smaller  reporting company   o |

 

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

 

The number of shares ofCommon Stock held by non-affiliates as of June 30, 2009 was 64,700,845shares, all of one class of common stock, no par value, having an aggregatemarket value of approximately $316,387,132 based upon the closing price ofregistrant’s common stock on such date of $4.89 per share as quoted on the NewYork Stock Exchange. For purposes of the foregoing calculation, all directors,executive officers, and 5% beneficial owners have been deemed affiliated.

 

As of March 26, 2010there were 115, 223,926 shares of common stock, no par value, outstanding.

 

**DOCUMENTS INCORPORATED BY REFERENCE**

** **

(1) Proxy Statementfor 2010 Annual Meeting of Stockholders — Part III

 

 

 

----

Table of Contents

 

**TABLE OF CONTENTS**

 
| **PART I**                       |                                                                                                                |   |
|---------------------------------------|---------------------------------------------------------------------------------------------------------------------|--------|
|                                  |                                                                                                                |   |
| Item 1.                               | Business                                                                                                            | 3      |
| Item 1A.                              | Risk Factors                                                                                                        | 12     |
| Item 1B.                              | Unresolved  Staff Comments                                                                                          | 25     |
| Item 2.                               | Properties                                                                                                          | 26     |
| Item 3.                               | Legal  Proceedings                                                                                                  | 34     |
| Item 4                                | Reserved                                                                                                            | 34     |
|                                  |                                                                                                                |   |
| **PART II**                      |                                                                                                                |   |
| Item 5.                               | Market  for Registrant’s Common Equity, Related Stockholder Matters and Issuer  Purchases of Equity Securities | 35     |
| Item 6.                               | Selected  Financial Data                                                                                            | 37     |
| Item 7.                               | Management’s  Discussion and Analysis of Financial Conditions and Results of Operations                        | 38     |
| Item 7A.                              | Quantitative  and Qualitative Disclosures About Market Risk                                                         | 70     |
| Item 8.                               | Financial  Statements and Supplementary Data                                                                        | 72     |
| Item 9                                | Changes  in and Disagreements with Accountants on Accounting and Financial Disclosures                              | 118    |
| Item 9A.                              | Controls  and Procedures                                                                                            | 118    |
| Item 9B.                              | Other  Information                                                                                                  | 119    |
|                                  |                                                                                                                |   |
| **PART III**                     |                                                                                                                |   |
| Item 10.                              | Directors,  Executive Officers and Corporate Governance                                                             | 120    |
| Item 11.                              | Executive  Compensation                                                                                             | 120    |
| Item 12.                              | Security  Ownership of Certain Beneficial Owners and Management and Related Stockholder  Matters                    | 120    |
| Item 13.                              | Certain Relationships and Related Transactions, and  Director Independence                                          | 120    |
| Item 14.                              | Principal Accountant Fees and Services                                                                              | 120    |
|                                  |                                                                                                                |   |
| **PART IV**                      |                                                                                                                |   |
| Item 15.                              | Exhibits  and Financial Statement Schedules                                                                         | 121    |
|                                  |                                                                                                                |   |
| Glossary of Oil and Natural Gas Terms | 122                                                                                                                 |
|                                  |                                                                                                                |
| Signatures                            | 124                                                                                                                 |

 

2

----

Table ofContents

 

**PART I**

 

*BPZ Resources, Inc.cautions that this document contains forward-looking statements within themeaning of the Private Securities Litigation Reform Act of 1995, Section 27Aof the Securities Act of 1933, as amended, and Section 21E of theSecurities Exchange Act of 1934, as amended. All statements, other thanstatements of historical facts, included in or incorporated by reference intothis Form 10-K which address activities, events or developments which theCompany expects, believes or anticipates will or may occur in the future areforward-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 identifyforward-looking statements. These statements are based on certain assumptionsand analyses made by the management of BPZ in light of its experience and itsperception of historical trends, current conditions and expected futuredevelopments as well as other factors it believes are appropriate under thecircumstances. The Company cautions the reader that these forward-lookingstatements are subject to risks and uncertainties, many of which are beyond itscontrol, that could cause actual events or results to differ materially fromthose expressed or implied by the statements. See Item 1A. — “Risk Factors”included in this Form 10-K.*

* *

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

* *

**ITEM 1. BUSINESS**

** **

**Overview**

 

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

 

We maintain asubsidiary, BPZ Exploración & Producción S.R.L. (“BPZ E&P”), registered in Peru through our wholly-owned subsidiary BPZ EnergyInternational Holdings, L.P., a British Virgin Islands limited partnership, andits subsidiary BPZ Energy, LLC, a Texas limited liability company. Currently,we, through BPZ E&P, have exclusive rights and license contracts for oiland gas exploration and production covering a total of approximately 2.2million acres, in four blocks, in northwest Peru. Our license contracts cover100% ownership of the following properties: Block Z-1 (0.6 million acres),Block XIX (0.5 million acres), Block XXII (0.9 million acres) and Block XXIII(0.2 million acres). The Block Z-1 contract was signed in November 2001,the Block XIX contract was signed in December 2003 and Blocks XXII andXXIII contracts were signed in November 2007. Generally, according to theOrganic Hydrocarbon Law No. 26221 and the regulations thereunder (the “OrganicHydrocarbon Law”) the seven-year term for the exploration phase can be extendedin each contract by up to an additional three years to a maximum of ten years.However, specific provisions of each license contract can vary the explorationphase of the contract as established by the hydrocarbon law. The licensecontracts require us to conduct specified activities in the respective blocksduring each exploration period in the exploration phase. If the explorationactivities are successful, we may decide to enter the exploitation phase andour total contract term can extend up to 30 years for oil exploration andproduction and up to 40 years for gas exploration and production. In the event ablock contains both oil and gas, as is the case in our Block Z-1, the 40-yearterm may apply to oil exploration and production as well.

 

Additionally,through our wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation,and its registered branch in Ecuador, we own a 10% non-operating workinginterest in an oil and gas producing property, Block 2, located in thesouthwest region of Ecuador (the “Santa Elena Property”). The license agreementcovering the property extends through May 2016.

 

We are in theprocess of developing our oil and natural gas reserves. We have been producingand selling oil from the CX-11 platform in the Corvina field of Block Z-1 undera well testing program and are in the process of satisfying the conditions totransition to commercial production in Corvina. From the time we began producing from the CX-11 platform in the Corvinafield in November 2007, through December 31, 2009, we have producedapproximately 1.9 million barrels (“MMBbls”) of oil. We are also in the initialstages of appraising, exploring and developing our potential oil and naturalgas reserves from the A platform in the Albacora field of Block Z-1 and havedrilled and completed our first well in December 2009.  Additionally, our activities in Peru includeanalysis and evaluation of technical data on our other properties, preparationof the development plans for the properties, refurbishment of and designs forplatforms to perform our drilling campaigns in the Corvina and Albacora fieldsin Block Z-1, procuring machinery and equipment for an extended drillingcampaign, obtaining all necessary environmental and operating permits, bringingadditional production on-line, seismic 

 

3

----

Table ofContents

 

acquisition, obtainingdetailed engineering and design of the power plant and gas processingfacilities, executing a contract to purchase three LM 6000 gas fired turbinesand securing the required capital and financing to conduct the current plan ofoperation.

 

At December 31,2009, we had estimated net proved oil reserves of 37.5 MMBbls, ofwhich 27.5 MMBbls were in the Corvina field and 10.0 MMBbls were from theAlbacora field; both fields being in Block Z-1, located offshore of northwestPeru. Of our total proved reserves, 9.9 MMBbls (26.4%) are classified asproved developed reserves consisting of 13 wells and 27.6 MMBbls (73.6%) areclassified as proved undeveloped reserves consisting of 22 future wells. The process ofestimating oil and natural gas reserves is complex and requires manyassumptions that may turn out to be inaccurate. See Item 1A - “Risk Factors” for further information.

 

Wehave determined our reporting structure provides for only one operating segmentas we only operate in Peru and currently have only one customer for ourproduction. Informationregarding our operating segment including our revenues and long-lived assetscan be found in the footnotes to our consolidated financial statements startingon page 72 of this Annual Report on Form 10-K.

 

**Our Business Plan**

 

Our business planis to enhance shareholder value primarily through application of our knowledgeof our targeted areas in Peru and leveraging management’s experience with thelocal suppliers and regulatory authorities to effectively and efficiently (i) quantifythe potential value of our oil and gas holdings in Peru; (ii) increaseproduction and cash flows from our identified holdings; and (iii) create arevenue stream through implementation of our gas-to-power project.

 

Our managementteam has extensive engineering, geological, geophysical, technical andoperational experience and extensive knowledge of international oil and gasoperations throughout Latin America and in particular, Peru.

 

Our focus is tore-appraise and develop properties in northwest Peru that have been explored byother companies and have reservoirs that appear to contain commerciallyproductive quantities of oil and gas, as well as other areas that havegeological formations that we believe potentially contain commercial amounts ofhydrocarbons.

 

Two of the fourblocks (Block Z-1 and Block XXIII) contain structures drilled by previousoperators who encountered hydrocarbons. However, at the time the wells weredrilled, the operators did not consider it economically feasible to producethose hydrocarbons.  Having found oil in our first well in the Corvinafield in offshore Block Z-1 in 2007, and oil in our first well in Albacora in December 2009,we are focusing on development of the proved oil reserves in the Corvina andAlbacora fields.

 

In addition, ourbusiness plan includes a gas-to-power project, which entails the installationof a 10-mile gas pipeline from the CX-11 platform to shore, construction of gasprocessing facilities and an approximately 135 megawatt (“MW”) simple cycleelectric generating plant using three LM 6000 gas fired turbines. The proposedpower plant site is located adjacent to an existing substation and powertransmission lines which, with certain upgrades, are expected to be capable ofhandling up to 320 MW of power. The gas-to-power project will allow us tocreate a revenue stream by creating a market for the gas discovered in ourCorvina field that is currently shut-in. We plan to utilize part of our future natural gas production as a supplysource for the development of a gas-fired power generation facility in Peru,which we currently plan to wholly or partially own.

 

We willconcentrate our efforts on areas we believe contain proven oil and gas reservesthat can be economically developed and produced in commercial quantities andleverage 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 effectivelyand efficiently to enhance the profitability of the Company, and thus increaseshareholder value.

 

**AvailableInformation**

** **

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

 

You can also obtain copies ofsuch material from the Public Reference Section of the SEC, 100 F Street,N.E., Room 1580, Washington, D.C. 20549 at prescribed rates. The SECmaintains a website that contains reports, proxy and information

 

4

----

Table of Contents

 

statements and other information regarding registrantsthat file electronically with it, like BPZ Resources, Inc. The SEC’swebsite can be accessed at http://www.sec.gov.

 

**Inaddition, we maintain a website (www.bpzenergy.com) on which we also makeavailable, free of charge, all of our above mentioned SEC filings, includingForms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) ofthe Securities Act of 1934. These filings will be available as soon asreasonably practicable after we electronically file such material with, orfurnish it to, the SEC.**

** **

**OurCompetition**

 

Intensecompetition exists in the oil and gas industry with respect to the acquisitionof producing properties, undeveloped acreage, and rights to explore for suchproperties. Many major and independent oil and gas companies actively pursueand bid for the mineral rights of desirable properties, and many companies havebeen actively engaged in acquiring oil and gas properties specifically in Peruand Ecuador.

 

Webelieve our efforts in and knowledge of our targeted areas has given us acompetitive advantage in Peru, and to a lesser extent, Ecuador. Althoughun-leased tracts exist within our target area, we believe these properties maybe less attractive to other companies because it will be difficult for them toobtain a significant amount of contiguous mineral acres. This results in partfrom our significant holdings in the vicinity of these un-leased tracts. However,increased demand for license contracts in surrounding areas may impact ourability to expand and grow in the future, particularly because many of ourcompetitors have substantially greater financial and other resources, inaddition to better name recognition and longer operating histories. As aresult, we may not be able to compete successfully to acquire additional oiland gas properties in desirable locations.

 

Intensecompetition for access to drilling and other contract services and experiencedtechnical and operating personnel needed to drill and complete wells alsoexists in the oil and gas industry. Competition for drilling and contractservices in our target area exists and may affect our plan of operation. We areadjusting our operating plans and timelines to adapt to this changingenvironment. However, increasing future demand for drillers and contractors maylimit our ability to execute in a timely manner and may negatively impact ourability to grow.

 

**Customers**

 

Todate, all of our sales of oil in Peru have been made under contract with thePeruvian national oil company, Petroleos del Peru - PETROPERU S.A. (“Petroperu”). However, we believe that the loss of our sole customer would notmaterially impact our business because we could readily find other purchasersfor our oil production both in Peru and internationally.

 

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

 

Additionally, we arecurrently negotiating a short-term oil sales contract for the oil produced fromthe Albacora field. The current contract being negotiated is expected toprovide for the sale of up to 400,000 barrels of oil under similar terms to theshort-term Corvina oil contract which was negotiated with Petroperu in late2008.

 

**RegulationImpacting Our Business**

** **

***General***

*** ***

Variousaspects of our oil and natural gas operations are currently or will be subjectto various foreign laws and governmental regulations. These regulations may bechanged from time to time in response to economic or political conditions.

 

5

----

Table ofContents

 

***Peru***

 

***Peruvian hydrocarbon legislation.***  Peru’s hydrocarbon legislation, whichincludes the Organic Hydrocarbon Law, governs our operations in Peru. Thislegislation covers the entire range of petroleum operations, defines the rolesof Peruvian government agencies and related authorities which regulate andinteract with the oil and gas industry, requires that investments in thepetroleum sector be undertaken solely by private investors (either national orforeign), and provides for the promotion of the development of hydrocarbonactivities based on free competition and free access to all economicactivities. This regulation provides that pipeline transportation and naturalgas distribution must be handled via contracts with the appropriategovernmental authorities. All other petroleum activities are to be freelyoperated and are subject to local and international safety and environmentalstandards.

 

Underthis legal system, Peru is the owner of the hydrocarbons located below thesurface in its national territory. However, Peru has given the ownership right toextract hydrocarbons to Perupetro S.A (“Perupetro”), a corporation owned by thePeruvian government empowered to become a party in the contracts for theexploration and/or exploitation of hydrocarbons in order to promote theseactivities in Peru. Perupetro is empowered to enter into contracts for theexploration and exploitation of hydrocarbons on behalf of Peru, the nature ofwhich are described further below. The Peruvian government also plays an activerole in petroleum operations through the involvement of the Ministry of Energyand Mines, which is the body of the executive branch of the Peruvian governmentin charge of devising energy, mining and environmental protection policies,enacting the rules applicable to all these sectors and supervising compliancewith such policies and rules. Within the Ministry of Energy and Mines, Organismo Supervisor de la Inversión enEnergía y Mineria (“OSINERGMIN”) is the governmental entitythat supervises both legal and technical aspects of hydrocarbon activities inPeru, and the GeneralDirectorate of Hydrocarbons (“DGH”) is the agency of the Ministry of Energy andMines responsible for regulating the optimum development of oil and gas fields.We are subject to the laws and regulations of all of these entities andagencies.

 

Perupetro,empowered by the Peruvian state as a contractual party, generally enters intoeither license contracts or service contracts for hydrocarbon exploration andexploitation. Peru’s laws also allow for other contract models, but the modelsmust be authorized by the Ministry of Energy and Mines. We only operate underlicense contracts and do not foresee operating under any services contracts inthe immediate future.  A company must bequalified by Perupetro to enter into hydrocarbon exploration and exploitationcontracts in Peru. In order to qualify, the company must meet the standardsunder the Regulations Governing the Qualifications of Oil Companies. Thesequalifications generally require the company to have the technical, legal,economic and financial capacity to comply with all obligations it will assumeunder the contract. These requirements will depend on the characteristics ofthe area requested, the possible investments and the environmental protection rules governingthe performance of its operations. When a contractor is a foreign investor, itis expected to incorporate a subsidiary company or registered branch inaccordance with Peru’s laws and appoint representatives who will interact withPerupetro.

 

Perupetroreviews the qualification for each contract signed by a company. Additionally,the qualification for foreign companies is granted in favor of the home officeor limited liability company, which provides a corporate guarantee to Perupetrowhich determines if it is jointly and severally liable before Perupetro withrespect to the fulfillment of each minimum work program of the exploration phase,as well as each annual exploitation program handed to Perupetro. BPZ Energy,LLC (Texas) and its corresponding subsidiary in Peru has been qualified byPerupetro with respect to our current contracts as required by currentregulation.

 

Whenoperating under a license contract, the licensee is the owner of thehydrocarbons extracted from the contract area during the performance ofoperations once the corresponding royalty has been paid to Perupetro. Thelicensee can market the hydrocarbons in any manner whatsoever, subject to alimitation in the case of natural emergencies where the law stipulates suchmanner.

 

Licenseesare obligated to submit quarterly reports to the DGH. Licensees must alsosubmit a monthly economic report to the Central Reserve of Peru (“Banco Centralde Reserva”). These reports are generally combined and delivered together withother operating reports required to be submitted to Perupetro.

 

Theduration of the license contracts is based on the nature of the hydrocarbonsdiscovered. The license contract duration for crude oil is 30 years, while thecontract duration for natural gas and condensates is 40 years. The licensecontract commences on an agreed date, the effective date, established in thelicense contract. Most contracts typically include an exploration phase and anexploitation phase, unless the contract is solely an exploitation contract.Within the contract term, seven years is allotted to exploration, with thepossibility of up to a three year extension. A potential deferment period for amaximum of ten years is also available if certain factors recognized by lawdelay the economic viability of a discovery, 

 

6

----

Table ofContents

 

suchas lack of transportation facilities or lack of a market. The exploration phaseis generally divided into several periods and each period includes a minimumwork program. The fulfillment of work programs must be supported by anirrevocable bank guaranty, usually in the amount of thirty to forty percent ofthe estimated value of the minimum work program.

 

Perupetroalso grants technical evaluation agreements. These agreements give thecontractor the right to conduct technical evaluations of the areas under suchagreements with the possibility to enter into license contracts if theevaluations indicate the potential for profitable operations. The technicalevaluation agreements terms depend upon the volume and nature of the work to becarried out.

 

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

 

New legislation in Peruwas passed by Supreme Decree 088-2009 on December 13, 2009 with respect toregulating well testing and gas flaring. The new legislation provides that all new wells may be placed onproduction testing for up to six months. If the operator believes a longer period for testing the well is neededto evaluate the productive capacity of the field properly, and can technicallyjustify such need, a request for the well to enter into an extended well testperiod must be submitted to the DGH.  Theapproval process for an extended well test permit requires that the DGH requestthe opinion of Perupetro on the technical justification for the extended welltest. After the initial six-month period or after an approved extended welltest program expires, the operator will be required to have the necessary gasand water reinjection equipment in place to continue operating the wellaccording to existing environmental regulations.

 

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

 

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

 

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

 

We initially planned tohave the needed gas and water reinjection facilities at the CX-11 platform by May 31,2010.  However, this no longer appears tobe reachable due to the delayed delivery of certain equipment. If we areunable to receive and install the necessary water and gas reinjection equipmentand receive approval of the corresponding environmental permits by May 31,2010, we may not be permitted to produce from some or all of the oil wells inCorvina until such installation is completed or an extension of the May 31,2010 date is obtained.  We will apply to the proper authoritiesfor an extension of the May 31, 2010 date to be able to maintain testingthe wells in Corvina; however, no assurance can be given that such extensionwill be awarded.  Depending on the extent of the delay, we plan to use theadditional time to drill one or two more wells from the CX-11 platform after thecurrent well, the CX11-22D, is completed. See Item 1A, “Risk Factors” for further information.

 

7

----

Table ofContents

 

***Peruvian fiscal regime.***  Peru’s fiscal regime determines the levels ofthe government’s entitlement from petroleum activities. This regime is subjectto change, which could negatively impact our business. Nevertheless, it isimportant to note that in Peru our License Contracts have fiscal stability.

 

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

 

TheOrganic Hydrocarbon Law and the Regulations Governing the Tax StabilityGuaranty and Other Tax Rules of the Organic Hydrocarbon Law provide thatthe tax regime in force on the date of signing a contract will remain unchangedduring the term of the contract. Therefore, any change to the tax regime, whichresults in either an increase or decrease in the tax burden, will not affectthe operator.

 

Duringthe exploration phase, operators are exempt from import duties and other formsof taxation applicable to goods intended for exploration activities. Exemptionsare withdrawn at the production phase, but exceptions are made in certaininstances, and the operator may be entitled to import goods tax-free for anadditional two-year period.

 

Taxableincome is determined by deducting allowable operating and administrativeexpenses, including royalty payments. Income tax is levied on the income of theoperator based upon the legal corporate tax rate in effect at the date thecontract was signed. Operators engaged in the exploration and production ofcrude oil, natural gas and condensates must determine their taxable incomeseparately for each license contract under which they operate. Where acontractor carries out these activities under different individual licensecontracts, it may offset its earnings before income tax under one licensecontract with losses under another license contract, as long as the contractwith the loss is in the commercial production phase or has been relinquished,for purposes of determining the corporate income tax provided that theindividual license contracts are held by the same company as Peruvian tax lawdoes not permit filing a consolidated tax return for related companies.However, under no circumstances can the investment in the producing property beamortized for tax purposes over a period of five years unless the company isunder the commercial stage of production.

 

***Peruvian labor and safety legislation.***  Our operations in Peru are also subject tothe Labor Law, which governs the labor force in the petroleum sector. Inaddition, the Organic Hydrocarbon Law and related Safety Regulations for thePetroleum Industry also regulate the safety and health of workers involved inthe development of hydrocarbon activities. All entities engaged in theperformance of activities related to the petroleum industry must provide theGeneral Hydrocarbons Bureau, on a semi-annual basis, with a list of theirpersonnel, indicating their nationality, specialty and position. These entitiesmust also permanently train their workers on the application of safety measuresin the operations, and control of disasters and emergencies. Each entity mustkeep detailed records of all accidents that occur in its operations and reportall accidents to the OSINERGMIN. Theregulations also contain provisions on accident prevention and personnel healthand safety, which in turn include rules on living conditions, sanitaryfacilities, water quality at workplaces, medical assistance and first-aidservices. Provisions specifically related to the exploration phase, which isour current phase of operations, are also contained in the regulations andinclude safety measures in camps, medical assistance, food conditions, andhandling of explosives. Additional safety regulations may also apply as weexpand and develop our operations.

 

TheConstitution of Peru and Legislative Decree Nos. 677 and 892 gives employeesworking in private companies engaged in activities generating income classifiedas third category income by the Income Tax Law the right to share in thecompany’s profits.  This profit sharingis carried out through the distribution by the company of a percentage of theannual income before tax.  According to Article 3of the United Nations International Standard Industrial Classification, BPZResources, 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 Courtruled, that hydrocarbons are not related to mining activities.  Hydrocarbons are included under “CompaniesPerforming other Activities”, thus Oil and Gas Companies pay profit sharing ata rate of 5%. The benefit granted by the law to employees is calculated on thebasis of the “net income subject to taxation” and not on the net business oraccounting income of companies. “Taxable income” is obtained after deductingfrom total revenues subject to income tax, the expenses required to producethem or maintain the source thereof.

 

Thefollowing factors are taken into account regarding the profit sharing system: (1) calculationof profits to be distributed to each employee is based on two criteria (a) thenumber of days actually worked by each employee, and (b) in proportion tothe remunerations of each employee; (2) number of days actually worked(including leave of absence, temporary shutdown of the workplace, and days notworked due to improper suspension by the employer); (3) remuneration (thefull amount received by the employee for his services); (4) maximum profitshare limit of 18 monthly remunerations; 

 

8

----

Table ofContents

 

(5) remainderbetween the maximum percentage of company profits to be distributed and themaximum limit of the percentage corresponding to all employees; (6) timingof distributions should be made within thirty calendar days after expiration ofthe 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 ofelectricity and the sale of such electric power in Peru. The basic laws in Perugoverning electric power, which will apply to our future operations, are theLaw of Electric Power Concessions and the Regulations for the EnvironmentalProtection of Electric Power Activities, the corresponding regulations foreach, as well as additional related laws and regulations, including alllegislation regarding Electric Power Tariffs and all regulations and technicalnorms created by the National Commission of Electric Power Tariffs.

 

***Peruvian environmental regulation.***  Our operations are subject to numerous and frequentlychanging laws and regulations governing the discharge of materials into theenvironment or otherwise relating to environmental protection. Peru has enactedspecific environmental regulations applicable to the hydrocarbon industry. TheCode on the Environment and the Natural Resources establishes a frameworkwithin which all specific laws and regulations applicable to each sector of theeconomy are to be developed. These laws and regulations are designed to ensurea continual balance of environmental and petroleum interests. The regulationsstipulate certain environmental standards expected from contractors. They alsospecify appropriate sanctions to be enforced by the Ministry of Mines andEnergy if a contractor fails to maintain such standards. The Ministry of Minesand Energy is charged with the responsibility of issuing the applicablestandards. OSINERGMIN is responsible for ensuring compliance with applicableenvironmental rules covering hydrocarbon activities.

 

TheOrganic Hydrocarbon Law also addresses the environmental regulatory regime inPeru. The law originally prohibited any mining or extractive operations withincertain areas designated for protection. It was, however, subsequently modifiedto enable investors to prospect for hydrocarbons within protected areas,provided there is compliance with several obligations. We must comply withthese obligations as we conduct our business on an ongoing basis. TheEnvironmental Regulations for Hydrocarbon Activities provide that companiesparticipating in the implementation of projects, performance of work andoperation of facilities related to hydrocarbon activities, are responsible forthe emission, discharge and disposal of wastes into the environment. Companiesmust annually file a report corresponding to the previous year describing thecompany’s compliance with the environmental legislation in force.

 

Companiesinvolved in hydrocarbon activities must also prepare and file an EnvironmentalImpact Study (“EIS”) with the General Hydrocarbons Bureau, which is part of theMinistry of Energy and Mines, in order for the relevant activities to complywith the maximum permissible emission limits set forth by the Ministry ofEnergy 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.

 

Inaddition, any party responsible for hydrocarbon activities must file an “OilSpill and Emergency Contingency Plan” with the General Hydrocarbons Bureau. Theplan must be updated at least once a year and must contain informationregarding 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 toestablish uninterrupted communication between the personnel, the governmentrepresentatives, the General Hydrocarbons Bureau and other State entities.

 

Peruhas recently enacted amendments to its environmental law, imposing substantialrestrictions on the use of natural resources, interference with the naturalenvironment, location of facilities, handling and storage of hydrocarbons, useof radioactive material, disposal of waste, emission of noise and otheractivities. Additionally, the laws require monitoring and reporting obligationsin the event of any spillage or unregulated discharge of hydrocarbons.

 

Anyfailure to comply with environmental protection rules, the import ofcontaminated products, or failure to keep a monitoring register or send reportsto the General Hydrocarbons Bureau in a timely fashion, could subject thecompany to fines. In addition, the General Hydrocarbons Bureau may considerimposing a prohibition or restriction of the relevant activity, an obligationto compensate the aggrieved parties and/or an obligation to immediately restorethe area. The company responsible for any default can also be subject to asuspension of operations for a term of one, two or three months, orindefinitely. Furthermore, any contract signed with the Peruvian government,the implementation of which jeopardizes or endangers the protection orconservation of protected natural areas, can be terminated.

 

Weare subject to all Peruvian environmental regulations applicable to thepetroleum industry now in existence and those existing in the future. Forexample, we are required to obtain an environmental permit or approval from thegovernment in Peru prior to conducting any seismic operations, drilling a wellor constructing a pipeline in Peruvian territory including 

 

9

----

Table ofContents

 

thewaters offshore Peru where we intend to conduct oil and gas operations.  The enactment and enforcement ofenvironmental laws and regulations in Peru is relatively new. We are thereforeuncertain how Peruvian authorities will enforce and supervise environmentalcompliance and standards. Further, we cannot predict any future regulation orthe cost associated with future compliance.

 

Althoughwe believe our operations are in substantial compliance with existingenvironmental requirements, our ability to conduct continued operations issubject to complying with applicable regulations. Our current permits andauthorizations and ability to obtain future permits and authorizations may besusceptible, on a going forward basis, to increased scrutiny, greatercomplexity resulting in increased costs, or delays in receiving appropriateauthorizations. In particular, we may in the future experience delays inobtaining permits and authorizations in Peru necessary for our operations.

 

***Compliance with Existing Legislation in Peru***

 

Althoughwe believe our operations are and will be in substantial compliance withexisting legislation and requirements of Peruvian governmental bodies, ourability to conduct continued operations is subject to satisfying applicableregulatory and permitting controls. Our principals have many collective decadesof experience in dealing directly with the Peruvian government on energyprojects. Therefore, we believe we are in a good position to understand andcomply with local rules and regulations. However, our current permits andauthorizations as well as our ability to obtain future permits andauthorizations may, over time, be susceptible to increased scrutiny and greatercomplexity which could result in increased costs or delays in receivingappropriate authorizations.

 

***Ecuador***

 

SMCEcuador, Inc., our wholly-owned subsidiary, has held its 10% non-operatinginterest in the Santa Elena oil fields since 1997. We acquired all of thecommon stock of SMC Ecuador, Inc. in 2004. As a non-operator, we are not directly subject to the laws andregulations of Ecuador covering the oil and gas industry and the environment.However, if we begin operating activities in Ecuador, we will be directlysubject to such laws and regulations.

 

**Environmental Compliance and Risks**

** **

As an owner or lessee and operator of oil and gasproperties in South America, in particular Peru, we are subject to variousnational, state and local laws and regulations relating to discharge ofmaterials into, and protection of, the environment. These laws and regulationsmay, among other things, impose liability on the contractor under an oil andgas license agreement for the cost of pollution clean-up resulting fromoperations, subject the contractor to liability for pollution damages, andrequire suspension or cessation of operations in affected areas.

 

In addition to certain pollution coverage related toour surface facilities, we also maintain insurance coverage for seepage andpollution, cleanup and contamination from our wells.  Regardless, no such coverage can insure usfully against all environmental risks. We are not aware of any environmentalclaims which would have a material impact upon our financial position orresults of operations.

 

We will continue our efforts to comply with theserequirements, which we believe are necessary to maintain successful long-termoperations in the oil and gas industry. As part of this effort we haveestablished guidelines for continuing compliance with environmental laws andregulations. In order to carry out our plan of operation, we are required toconduct environmental impact studies and obtain environmental approvals foroperations. We have engaged outside consultants to perform these studies andassist us in obtaining necessary approvals. Our cost for these studies and assistancerelated to the Block Z-1, Corvina and Albacora fields and Block XIX for theyears ended December 31, 2009, 2008, and 2007 were approximately $1.2million, $0.5 million and $0.3 million, respectively.  We are currently assessing what studies are necessaryand the associated cost estimate for Blocks XXII and XXIII.

 

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

 

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

 

10

----

Table ofContents

 

Americas(“CCA”) to assist us in response to this incident. As part of their assistancethey conducted an oil pollution assessment in and around the area surroundingthe incident.  CCA concluded that themajority of the crude oil contained in the Navy tanker was consumed during thefire subsequent to the explosion.  Thiswas confirmed after divers inspected the sunken tanker, which is resting 200feet underwater, and reported that no crude oil was detected in any of thetanks.  Our environmental consultants, aswell as several independent organizations, conducted additional lab tests onseawater and marine life within the potentially affected area and these labtest results indicated no contamination related to the incident. In March 2008,OSINERGMIN, thegovernment regulatory agency in Peru responsible for monitoring industrialsafety, cleared the Company to resume operations at the CX-11 platform in theoffshore Z-1 Block in northwest Peru. We have not received any additionalrequests from any regulatory agency requiring us to perform additional servicesrelated to this incident in order for us to be in compliance with environmentalregulation.

 

We do not believe compliance with national, state orlocal provisions regulating the discharge of materials into the environment, orotherwise relating to the protection of the environment, will have a materialadverse effect upon the capital expenditures, earnings or competitive positionof the Company or its subsidiaries. However, there is no assurance that changesin or additions to laws or regulations regarding the protection of theenvironment will not have such an impact.

** **

**Operational Hazards and Insurance**

** **

Our operations are subject to the usual hazardsincidental 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 anddestruction of property and equipment, pollution or environmental damage andsuspension of operations.

 

As is common in the oil and natural gas industry, wedo not insure fully against all risks associated with our business eitherbecause such insurance is not available or because premium costs are consideredprohibitive. We currently have insurance coverage which we believe is adequatefor our current stage of operations based on management’s assessment.  Such insurance may not cover every potentialrisk associated with the drilling, production and processing of oil and gas. Inparticular, coverage is not obtainable for all types of environmental hazards.Additionally, the occurrence of a significant adverse event, the risks of whichare not fully covered by our insurance policy, could have a material adverseeffect on our financial condition and results of operations. Moreover, noassurance can be given that we will be able to maintain adequate insurance orincrease current coverage amounts at rates we consider reasonable.

 

**Research and Development**

** **

We seek to use advanced technologies in theevaluation of our oil and gas properties and new opportunities. We generally donot develop such technologies internally, but our technical team works withoutside vendors to test and utilize these technologies to the fullest practicalextent, particularly in the application of geophysical and explorationsoftware. In certain cases, our collaboration has aided the development ofthese technologies. We do not believe we have incurred any quantifiableincremental costs in connection with research and development

 

**Employees**

 

As of December 31, 2009, we employed 27 full-timeemployees in our Houston office and 153 full-time employees in our Lima, Peruoffice. We had two full-time employees in the Quito, Ecuador office. BPZbelieves that its relationship with its employees is satisfactory. None of ouremployees are currently represented by a union.

 

11

----

**Table of Contents**

 

**ITEM 1A.  RISKFACTORS**

** **

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

 

***We have a limited operating history and have onlyengaged in start-up and development activities.*** We are in theinitial stages of developing our oil and natural gas reserves and have begunproducing and selling oil from our discoveries under a well test program. We are also subject to all of the risks inherent in attempting to expand arelatively new business venture. Such risks include, but are not limited to,the possible inability to profitably operate our existing properties or propertiesto be acquired in the future, our possible inability to fully fund thedevelopment requirements of such properties and our possible inability toacquire additional properties that will have a positive effect on ouroperations. We can provide no assurance that we will achieve a level ofprofitability that will provide a return on invested capital or that willresult in an increase in the market value of our securities.  Accordingly, we are subject to the risk thatbecause of these factors and other general business risks noted throughoutthese “Risk Factors,” we may, in particular, not be able to profitably executeour plan of operation.

 

***We must comply with Peruvian legal and regulatoryrequirements to be able to produce and sell oil after the expiration ofproduction testing or approved extended well testing. If we do not obtainapproval to continue our well testing on wells producing for more than sixmonths, we would be required to suspend production from such wells and we wouldexperience an interruption in production that would negatively impact therevenues and cash flow associated with those wells.*** Under newlegislation regulating well testing in Peru, all new wells may be placed onproduction testing for up to six months. If we need additional time for testinga new well, we must submit a request for the well to enter into an extendedwell test period, together with technical justification for such need andduration, to the DGH, the agency of the Ministry of Energy and Minesresponsible for regulating the optimum development of oil and gas fields. Afterthe initial six-month period or before an approved extended well test periodexpires, we will be required to have the necessary gas and water reinjectionequipment in place to continue producing the well according to existingenvironmental regulations.

 

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

 

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

 

We initially planned to havethe needed gas and water reinjection facilities at the CX-11 platform by May 31,2010.  However, this no longer appears tobe reachable due to the delayed delivery of certain equipment. If we areunable to receive and install the necessary water and gas reinjection equipmentand receive approval of the corresponding environmental permits by May 31,2010, we may not be permitted to produce from some or all of the oil wells inCorvina until such installation is completed or an extension of the May 31,2010 date is obtained.  We will apply to the proper authoritiesfor an extension of the May 31, 2010 date to be able to maintain testingthe wells in Corvina; however, no assurance can be given that such extensionwill be awarded. Therefore, it is likely we will experience adisruption of revenues and cash flows associated with the Corvina wells untilthe reinjection equipment is successfully commissioned and other applicablerequirements have been satisfied.

 

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

 

12

----

Table ofContents

 

originalsix-month test period, we will experience an interruption in production thatwould negatively impact any revenue and cash flow associated with those wellsuntil the applicable requirements are satisfied for commercial production inAlbacora.

 

***Our reserve estimates depend on many assumptionsthat may turn out to be inaccurate.*** The process of estimatingoil and natural gas reserves is complex. It requires interpretations ofavailable technical data and many assumptions, including assumptions relatingto economic factors that may turn out to be inaccurate. Any significantinaccuracies in these interpretations or assumptions could materially affectthe estimated quantities and the calculation of the present value of reservesshown or incorporated by reference in this Annual Report.

 

In order to prepare our reserve estimates, our independent petroleumengineer must project production rates and timing of development expendituresas well as analyze available geological, geophysical, production andengineering data, and the extent, quality and reliability of this data canvary. The process also requires economic assumptions about matters such as oiland natural gas prices, drilling and operating expenses, capital expenditures,taxes, and availability of funds. Therefore, estimates of oil and natural gasreserves are inherently imprecise.

 

Actual future production, oil and natural gas prices, revenues, taxes,development expenditures, operating expenses and quantities of recoverable oiland natural gas reserves will most likely vary from our estimates, and thosevariances may be material. Any significant variance could materially affect theestimated quantities and present value of our reserves. In addition, ourindependent petroleum engineer may adjust estimates of proved reserves toreflect production history, drilling results, prevailing oil and natural gasprices and other factors, many of which are beyond our control.

 

One should not assume that the net present value of our proved reservesprepared in accordance with the Commission’s guidelines referred to in thisreport is the current market value of our estimated oil reserves. We base thenet present value of future net cash flows from our proved reserves on an unweighted arithmetic average of thefirst-day-of-the month price for each month during the 12-month calendar yearand year-end costs. Actual future prices, costs, taxes and the volumeof produced reserves may differ materially from those used in the net presentvalue estimate.

 

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

 

***We have received comments from the SEC to our mostrecent annual report, quarterly report and proxy statement that are stillpending and that may not be resolved in our favor.*** In connectionwith a registration statement filed on October 21, 2009 to register sharesissued to an institutional investor in a private transaction, we receivedcomments from the SEC pertaining to our registration statement, our most recentForm 10-K for the year ended December 31, 2008, our Definitive ProxyStatement filed on April 30, 2009, and our most recent Form 10-Q forthe period ended September 30, 2009 and the related earnings pressrelease. In general, the pending questions or comments from the SEC relate to: (i) clarificationsin several of our disclosures; (ii) the basis for the assumptionsunderlying our SEC oil reserves reported for 2008 in light of our actualproduction performance in 2009; (iii) the reasons our 2009 production fellshort of 2008 projections; (iv) the consideration we gave to the reasonablecertainty of our assumptions underlying our SEC oil reserves and the relatedaccounting reported in our financial statements; and (v) how we are takinginto consideration certain items and uncertainties for our 2009 reservesreport. The SEC is currently reviewing our responses, and could ask additionalquestions or request additional revisions to our filings, some of which couldbe material. In particular, the process of estimating oil and natural gasreserves is complex, requiring interpretations of available technical data andmany assumptions, including assumptions relating to economic factors, andtherefore are inherently imprecise. In its review of our responses and reservedata provided to them, the SEC could disagree with our independent petroleumengineer’s reserve estimates, including the underlying interpretations andassumptions or the reasonable certainty of our assumptions, and request arevision to our estimates of proved reserves and the related accounting of thereserves in our financial statements. Any restatement of our financialstatements or our estimates of proved reserves could have a material adverseeffect on the trading price of our common stock.

 

***As of December 31, 2009, approximately 74% ofour estimated net proved reserves were undeveloped.***  ***There can be no assurance that all of thesereserves will ultimately be developed or produced. *** We ownrights to oil and gas properties that have limited or no development. There areno guarantees that our properties will be developed profitably or that thepotential oil and gas resources on the property will produce as expected ifthey are developed.

 

Recovery of undeveloped reserves requires significant capitalexpenditures and successful drilling operations.  The reserve data assumesthat we will make significant capital expenditures to develop ourreserves.  We have prepared estimates of our natural gas and oil reservesand the costs associated with these reserves in accordance with industrystandards.  However, the estimated costs may not be accurate, developmentmay not occur as scheduled, or the actual results may not be asestimated.  We may not have or be able to obtain the capital we need todevelop these proved reserves.

 

13

----

Table ofContents

 

***We have not been profitable since we commencedoperations and have historically had significant working capital deficits***.  To date we have had limited revenue and limitedearnings from operations.  As of December 31,2009, we had a working capital surplus of approximately $7 million. As of December 31,2008, however, we had a working capital deficit of approximately $30 million,and we may incur working capital deficits in the future.  The sources of our working capital surplushave generally been equity and debt financings rather than revenue fromoperations.  We cannot provide anyassurance that we will be profitable in the future or that we will be able togenerate cash from operations or financings to fund working capital deficits.

 

***We require additionalfinancing for the exploration and development of our foreign oil and gasproperties and the construction of our proposed power generation facility,pipeline and gas processing facility.*** Since the merger withNavidec, Inc. (“Navidec”) on September 10, 2004 (the “Merger”), wehave funded our operations with the net proceeds of (i) approximately $288million in various private placements of our common stock, (ii) $186.4 millionin convertible debt financings, including $170.9 million of convertible debtsold in a private offering and $15.5 million in convertible debt financing from the InternationalFinance Corporation (“IFC”) that was converted into approximately 1.5 millionshares of our common stock in May 2008, and (iii) $15.0million in a reserve-based lending facility with IFC. We have recently begun togenerate revenues from operations. With these funds we have begun to implementour plans to develop our existing oil and gas properties, but we will needsignificant additional financing to fully implement our plan of operation. Ifwe are unable to timely obtain adequate funds to finance our exploration anddevelopment, our ability to develop our oil and natural gas reserves may belimited or substantially delayed. Such limitations or delays could result inthe potential loss of our oil and gas properties if we were unable to meet ourobligations under the license agreements, which could, in turn, limit ourability to repay our debts. Inability to timely obtain funds also could causeus to delay, scale back or abandon our plans for construction of our powergeneration facility, pipelines, and gas processing facility.

 

Future amounts required to fund our foreignactivities may be obtained through additional equity and debt financing, jointventure arrangements, the sale of oil and gas interests, and/or future cashflows from operations. However, adequate funds may not be available when neededor may not be available on favorable terms. The exact nature and terms of suchfunding sources are unknown at this time, and there can be no assurance that wewill obtain such funding or have adequate funding available to finance ourfuture operations.

 

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

 

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

 

·                  paymentbreaches under any of the finance documents for the first and second tranche ofthe senior debt;

 

·                  failure tocomply with obligations under the finance documents;

 

·                  representationand warranty breaches;

 

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

 

·                  insolvencies ofany borrower;

 

·                  certainattachments against the assets of any borrower;

 

·                  abandonment orextended business interruption of the Corvina field or certain other petroleumassets for a period over 100 consecutive days or an aggregate of 120 days inany twelve month period;

 

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

 

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

 

14

----

Tableof Contents

 

·                  defaults oncertain liabilities;

 

·                  certainjudgments against the borrower or any subsidiary;

 

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

 

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

 

·                  restrictionsenacted in Peru that could inhibit any payment a borrower is required to makeunder the financing documents with the IFC.

 

Upon the occurrence of an event of default or a specified change ofcontrol event, the IFC under our debt facility may: (i) terminate all orpart of the relevant facility; (ii) declare all or part of the principalamount of the loan, together with accrued interest, immediately due andpayable;  (iii) declare all or part of the principal amount of theloan, together with accrued interest, payable on demand; or (iv) declareany and all of the security documents under the facility enforceable andexercise its rights under such documents, including rights of foreclosureagainst the collateral. In addition, if any borrower is liquidated or declaredbankrupt, all loans and interest accrued on it or any other amounts due, willbecome immediately due and payable without notice.

 

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

 

Our ability to meet our current and future debt obligations and otherexpenses will depend on our future performance, which will be affected byfinancial, business, economic, regulatory and other factors, many of which weare unable to control.  If our cash flow is not sufficient to service ourdebt, we may be required to refinance the debt, sell assets or sell shares ofcommon stock on terms that we do not find attractive, if it can be done at all.

 

***Demand for oil andnatural gas is highly volatile. A substantial or extended decline in oil ornatural gas prices may adversely affect our business, financial condition, cashflow, liquidity or results of operations as well as our ability to meet ourcapital expenditure obligations and financial commitments to implement ourbusiness plan.***Any revenues, cash flow, profitability and future rate of growth we achievewill be greatly dependent upon prevailing prices for oil and gas. Our abilityto obtain additional capital on attractive terms is also expected to bedependent on oil and gas prices.

 

Historically, oil and gasprices and markets have been volatile and are likely to continue to be volatilein the future. Forexample, oil and natural gas prices increased to historical highs in 2008 andthen declined significantly over the last two quarters of 2008. In early July 2008,commodity prices reached levels in excess of $140.00 per Bbl of crude oil and$13.00 per Mcf for natural gas. As of March 23, 2010, those prices were$79.45 per Bbl and $4.39 per MMBtu, respectively. These prices will likelycontinue to be volatile in the future. Oil and natural gas arecommodities, and, therefore, their prices are subject to wide fluctuations inresponse 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 politicalconditions (including wars and civil unrest);

 

·                  the domesticand foreign supply of oil and gas;

 

·                  the level ofconsumer demand;

 

·                  weatherconditions;

 

·                  domestic andforeign governmental regulations and other actions;

 

·                  actions takenby the Organization of Petroleum Exporting Countries (OPEC);

 

·                  the price andavailability of alternative fuels; and

 

15

----

Tableof Contents

 

·                  overalleconomic conditions.

 

Lower oil and natural gas prices may not only decrease our revenues ona per unit basis, but may also reduce the amount of oil and natural gas we canproduce economically, if any. A continuation of low or a further decline in oiland natural gas prices may materially affect our future business, financialcondition, results of operations, liquidity and borrowing capacity, and mayrequire a reduction in the carrying value of our oil and gas properties. Whileour revenues may increase if prevailing oil and gas prices increasesignificantly, exploration and production costs and acquisition costs foradditional properties and reserves may also increase.  We do not enter into hedging arrangements oruse derivative financial instruments such as crude oil forward and swapcontracts to hedge our risk associated with fluctuations in commodity prices.

 

***Recent changes in the financial and credit marketmay impact economic growth, and combined with the recent volatility of oil andnatural gas prices, may also affect our ability to obtain funding on acceptableterms or obtain funding under our proposed credit facilities.***  Global financial markets and economicconditions have been, and continue to be, disrupted and volatile.  Accordingly, the equity capital markets havebecome exceedingly distressed.  Theseissues, along with significant asset write-offs in the financial servicessector, 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 orequity capital funding.

 

Due to these and possibly other factors, we cannot be certain fundingwill be available if needed, and to the extent required, on acceptableterms.  If funding is not available asneeded, or is available only on unfavorable terms, we may be unable to meet ourobligations as they come due or we may be unable to implement our exploratoryand development plan, enhance our existing business, complete acquisitions orotherwise take advantage of business opportunities or respond to competitivepressures, any of which could have a material adverse effect on our production,revenues and results of operations.

 

***Our future operating revenue is dependent upon theperformance of our properties.*** Our future operatingrevenue depends upon our ability to profitably operate our existing propertiesby drilling and completing wells that produce commercial quantities of oil andgas and our ability to expand our operations through the successfulimplementation of our plans to explore, acquire and develop additionalproperties. The successful development of oil and gas properties requires anassessment of potential recoverable reserves, future oil and gas prices,operating costs, potential environmental and other liabilities and otherfactors. Such assessments are necessarily inexact. No assurance can be giventhat we can produce sufficient revenue to operate our existing properties oracquire additional oil and gas producing properties and leases. We may notdiscover or successfully produce any recoverable reserves in the future, or wemay not be able to make a profit from the reserves that we may discover. In theevent that we are unable to produce sufficient operating revenue to fund ourfuture operations, we will be forced to seek additional, third-party funding,if such funding can be obtained. Such options would possibly include debtfinancing, 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 financingon 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, thiscould result in the termination of our operations and the loss of an investor’sentire investment.

 

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

 

·                  fires;

 

·                  explosions;

 

·                  blow-outs andsurface cratering;

 

·                  uncontrollableflows of natural gas, oil and formation water;

 

·                  naturaldisasters, such as earthquakes and tsunamis and adverse weather conditions;

 

·                  pipe, cement,subsea well or pipeline failures;

 

16

----

Tableof Contents

 

·                  casingcollapses;

 

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

 

·                  abnormallypressured formations; or

 

·                  environmentalhazards, such as natural gas leaks, oil spills, pipeline ruptures anddischarges of toxic gases.

 

Experiencing any of these operating risks could lead to problems withany well bores, platforms, gathering systems and processing facilities, whichcould adversely affect any drilling operations we may commence. Affecteddrilling operations could further lead to substantial losses as a result of:

 

·                  injury or lossof life;

 

·                  severe damageto and destruction of property, natural resources and equipment;

 

·                  pollution andother environmental damage;

 

·                  clean-upresponsibilities;

 

·                  regulatoryrequirements, investigations and penalties;

 

·                  suspension ofour operations; or

 

·                  repairs toresume operations.

 

If any of these risks occur, we may have to curtail or suspend anydrilling or production operations and we could have our sales of oilinterrupted or suspended, which could have a material adverse impact on ourfinancial condition, operations and ability to execute our business plan.

 

***We conduct offshore exploration, exploitation andproduction operations off the coast of northwest Peru, all of which are alsosubject to a variety of operating risks peculiar to the marine environment.*** Such risksinclude collisions, allisions, groundings and damage or loss from adverseweather conditions or interference from commercial fishing activities. Theseconditions can cause substantial damage to facilities, tankers and barges, aswell as interrupt operations. As a result, we could incur substantialliabilities 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 andtankers could temporarily impair our operations and delay delivery of our oilto be sold.***We depend on our deck barges BPZ-01 and BPZ-02 to act as tender supportvessels for our offshore drilling operations in our Corvina and Albacora fieldsin Block Z-1. In addition, we have two barges under capital lease to use insupport of our offshore oil production operations. One barge is used as afloating production, storage and offloading facility (“FPSO”) and the other is currently beingused as a floating storage and offloading facility (“FSO”).  In addition, we have time chartered a double hull tankvessel to transport crude oil from our offshore production and storagefacilities in Block Z-1 to the Talara refinery approximately 70 miles south ofthe platform where the oil is sold at market prices under a sales contract withthe Peruvian national oil company Petroperu. Any disruption or delay of theservices provided by our barges or tanker because of adverse weatherconditions, accidents, mechanical failures, insufficient personnel or otherevents could temporarily impair our operations, delay implementation of ourbusiness plan, and increase our costs.

 

***Future oil and natural gas declines or unsuccessfulexploration efforts may result in significant charges or a write-down of ourasset carrying values.***  We follow thesuccessful efforts method of accounting for our investments in oil and naturalgas properties.  Under this method, oil and gas lease acquisition costsand intangible drilling costs associated with exploration efforts that resultin the discovery of proved reserves and costs associated with developmentdrilling, whether or not successful, are capitalized when incurred. Certaincosts of exploratory wells are capitalized pending determinations that provedreserves have been discovered.  If proved reserves are not discovered withan exploratory well, the costs of drilling the well are expensed.

 

17

----

Table ofContents

 

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

 

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

 

***Our management team haslimited experience in the power generation business************andwe need additional funding to construct power generation and gas processingfacilities and pipelines.***Our plan of operationincludes constructing power generation and gas processing facilities andpipelines in Peru and in the future potentially in Ecuador.  However, the experience of our managementteam has been in the oil and natural gas exploration and production industryand we have limited experience in the power generation business. We areinitially relying on consultants and outside engineering and technical firms toprovide the expertise to plan and execute the power generation aspects of ourstrategy and we have not yet hired all necessary full-time employees to managethis line of business.If we do not have sufficient funds or if we are unable tosuccessfully find partners to participate in our gas-to-power project, we willneed to find alternative sources of funding for the construction of thepower generation and gas processing facilities, which may not be available whenneeded or available on favorable terms.

 

***Construction and operation of power generation andgas processing facilities and pipelines involve significant risks and delays thatcannot always be covered by insurance or contractual protections.*** Theconstruction of power generation and gas processing facilities and pipelinesinvolve many risks, including:

 

·                  supplyinterruptions;

 

·                  work stoppages;

 

·                  labor disputes;

 

·                  social unrest;

 

·                  inability tonegotiate acceptable construction, supply or other contracts;

 

·                  inability toobtain required governmental permits and approvals;

 

·                  weatherinterferences;

 

·                  unforeseenengineering, environmental and geological problems;

 

·                  unanticipatedcost overruns;

 

·                  possible delaysin the acquisition of necessary gas turbines;

 

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

 

·                  possible delaysin connection with power plant construction;

 

·                  possible delaysor difficulties in completing financing arrangements for the gas-to-powerproject; and

 

·                  possibledifficulties or delays with respect to any necessary Peruvian regulatorycompliance.

 

The ongoing construction and future operation of these facilitiesinvolve all of the risks described above, in addition to risks relating to thebreakdown or failure of equipment or processes and performances below expectedlevels of output or efficiency. We intend to maintain commercially reasonablelevels of insurance where such insurance is available and cost-effective, aswell as obtain warranties from vendors and obligate contractors to meet certainperformance levels. However, the coverage 

 

18

----

Table ofContents

 

orproceeds of any such insurance, warranties or performance guarantees may not beadequate to cover lost revenues or increased expenses. Any of these risks couldcause us to operate below expected capacity levels, which in turn could resultin lost revenues, increased expense and higher costs.

 

***The success of our gas-to-power project depends, inpart, on the existence and growth of markets for natural gas and electricity inPeru and Ecuador.*** Peru has a relatively well-developed andstable market for electricity, while the power market in Ecuador is not aswell-developed or stable. Both countries rely on hydroelectric generatingcapacity for a significant portion of their power demand. Hydroelectric plantsare much less expensive to operate than plants that utilize natural gas, butthey are subject to variable output based on rainfall and reservoir levels. Themajority of the non-hydroelectric or thermal power capacity in both countriesconsists of generating plants that utilize diesel or fuel oil, which aresignificantly more costly than natural gas at this time. Both countries havenatural gas reserves and production, but neither has a well-developed naturalgas infrastructure. Our immediate business plan relies on the continuedstability of the power market in Peru (and Ecuador for the purpose of potentialfuture gas sales to third-party power producers in Ecuador), and ourlonger-term plans depend on the further development of the electricity marketin 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 couldbe inaccurate. We are subject to the risks that:

 

·                  relatively morefavorable business conditions for hydroelectric plants, a material reduction inpower demand or other competitive issues may adversely affect the demand andprices for the electricity that we expect to produce by the time the powerplant is completed;

 

·                  our liftingcosts could exceed the minimum wholesale power prices available, making thesale of our gas uneconomical;

 

·                  potentialdisruptions or changes to regulations of the natural gas or power markets inthese countries could occur by the time our power plant is completed, or we maynot receive the necessary environmental or other permits and governmentalapprovals to operate our power plant;

 

·                  although weplan to enter into long-term contracts to sell a significant part of our futurepower production, there can be no assurance that we will be successful inobtaining such contracts or that they will be on favorable terms; and

 

·                  we will also besubject to the general commercial issues related to being in the powerbusiness, including the credit-worthiness of, and collections from futurecustomers and the ability to profitably operate our future power plants.

 

***The geographic concentration of our properties innorthwest Peru and southwest Ecuador subjects us to an increased risk of lossof revenue or curtailment of production from factors affecting that regionspecifically.*** The geographic concentration of our properties innorthwest Peru and southwest Ecuador and adjacent waters means that some or allof our properties could be affected by the same event should that region, forexample, experience:

 

·                  severe weather(such as the effects of “El Niño,” which can cause excessive rainfall andflooding in Peru and Ecuador);

 

·                  delays ordecreases in production, the availability of equipment, facilities or services;

 

·                  delays ordecreases in the availability of capacity to transport, gather or processproduction; or

 

·                  changes in thepolitical or regulatory environment.

 

Because all our properties could experience the same conditions at thesame time, these conditions could have a relatively greater impact on ourresults of operations than they might have on other operators who haveproperties over a wider geographic area.

 

***Along with the general instability that comes frominternational operations, we face political and geographical risk specific toworking in South America.*** Presently, all of our oiland gas properties are located in South America, specifically Peru and Ecuador.The success and profitability of our international operations may be adverselyaffected by risks associated with international activities, including:

 

19

----

Tableof Contents

 

·                                          economic,labor, and social conditions;

 

·                                          local andregional political instability;

 

·                                          tax laws(including host-country export, excise and income taxes and U.S. taxes onforeign operations); and

 

·                                          fluctuations inthe value of the U.S. dollar versus the local currencies in which oil and gasproducing activities may be conducted.

 

This instability in laws, expenses of operations and fluctuations inexchange rates may make our assumptions about the economic viability of our oiland gas properties incorrect. If these assumptions are incorrect, we may not beable to earn sufficient revenue to cover our costs of operations.

 

***Social andpolitical unrest in Peru could cause heightened scrutiny over oil and gasregulatory matters.***We believe there has been recent heightened scrutiny over regulatorymatters concerning oil and gas exploration and production and the award oflicensing contracts in Peru, in large part due to social and political unrest.For example, in August 2008, Peru’s Congress repealed two presidentialdecrees that made it easier for companies and individuals to buy land belongingto indigenous peoples as a result of protests from a large number of indigenouspeople in Peru’s Amazon jungle. Beginning in April 2009, thousands ofindigenous people again protested by blocking roads and waterways in easternPeru to try to force the repeal of additional decrees facilitating oilexploration, commercial farming and logging in parts of the Amazon jungle,resulting in a violent clash between police officers and the protestors in June 2009.The violence led to the suspension of several of the decrees and the PeruvianPresident’s third reshuffle of his cabinet since he came to power in 2006.

 

Peru’s next municipal and regional political electionswill be in November 2010, and the next Peruvian Presidential andCongressional election will be in April 2011. The campaigning leading upto the elections will likely cause heightened political risk and attention tovarious topics, including the regulation of oil and gas companies operating inPeru, and related environmental law compliance. As a result of these or similarevents, a shift in policy could occur with respect to the regulation of oil andgas companies making it more difficult or expensive to operate in such anenvironment.

 

***Our operations in Peru and Ecuador involvesubstantial costs and are subject to certain risks because the oil and gasindustry in Peru and Ecuador is less developed when compared to the UnitedStates.*** Because the oil and gas industry in Peru andEcuador is less developed than in the United States, our drilling anddevelopment operations in many instances will take longer to complete and maycost more than similar operations in the United States. The availability oftechnical expertise, specific equipment and supplies may be more limited orcostly in Peru and Ecuador than in the United States.  If we are unable to obtain or unable toobtain without undue cost drilling rigs, equipment, supplies or personnel, ourexploitation and exploration operations could be delayed or adversely affected,which could have a material adverse effect on our business, financial conditionor results of operations.  Furthermore,once oil and natural gas production is recovered, there are fewer ways to transportit to market for sale. Marine transportation is subject to risks such asadverse weather conditions, collisions, groundings and other risks of damage ordelay. Pipeline and trucking operations are subject to uncertainty and lack ofavailability. Oil and natural gas pipelines and truck transport travel throughmiles of territory and are subject to the risk of diversion, destruction ordelay. We expect that such factors will continue to subject our internationaloperations to economic and operating risks that companies with domestic operationsdo not experience.

 

***We are subject to numerous foreign laws andregulations of the oil and natural gas industry that can adversely affect thecost, manner or feasibility of doing business.*** Our operationsare subject to extensive foreign laws and regulations relating to theexploration for and the development, production and transportation of oil andnatural gas as well as electrical power generation.  Because the oil and gas industry in thecountries in which we operate is less developed than elsewhere, changes in lawsand interpretations of laws are more likely than in countries with a moredeveloped oil and gas industry.  Futurelaws or regulations, as well as any adverse change in the interpretation ofexisting laws or our failure to comply with existing legal requirements mayharm our results of operations and financial condition. In particular, thereare indications that the current administration in Ecuador is likely toincrease state intervention in the economy via new legislation and tighteningcontrol of areas such as energy, which could have a significant impact on ourability to operate in that country. We may be required to make large andunanticipated capital expenditures to comply with governmental regulations,such as:

 

·                  work programguarantees and other financial responsibility requirements;

 

·                  taxation;

 

20

----

Tableof Contents

 

·                  royaltyrequirements;

 

·                  customerrequirements;

 

·                  operationalreporting;

 

·                  environmentaland safety requirements; and

 

·                  unitizationrequirements.

 

Under these laws and regulations, we could be liable forpersonal injuries, property and natural resource damages, governmentalinfringements and sanctions and unitization payments.

 

***If we fail to comply with the terms of certaincontracts related to our foreign operations, we could lose our rights undereach of those contracts.*** The terms of each of ourcontracts with the government of Peru, including our Peruvian oil and gaslicense contracts require that we perform certain activities, such as seismicacquisition, processing and interpretations and the drilling of required wellsin accordance with those contracts and agreements. We are also required toconduct environmental impact assessments and establish our ability to complywith environmental regulations.  Our failureto timely perform those activities as required could result in the suspensionof our current production and sale of oil, the loss of our rights under aparticular contract and/or the loss of the amounts we have posted as a guarantyfor the performance of such activities, which would result in a significantloss to us.

 

***We are subject to the ForeignCorrupt Practices Act (the “FCPA”), and our failure to comply with the laws andregulations thereunder could result in penalties which could harm our reputationand have a material adverse effect on our business, results of operations andfinancial condition.***  We are subject to the FCPA, whichgenerally prohibits companies and their intermediaries from making improperpayments to foreign officials for the purpose of obtaining or keeping businessand/or other benefits. Since all of our oil and gas properties are in Peru andEcuador, there is a risk of potential FCPA violations.  We have a FCPApolicy and a limited compliance program designed to ensure that the Company,its employees and agents comply with the FCPA.  There is no assurance thatsuch policy or program will work effectively all of the time or protect usagainst liability under the FCPA for actions taken by our agents, employees andintermediaries with respect to our business or any businesses that weacquire.  Any violation of these laws could result in monetary penaltiesagainst us or our subsidiaries and could damage our reputation and, therefore,our ability to do business.

 

***We are subject to complex environmental regulatoryand permitting laws and regulations that can adversely affect the cost, mannerand feasibility of our planned operations.*** The exploration for, andthe development, production and sale of, oil and gas in South America are subjectto extensive environmental laws and regulations. Our ability to conductcontinued operations is subject to satisfying applicable regulatory andpermitting controls. For example, we are required to obtain an environmentalpermit or approval from the government in Peru prior to conducting seismicoperations, drilling a well or constructing a pipeline in Peruvian territory,including the waters offshore of Peru, where we intend to conduct future oiland gas operations. We are also required to comply with numerous environmentalregulations in order to continue commercial sales of oil beyond May 31,2010, the date under our current FDP to transition from exploration tocommercial production in Corvina, unless an extension is obtained.  Additionally, environmental laws andregulations promulgated in Peru impose substantial restrictions on the use ofnatural resources, interference with the natural environment, location offacilities, handling and storage of hydrocarbons, use of radioactive material,disposal of waste, emission of noise and other activities. The laws createadditional monitoring and reporting obligations in the event of any spillage orunregulated discharge of hydrocarbons. Failure to comply with these laws andregulations also may result in the suspension or termination of our planneddrilling operations and subject us to administrative, civil and criminalpenalties.

 

Our current permits and authorizations and our ability to get futurepermits and authorizations may, over time, be susceptible to increasedscrutiny, resulting in increased costs, or delays in receiving appropriateauthorizations. In particular, we may experience delays in obtaining permitsand authorizations in Peru necessary for our operations. Compliance with theselaws and regulations may increase our costs of operations, as well as furtherrestrict our foreign operations. Moreover, these laws and regulations couldchange in ways that substantially increase our costs. These laws andregulations have changed in the past and have generally imposed more stringentrequirements that increase operating costs or require capital expenditures inorder to remain in compliance. It is also possible that unanticipateddevelopments could cause us to make environmental expenditures that are significantlyhigher than those we currently anticipate, thereby increasing our overallcosts. Any failure to comply with applicable regulations could cause us tosuspend or terminate certain operations or subject 

 

21

----

Table ofContents

 

usto administrative, civil or criminal penalties. Any of these liabilities,penalties, suspensions, terminations or regulatory changes could materially adverselyaffect our financial condition and our ability to implement our plan ofoperation.

 

***Compliance with, or breach of, laws relating to thedischarge of materials into, and the protection of, the environment can becostly and could limit our operations.*** As an owner or lessee andoperator of oil and gas properties in Peru and Ecuador, we are subject tovarious national, state and local laws and regulations relating to discharge ofmaterials into, and protection of, the environment. These laws and regulationsmay, among other things, impose liability on the owner or lessee under an oiland gas lease for the cost of property damage, oil spills, discharge ofhazardous materials, remediation and clean-up resulting from operations,subject the owner or lessee to liability for pollution damages and otherenvironmental damages, and require suspension or cessation of operations inaffected areas or related sales of oil and gas.

 

We have established practices for continued compliance withenvironmental laws and regulations and we believe the costs incurred by thesepolicies and procedures so far have been necessary business costs in the oiland gas industry. However, there is no assurance that changes in or additionsto laws or regulations regarding the protection of the environment will notincrease such compliance costs, or have a material adverse effect upon ourcapital expenditures, earnings or competitive position.

 

***Our oil and gas operations involve substantialcosts and are subject to various economic risks.*** Our oil andgas operations are subject to the economic risks typically associated withexploration, development and production activities, including the necessity ofsignificant expenditures to locate and acquire producing properties and todrill exploratory wells. The cost and length of time necessary to produce anyreserves may be such that it will not be economically viable. In conductingexploration and development activities, the presence of unanticipated pressureor irregularities in formations, miscalculations or accidents may cause ourexploration, development and production activities to be unsuccessful. Inaddition, the cost and timing of drilling, completing and operating wells isoften uncertain. We also face the risk that the oil and/or gas reserves may beless than anticipated, that we will not have sufficient funds to successfullydrill on the property, that we will not be able to market the oil and/or gasdue to a lack of a market and that fluctuations in the prices of oil and/or gaswill make development of those leases uneconomical. Further, the quality of theextracted oil or gas could limit potential markets or could require expensivechemical treatment to make it marketable. This could result in a total loss of our investments made in ouroperations.

 

***Competition for oil and natural gas properties andprospects is intense; many of our competitors have larger financial, technicaland personnel resources that give them an advantage in evaluating and obtainingproperties and prospects.*** We operate in a highlycompetitive environment for reviewing prospects, acquiring properties,marketing oil and natural gas and securing trained personnel and equipment. Inaddition, changes in Peruvian government regulation have enabled multinationaland regional companies to enter the Peruvian energy market. We actively competewith other companies in our industry when acquiring new leases or oil and gasproperties. Competition in our business activities has increased and willincrease further, as existing and new participants expand their activities as aresult of these regulatory changes. Many of our competitors possess and employfinancial resources that allow them to obtain substantially greater technicaland personnel resources than we have. For example, if several companies areinterested in an area, Perupetro (a state company responsible for promoting andoverseeing the investment of hydrocarbon exploration and exploitationactivities in Peru) may choose to call for bids, either through internationalcompetitive biddings or through private bidding processes by invitation, andaward the contract to the highest bidder. These additional resources can beparticularly important in reviewing prospects and purchasing properties. Ourcompetitors may be able to evaluate, bid for and purchase a greater number ofproperties and prospects than our financial or personnel resources permit. Ourcompetitors may also be able to pay more for productive oil and natural gasproperties and exploratory prospects than we are able or willing to pay. On theacquisition opportunities made available to us, we compete with other companiesin our industry for properties operated by third parties through a privatebidding process, direct negotiations or some combination thereof. Our abilityto acquire additional prospects and to find and develop reserves in the futurewill depend on our ability to evaluate and select suitable properties and toconsummate transactions in a highly competitive environment. If we are unableto compete successfully in these areas in the future, our future revenues andgrowth may be diminished or restricted. The availability of properties foracquisition depends largely on the divesting practices of other oil and naturalgas companies, commodity prices, general economic conditions and other factorswe cannot control or influence.

 

***The loss of senior management or key technicalpersonnel could adversely affect us.*** We have engaged certainmembers of management who have substantial experience and expertise in the typeof endeavors we presently conduct and the geographical areas in which weconduct them. We do not maintain any life insurance against the loss of any ofthese individuals. To the extent their services become unavailable, we will berequired to retain other qualified personnel. There can be no assurance we willbe able to recruit and hire qualified persons upon acceptable terms.  Similarly, the oil and gas explorationindustry requires the use of personnel with substantial technical expertise. Inthe event that the services of our 

 

22

----

Table ofContents

 

currenttechnical personnel become unavailable, we will need to hire qualified personnelto take their place. No assurance can be given that we will be able to recruitand hire such persons on acceptable terms. Inability to replace lost members of management or personnel mayadversely affect us.

 

***Insurance does not cover all risks.*** Explorationfor, and production of, oil and natural gas can be hazardous, involvingunforeseen occurrences such as blowouts, cratering, fires and loss of wellcontrol, which can result in damage to or destruction of wells or productionfacilities, formations, injury to persons, loss of life, or damage to propertyor the environment. As a result, we presently maintain insurance coverage inamounts consistent with our business activities and to the extent required byour license contracts. Such coverage includes certain physical damage to theCompany’s and third parties’ property, hull and machinery, protection andindemnity, employer’s liability, comprehensive third party general liability,workers compensation and certain pollution and environmental risks. However, weare not fully insured against all risks in all aspects of our business, such aspolitical risk, civil unrest, war, business interruption, environmental damageand reservoir loss or damage. Further, no such insurance coverage can insurefor all operational or environmental risks. The occurrence of an event that isnot insured or not fully insured could result in losses to us. For example,uninsured or under insured environmental damages, property damages or damagesrelated to personal injuries could divert capital needed to implement our planof operation. If any such uninsured losses are significant, we may have tocurtail or suspend our drilling operations until such time as replacementcapital is obtained, if ever, and this could have a material adverse impact onour financial position.

 

***We may not be able to replace our reserves.*** Our futuresuccess will depend upon our ability to find, acquire and develop oil and gasreserves that are economically recoverable. Any reserves we develop willdecline as they are produced unless we are able to conduct successfulrevitalization activities, or are able to acquire properties containing provenreserves, or both. To develop reserves and achieve production, we mustimplement our development and production programs, identify and producepreviously overlooked or by-passed zones and shut-in wells, acquire additionalproperties or undertake other replacement activities. We can give no assurancethat our planned development, revitalization, and acquisition activities willresult in significant reserves replacement or that we will have success indiscovering and producing reserves at economical exploration and developmentcosts. We may not be able to locate geologically satisfactory property,particularly since we will be competing for such property with other oil andgas companies, most of which have much greater financial resources than we do.Moreover, even if desirable properties are available to us, we may not havesufficient funds with which to acquire or develop them.

 

**RisksRelating to Our Securities**

 

***Investor profits, if any, may be limited for the nearfuture.***Inthe past, we have never paid a dividend. We do not anticipate paying anydividends in the near future. Accordingly, investors in our common stock may notderive 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 ornonexistent as long as we continue to have operating losses. We have not beenprofitable and have accumulated deficits from operations totaling $241.2million through December 31, 2009. To date we have had limited revenue andno earnings from operations.  There can be no assurances that sufficientrevenue to cover total expenses can be achieved until, if at all, we fullyimplement our operational plan.

 

***Additional infusions of capital may have a dilutive effecton existing shareholders.***To finance our operations we may sell additionalshares of our common stock.  In February 2010and March 2010, we issued $170.9 million of Convertible Notes due 2015that, if converted to common stock, could potentially significantly increasethe amount of our common shares outstanding by up to approximately 23 millionshares currently. Our certificate of formation does not provide for preemptiverights. We currently have $134.6 million in common stock available under aneffective shelf registration statement, which we may sell from time to time inone or more offerings pursuant to underwritten public offerings, negotiatedtransactions, block trades or a combination of these methods prior to the December 7,2010 expiration date of our shelf registration statement.  Any additionalequity financing that we receive may involve substantial dilution to ourthen-existing shareholders. Furthermore, we may issue common stock to acquireproperties, assets, or businesses. In the event that any such shares areissued, the proportionate ownership and voting power of other shareholders willbe reduced. In addition, we are authorized to issue up to 25,000,000 shares ofpreferred stock, the rights and preferences of which may be designated by ourBoard of Directors. If we issue shares of preferred stock, such preferred stockmay have rights and preferences that are superior to those of our common stock.

 

***Our operations may not generatesufficient cash to enable us to service our debt, including the ConvertibleNotes due 2015***.  Our future cash flow may be insufficient tomeet our debt obligations and commitments. Any insufficiency could negativelyimpact our business.  A range ofeconomic, competitive, business and industry factors will affect our future 

 

23

----

Table of Contents

 

financial performance, and, as a result, our abilityto generate cash flow from operations and to pay our debt, including theConvertible Notes due 2015. Many of these factors, such as oil and gas prices,economic and financial conditions in our industry and the global economy orcompetitive initiatives of our competitors, are beyond our control.

 

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

 

·                  refinancing or restructuring our debt;

 

·                  selling assets;

 

·                  reducing or delaying capital investments; or

 

·                  seeking to raise additional capital.

 

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

 

***Shares eligible for future sale by our current shareholdersmay impair our ability to raise capital through the sale of our stock.***As of December 31, 2009, we had115,223,926 shares of common stock issued and outstanding. In addition, we haveoutstanding 4,545,332 shares of other potentially dilutive securities, whichmainly consist of options granted under our 2005 Long-Term IncentiveCompensation Plan, as amended and restated.  We also have an additional1,538,900 shares of common stock allocated under our 2007 Long-Term IncentiveCompensation Plan, as amended and restated, and our 2007 Directors’Compensation Incentive Plan. During the first quarter of 2010, we issued$170.9 million of Convertible Notes due 2015 that, if converted to commonstock, could potentially increase the amount of our common sharesoutstanding, by up to approximately 23 million shares currently. The possibility that substantial amountsof shares of our common stock may be sold in the public market may causeprevailing market prices for our common stock to decrease and thus could impairour ability to raise capital through the sale of our equity securities.

 

***Our officers,directors, entities affiliated with them and certain institutional investorsmay exercise significant control over us.***In the aggregate, our management and directors own orcontrol approximately 14.8% of our common stock, and several institutionalinvestors own approximately another 34.4% of our common stock, issued as of December 31,2009. These shareholders, if acting together and owning approximately 49.2%,will be able to significantly influence all matters requiring approval by ourshareholders, including the election of directors and the approval of mergersor other business combination transactions.

 

***Our corporate organizational documents and the provisions ofTexas law to which we are subject may delay or prevent a change in control thatsome shareholders may favor. ***Our certificate of formation and bylawscontain provisions that, either alone or in combination with the provisions ofTexas law described below, may have the effect of delaying or making it moredifficult 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 ofdirectors with each class having staggered, three-year terms.  As a result of this provision, at least twoannual meetings of shareholders may be required for the shareholders to changea majority of our board of directors.

 

·                  The board’s authority to issue shares of preferredstock without shareholder approval, which preferred stock could have voting,liquidation, dividend or other rights superior to those of our commonstock.  To the extent any such provisionsare 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 unanimouswritten consent and must comply with the provisions of our bylaws requiringadvance notification of shareholder nominations and proposals.  These provisions could have the effect ofdelaying or impeding a proxy contest for control of us.

 

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

 

24

----

Table ofContents

 

Any or all ofthese provisions could discourage tender offers or other business combinationtransactions that might otherwise result in our shareholders receiving apremium over the then current market price of our common stock.

 

***The market price and trading volume of our common stock maybe volatile. ***The market price of our common stock maybe highly volatile and subject to wide fluctuations. In addition, the tradingvolume in our common stock may fluctuate and cause significant price variationsto occur.  If the market price of ourcommon stock declines significantly, you may be unable to resell your shares ator above the price at which the shares were acquired.  We cannot assure you that the market price ofour common stock will not fluctuate or decline significantly in thefuture.  Some of the factors that couldadversely affect our share price or result in fluctuations in the price ortrading volume of our common stock include:

 

·                  actual or anticipated fluctuations in our results ofoperations;

 

·                  failure to be covered by securities analysts, orfailure by us to meet securities analysts’ expectations;

 

·                  success of our operating strategies;

 

·                  decline in the stock price of companies that are ourpeers;

 

·                  realization of any of the risks described in thissection; or

 

·                  general market and economic conditions.

 

Because we are arelatively new public company, these fluctuations may be more significant forus than they would be for a company whose stock has been publicly traded overan extended period of time.

 

In addition, thestock market has in the past, and may in the future, experience extreme priceand volume fluctuations. These market fluctuations may materially and adverselyaffect the trading price of our common stock, regardless of our actualoperating performance.

 

**ITEM 1B.  UNRESOLVED STAFFCOMMENTS**

 

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

 

In connection with a registration statement filed on October 21,2009 to register shares issued to IFC in a private transaction, we havereceived comments from the SEC pertaining to our registration statement, our Form 10-Kfor the year ended December 31, 2008, our Definitive Proxy Statement filedon April 30, 2009, and our Form 10-Q for the period ended September 30,2009 and the related earnings press release. In general, the pending questionsor comments from the SEC relate to: (i) clarifications in several of ourdisclosures; (ii)  the basis for the assumptions underlying our SEC oilreserves reported for 2008 in light of our actual production performance in2009; (iii) the reasons our 2009 production fell short of 2008projections; (iv) the consideration we gave to the reasonable certainty ofour assumptions underlying our SEC oil reserves and the related accountingreported in our financial statements; and (v) how we are takinginto consideration certain items and uncertainties for our 2009 reservesreport. We havepromptly responded to the SEC’s requests and are currently waiting on requestsfor additional information, if any. In addition, where appropriate, we haveproposed clarifications to our disclosures, none of which we believe arematerial in light of all of the disclosures and risk factors provided in ourpublic filings to date. The SEC is currently reviewing our responses, and couldask additional questions or request additional revisions to our filings, someof which could be material. In particular, the process of estimating oil andnatural gas reserves is complex, requiring interpretations of availabletechnical data and many assumptions, including assumptions relating to economicfactors, and therefore are inherently imprecise. In its review of our responsesand reserve data provided to them, the SEC could disagree with our independentpetroleum engineer’s reserve estimates, including the underlyinginterpretations and assumptions or the reasonable certainty of our assumptions,and request a revision to our estimates of proved reserves and the relatedaccounting of the reserves in our financial statements. In addition, results ofactual future production will depend on expected production levels that mightnot be achieved, oil and natural gas prices, drilling and operating expenses,capital expenditures, taxes and availability of funds, which will most likelyvary from our estimates, and those variances may be material.

 

25

----

Table of Contents

 

**ITEM 2.   PROPERTIES**

 

**Offices**

 

Ourcorporate headquarters office is in Houston, Texas, where we lease approximately20,400 square feet of office space under a lease agreement which expires in February 2016.We sublease approximately 4,400 square feet of our office space to a tenantunder a sublease agreement which expires in December 2012. We also currentlylease four administrative offices and a warehouse in Peru of approximately12,100 square feet and 68,000 square feet, respectively. The currentadministrative offices in Lima, Peru and a warehouse in Piura, Peru are undermonth-to-month leasing arrangements until we are ready to move into our newconsolidated administrative offices in Lima, Peru and new warehouse located inCaleta Cruz which is near our operations in Tumbes, Peru. The newadministrative office and warehouse leased areas are approximately 22,500square feet and 101,300 square feet, respectively, and both leases expire in December 2013.Additionally, we lease an administrative office in Quito, Ecuador of 829 squarefeet under a month-to-month lease.

 

**Properties in Peru**

** **

** **

** **

We currently have exclusive rights to fourproperties in northwest Peru. We have a 100% working interest in licensecontracts for Block Z-1, Block XIX, Block XXII and Block XXIII. The licensecontracts afford an initial exploration phase of seven years.  As described below, each license contractprovides for additional exploration periods which can extend the explorationphase of the license contract.  Ifexploration efforts are successful, the license contracts term can extend up to30 years for oil exploration and production and up to 40 years for gasexploration and production.  In the event a block contains 

 

26

----

Table ofContents

 

both oil and gas, as is thecase in the Block Z-1 contract, the 40 year term may apply to oil explorationand production as well. These four blocks cover a combined area ofapproximately 2.2 million acres.

 

The following table is a summary of our propertiesin northwest Peru. As of December 31, 2009 only acreage in Block Z-1 hasbeen partially developed.

 
| **PROPERTY** | ** ** | **BASIN**       | ** ** | **BPZ’S  OWNERSHIP** | ** ** | **LICENSE  CONTRACT  SIGNED** | ** ** | **UNDEVELOPED  ACRES** | ** ** | **DEVELOPED  ACRES** | ** ** | **PRODUCTIVE  WELLS (1)** | ** ** |
|--------------|------------|-----------------|------------|---------------------------|------------|-------------------------------|------------|------------------------|------------|----------------------|------------|---------------------------|------------|
| ** **   | ** ** | ** **      | ** ** | ** **                | ** ** | ** **                    | ** ** | ** **             | ** ** | ** **           | ** ** | ** **                | ** ** |
| Block Z-1    |       | Tumbes/Talara   |       | 100                       | %          | November 2001            |       | 554,300                |       | 700                  |       | 7                         |       |
| Block XIX    |       | Tumbes/Talara   |       | 100                       | %          | December 2003            |       | 473,000                |       |                 |       |                      |       |
| Block XXII   |       | Lancones/Talara |       | 100                       | %          | November 2007            |       | 912,000                |       |                 |       |                      |       |
| Block XXIII  |       | Tumbes/Talara   |       | 100                       | %          | November 2007            |       | 230,000                |       |                 |       |                      |       |
| Total        |       |            |       |                      |       |                          |       | 2,169,300              |       | 700                  |       | 7                         |       |

 

----

**(1)****                                **Does notinclude the****CX11-16X well which testedquantities of gas which we believe to be of commercial amounts and is currentlyshut-in. Until such time as sufficient funding has been secured and thenecessary infrastructure is in place for our gas-to power project, we cannotinclude any of these reserves as part of our SEC reserves nor include the well(s) asproductive.

 

**Description of Block Z-1 and License Contract**

 

Block Z-1, a coastal offshore area encompassingapproximately 555,000 acres, is situated at the southern end of the Gulf ofGuayaquil in northwest Peru. Geologically, the block lies within the TumbesBasin. From the coastline, water depths increase gradually. The average waterdepth of the area is approximately 200 feet and approximately 10% of the areahas depths ranging from 500 feet up to 1,000 feet. Located within Block Z-1 arefive structures which were drilled in the 1970s and 1980s by previousoperators, including Tenneco, Inc. and Belco Oil and Gas Corporation (“Belco”).These structures are known as the Albacora, Barracuda, Corvina, Delfin andPiedra Redonda fields. Wells drilled in each of these structures tested positive for oil or gas in what we believe to be economicquantities 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 produceand sell natural gas from the fields. Consequently, the wells were eithersuspended or abandoned.

 

In the Corvina field, five wells were drilled,including two wells drilled by Tenneco in the mid-1970s and three wells drilledby Belco in the late 1970s and early 1980s. Two drilling and productionplatforms were set up by Belco during this period and are still in place in theCorvina field.  The first platform islocated in the East Corvina prospect field and we need to conduct anengineering study to determine the viability of repairing and refurbishing theplatform or building a new platform prior to initiating any drilling activitiesin this section of the Corvina field. The second platform, CX-11, is located inthe West Corvina development field and, after repairs and refurbishment, iscurrently being used in our West Corvina drilling and productionactivities.  All five of the previouslydrilled wells in the Corvina field encountered indications of natural gas andapparent reservoir-quality formations, although only one of the wells, theCX11-16X, was completed and tested. At the time these wells were drilled, therewas no commercial market for natural gas in the region. The CX11-16X ,whentested by Belco, produced natural gas at rates as high as 16.6 millioncubic feet of gas per day during two separate tests over a period ofapproximately 20 days each. Following these tests, the well was shut-in.In June 2007, we successfully recompleted the CX11-16X well as a naturalgas producing well and completed a total of four drill stem tests on variouszones in the well including one in a formation previously untested in theentire basin. The tests produced quantities of gas we believe to be incommercial amounts.  The CX11-16X wellremains shut-in pending development of our planned gas-to-power project.

 

In the Albacora field, three wells were drilled andproduced oil for a very limited time. The original drilling andproduction platform set up by Belco during this period is still in place in theAlbacora field and has been repaired and refurbished by us. The Albacora field is located in thenorthern part of our offshore Block Z-1.  It consists of approximately7,500 acres and is located in water depths of less than 200 feet.

 

In the Piedra Redonda field, two wells were drilledby Belco in the late 1970s and early 1980s. Indications of natural gas werepresent in both wells. One well was completed, while the other well encounteredabnormally high pressures and was abandoned for mechanical reasons prior toreaching its intended total depth. The completed well in the Piedra Redondafield, the C18X, when tested by Belco, produced natural gas at rates as high as8.3 MMcfe per day over a period of approximately 20 days during anextended test in 1979 and was also shut-in.

 

27

----

Table of Contents

 

We originally acquired our initial interest in BlockZ-1 in a joint venture with Syntroleum Peru Holdings Limited, sucursal delPeru, under an exploration and production license contract dated November 30,2001, with an effective date of January 29, 2002. Under the originalcontract, BPZ owned a 5% non-operating working interest, along with the rightof first refusal, in the block. Syntroleum later transferred its interest toNuevo 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% workinginterest, as well as the remaining obligations under the contract. Perupetroapproved the assumption of Nuevo’s interest by BPZ and the designation of BPZas a qualified operator under the contract in November 2004. This actionwas subject to official ratification and issuance of a Supreme Decree by thegovernment of Peru, which was issued in February 2005. Accordingly, anamended contract was signed with Perupetro, naming BPZ as the owner of 100% ofthe participation under the license contract.

 

The license contract provides for an initialexploration phase of seven years, and can be extended under certaincircumstances an additional six years up to thirteen years. Each period has acommitment for exploration activities and requires a financial guarantee tosecure the performance of the work commitment during such period. Block Z-1 iscurrently in the fourth exploration period. This period was initially scheduledto expire in November 2010.  However, due to receiving a statementfrom the Ministry of Energy and Mines to suspend our seismic data survey, thefourth period is currently under suspension until our revised EnvironmentalImpact Study is approved by the DGAAE (“Dirección General de AsuntosAmbientales y Energéticos”), a division of the Ministry of Energy and Mines,who is responsible for environmental protection matters in Peru. The fourth andfinal exploration period requires the drilling of an additional exploratorywell or other equivalent work commitments, such as conducting a seismic datasurvey.  A performance bond of $1.0million was posted for cash collateral of $1.0 million related to the fourthexploration period. The performance bond will be released at the end of theexploration period if the work commitment for that period has been satisfied.In addition, we are required to make technology transfer payments related totraining costs of Perupetro professional staff during the exploration phase of$50,000 per year.

 

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

 

On November 21, 2007,we submitted a letter to Perupetro declaring a commercial discovery in theBlock Z-1 field.  On May 19, 2008 wefiled the field development plan with Perupetro.  The commercialdevelopment period of the Corvina field will commence on May 31,2010.  In December 2009 Perupetro approved our proposed FDCP as set forthin the current FDP for our Corvina field. The FDP sets May 31, 2010 as thedate to transition from exploration to commercial production in the Corvinafield.   Accordingly, on or before the FDCP we will be required tohave installed and commissioned any equipment needed to process and transportall produced fluids, including reinjection facilities for any formation waterand unused associated gas produced with the crude oil, unless an extension isobtained.  Under the contract, oil exploration, developmentand production can continue for a total of up to 30 years from the effectivedate of the contract, and gas exploration, development and production cancontinue for up to 40 years. In the event a block contains both oil and gas, as is the case in theBlock Z-1 contract, the 40 year term may apply to oil exploration andproduction as well. Royalties under the contract vary from 5% to 20%based on production volumes. Royalties start at 5% if and when production isless than 5,000 boepd and are capped at 20% if and when production surpasses100,000 boepd.

 

Afterthe third exploration period, we relinquished 25% of the least prospectiveacreage as stipulated under the terms of the Block Z-1 License Contract as wetransitioned into the fourth exploration phase under the licensecontract.  None of the mapped prospects identified by us were includedwithin the acreage relinquished.  At the end of the fourth explorationphase, we may keep the remaining contract area, provided we commit to certainexploration commitments every two years, for a maximum additional period of upto six years.  If we decide not to continue this minimum work program, wewill only be allowed to keep the fields discovered and the surrounding fivekilometer areas for the remainder of the contract life.

 

**Description of Block XIX and License Contract**

 

Block XIX covers approximately 473,000 acres, lyingentirely onshore and adjacent to Block Z-1 in northwest Peru. Geologically, theblock lies primarily within the Tumbes Basin of Oligocene-Neogene age, but alsocovers part of the Talara Basin to the south. Several older wells showed evidence of gas potential in the Mancoraformation as well as oil shows from the Heath Formation.  The sections of the Tumbes and Talara Basinsin Block XIX are primarily exploratory areas and have had limited drilling andseismic activity.  However, the Mancoraformation is expected to continue from offshore in Block Z-1 in Piedra Redondathrough Block XXIII, also under license to us, and into Block XIX, an areawhich spans approximately fifty miles.

 

28

----

Table of Contents

 

In February 2003, we entered into a TechnicalEvaluation Agreement with Perupetro for Block XIX. In December 2003, wesigned a license contract whereby we acquired a 100% interest in Block XIX. Theterm for the exploration period is seven years and can be extended undercertain circumstances for an additional period of up to four years. If acommercial discovery is made during the exploration period, the contract willallow for the exploration and production of oil for a period of 30 years fromthe effective date of the contract and the exploration and production of gasfor a period of 40 years. In the event a block contains both oil and gas, the 40 year term may applyto oil exploration and production as well. Royalties under the contractvary from 5% to 20% based on production volumes. Royalties start at 5% if andwhen production is less than 5,000 boepd and are capped at 20% if and whenproduction surpasses 100,000 boepd.

 

The seven year exploration phase is divided intofive periods of 18 months, 24 months, 15 months, 15 months and 12 months,respectively. We are currently in the third exploration period, which wasscheduled to end in September of 2010. However, due to the fact theauthorization for access is still in process by DGH, last February weasked Perupetro to declare force majeure.  Once approved by Perupetro, the thirdexploration period requires us to drill and test one well or perform otherequivalent work commitments.  Once we complete the third explorationperiod we will reestablish timelines for the remaining exploration periods.  In connection with the third exploration period, weposted a $585,000 performance bond for $292,500 in cash collateral. The fourthexploration period will require a performance bond of $585,000. The fifth andfinal exploration period is scheduled to begin in December 2011 and willrequire a performance bond of $585,000. The performance bond amounts are notcumulative, and will be released at the end of each exploration period if thework commitment for that period has been satisfied. In addition, we are requiredto make technology transfer payments related to training costs of Perupetroprofessional staff during the exploration phase in the amount of $5,000 peryear. We must declare a commercial discovery no later than the end of the lastexploration period, including any extensions or deferments.

 

Under the terms of theBlock XIX License Contract, we are required to relinquish 20% of the leastprospective licensed acreage by the end of the fourth exploration period. Accordingly, we intend to retain the most prospective acreage identified. At the end of the exploration phase, we may keep the remainder of the contractarea, provided we commit to purse and implement an additional work programevery two years, up to a maximum of four years.   If we decide not tocontinue this minimum work program, we will only be allowed to keep the areaover the fields discovered, plus a technical security zone around suchdiscoveries.

 

**Description of Block XXII and License Contract**

 

On November 21, 2007, we signed a licensecontract whereby we acquired a 100% interest in Block XXII.  Block XXII is located onshore in northwestPeru within the Lancones Basin of Cretaceous—Upper Eocene Age and covers anarea of approximately 912,000 acres. The Lancones Basin is primarily an exploratoryarea and has had limited drilling and seismic activity.  The southern sector of this block also coversthe productive Talara basin of northwest Peru, near the Talara Refinery.  The exploration period of the licensecontract extends over a seven year period divided into five periods or fourperiods of 18 months and a final period of 12 months.  Under certain circumstances, the explorationperiods may be extended for an additional period of up to three years.  We are in the first exploration period which was originally scheduled to expirein July 2009.  However, since our Environmental Impact Study tookseveral months to be approved, the first exploration period time limit was onsuspension until such approval was obtained from the DGAAE. We obtained theapproval in March 2011 which extended the first exploration period up to September 2010.The first exploration period requires that we acquire, process andinterpret 260 kms of two dimensional (“2-D”) seismic data and prepare acomprehensive geological and engineering study for the area. In each subsequentperiod after the first 18 month period we are required to drill an exploratorywell or perform other equivalent work commitments.  If a commercial discovery is made during theexploration period, the contract will allow for the exploration and productionof oil for a period of 30 years from the effective date of the contract and theexploration and production of gas for a period of 40 years. In the event a block contains both oiland gas, the 40 year term may apply to oil exploration and production as well. Royalties underthe contract vary from 15% to 30% based on production volumes.  Royalties start at 15% if and when productionis less than 5,000 boepd and are capped at 30% if and when production surpasses100,000 boepd.

 

In connection with the first exploration period, wewere required to obtain a cash collateralized $600,000 bond for cash collateralin the amount of $300,000. The performance bond amounts are not cumulative, andwill be released at the end of each exploration period if the work commitmentfor that period has been satisfied.

 

Under the Blocks XXIILicense Contract, we are required to relinquish at least 20% of the leastprospective original agreement area at the end of the third period and at leastanother 30% of the original agreement area at the end of the fourth period suchthat at the end of the fourth period, we will have released 50% of the originalagreement area. Accordingly, we 

 

29

----

Table of Contents

 

intend to retain the mostprospective acreage identified.  The contract does not call for anyadditional relinquishment of acreage within the contract area and we may retainthe remaining un-relinquished area for the remainder of the contract lifeprovided we continue executing a minimum work program as defined under thelicense contract.  If we decide not to continue this minimum work program,we will only be allowed to keep the fields discovered and the surrounding fivekilometer areas for the remainder of the contract life.

 

**Description of Block XXIII and License Contract**

 

On November 21, 2007, we signed a licensecontract whereby we acquired a 100% interest in Block XXIII, which consists ofapproximately 230,000 acres and is located onshore in northwest Peru betweenBlocks Z-1 and XIX.  This block islocated in the Tumbes basin, although in its southern section Talara Basinsediments may be found deeper.  Thesections of the Tumbes and Talara Basins in Block XXIII are primarilyexploratory areas and have had limited drilling and seismic activity.  The exploration period of the licensecontract extends over a seven year period divided in to two periods of 18 monthsand two periods of 24 months.  We are inthe first exploration period which was originally scheduled to expire in July 2009. However, since our Environmental Impact Study is still pending approval fromDGAAE, the first exploration period time limit is on suspension until suchapproval is obtained. Once we complete the first exploration period we willreestablish timelines for the remaining exploration periods. The firstexploration period requires that we acquire, process and interpret 360 kms of threedimensional (“3-D”) seismic data and 290 kms of 2-D seismic data and prepare anintegrated geological, geochemical and reservoir engineering evaluation of thehydrocarbon prospects in the block.  Ineach subsequent period after the first exploration period, we will be required to drill a certain number of wells and/oracquire certain amount of either 2-D or 3-D seismic data. If a commercialdiscovery is made during the exploration period, the contract will allow forthe exploration and production of oil for a period of 30 years from theeffective date of the contract and the exploration and production of gas for aperiod of 40 years. Inthe event a block contains both oil and gas, the 40 year term may apply to oilexploration and production as well. Royalties under the contractvary from 15% to 30% based on production volumes.  Royalties start at 15% if and when productionis less than 5,000 boepd and are capped at 30% if and when production surpasses100,000 boepd.

 

In connection with the first exploration period, wewere required to obtain performance bond of $3,075,000 bond for $1,537,500 in cash collateral. Theperformance bond amounts are not cumulative, and will be released at the end ofeach exploration period if the work commitment for that period has beensatisfied.

 

Underthe Blocks XXIII License Contract, we are required to relinquish 20% of theleast prospective original agreement area at the end of the third period and atleast another 30% of the original agreement area at the end of the fourth periodsuch that at the end of the fourth period, we will have released 50% of theoriginal agreement area. Accordingly, we intend to retain the most prospectiveacreage identified.  The contract does not call for any additionalrelinquishment of acreage within the contract area and we may retain theremaining un-relinquished area for the remainder of the contract life providedwe continue executing an exploration work program as defined under the licensecontract.  If we decide not to continue this exploration work program, wewill only be allowed to keep the fields discovered and the surrounding fivekilometer areas for the remainder of the contract life.

 

**Proved Reserves**

 

Our estimated proved oil reserve quantities wereprepared by Netherland, Sewell & Associates, Inc. (“NSAI”),independent petroleum engineers.  NSAIwas chosen based on their knowledge and experience of the region in which weoperate.  Numerous uncertainties arise inestimating quantities of proved reserves and projecting future rates ofproduction and the timing of development expenditures.  These uncertainties are greater forproperties which are undeveloped or have a limited production history, such asour properties in Northern Peru.  Ouractual reserves, future rates of production and timing of developmentexpenditures may vary substantially from these estimates.  See Item 1A “Risk Factors, “ *Our reserve estimates depend on many assumptions that may turn out tobe inaccurate*” and , “*We have received commentsfrom the SEC to our most recent annual report, quarterly report and proxystatement that are still pending and that may not be resolved in our favor*”for further information.   All of ourproved reserves are in the Corvina and Albacora fields.  Our net quantities of proved developed andundeveloped reserves of crude oil and standardized measure of future net cashflows are reflected in the table below. See further information about the basis of presentation of these amountsin “Supplemental Oil and Gas Disclosures (Unaudited)” to our consolidatedfinancial statements provided herein.

 

As of December 31, 2009, we owned a 100%working interest in the Corvina and Albacora fields, subject to Peruviangovernment royalties of 5% to 20% net revenue interest depending on the levelof production.  The effect of theseroyalty interest payments is reflected in the calculation of our net provedreserves.  Our estimate of provedreserves have been prepared under the assumption that our license contract willallow production for the possible 40-year term for both oil and gas, as morefully discussed under “Description of Block Z-1” above.

 

30

----

Table of Contents

 

**Net Proved Crude Oil Reserves andFuture Net Cash Flows**

**As of December 31, 2009**

**Based on Average Fiscal-YearPrices**

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

 

These estimates are basedupon a reserve report prepared by NSAI, independent petroleum engineers.NSAI used internally developed reserve estimates and criteria incompliance with the SEC guidelines based on data provided by us.  See Item 7. “Management’s Discussion andAnalysis of Financial Condition and Results of Operations - Critical AccountingPolicies and Estimates” and “Supplemental Oil and GasDisclosures.”  NSAI’s report is attached as Exhibit 99.1 to thisForm 10-K.

 

The reserve volumes andvalues were determined under the method prescribed by the SEC, which for 2009requires the use of an average price, calculated as the twelve-month first dayof the month historical average price for the twelve-month period prior to theend of the reporting period, unless prices are defined by contractualarrangements, excluding escalations based upon futureconditions.  For years prior to 2009, the SEC rules required theuse of year-end prices.

 

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

 

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

 

**Qualifications of Technical Persons and Internal Controls Over ReservesEstimation Process**

 

Our policies regardinginternal controls over the recording of reserves estimates requires reserves tobe in compliance with the SEC definitions and guidance and prepared inaccordance with generally accepted petroleum engineering principles.

 

Our Chief OperatingOfficer is responsible for compliance in reserves bookings and utilizes the reservesestimates made by our third party reserve consultant, NSAI for the preparationof our reserve report. Our Chief Operating Officer is a petroleum engineer withover 20 years operating experience in international oil and gas projects.  He holds an Advanced Degree in Mathematicsfrom Ecole Centrale de Paris, France, a Master’s Degree and Ph.D. in PetroleumEngineering from Texas A&M University, as well as an MBA from theUniversity of Colorado.

 

The technical personnelresponsible for preparing the reserves estimates at NSAI meet the requirementsregarding qualifications, independence, objectivity, and confidentiality setforth in the Standards Pertaining to the Estimating and Auditing of Oil and GasReserves Information promulgated by the Society of PetroleumEngineers.  NSAI is an independent firm of petroleum engineers,geologists, geophysicists, and petrophysicists; it does not own an interest inour properties and is 

 

31

----

Table of Contents

 

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

 

**Reserve Technologies**

 

The SEC’s new rules expanded the technologiesthat a company can use to establish reserves. The SEC now allows use oftechniques that have been proved effective by actual production from projectsin the same reservoir or an analogous reservoir or by other evidence usingreliable technology that establishes reasonable certainty. Reliable technologyis a grouping of one or more technologies (including computational methods)that has been field tested and has been demonstrated to provide reasonablycertain results with consistency and repeatability in the formation beingevaluated or in an analogous formation. We used a combination of production andpressure performance, wireline wellbore measurements, analytical and simulationstudies, offset analogies, seismic data and interpretation, geological data,interpretation, and modeling, wireline formation tests, geophysical logs andcore data, and laboratory fluid studies to calculate our reserves estimates,including the material additions to the 2009 reserves estimates.

 

**Development of Proved Reserves**

 

As of December 31,2009, we had proved reserves of 37.5 MMBbls, an increase of 20.3 MMBblsrelative to December 31, 2008 of proved reserves of 17.2MMBbls.  Additions to proved developed non-producing reserves were5.6 MMBbls at December 31, 2009. There were no proved developed non-producing wells at December 31,2008.  Additions to proved undevelopedreserves of 14.6 MMBbls resulted primarily from additional proved undevelopedlocations in our Corvina field of 10.3 MMBbls, or 23.2 MMBbls total, and to alesser extent to our Albacora field of approximately 4.3 MMBbls.

 

**Production, Average Sales Price and Production Costs**.

 

Thefollowing table presents our production, average realized sales prices andaverage production costs for the indicated periods.

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

 

----

| (1)               We inventory our oil that has not been  sold. Therefore, per unit costs, after allocating operating costs to  inventory, are based on sales volume. |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|                                                                                                                                                                                                                                        |
| (2)               Production costs includes the oil  operating, workover and repair costs.                                                                            |

 

**Acreage**

 

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

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

 

32

----

Table of Contents

 

**Drilling Activity**

 

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

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

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

 

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

 

In the first quarter of2010, we drilled and tested the CX11-17D well in the Corvina field.  The development well was drilled to a totaldepth 9,830 feet.

 

**Present Activities**

 

***Corvina Field***

 

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

 

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

 

Additionally, in February of2010, the CX11-17D well, our seventh oil well in the Corvina field, wassuccessfully completed and placed into production with normal gas-oil-ratio andno formation water.  We first tested aset of lower sands that had not been tested before in prior wells before addingthe second set of sands, thus allowing us to gather data to continue updatingthe Corvina geologic and reservoir models. While all wells decline over time, it is too early to model the declinerate in the Corvina field as we are still collecting data to determine thefield’s drive mechanism.

 

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

 

***Albacora******Field***

 

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

 

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

 

33

----

Table of Contents

 

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

 

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

 

Additionally, while preparing to drill the A-16D well, we learned thatone of the main beams of the upper platform deck was bent. It appears that thedamage occurred during the drilling of the A-15D well. We are investigatingthis incident to confirm our initial assessment of the cause and structuralintegrity of the platform. At present, structural engineers are evaluating theoverall condition of the platform to insure its structural integrity. Initialestimates to complete repairs are two weeks. On completion of all repairs wewill begin drilling the A-16D well.

 

***Marine Operations***

 

Subsequent to December 31,2009, we have upgraded our oil transportation capabilities by time chartering adouble-hull tanker with a capacity of approximately 65,000 barrels.  This vessel should allow us to optimizedelivery of our oil to the Talara refinery. We have also leased a storage vessel with capacity of approximately160,000 barrels and plan to place it near the Albacora platform.  The additional transportation and storagecapacity should provide needed operational flexibility to minimize future oilproduction restrictions due to possible delays at the Talara refinery’sterminal caused by high tanker traffic or adverse sea conditions.

 

**Property in Ecuador**

 

Through our wholly-owned subsidiary, SMCEcuador Inc., a Delaware corporation, and its registered branch inEcuador, we also own a 10% non-operated working interest in an oil and gasproducing property, Block 2, located in the southwest region of Ecuador (the “SantaElena Property”). The Santa Elena Property is located west of the city ofGuayaquil along the coast of Ecuador. The license contract provides for royaltypayments equal to 23% of production. There have been almost 3,000 wells drilledin the field since production began in the 1920s. There are approximately 1,450active wells which produce approximately 1,400 barrels of oil per day. Themajority of the wells produce intermittently by gas lift, mechanical pump orswabbing techniques. Crude oil is gathered in holding tanks and pumped viapipeline to an oil refinery in the city of Libertad, Ecuador. The licenseagreement covering the property extends through May 2016.

 

**ITEM 3. LEGAL PROCEEDINGS**

** **

*Navy Tanker Litigation*

 

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

 

**ITEM 4. RESERVED**

 

34

----

Table of Contents

 

**PART II**

 

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

 

**Market Information**

 

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

 

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

 

The following table sets forth, for the periodsindicated, the high and low prices of a share of our Common Stock as reportedon the NYSE, NYSE Amex , NYSE Alternext U.S., and AMEX for the applicable timeperiods.

 
| ** **      | ** ** | **High**   | ** ** | **Low**    | ** ** |
|-----------------|------------|------------|------------|------------|------------|
| **2009**        |       |       |       |       |       |
| Fourth  quarter |       | $          | 9.98       |       | $          | 6.05 |   |
| Third  quarter  |       | 8.07       |       | 4.52       |       |
| Second  quarter |       | 7.65       |       | 3.60       |       |
| First  quarter  |       | 9.18       |       | 2.25       |       |
| ** **      | ** ** | ** ** | ** ** | ** ** | ** ** |
| **2008**        |       |       |       |       |       |
| Fourth  quarter |       | $          | 17.39      |       | $          | 3.95 |   |
| Third  quarter  |       | 29.88      |       | 12.00      |       |
| Second  quarter |       | 29.52      |       | 17.20      |       |
| First  quarter  |       | 23.20      |       | 10.51      |       |

 

**Holders**

 

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

 

**Wecurrently intend to retain all future earnings to fund the development andgrowth of our business.  We have neverpaid cash or other dividends on our stock. For the foreseeable future, we intend to retain earnings, if any, tomeet our working capital requirements and to finance future operations.Accordingly, we do not plan to declare or distribute cash dividends to theholders of our Common Stock in the foreseeable future.  As of the date of this filing, we have notrepurchased any of our equity securities and have not adopted a stockrepurchase program.**

 

**RecentSales of Unregistered Securities**

 

The information on our recent salesof unregistered securities has been previously reported in the followingreports filed with the SEC:

 

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

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

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

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

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

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

 

35

----

Table of Contents

 

**Performance Graph**

 

The following graph compares the cumulative totalshareholder return for the Company’s Common Stock to that of (i) theRussell 2000 Stock Index, and (ii) a Company peer group of fiveindependent oil and gas exploration companies selected by us, for the periodindicated as prescribed by the SEC’s rules. The companies in our selected peergroup are Toreador Resources Corp., Contango Oil & Gas, Co, HarvestNatural Resources, Inc., Far East Energy Corp, and Carrizo Oil &Co Inc.  “Cumulative total return” isdefined as the change in share price during the measurement period, pluscumulative dividends for the measurement period (assuming dividendreinvestment), divided by the share price at the beginning of the measurementperiod. The graph assumes $100 was invested on January 1, 2004 in ourCommon Stock, the Russell 2000 Stock Index and a Company peer group.

 

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

 

36

----

Table of Contents

 

**ITEM 6.  SELECTED FINANCIAL DATA**

 

Thefollowing selected financial information should be read in conjunction with “Management’sDiscussion and Analysis of Financial Condition and Results of Operation” andthe consolidated financial statements and the notes thereto included under Item8. — “FinancialStatements and Supplementary Data”.

 
| ** **                                                       | ** ** | **For the Year Ended December 31,**                                            | ** ** |
|------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------|------------|
| ** **                                                       | ** ** | **2009**                                                                                                | ** ** | **2008** | ** ** | **2007 (Restated)  (1)** | ** ** | **2006 (Restated)  (1)** | ** ** | **2005 (Restated)  (1)** | ** ** |
| ** **                                                       | ** ** | **(In thousands, except per share and per barrel information)** | ** ** |
| **Operating  Results:**                                          |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Revenue (net)                                                    |       | $                                                                                                       | 52,454     |   | $ | 62,955 |   | $ | 2,350 |   | $ | — |   | $ | — |   |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Operating and administrative expenses:                           |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Lease operating expense                                          |       | 28,113                                                                                                  |       | 11,649 |   | 755 |   | — |   | — |   |
| General and administrative expense                               |       | 33,258                                                                                                  |       | 42,094 |   | 18,548 |   | 11,532 |   | 5,805 |   |
| Geological, geophysical and engineering expense                  |       | 7,768                                                                                                   |       | 794 |   | 4,045 |   | 2,048 |   | 998 |   |
| Depreciation, depletion and amortization expense                 |       | 25,803                                                                                                  |       | 16,062 |   | 793 |   | 214 |   | 30 |   |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Total operating expenses                                         |       | 94,942                                                                                                  |       | 70,599 |   | 24,141 |   | 13,794 |   | 6,833 |   |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Operating loss                                                   |       | (42,488                                                                                                 | )          | (7,644 | ) | (21,791 | ) | (13,794 | ) | (6,833 | ) |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Other income (expense):                                          |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Income from investment in Ecuador property, net of  amortization |       | 1,208                                                                                                   |       | 718 |   | 264 |   | 1,403 |   | 469 |   |
| Interest expense                                                 |       | —                                                                                                  |       | — |   | — |   | (16 | ) | (11 | ) |
| Amortization of deferred financing costs                         |       | —                                                                                                  |       | — |   | — |   | — |   | (68 | ) |
| Registration delay expense                                       |       | —                                                                                                  |       | — |   | — |   | (3,553 | ) | (516 | ) |
| Interest income                                                  |       | 215                                                                                                     |       | 319 |   | 855 |   | 787 |   | 510 |   |
| Miscellaneous income (expense)                                   |       | (1,312                                                                                                  | )          | 102 |   | 201 |   | (314 | ) | 42 |   |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Total other income (expense)                                     |       | 111                                                                                                     |       | 1,139 |   | 1,320 |   | (1,693 | ) | 426 |   |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Loss before income taxes                                         |       | (42,377                                                                                                 | )          | (6,505 | ) | (20,471 | ) | (15,487 | ) | (6,407 | ) |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Income taxes (benefit)                                           |       | (6,575                                                                                                  | )          | 3,141 |   | 39 |   | — |   | — |   |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Net loss                                                         |       | $                                                                                                       | (35,802    | ) | $ | (9,646 | ) | $ | (20,510 | ) | $ | (15,487 | ) | $ | (6,407 | ) |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Basic and diluted net loss per share                             |       | $                                                                                                       | (0.35      | ) | $ | (0.12 | ) | $ | (0.33 | ) | $ | (0.35 | ) | $ | (0.23 | ) |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Weighted average common shares outstanding                       |       | 103,362                                                                                                 |       | 77,390 |   | 61,660 |   | 44,752 |   | 27,399 |   |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Oil sales price per barrel, net                                  |       | $                                                                                                       | 54.49      |   | $ | 76.23 |   | $ | 81.78 |   | $ | — |   | $ | — |   |
| Operating cost per barrel                                        |       | $                                                                                                       | 29.21      |   | $ | 14.11 |   | $ | 26.26 |   | $ | — |   | $ | — |   |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| **Balance Sheet Data:**                                          |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Working Capital/(Defecit)                                        |       | $                                                                                                       | 7,385      |   | $ | (30,562 | ) | $ | 1,549 |   | $ | 22,057 |   | $ | 29,036 |   |
| Property, equipment and construction in progress,  net           |       | 262,517                                                                                                 |       | 193,934 |   | 100,366 |   | 38,727 |   | 4,365 |   |
| Total assets                                                     |       | 349,172                                                                                                 |       | 235,365 |   | 129,619 |   | 74,037 |   | 38,091 |   |
| Total long-term debt                                             |       | 22,581                                                                                                  |       | 15,018 |   | 15,537 |   | 56 |   | 71 |   |
| Stockholders’ equity                                        |       | 271,957                                                                                                 |       | 159,180 |   | 90,740 |   | 63,636 |   | 36,732 |   |
|                                                             |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| **Cash Flow Data:**                                              |       |                                                                                                    |       |   |   |   |   |   |   |   |   |
| Cash flow provided by/(used in) operating activites              |       | (30,785                                                                                                 | )          | 48,722 |   | (15,171 | ) | (6,682 | ) | (4,461 | ) |
| Cash flow used in investing activities                           |       | (90,005                                                                                                 | )          | (102,185 | ) | (58,464 | ) | (34,270 | ) | (5,745 | ) |
| Cash flow provided by financing activities                       |       | 133,620                                                                                                 |       | 51,266 |   | 55,825 |   | 36,820 |   | 35,647 |   |

 

----

(1)           For further information regarding therestated amounts, see Note 11 — “Restatementof Merger Earn-Out Shares”.

 

37

----

Table of Contents

 

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

 

*The following discussion and analysis of ourfinancial condition and results of operations should be read in conjunctionwith our audited consolidated financial statements and related notes containedelsewhere in this report.  The followingdiscussion includes forward-looking statements that reflect our plans,estimations and beliefs.  Our actualresults could differ materially from those discussed in these forward-lookingstatements.  Factors that could cause orcontribute to such differences include, but are not limited to, those discussedbelow and elsewhere in this report.*

 

**Overview**

 

We are an independent oil and gas company focused onthe exploration, development and production of oil and natural gas in Peru andEcuador.  We also intend to utilize partof our planned future natural gas production as a supply source for thedevelopment of a gas-fired power generation facility in Peru, which wecurrently plan to wholly or partially own. We have the exclusive rights and license agreements for oil and gasexploration and production covering approximately 2.2 million acres in fourblocks in northwest Peru and off the northwest coast of Peru in the Gulf ofGuayaquil.  We also own a 10% non-operatedworking interest in an oil and gas producing property, Block 2, located in thesouthwest region of Ecuador (the “Santa Elena Property”).

 

Ourcurrent activities and related planning are focused on the followingobjectives:

 

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

 

·                  Development of the Albacora field in BlockZ-1 where we have commenced drilling and begun initial production welltesting.  We will also need to installequipment in Albacora as necessary to comply with Peruvian environmentalregulations and are planning on an approximately two-year period to transitionto commercial production.

 

·                  Continued development of our gas-to-powerproject to monetize our natural gas reserves, which we have identified inCorvina, but for which no market has yet otherwise developed, preventing usfrom reporting volumes of gas reserves for SEC reporting purposes.

 

·                  Continued acquisition of seismic and well testingdata to better understand the characteristic and potential of our licenseproperties and build our reportable asset values.

 

·                  Commencement of an on-shore drilling campaignto develop our on-shore properties and meet our applicable licenserequirements.

 

**Extended Well Testing Program**

 

On December 13,2009 new legislation regulating well testing in Peru became effective by meansof a Supreme Decree.  The new regulation provides that all new wells maybe placed on production testing for up to six months.  If the operatorbelieves that additional time for testing is needed to properly evaluate theproductive capacity of the field, and can technically justify such need, arequest for the well to enter into an Extended Well Test (“EWT”) period must besubmitted to the DGH, the agency of the Ministry of Energy and Minesresponsible for regulating the optimum development of oil and gas fields. The approval process for an EWT permit requires that the DGH request Perupetro’sopinion on the technical justification for the EWT.  After the initial sixmonth period or after an approved EWT program expires, the operator will berequired to have the necessary gas and water reinjection equipment in place tocontinue producing the well according to existing environmentalregulations.  For wells that have been under testing for more than sixmonths as of the date of publication of the Supreme Decree, the new regulationprovides 30 business days to apply to the DGH for the corresponding EWT permit.

 

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

 

38

----

Table of Contents

 

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

 

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

 

Inaddition, we are in the initial stages of appraising, exploring and developingour potential oil and natural gas reserves in the Albacora field of BlockZ-1.  Our first well in Albacora hasbeen, and all new wells drilled in Albacora will be, placed in the initialsix-month production testing under the new legislation.  As in Corvina, we will need to receiveapproval for all the pertinent environmental and technical permits and installthe required gas and water reinjection facilities at the Albacora platform inorder to transition from exploration to commercial production in Albacora,which as currently estimated could take up to two years.  If we do not receive extended well testingpermits on wells in Albacora beyond the original six-month test period, we willexperience an interruption in production that would negatively impact anyrevenue and cash flow associated with those wells until the applicablerequirements are satisfied for commercial production in Albacora.

 

**Oil Development**

 

***General***

 

We will conduct our drilling and explorationactivities based in part on an ongoing assessment of economic efficiencies,likely success and logistical issues such as license requirements, scheduling, requiredmaintenance and replacement of equipment.  This assessment could result inincreased emphasis and activities on a given prospect and conversely, couldresult in decreased emphasis on a given prospect for a period of time.

 

***Seismic Data Acquisition***

 

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

 

For Block Z-1, we intend to acquire approximately1,500 square kilometers of 3-D seismic data.  The 3-D seismic data surveywill include areas of interest within the Corvina, Albacora, and Delfin fieldsas well as certain prospects and leads located within the Mero and PiedraRedonda regions and certain deep water leads located within Block Z-1.Additionally, the 3-D seismic survey will include data underneath four existingplatforms in the Albacora, Corvina and Piedra Redonda fields.  The seismicdata survey will fulfill our commitments under the fourth exploration period ofthe Block Z-1 license contract if conducted within the allowed contractual timeframe.  We initially attempted to conductthis seismic survey in late 2009 but encountered opposition that led us tosuspend the survey as directed by the Ministry of Energy and Mines.  We are currently working on a new seismicenvironmental permit and we estimate the 3-D seismic data survey to becompleted by 2011.

 

39

----

Table of Contents

 

For Block XXIII, we intend to acquire approximately360 square kilometers of 3-D seismic data and 290 kilometers of 2-D seismicdata which will include certain areas of interest within the PaloSanto regionand four other prospects that are part of the Mancora gas play.  We expectthe 3-D and 2-D seismic data survey to be completed by the end of 2010.

 

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

 

***Corvina Field***

 

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

 

At December 31, 2008 we had four oil wellsproducing under a well testing program. These wells were the CX11-14D, the CX11-18XD, the CX11-21XD, and theCX11-20XD.

 

In November 2008, we commenced drilling on theCX11-15D well and reached total drilling depth in January 2009. However,during the testing it was confirmed that the deeper prospective sands werefound lower than expected and were located below the estimated oil-watercontact, thus testing formation water. Subsequently, we commenced sidetrackingthe CX11-15D well, targeting a location higher in the geological formation andreached total drilling depth of 9,390 feet in March 2009.  We begantesting the sands that previously tested water and found them to beoil-bearing. We added the CX11-15D well to the wells currently producing underour long-term well testing program in June 2009.  The CX11-15D well was completed with a singleproduction string in three of the oil sands that were successfully tested,leaving two accessible oil sands to be added at a later date and leaving thetwo uppermost oil sands isolated from the producing sands.  Additionally,the CX11-15D well has six gas sands.  The gas sands remain behind pipeuntil they are needed for the gas-to-power project. During the testing of theCX11-15D well, gas channeling was discovered.  During the time needed toconduct additional testing and identify possible solutions, we moved the rig tothe CX11-20XD well to perform a workover to correct gas channeling problemsthere, which were similar to the CX11-15D well.

 

In June 2009, we completed the workover of theCX11-20XD well and successfully upgraded both production flow lines fromthe CX-11 platform in Corvina to the FPSO. The new lines enhanced capacity tohandle the combined production of oil, gas and water from the CX-11 platform ina safe and efficient manner.

 

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

 

In October 2009, we commenced drilling on theCX11-19D well. The CX11-19D well is adjacent to the CX11-21XD well, our firstoil discovery well completed in 2007. The CX11-19D is being drilled in a highergeological location that should also allow us to continue appraising theCorvina field. We plan to implement a well design on the CX11-19D to helpalleviate previous gas channeling issues encountered on the CX11-15D andCX11-20XD wells.

 

In December 2009, wecompleted the CX11-19D well in the Corvina field in offshore Block Z-1 innorthwest Peru.  The CX11-19D well is thesixth oil well from the CX-11 platform and has been placed into the productionwell testing program.

 

The CX11-19D wellwas drilled and successfully completed into a proved undeveloped area of theCorvina field, targeting not only sands currently produced in other wells butalso lower untested oil sands that turned out to be productive.  TheCX11-19D well is presently producing from these sands.  During thedrilling of this well, the Zorritos formation was encountered higher thanpreviously mapped.  The electric logs show approximately 148 feet of netoil pay plus an additional 34 feet of net gas pay.  We selectivelyperforated approximately 100 feet of the total 148 feet of estimated net oilpay to test 

 

40

----

Table of Contents

 

the lower sands that hadnot previously been included in the Corvina testing program.  The initialperformance of the well will be evaluated over a period of time before adecision is made whether to perforate any of the remaining net pay found in theupper oil zones.

 

The CX11-19D well wascarefully evaluated prior to placing it into the ongoing production testingphase. Although each of the previous Corvina wells has declined differently,partly due to the fact that these wells were completed in different zones andsome of the wells encountered mechanical problems, they all have initially showntypical solution gas drive behavior which can lead to significant declinesduring the first year of production before leveling off to sustainablerates.  However, the representative ratesof decline remain to be determined, as the effective production mechanism inthe Corvina field has yet to be fully understood.  Hence the need to continue testing theseinitial wells.

 

The CX11-19D well will betested and produced under the new well testing regulation giving companies sixmonths to evaluate a well before applying for the extended well testingprogram.  We plan to have the needed gasand water reinjection facilities at the CX-11 platform as soon aspossible.  The initial estimated date of May 31,2010, proposed by us and viewed as reasonable by Perupetro, no longer appearsto be reachable due to the delayed delivery of certain equipment. We arecurrently assessing a revised date to have all equipment in place, as well asall other requirements complied with, at which time the CX11-19D would beplaced into commercial production.  Anydelays in delivering or commissioning reinjection equipment or delays in otherpermitting aspects may force us to shut-in the CX11-19D well, and our otherCorvina wells, until we are ready to transition from exploration to exploitation,unless we obtain an approval for extended well testing for each well asrequired by the regulations.

 

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

 

The Corvina wells haveseen initial declines of approximately 50% during the first year of productionbefore stabilizing.  We do not believethese results are indicative of the Corvina field generally, but are insteadthe result of technical/mechanical problems encountered with our initial wells;however, it is possible we will see similar production declines with newCorvina wells.  Further, our ability toproduce indicated reserves in Corvina depends on our ability to finance ourcontinued operations, install the necessary water and gas reinjection equipmentand get our produced oil to market. While we do not foresee difficulties in meeting these requirements, anyfailure to do so could negatively affect our indicated reserves as reportedunder SEC rules. As such, in the evaluation of its reserves, we attempt toaccount for all possible delays we are aware of and their impact on theproduction forecast and remaining reserves to be produced.  When dealing with an issue with a futureoutcome that is uncertain, we attempt to take the most conservative scenario.As an example, we are assuming certain shut-in periods for wells that may notoccur in reality.

 

***Albacora Field***

 

The Albacora field islocated in the northern part of our offshore Block Z-1 in northwest Peru. The current area of interest within the Albacora field is a mapped structureclosure of the target Zorritos formation of approximately 7,500 acres and islocated in water depths of less than 200 feet.

 

In September 2009,we commenced drilling on the A-14XD well, our first new well in the Albacorafield, from our recently renovated A platform. The A platform also has threeshut-in oil wells that were drilled and produced for a short period of time byBelco Oil & Gas around 1980.  Atthe time, each well showed different productive capacity and decline rates. TheA-14XD well was drilled, cased, tested, completed, and put on productiontesting before year end.  The top of theUpper Zorritos formation was found at approximately 9,300 feet measured depth,while the bottom of the Lower Zorritos formation was found at approximately14,450 feet measured depth, resulting in approximately a 5,150 foot section ofUpper and Lower Zorritos formation.  Thelogs indicate the presence of multiple prospective sands throughout the entiresection, as was also observed in the 8X2 discovery well drilled by Tenneco in1972.  The A-14XD and 8X2 wells are closetogether by field standards and can be considered twin wells.

 

We estimate fromthe mud log and electric logs that the A-14XD well has approximately 100 feetof net gas pay and approximately 150 feet of net oil pay, plus similar amountsof prospective pay that still require further evaluation.  We selectively perforated one interval whichaccounts for approximately 80 feet of the total 150 feet of estimated net oilpay.  The well was then completed and itsinitial performance will be evaluated over a period of time before a decisionis made whether to perforate any of the additional net pay found in the upperoil zones.

 

41

----

Table of Contents

 

The well hasinitially maintained a stabilized IPR from an oil zone lower than any of theoil zones tested in the discovery well drilled by Tenneco in 1972.  Thewell has continued to produce consistently, according to the various chokesizes being used, with no apparent increase in its gas-oil-ratio and with noformation water reported to date. Additionally, the mud log and the electric logs show in a preliminaryevaluation that the A-14XD well contains gas sands that are likely to be richin condensates, as demonstrated in the twin well 8X2 drilled by Tenneco in1972. The only previous production history in Albacora is from the shut-inBelco wells drilled in the 1970’s that were produced for a very limited time,with each showing different productive capacity and decline rates.  Theongoing testing program aims at determining the field’s drive mechanisms, aswell as a representative decline rate for this and future wells. With thedrilling of the A-14XD well we have complied with our previous explorationcommitment under the Block Z-1 license contract and have now entered into thefourth exploration period. The fourth exploration period requires us to drillan exploratory well or acquire a certain amount of seismic data.  We are installing the required production processingfacilities for well testing at the platform and, as a result, stopped oilproduction from the A-14XD well, for approximately three weeks, during theoffloading of the production equipment onto the platform.  Theinstallation and commissioning of these facilities are estimated to takeapproximately eight weeks.  The A-14XD well has been re-opened usingtemporary well testing equipment, while the work on the permanent well testingequipment continues. We have re-opened the A-14XD with the availability of alarge FSO vessel.  We are currentlynegotiating an initial short-term oil sales contract with the Talara refinery,which is expected to be finalized by the end of the first quarter. Additionally,we are also evaluating the feasibility of having other buyers for our Albacoraoil.

 

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

 

**Gas-to-Power Project**

 

TheCorvina gas-to-power project entails the installation of a 10-mile gas pipelinefrom the CX-11 platform to shore, construction of gas processing facilities andan approximately 135 megawatt (“MW”) simple-cycle electric generatingplant.  The proposed power plant site is located adjacent to an existingsubstation and power transmission lines which, after the Peruvian governmentcompletes their expansion, are expected to be capable of handling up to 320 MWof power. The existing substation and transmission lines are owned and operatedby third parties.

 

In order to support our proposed electric generationproject, we commissioned an independent power market analysis for the region.The Peruvian electricity market is deregulated and power is transported throughan interconnected national grid managed by the Committee for EconomicDispatching of Electricity (known as “COES”). Based on this study, we believewe will be able to sell economic quantities of electricity from the initial 135MW power plant. The market study also indicates that there may be futureopportunities for us to generate and sell significantly greater volumes ofpower into the Peruvian and possibly Ecuadorian power markets. Accordingly, the revenues from the natural gas delivered to the power plantwill be derived from the sale of electricity.

 

We currently estimate the gas-to-power project willcost approximately $135.0 million, excluding 19% value-added tax which will berecovered via early recovery and/or future revenue billings.  The $135.0million includes $115.0 million for the estimated cost of the power plant and$20.0 million for the estimated cost of the construction of the natural gaspipeline. After a private tender process, we commenced discussions withpotential joint venture partners for the gas-to-power project in June 2009.The joint venture will be subject to the satisfactory negotiation of a jointventure agreement and related documents. To date, we have not entered into anydefinitive agreements and are not currently in ongoing negotiations with apotential partner. In the event we are able to reach agreement with a potentialjoint venture partner, we may only retain a minority position in the project.However, we expect to retain the responsibility for the construction of thepipeline as well as retain ownership of the pipeline. If we are unable to reachagreement with a potential partner, we are planning to continue moving theproject forward to completion. Decisions regarding project financing will bedetermined as we move the project forward to completion.

 

**Pending SEC Comments**

 

In connection with a registration statement filed on October 21,2009 to register shares issued to IFC in a private transaction, we havereceived comments from the SEC pertaining to our registration statement, our Form 10-Kfor the year ended December 31, 2008, our Definitive Proxy Statement filedon April 30, 2009, and our Form 10-Q for the period ended September 30,2009 and the related earnings press release. In general, the pending questionsor comments from the SEC relate to: (i) clarifications in several of ourdisclosures; (ii) the basis for the assumptions underlying our SEC oilreserves 

 

42

----

Table of Contents

 

reported for 2008 in light of our actual productionperformance in 2009; (iii) the reasons our 2009 production fell short of2008 projections; (iv) the consideration we gave to the reasonablecertainty of our assumptions underlying our SEC oil reserves and the relatedaccounting reported in our financial statements; and (v) how we aretaking into consideration certain items and uncertainties for our 2009 reservesreport. We havepromptly responded to the SEC’s requests and are currently waiting on requestsfor additional information, if any. In addition, where appropriate, we haveproposed clarifications to our disclosures, none of which we believe arematerial in light of all of the disclosures and risk factors provided in ourpublic filings to date. The SEC is currently reviewing our responses, and couldask additional questions or request additional revisions to our filings, someof which could be material. In particular, the process of estimating oil andnatural gas reserves is complex, requiring interpretations of availabletechnical data and many assumptions, including assumptions relating to economicfactors, and therefore are inherently imprecise. In its review of our responsesand reserve data provided to them, the SEC could disagree with our independentpetroleum engineer’s reserve estimates, including the underlyinginterpretations and assumptions or the reasonable certainty of our assumptions,and request a revision to our estimates of proved reserves and the relatedaccounting of the reserves in our financial statements. In addition, results ofactual future production will depend on expected production levels that mightnot be achieved, oil and natural gas prices, drilling and operating expenses,capital expenditures, taxes and availability of funds, which will most likelyvary from our estimates, and those variances may be material.

** **

**Restatement of Merger Earn-Out Shares**

** **

On September 10,2004, BPZ Energy, Inc., a Texas corporation (“BPZ-Texas”), consummated areverse merger with Navidec, Inc. (“Navidec”) whereby BPZ-Texas became awholly owned subsidiary of Navidec (the “Merger”). As a result of the Merger,the shareholders of BPZ-Texas received the majority of the voting interestcontrol of the Board of Directors and management of the combined entity and on February 4,2005, Navidec changed its name to BPZ Energy, Inc. (now known as BPZ Resources, Inc.).For accounting purposes, BPZ-Texas was treated as the acquiring entity. TheMerger Agreement provided for the immediate issuance by Navidec of 9,000,000shares of its common stock to the shareholders of BPZ-Texas and the futureissuance of additional merger consideration of 18,000,000 shares on an earn-outbasis if the Company achieved certain reserve and production goals. The first9,000,000 earn-out shares were contingent on achieving certain reserve targets,which were achieved in December 2004. However, the contingent earn-outshares could only be issued after the shareholders approved an increase in thenumber of authorized common shares of the Company. The shareholders approved anincrease in the number of authorized shares from 20,000,000 to 250,000,000 atits 2005 Annual Meeting held on July 1, 2005 and the 9,000,000 shares wereissued at that time.  The closing priceof BPZ common stock was $4.40 per share on that day.  The remaining 9,000,000 earn-out shares werecontingent on the Company becoming entitled to receive as its proportionateshare from gross production from any oil and gas wells owned or operated by theCompany not less than 2,000 barrels of oil per day or its equivalent(approximately 12 million cubic feet of gas per day) prior to December 28,2007. On November 2, 2007 this production target was achieved, based oncertification by an independent engineering firm that the Company’s productionin Peru had met or exceeded the required level of production and the shareswere issued.  On November 2, 2007,the closing price of the Company’s common shares was $10.87 per share.

 

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

 

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

 

(ii) Weadjusted our presentation to show the merger earn-out shares when issued foreach period presented without retroactively increasing the prior periods commonshares outstanding.  The effect of thistransaction decreased the weighted average outstanding share count for theyears ended December 31, 2005, 2006 and 2007 by 13.5 million shares, 9.0million shares and 7.5 million shares, respectively.

 

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

 

43

----

Table of Contents

 

**Financing Activities**

 

***$170.9 Million Convertible Notesdue 2015***

 

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

 

The 2015 Convertible Notes are our general seniorunsecured obligations and rank equally in right of payment with all of ourother existing and future senior unsecured indebtedness.  The 2015Convertible Notes are effectively subordinated to all of our securedindebtedness to the extent of the value of the assets collateralizing suchindebtedness.  The 2015 Convertible Notes are not guaranteed by oursubsidiaries.

 

We will pay interest on the 2015 Convertible Notes ata rate of 6.50% per year on March 1 and September 1 of each year,beginning on September 1, 2010.  The 2015 Convertible Notes mature onMarch 1, 2015. The initial conversion rate is 148.3856 shares per $1,000principal amount of the 2015 Convertible Notes (equal to an initial conversionprice of approximately $6.74 per share of common stock), subject to adjustment.Upon conversion, we must deliver, at our option, either (1) a number ofshares of our common stock determined as set forth in the Indenture, (2) cash,or (3) a combination of cash and shares of our common stock (but not toexceed 19.99% of our outstanding shares at the time of such delivery).

 

The initial conversion rate may be adjusted on February 3,2011 if the volume weighted average price of our common stock for each of the30 trading days ending on February 3, 2011 is less than $5.6160 per share.In addition, following the occurrence of any one of certain corporatetransactions that constitutes a fundamental change (as defined in theIndenture), we will increase the conversion rate, subject to certainlimitations, for a holder who elects to convert the 2015 Convertible Notes inconnection with such corporate transactions during the 30-day period after theeffective date of such fundamental change.

 

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

 

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

 

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

 

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

 

(4) upon the occurrence of one of specifiedcorporate transactions. Holders may also convert the 2015 Convertible Notes attheir option at any time beginning on February 1, 2015, and ending at theclose of business on the second business day immediately preceding the maturitydate.

 

On or after February 3, 2013, we may redeem forcash all or a portion of the 2015 Convertible Notes at a redemption price of100% of the principal amount of the notes to be redeemed plus any accrued andunpaid interest to, but not including, the redemption date, plus a “make-whole”payment if: (1) for at least 20 trading days in any consecutive 30 tradingdays ending within five trading days immediately before the date we mail theredemption notice, the “last reported sale price” of our common stock exceeded175% of the conversion price in effect on that trading day, and (2) thereis no continuing default with respect to the notes that has not been cured orwaived on or before the redemption date.

 

If we experience any one of the certain specifiedtypes of corporate transactions, holders may require us to purchase all or aportion of their 2015 Convertible Notes. Any repurchase of the notes pursuantto these provisions will be for cash at a 

 

44

----

Table of Contents

 

price equal to 100% of the principal amount of thenotes to be purchased plus any accrued and unpaid interest to, but excluding,the purchase date.

 

The Indenture contains customary terms and covenantsand events of default. If an event of default (as defined therein) occurs andis continuing, the Trustee by notice to us, or the holders of at least 25% inaggregate principal amount of the 2015 Convertible Notes then outstanding bynotice to us and the Trustee, may declare the principal of and accrued andunpaid interest (including additional interest or premium, if any) on the 2015Convertible Notes to be due and payable. In the case of an event of defaultarising out of certain bankruptcy events (as set forth in the Indenture), theprincipal of and accrued and unpaid interest (including additional interest orpremium, if any), on the notes will automatically become due and payable.

 

Net proceeds from the sale of the 2015 ConvertibleNotes, after deducting the discounts and commissions and any offering expensespayable by us, was approximately $165.4 million.  The initial purchaserreceived commissions of approximately $5.5 million in connection with the saleof the Notes.  We intend to use the net proceeds for general corporatepurposes, including without limitation, capital expenditures and workingcapital, reduction or refinancing of debt, or other corporate obligations.

 

As a result of our adoption of the new accountingstandard for convertible debt that may be settled in cash upon conversion, weare required to separately account for the liability and equity components in amanner that reflects our nonconvertible borrowing rate when interest cost isrecognized in subsequent periods. The value assigned to the liability componentis determined by measuring the fair value of a similar liability that does nothave an equity conversion feature. The value assigned to the equity componentis determined by deducting the fair value of the liability component from theinitial proceeds. The excess of the principal amount of the liability componentover its carrying amount (the non-cash discount) is amortized to interest costusing the effective interest method over the term of the debt agreement. Inaddition, transaction costs incurred that directly relate to the issuance ofconvertible debt instruments must be allocated to the liability and equitycomponents in proportion to the allocation of proceeds and accounted for asdebt issuance costs and equity issuance costs, respectively. The accountingstandard requires retrospective restatement of all periods presented back tothe date of debt issuance with a cumulative effect of the change in accountingprinciple on all prior periods being recognized as of the beginning of thefirst period.

 

We estimated our nonconvertible borrowing rate at thedate of issuance of our 2015 Convertible Notes to be 12%.  The 12% nonconvertible borrowing raterepresents the borrowing rate of similar companies with the same credit qualityas us and was obtained through a quote from the initial purchaser. Using theincome method and discounting the principal and interest payments of the 2015Convertible Notes using the 12% nonconvertible borrowing rate, we estimate thefair value of the $170.9 million 2015 Convertible Notes to be approximately$136.3 million with the discount being approximately $34.6 million. Thediscount will be amortized as non-cash interest expense into income over thelife of the notes using the interest method. In addition, we plan to recordapproximately $4.4 million of the $5.5 million of fees and commissions as debtissue costs that will be amortized over time using the interest method asinterest expense. The remaining $1.1 million of fees and commissions will betreated as an original issue discount against the value of the equitycomponent. We estimate the cash payments related to the 2015 Convertible Notes,assuming no conversion, for the years ended 2010, 2011, 2012, 2013, 2014 andthereafter to be approximately $6.4 million, $11.1 million, $11.1 million,$11.1 million, $11.1 million and $176.5 million, respectively

 

***September 2009Private Placement of Common Stock***

 

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

 

45

----

Table of Contents

 

Under the September 15, 2009 SubscriptionAgreement, we committed to file a registration statement with the SEC coveringthe shares no later than 45 days after the closing with respect to such shares,and will use our reasonable best efforts to obtain its effectiveness no later thanthe 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 theclosing and (ii) the third business day following the date on which BPZ isnotified (orally or in writing, whichever is earlier) by the SEC that theregistration statement will not be reviewed or is no longer subject to furtherreview and comment unless, upon the advice of legal counsel, it is advisablenot to accelerate the effectiveness of such registration statement. On October 21,2009, we filed a registration statement with the SEC covering the shares.Subsequently, we received comments from the SEC pertaining to our registrationstatement, Form 10-K for the year ended December 31, 2008, DefinitiveProxy Statement filed on April 30, 2009, Form 10-Q for the periodended September 30, 2009 and the related earnings press release. Wepromptly responded to the SEC’s requests and are currently waiting on requestsfor additional information, if any. In addition, where appropriate, we haveproposed clarifications to our disclosures. Once we are notified by the SEC ourresponses are no longer subject to further review, we will use our reasonablebest efforts to obtain the registration statement’s effectiveness. There are nopenalty payments associated with the delay in obtaining effectiveness of theregistration statement.

 

***June 2009Registered Direct Offering of Common Stock***

 

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

 

***February 2009Private Placement of Common Stock***

 

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

 

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

 

***GE Turbine PurchaseAgreement, Amendment and Letter Agreement***

 

On September 26, 2008, we, through our subsidiaryEmpresa Electrica Nueva Esperanza S.R.L., entered into a $51.5 million contract(the “Agreement”) for the purchase of three LM6000 gas-fired turbines from GEPackaged Power, Inc. and GE International, Inc. Sucursal de Peru(collectively “GE”). The Agreement required an initial down payment of $5.1million and monthly progress payments of $1.1 million per unit. In January 2009,BPZ and GE entered into an amendment of the contract. Under the terms of theamendment, both GE and BPZ agreed to a suspension period under the Agreementfrom and including December 15, 2008 through November 15, 2009,whereby no failure on the part of BPZ or GE to perform any obligations underthe Agreement will give rise to a breach of contract or the right to terminatethe contract, provided we make a $3.4 million progress payment no later than February 25,2009 and a $3.5 million progress payment to GE no later than November 16,2009. On February 24, 2009, we paid the first progress payment of $3.4million. We were still in negotiations with GE to modify the terms of theAgreement at the time the second progress payment was due on November 16,2009, and GE agreed to a short extension of the deadline for the milestonepayment in order to conclude ongoing negotiations with

 

46

----

Table of Contents

 

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

 

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

 

***Reserve-BasedCredit Facility***

 

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

 

Subsequent to December 31, 2010, we, through oursubsidiary, BPZ E&P, elected to terminate negotiations on the previouslyannounced $55.0 million portion of the reserve based credit facility beingarranged by Natixis.  With theproceeds from the 2015 Convertible Notes offering, the termination of thesenegotiations is not expected to impact our ability to undertake our 2010capital expenditures program, including drilling and continued development ofthe Corvina and Albacora fields as well as payments due under the GE turbinepurchase agreement.

 

***May 2008 $15.5Million Debt Conversion to Equity***

 

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

 

***March 2008Equity Offering***

 

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

 

***Contingent IncentiveEarn-Out Shares***

 

During2005, the Company’s Board of Directors awarded a total of 485,000 shares ofincentive stock awards to three of our officers. The incentive stock awardsvest and the earn-out shares are issuable once BPZ is entitled to receive asits proportionate share from gross production from any oil and gas wells ownedor operated by us not less than 2,000 barrels of oil per day or its equivalent(approximately 12 million cubic feet of gas per day) prior to December 28,2007, the same target applicable to the Merger earn-out shares. However, one ofour officers entitled to receive earn-out shares resigned from BPZ and itssubsidiaries effective June 15, 2006, and as a result 225,000 of theunvested contingent incentive stock awards, representing $990,000 of futurepossible compensation expense, were forfeited. Subsequently, 190,000 shares ofthose 225,000 shares were awarded to the officer’s successor to supplement aprevious award of 35,000 shares. The second earn-out targetprovided for in the original merger agreement related to its merger withNavidec, Inc.  In November 2007,the production target in the Merger Agreement dated July 8, 2004 wasachieved. The determination was made by our Board of Directors based oncertification by the independent engineering firm that BPZ’s production in Perumet or exceeded the required level of production.

 

47

----

Table of Contents

 

Theachievement of the required level of production resulted in the issuance of450,000 shares.  For accounting purposes,during the year ended December 31, 2007, $1,980,000 was recorded ascompensation expense.

 

48

----

Table of Contents

 

**FutureMarket Trends and Expectations**

 

                Our business depends primarilyon the level of current and future oil and gas demand and prices which may impactour ability to raise capital to finance the development of our current andfuture oil and gas opportunities, to continue developing our gas-to-powerproject, which anchors our gas monetizing strategy, and to maintain our commitmentsand obligations under our current and future license contracts.  The world economies are slowly recoveringfrom a recession which began in 2008 and extended into 2009. Growth hasresumed, but is modest.  There are likely to be significant long-termeffects resulting from the recession and credit market crisis, including afuture global economic growth rate that is slower than what was experienced inrecent years.  In addition, more volatility may occur before asustainable, yet lower, growth rate is achieved. Global economic growthdrives demand for energy from all sources, including fossil fuels.  Alower future economic growth rate could result in decreased demand growth forour crude oil and natural gas production as well as lower commodity prices, whichwill reduce our cash flows from operations and our profitability.

 

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

 

                From a production perspective,our goal is to continue to increase production during 2010, assuming weencounter minimal technical difficulties and successfully complete the gas andwater injection facilities.  In order toattain that goal we plan to commit a majority of our 2010 capital budget ofapproximately $200 million on further development of the Corvina field and the continuedappraisal and development of oil in the Albacora field. Our drilling plansinclude drilling two additional oil development wells from the CX-11 platformin the Corvina field and drilling four new wells in the Albacora field from theAlbacora platform using a recently contracted drilling rig.

 

                Expected operational cash flowfrom Corvina and Albacora oil sales as well as the additional proceeds from therecent covertible debt offering should cover the capital expenditures necessaryto complete our 2010 capital program.  Inaddition, we are working to obtain the necessary financing for the gas-to-powerproject and we will continue to evaluate our options on additional financing asneeded. We anticipate future results will be based on our production levels andcurrent and future oil prices. When forecasting our 2010 performance, we reliedon assumptions about the market for oil, our customers and suppliers, pastresults and operational and regulatory delays. We expect the average spot pricefor oil in 2010 to be approximately $71.00 or 30% more than the average pricewe received in 2009.  With our plannedoil production increases, we expect earnings for 2010 to exceed that of 2009.Our results could materially differ from what we anticipate if any of ourassumptions, such as major technical or mechanical well issues, commoditypricing, production levels or our ability to raise additional capital, prove tobe incorrect. In addition, our businesses’ operations, financial condition andresults of operations are subject to numerous risks and uncertainties that ifrealized could cause our actual results to differ substantially from ourforward-looking statements. These risks and uncertainties are further describedin Item 1A. — “Risk Factors” of this report.

 

49

----

Table of Contents

 

**Resultsof Operations**

 

***Year Ended December 31,2009 Compared to Year Ended December 31, 2008***

 
| ** **                                       | ** ** | **Year Ended  December 31,**                                 | ** ** | **Increase/** | ** ** |
|--------------------------------------------------|------------|------------------------------------------------------------------------|------------|---------------|------------|
| ** **                                       | ** ** | **2009**                                                               | ** ** | **2008**      | ** ** | **(Decrease)** | ** ** |
| ** **                                       | ** ** | **(in thousands except per bbl information)** | ** ** | ** **    | ** ** |
| Net sales volume:                                |       |                                                                   |       |          |       |   |   |
| Oil and condensate (MBbls)                       |       | 963                                                                    |       | 826           |       | 137 |   |
|                                             | ** ** | ** **                                                             | ** ** | ** **    | ** ** | ** ** | ** ** |
| Net revenue:                                     |       |                                                                   |       |          |       |   |   |
| Oil and condensate                               |       | $                                                                      | 52,454     |          | $          | 62,955 |   | $ | (10,501 | ) |
|                                             | ** ** | ** **                                                             | ** ** | ** **    | ** ** | ** ** | ** ** |
| Average sales price (approximately):             | ** ** | ** **                                                             | ** ** | ** **    | ** ** | ** ** | ** ** |
| Oil (per Bbl)                                    |       | $                                                                      | 54.49      |          | $          | 76.23 |   | $ | (21.74 | ) |
|                                             | ** ** | ** **                                                             | ** ** | ** **    | ** ** | ** ** | ** ** |
| Operating expenses                               | ** ** | ** **                                                             | ** ** | ** **    | ** ** | ** ** | ** ** |
| Lease operating expense                          |       | $                                                                      | 28,113     |          | $          | 11,649 |   | $ | 16,464 |   |
| General and administrative expense               |       | 33,258                                                                 |       | 42,094        |       | (8,836 | ) |
| Geological, geophysical and engineering expense  |       | 7,768                                                                  |       | 794           |       | 6,974 |   |
| Depreciation, depletion and amortization expense |       | 25,803                                                                 |       | 16,062        |       | 9,741 |   |
| Total operating expenses                         |       | $                                                                      | 94,942     |          | $          | 70,599 |   | $ | 24,343 |   |
|                                             |       |                                                                   |       |          |       |   |   |
| Operating loss                                   |       | $                                                                      | (42,488    | )             | $          | (7,644 | ) | $ | (34,844 | ) |

 

*Net Revenue*

 

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

 

For the year ended December 31, 2009, our netrevenue decreased by $10.5 million to $52.5 million from $63.0 million for thesame period in 2008. The decrease in net revenue is due to a decrease of$21.74, or 29% in the average per barrel sales price received which waspartially offset by an increase in oil sales of 137 MBbls. Oil prices reachedrecord levels during the third quarter of 2008 before sharply falling towardsthe end of the year.  During 2009, oil prices rose steadily from the lowsseen at the beginning of the year but the average price received for oil in2009 was considerably less than the average oil price received during 2008.

 

During the year ended December 31, 2009 oilproduction from the CX11-21XD, CX11-20XD and the CX11-15D wells were at varioustimes and intervals partially or fully suspended due to workovers andmaintenance of the wells in order to perform routine maintenance activities andto attempt to resolve certain gas channeling and water production issuesencountered in the operation of the wells. Additionally, oil production fromthe CX11-14D well was suspended since November 7, 2009 due to water issuesin production that began in May 2009 that caused sand production andlifting issues.  With respect to theCX11-14D, we have no plans in our 2010 budget to further workover this well.

 

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

 

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

 

50

----

Table of Contents

 

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

 

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

 

During 2009, we had oil production for approximately10 of the 12 months for four of the seven wells. The CX11-15D began its initialproduction in June 2009. The CX11-19D and A-14D began their initialproduction in December 2009.

 

During the same period in 2008, oil productionoperations were suspended on January 30, 2008 and our oil sales did notresume until June 2008, due to an incident involving a small tanker leasedby our marine transportation contractor from the Peruvian Navy.  In July 2008the CX11-18XD was placed on production. Subsequent to June 2008, we hadfull oil production for three of the four wells while the CX11-20XD well beganits initial production toward the end of September 2008.

 

The revenues above are reported net of royalties owedto the government of Peru. Royalties are assessed by Perupetro as stipulated inthe Block Z-1 license agreement based on production levels. However, theroyalty calculation is based on the prior five-day average of a blend of crudeoil prices before the crude oil delivery date, as opposed to the price wereceive for oil which is based on the prior two-week average of a blend ofcrude oil prices before the crude oil delivery date. For both the year ended December 31,2009 and 2008, the revenues received by us are net of royalty costs ofapproximately 5% of gross revenues or $2.9 million and $3.3 million,respectively.

 

*Lease Operating*

 

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

 

*General and Administrative*

 

General and administrative expenses areoverhead-related expenses, including employee compensation, legal, consultingand accounting fees, insurance, and investor relations expenses. For the yearended December 31, 2009, general and administrative expenses decreased$8.8 million to $33.3 million from $42.1 million for the same period in2008.  Stock-based compensation expense, a subset of general andadministrative expenses, decreased by $5.8 million to $12.6 million for theyear ended December 31, 2009 from $18.5 million for the same period in2008. The decrease in stock-based compensation expense is due to the decreasein fair market value of awards granted in 2009 as a result of the decline in thestock price of BPZ.  Additionally the 2009 stock-based compensationexpense includes approximately $0.7 million of stock-based compensation expenserelated to the accelerated vesting for certain restricted stock and stockoption awards granted to a former member of the Board of Directors but excludes$0.4 million of compensation expense that is included in “Other income(expense)” on the Consolidated Statements of Operations. The $0.4 millionrelates to 100,000 stock options awarded to a former member of the Board ofDirectors. The grant date fair value of the award was recognized upon issuanceof the award. Other general and administrative expenses decreased $3.0million to $20.6 million from $23.6 million for the same period in 2008. The$3.0 million decrease is due to $2.3 million decrease of salary and salaryrelated expenses, $1.2 million 

 

51

----

Table of Contents

 

of decreased consulting and contract labor expense,$0.4 million of decreased legal expenses and $0.4 million decreased travel andtravel related expenses partially offset by $0.4 million of increased bank feesand $0.8 million increased rent expenses. The reduction in salary and salaryrelated expense is due to the voluntary salary reduction initiatives and timingof executive bonuses and employee salary increases. During the first half of2009, certain executive and other key personnel agreed to a voluntary salaryreduction of 5% to 15% of their base salaries and the Chairman of the Board ofDirectors agreed forgo his salary for 2009. Additionally, BPZ did not paybonuses in 2009. In July 2009, employees who participated in the voluntarysalary reduction, other than the Chairman of the Board of Directors, received asalary reinstatement.  During 2008,executives and other key employees received bonuses and employees receivedsalary increases that were retroactive to the beginning of the year. Thereduction in contract labor, consulting and legal fees is due to the Shelljoint venture negotiations and tax reorganization expenses for which weincurred significant fees in 2008 that were not repeated in 2009.  The reduced travel and travel related anexpense is due to less travel incurred by our personnel in 2009 compared to2008. The increase in bank fees is due to higher fees charged by financialinstitutions in 2009 compared to 2008. The higher rent expense is due toincreased office space rented by both our Houston and Peru offices in 2009compared to 2008.

 

*Geological, Geophysical andEngineering*

 

Geological, geophysical and engineering expensesinclude laboratory, environmental and seismic acquisition related expenses. Forthe year ended December 31, 2009, geological, geophysical and engineeringexpenses increased $7.0 million to $7.8 million compared to $0.8 million forthe same period in 2008. During the fourth quarter of 2009, we incurredapproximately $6.3 million for seismic acquisition expenses. At the end of thethird quarter of 2009, we entered into a contract to acquire approximately 950square kilometers of 3-D seismic data for Block Z-1 to assist us in exploring,appraising and developing certain areas of interest and to better define theposition of future wells as well as to comply with our exploration commitmentsunder our license contracts. As Block Z-1 is located offshore, the seismicactivity was to be conducted by marine seismic vessels from a third partyseismic contractor.  Shortly afterstarting the seismic operations, and following protests fromfisherman in the area where our third party contractor was performing seismictests, we received astatement from the Peruvian Ministry of Energy and Mines to suspend ourseismic testing. As a result of the suspension we incurred approximately $4.7million in standby fees and mobilization and support costs as well as $1.5million in contract extension costs of which approximately $0.8 million will becredited against the future cost of the seismic acquisition by the contractor.The contract extension guarantees the original seismic acquisition pricing aslong as we are able to resume our seismic acquisition within the next twoyears. We arecurrently working with the Peruvian Ministry of Energy and Mines to resume conductingthe seismic survey. The remaining increase of $0.7 million is due to increasedlaboratory and consulting costs as a result of more environmental impactstudies performed on Blocks XIX, XXII and XXIII in the current year compared tothe activities of the prior year.

 

*Depreciation, Depletion andAmortization*

 

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

 

*Other Income/(Expense)*

 

For the year ended December 31, 2009, income fromour investment in Ecuador property, net of investment amortization, increased$0.5 million to $1.2 million in 2009 from $0.7 million in 2008. The increase isdue to receiving $1.4 million in payments during 2009 from our investment inthe Santa Elena Property while receiving $0.9 million for the same periods in2008. Income/(expense) from our investment in Ecuador is net of investmentamortization expense.  For both the years ended December 31, 2009 and2008, investment income / (expense) includes amortization expense ofapproximately $0.2 million.

 

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

 

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

 

For the year ended December 31, 2009, otherexpense increased by $1.4 million to an expense of $1.3 million in 2009 fromincome of $0.1 million in 2008.  The reason for the increase in expense isdue to $0.4 million of stock compensation expense related to stock optionsawarded to a former member of the Board of Directors that was recognized 

 

52

----

Table of Contents

 

upon issuance of the award and approximately $0.8million of expense related to the settlement of a disputed contractualobligation with a former consultant of ours concerning services provided toboth BPZ and its predecessor at the time BPZ became publicly traded. We werenotified of this alleged dispute towards the end of the first quarter of2009. The settlement was paid in April 2009. Additionally, for theyear ended December 31, 2009, we recognized $0.1 million of foreigncurrency losses and for the same period in 2008 we recognized a $0.1 millionforeign currency gain.

 

*Income Taxes*

 

The source of income (loss) before income taxexpense (benefit) for the year ended December 31, is as follows (inthousands):

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

 

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

 
| ** **                            | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|---------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Current Taxes                         |       |     |       |     |       |     |       |
| Federal                               |       | $        | 200        |     | $          | —   |       | $ | 39 |   |
| Foreign                               |       | 6,709    |       | 7,536    |       | —   |       |
| Total Current Taxes                   |       | 6,909    |       | 7,536    |       | 39       |       |
|                                  |       |     |       |     |       |     |       |
| Deferred Taxes                        |       |     |       |     |       |     |       |
| Federal                               |       |     | —     |     |       | —   |       |   | — |   |
| Foreign                               |       | (13,484  | )          | (4,395   | )          | —   |       |
| Total Deferred Taxes                  |       | (13,484  | )          | (4,395   | )          | —   |       |
| Total Income Tax Provision  (Benefit) |       | $        | (6,575     | )        | $          | 3,141    |       | $ | 39 |   |

 

The income tax expense (benefit) for the years endedDecember 31, 2009, 2008 and 2007 differs from the amount computed byapplying the U.S. statutory federal income tax rate for the applicable year toconsolidated net loss before income taxes as follows (in thousands):

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

 

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

 

53

----

Table of Contents

 
| ** **                              | ** ** | **2009** | ** ** | **2008** | ** ** |
|-----------------------------------------|------------|----------|------------|----------|------------|
| Deferred Tax:                           |       |     |       |     |       |
| Asset:                                  |       |     |       |     |       |
| Net Operating Loss                      |       | $        | 16,546     |     | $          | 19,941 |   |
| Deferred Compensation                   |       | 2,514    |       | 1,889    |       |
| Foreign Tax AMT                         |       | 1,647    |       | —   |       |
| Asset Basis Difference                  |       | —   |       | —   |       |
| Exploration Expense                     |       | 7,256    |       | 2,080    |       |
| Depreciation                            |       | —   |       | 12       |       |
| Depletion                               |       | 8,162    |       | 3,340    |       |
| Asset Retirement Obligation             |       | 67       |       | 27       |       |
| Overhead Allocaion to Foreign Locations |       | 2,298    |       | —   |       |
| Other                                   |       | 119      |       | 666      |       |
| Liability:                              |       | —   |       | —   |       |
| Preoperation Expenses                   |       | (295     | )          | (295     | )          |
| Depreciation                            |       | (18      | )          |     |       |
| Asset Basis Difference                  |       | (1,819   | )          | (1,298   | )          |
| Other                                   |       | (1       | )          | (300     | )          |
| Net Deferred Tax Asset                  |       | $        | 36,476     |     | $          | 26,062 |   |
|                                    |       |     |       |     |       |
| Less Domestic Valuation Allowance       |       | (19,548  | )          | (21,191  | )          |
| Deferred Tax Asset                      |       | $        | 16,928     |     | $          | 4,871 |   |

 

As of December 31,2009, we had a valuation allowance for the full amount of the domestic deferredtax asset resulting from the income tax benefit generated from net losses, aswe believe, based on the weight of available evidence, that it is more likelythan not that the deferred tax asset will not be realized prior to theexpiration of net operating loss carryforwards in various amounts through 2028.Furthermore, because we have no operations within the U.S. taxing jurisdiction,it is likely that a sufficient generation of revenue to offset our deferred taxasset is remote.  As a result, we have a full allowance on our deferredtax asset generated in the U.S.  However,we are subject to Peruvian income tax on our earnings at a statutory rate, asdefined in the Block Z-1 License Contract, of 22%.  Because we are under awell testing program from which we will finalize a development plan for BlockZ-1, we have not moved into the commercial phase of production as defined bythe license contract.  As such, certain deductions are disallowed by thePeruvian tax regime while we operate under the well testing program.  Inaddition, the tax provision is based on taxable Peruvian income that excludescertain U.S. expenses that are not deductible at the Peruvian level. As aresult, we recognized a total tax provision for the year ended December 31,2009 of approximately $6.6 million.

 

We anticipatemoving into commercial production in Block Z-1 under the license contract in2010, at which time our full investment in our producing properties will beeligible to be amortized over five years. We assessed the realizability of thedeferred tax asset generated in Peru.  Weconsidered whether it is more likely than not that some portion or all of thedeferred tax asset will not be realized. The ultimate realization of the deferred tax asset is dependent upon thegeneration of future taxable income in Peru during the periods in which thosetemporary differences become deductible. Based upon the level of historical taxable income and projections forfuture taxable income over the periods in which the deferred tax assets aredeductible, along with the transition into the commercial phase under the BlockZ-1 License Contract, we believe it is more likely than not that we willrealize the benefits of the these deductible differences at December 31,2009.  As a result, we recognized adeferred tax asset of $16.9 million as of December 31, 2009.

 

**Estimatedinterest and penalties related to potential underpayment on unrecognized taxbenefits, if any, are classified as a component of tax expense in theConsolidated Statement of Operations. As of the date of adoption of FIN 48, nowcodified under ASC Topic 740, “Income Taxes”, we did not have any accruedinterest or penalties associated with any unrecognized tax benefits, nor wasany interest expense recognized during the year.**  Additionally, theadoption had no effect on our financial position or results of operations.  We did not have any uncertain tax positionsgenerated from unrecognized tax benefits resulting from differences betweenpositions taken in tax returns and amounts recognized in the financialstatements as of December 31, 2009 or December 31, 2008.

 

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

 

54

----

Table of Contents

 

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

 
| ** **                                       | ** ** | **Year Ended  December 31,**                                 | ** ** | **Increase/** | ** ** |
|--------------------------------------------------|------------|------------------------------------------------------------------------|------------|---------------|------------|
| ** **                                       | ** ** | **2008**                                                               | ** ** | **2007**      | ** ** | **(Decrease)** | ** ** |
| ** **                                       | ** ** | **(in thousands except per bbl information)** | ** ** | ** **    | ** ** |
| Net sales volume:                                |       |                                                                   |       |          |       |   |   |
| Oil and condensate (MBbls)                       |       | 826                                                                    |       | 28            |       | 798 |   |
|                                             | ** ** | ** **                                                             | ** ** | ** **    | ** ** | ** ** | ** ** |
| Net revenue:                                     |       |                                                                   |       |          |       |   |   |
| Oil and condensate                               |       | $                                                                      | 62,955     |          | $          | 2,350 |   | $ | 60,605 |   |
|                                             | ** ** | ** **                                                             | ** ** | ** **    | ** ** | ** ** | ** ** |
| Average sales price (approximately):             | ** ** | ** **                                                             | ** ** | ** **    | ** ** | ** ** | ** ** |
| Oil (per Bbl)                                    |       | $                                                                      | 76.23      |          | $          | 81.78 |   | $ | (5.55 | ) |
|                                             | ** ** | ** **                                                             | ** ** | ** **    | ** ** | ** ** | ** ** |
| Operating expenses                               | ** ** | ** **                                                             | ** ** | ** **    | ** ** | ** ** | ** ** |
| Lease operating expense                          |       | $                                                                      | 11,649     |          | $          | 755 |   | $ | 10,894 |   |
| General and administrative expense               |       | 42,094                                                                 |       | 18,548        |       | 23,546 |   |
| Geological, geophysical and engineering expense  |       | 794                                                                    |       | 4,045         |       | (3,251 | ) |
| Depreciation, depletion and amortization expense |       | 16,062                                                                 |       | 793           |       | 15,269 |   |
| Total operating expenses                         |       | $                                                                      | 70,599     |          | $          | 24,141 |   | $ | 46,458 |   |
|                                             |       |                                                                   |       |          |       |   |   |
| Operating loss                                   |       | $                                                                      | (7,644     | )             | $          | (21,791 | ) | $ | 14,147 |   |

 

*Net Revenue*

 

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

 

Although our production increased in 2008 compared to2007, we were not able to produce fully during the year.  During January 2008, we incurredproduction and transportation delays due to the incident involving one of thePeruvian Navy tankers being leased by our marine transportation contractor andused in our offshore oil production operation as part of our well testingprogram.   As a result of the incident, our production was shut-in forapproximately five months while we completed a series of safety and integritytests on the facilities at the CX-11 Corvina platform and waited to receive theclearance needed to transport oil from the CX-11 platform to thenearby Talara refinery by thecorresponding Peruvian environmental agencies.

 

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

 

In 2008, we had oilproduction from four producing wells, the CX11-21XD, the CX11-14D, theCX11-18XD and the CX11-20XD. The CX11-21XD and the CX11-14D wells produced forthe full year, except when production was voluntarily suspended, as noted above, and during certainperiods by drilling and testing activity. The CX11-18XD well produced oil from June 2008 through December 2008,except when production was suspended during certain periods due to the drillingand testing of the CX11-20XD and CX11-15D wells. The CX11-20XD well producedoil from September 2008 through December 2008, except when productionwas suspended during certain periods due to the drilling and testing of the 

 

55

----

Table of Contents

 

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

 

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

 

*Lease Operating*

 

      Leaseoperating expenses include costs incurred to operate and maintain wells andrelated equipment and facilities. These costs include, among others, workoverexpenses, 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 perBbl) in 2007. The increase was attributable to the production increases notedabove.  Additionally as we had limitedoil production during 2007 we also incurred limited lease operating expense forthe same period. Typically, as production increases, our lease operatingexpense per unit decreases as a result of fixed costs.  Our 2008 leaseoperating expense includes approximately $38,000 related to the cost of theapproximately 1,300 barrels of oil that was lost as a result of the tankerincident.

 

*General and Administrative*

 

*     *General andadministrative expenses are overhead-related expenses, including employeecompensation, legal,consulting and accounting fees, insurance, and investor relationsexpenses.  General and administrativeexpenses for 2008 increased $23.6 million to $42.1 million compared to $18.5 million in 2007.  The increase in general and administrativeexpenses is due to additional employees in Peru and related increases incompensation expenses of $6.5 million, and increased legal and consulting feesof $2.4 million, and increased other expenses of $3.2 million, which include insurance, travel and travelrelated expenses, and contract labor, incurred in 2008. In the third quarter of 2008 we internalized ourpreviously outsourced marine operations in order to better manage our long termgrowth initiatives and tripled the number of our employees in Peru.  Additionally we incurred increased personneland compensation expense in order to administer our growth and to support ourincreased operations.  Further weincurred additional consulting and legal fees as part of our negotiations withShell to explore jointly developing Blocks Z-1, XIX and XXIII in Northwest Peruinto large-scale oil and gas ventures. A subset of compensation expense,stock-based compensation expense increased by $11.5 million to $18.5 million in2008 from $7.0 million in 2007. The increase results from of additional awardsgranted in the current year at the time when the price of our Common Stock wasrelatively high and therefore fair value of the awards and related expenserecognized increased as a result. Further, we recognized an additional $0.7million of stock-based compensation expense, as compared to 2007, as a resultof the accelerated vesting for certain stock option awards. The awards grantedunder our 2007 Long-Term Incentive Plan and 2007 Directors CompensationIncentive Plan allows us to attract and retain key personnel.

 

*Geological, Geophysical andEngineering*

 

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

 

*Depreciation, Depletion andAmortization*

 

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

 

*Other Income/(Expense)*

 

Income from our investment in Ecuador propertyincreased $0.4 million to $0.7 million in 2008 from $0.3 million in 2007. Theincrease is due to increased production and increased oil prices received in2008.  Since our investment consists of an interest in a producing oil andgas property, we are amortizing the investment on a straight-line basis overthe remaining 

 

56

----

Table of Contents

 

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

 

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

 

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

 

Other income decreased $0.1 million to $0.1 million in2008 from $0.2 million in 2007. The decrease in other income is due to areduction in realized foreign exchange rate gains of approximately $0.1 millionin 2008.  The exchange rate gain isrelated to the early recovery of IGV or Value Added Taxes in Peru.  IGVunder the early recovery program is denominated in the Peruvian Nuevo Solcurrency. The decrease in the net foreign currency gain was due to thestrengthening of the Nuevo Sol against the U.S. Dollar.

 

*Taxes*

 

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

 

The source of net lossbefore income tax expense/ (benefit) for the year ended December 31, is asfollows (in thousands):

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

 

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

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

 

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

 

57

----

Table of Contents

 

**Liquidity,Capital Resources and Capital Expenditures**

 

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

 

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

 

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

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

 

*Operating Activities*

 

Cash used in operatingactivities increased by $79.5 million to a use of cash of $30.8 million in 2009from a source of cash of $48.7 million in 2008. Cash flow before changes inoperating assets and liabilities decreased by $29.1 million reflectinglower oil production revenues and higher lease operating costs and geological,geophysical, and engineering costs during 2009 compared to 2008, partiallyoffset by lower general and administrative expenses. Changes in operatingassets and liabilities provided a use of cash of $50.4 million.  In 2009 the change in accounts payableprovided a use of cash of $2.6 million and in 2008 provided a source of cash of$23.5 million, the change being a net use of cash of $26.1 million. The reasonfor the change in accounts payable is due to initiatives in 2009 taken by us tobetter manage our accounts payable balance. In 2009 the change in income taxespayable provided a use of cash of $6.5 million and in 2008 provided a source ofcash of $6.9 million, the change being a net use of cash of $13.4 million. Thereason for the change in income taxes payable is primarily due to the incometax cash payments made in 2009. In 2009 the change in value added tax receivableprovided a use of cash of $14.0 million and in 2008 provided a use of cash of$4.6 million, the change being a net use of cash of $9.4 million. The reasonfor the change in the balance is due to lower oil revenues in the current yearand increased costs. In 2009 the change in inventory provided a use of cash of$7.6 million and in 2008 provided a use of cash of $0.6 million, the changebeing a net use of cash of $7.0 million. The reason for the change is due tothe increased purchase of casing and accessories for use in the Company’scurrent and future operations. In 2009 the change in accounts receivableprovided a source of cash of $2.4 million and in 2008 provided a use of cash of$2.3 million, the change being an increase of cash of $4.7 million. The reasonfor the change is due to the timing and amount of our account receivablebalances. The balance at the end of 2009 was lower than the balance at the endof 2008 by $2.4 million.  The balance atthe end of 2008 was higher than the balance at the end of 2007 by $2.3 million.

 

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

 

*Investing Activities*

 

Net cash used in investing activities decreased by$12.2 million to cash used in investing activities of $90.0 million in2009 from $102.2 million in 2008, respectively, and is primarily due todecreased capital expenditures in 2009.

 

58

----

Table of Contents

 

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

 

*2009Equipment Activity*

 

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

 

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

 

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

 

In 2009, we entered intoa lease-purchase agreement to acquire the Don Fernando barge resulting inadditional capital assets of approximately $7.2 million.  The Don Fernando will serve as ourconstruction lay barge as well as tender assist barge for drilling andconstruction operations and will eventually be fitted to lay subsea pipe forthe gas-to-power project.  Additional outfittingof the barge will cost approximately $1.5 million to $2.0 million.

 

For the development of aCompany owned gas-fired power generation facility, we incurred costs ofapproximately $4.9 million as part of our agreement to purchase three LM6000gas-fired turbines.

 

We also incurred costs forthe purchase of machinery and equipment used in operations in Peru ofapproximately $2.9 million.

 

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

 

*2008Equipment Activity*

 

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

 

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

 

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

 

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

 

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

 

59

----

Table of Contents

 

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

 

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

 

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

 

*Financing Activities*

 

Cashprovided by financing activities increased by $82.4 million to $133.6million in 2009 compared to $51.3 million in 2008. The increase in cashprovided by financing activities reflects increased proceeds from sales of ourcommon stock and proceeds from the exercise stock options and warrants of $91.4million. Partially offsetting these proceeds are reduced borrowings, loan feesand reduced repayments of borrowings of $9.0 million.

 

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

 

*ShelfRegistration*

 

To finance our operationswe may sell additional shares of our common stock. Our certificate of formationdoes not provide for preemptive rights, although we may grant similar rights bycontract from time to time. We currently have approximately $134.6 million incommon stock available under an effective shelf registration statement, whichwe may sell from time to time in one or more offerings pursuant to underwrittenpublic offerings, negotiated transactions, block trades or a combination ofthese methods. This registration statement will expire on December 7,2010.

 

*Long-TermDebt and Capital Lease Obligations*

 

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

 
| ** **                                                             | ** ** | **December 31,  2009** | ** ** | **December 31,  2008** | ** ** |
|------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                                             | ** ** | **(in  thousands)**         | ** ** |
|                                                                   |       |                        |       |                        |       |
| $15 million IFC Senior Note, Libor plus 2.75%, due 2012                |       | $                           | 15,000     |                        | $          | 15,000 |   |
| Capital Lease Obligations                                              |       | 11,910                      |       | 7,838                       |       |
| Other                                                                  |       | 1,023                       |       | —                      |       |
|                                                                   |       | 27,933                      |       | 22,838                      |       |
| Less: Current Portion of  Long-Term Debt and Capital Lease Obligations |       | 5,352                       |       | 7,820                       |       |
|                                                                   |       | $                           | 22,581     |                        | $          | 15,018 |   |

 

*$15.0Million IFC Reserve-Based Credit Facility*

 

We have a $15.0 millionreserve-based lending facility (“IFC Facility”) agreement (the “Loan Agreement”)with IFC through our subsidiaries BPZ E&P and BPZ Marine Peru S.R.L. asborrowers. The reserve-based lending facility was to originally mature in December 2012,however, as result of the $170.9 million Convertible Debt issuance by us in February andMarch 2010, we expect to use a portion of the proceeds to repay the amountoutstanding to the IFC in 2010. Therefore $2.5 million of the $15.0 million that was originally due at December 31,2010 and that would have being classified as a 

 

60

----

Table of Contents

 

current liability at December 31, 2009 is beingclassified as a long term liability, in accordance with Accounting StandardCodification (“ASC”) Topic 470, “Debt”, as we intend to refinance the obligationon a long-term basis.

 

The reserve-based lendingfacility bears interest at an approximate rate of LIBOR plus 2.75%, currentlyequivalent to 3.19% based on the six month LIBOR rate of 0.44% at December 31,2009.  The maximum amount available under this facility begins at $15.0million and will be reduced by $2.5 million beginning on December 16, 2010and every six months thereafter during the term of the Loan Agreement. The amount available under the Loan Agreement is subject to a semi-annualborrowing base determination based on the value of oil reserves.  Inaddition, we are subject to various financial covenants calculated as of thelast day of each quarter, including a life of field coverage ratio, life ofloan coverage ratio, debt to equity ratio and interest coverage ratio. Werequested and received a waiver and amendment from IFC which extended theperiod of time to assign a first priority lien on Empresa Electrica NuevaEsperanza S.R.L.’s interest in the Agreement with GE for three gas firedturbines to IFC until December 2010. Accordingly, we were in compliancewith all material covenants of the Loan Agreement as of December 31, 2009.

 

The LoanAgreement provides for events of default customary for agreements of this type,including, among other things, payment breaches under any of the financedocuments for the first and second tranche of the senior debt; failure tocomply with obligations; representation and warranty breaches; expropriation ofthe assets, business or operations of any borrower; insolvencies of anyborrower; certain attachments against the assets of any borrower; failure tomaintain certain authorizations with respect to any financing documents withthe IFC, the development and operation of the Corvina field in Block Z-1, anyadditional petroleum assets under license contracts with Perupetro or certainother key agreements; revocation of any financing or security documents withthe IFC or certain key agreements; defaults on certain liabilities; certainjudgments against the borrower or any subsidiary; abandonment or extendedbusiness interruption of the Corvina field or certain other petroleum assets;engagement in certain sanctionable practices; or restrictions are enacted inPeru that could inhibit any payment a borrower is required to make under thefinancing documents with the IFC.

 

If anevent of default occurs, IFC and any additional facility agent may (i) terminateall or part of the relevant facility; (ii) declare all or part of theprincipal amount of the loan, together with accrued interest, immediately dueand payable;  (iii) declare all or part of the principal amount ofthe loan, together with accrued interest, payable on demand; or (iv) declareany and all of the security documents under the facility enforceable andexercise its rights under such documents. In addition, if any borrower isliquidated or declared bankrupt, all loans and interest accrued on it or anyother amounts due, will become immediately due and payable without notice.

 

*Other*

 

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

 

*NotePayable*

 

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

 

*CapitalLeases*

 

In November 2009, weentered into a capital lease agreement for a construction barge, the DonFernando, to assist us in our offshore construction projects. The capital leaseasset and corresponding liability was recorded at $7.0 million, whichrepresents the present value of the minimum lease payments, or the aggregatefair market value of the assets.  At theend of the two year lease the title to the barge transfers to us.  We accounted for the lease agreement in accordancewith ASC Topic 840, “Leases”, previously accounted for under Statement ofFinancial Accounting Standards (“SFAS”) No. 13, “Accounting for Leases (AsAmended)”. Under the guidance, the lease agreement is accounted for as acapital lease and the imputed interest rate necessary to reduce the net minimumlease payments to present value over the lease term is 22.4%.

 

61

----

Table of Contents

 

In June 2007, weentered into a capital lease agreement, with an option to purchase, for twobarges, Namoku and the Nu’uanu, to assist in the development of the Corvinaoil. The capital lease assets were recorded at $6.2 million, which representsthe present value of the minimum lease payments, or the aggregate fair market valueof the assets.

 

In May 2009, weentered into an amendment of our lease agreement for two barges currently undercharter, the Namoku and the Nu’uanu. Under the terms of the amended leaseagreement, the current charter, originally set to expire in November 2009,is extended for five years commencing on May 1, 2009.  During thefirst 18 months of the amended lease term, the daily charter rate for the useof both barges is fixed. Commencing on November 2010, the dailycharter rate for the use of both vessels will be based on a tiered structurewith the daily rate dependent upon the amount of the previous month’s averagedaily per barrel price of West Texas Intermediate Crude Oil (“WTI”), asindicated on the New York Mercantile Exchange. Any amount paid by us after November 2010over the initial daily rate, as a result of the escalated tiered structurebased on the price of WTI, will be considered contingent rental payments. The amended lease agreement contains a $3.0 million purchase option after thethird year of the lease, a $2.0 million purchase option after the fourth yearof the lease and a mandatory $1.0 million purchase obligation by us after thefifth year of the lease.We accounted for the amended lease agreement in accordance with ASCTopic 840, “Leases”, previously accounted for under SFAS No. 13, “Accountingfor Leases (As Amended)”. Under the guidance, the lease agreement continues tobe accounted for as a capital lease and the imputed interest rate necessary toreduce the net minimum lease payments to present value over the lease term is34.9%.

 

In June 2008, weentered into a two year capital lease agreement to acquire the productionequipment used on board the Namoku resulting in additional capital assets ofapproximately $2.4 million. Further we capitalized an additional $2.8 millionof production equipment in order to have the FPSO ready to receive and treatoil received from the CX-11 platform. The FPSO lease contains two bargainpurchase options; therefore, depreciation of these leased asset will be overits useful life.  The lease contains abargain purchase option of $1.0 million at the end of the first year of thelease and a $0.5 million bargain purchase option at the end of the second yearof the lease. We accounted for the lease agreement in accordance with ASC Topic840, “Leases”, previously accounted for under SFAS No. 13, “Accounting forLeases (As Amended)”. Under the guidance, the lease agreement is accounted foras a capital lease and the imputed interest rate necessary to reduce the netminimum lease payments to present value over the lease term is 28.3%.

 

In March 2008, weentered into a lease-purchase agreement to acquire the BPZ-02 barge resultingin additional capital assets of approximately $7.0 million. In February 2009,we made the final lease payment on the BPZ-02 deck barge at which point titleto the barge was transferred to us.

 

In 2007, the Companyentered into two capital loans for the purchase of office furniture.  Bothloans 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.

 

*PerformanceBonds*

 

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

 

All of the performanceand insurance bonds are issued by Peruvian banks and their terms are governedby the corresponding license contracts, customs laws, lending practices orrental practices.

 

62

----

Table of Contents

 

*2010 Estimated Capital Expenditures Budget*

 

Weestablished a 2010 capital expenditures budget of approximately $200.0 millionwhich includes $18.0 million in seismic costs that will be expensed under theSuccessful Efforts Method of Accounting, as well as $35 million in remainingcontract payments to purchase the GE turbines for the gas-to-powerproject.  We will continue to focus ourefforts on oil production in Block Z-1 by committing a majority of our capital expendituresbudget to continue to appraise and develop the oil in the Corvina and Albacorafields.  Accordingly, we plan to complete our final two wellson the CX-11 platform in the Corvina field and drill approximately four newwells in Albacora from the A platform. We also plan to install permanentreinjection facilities in Albacora and complete our production and reinjectionfacilities to begin commercial production in the Corvina field.   In accordance with our Block XIX 2010exploration commitments, upon completion of the last Corvina well in 2010, weintend to mobilize the Corvina rig to Block XIX and drill a step out well tothe 5215 in the Pampa de la Gallina field. The step out well will qualify as an exploration well under the BlockXIX License Contract as it will target previously untested sands lower in theHeath formation.

 

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

 
| ** **                                                       | ** ** | **2010 Capital  Budget** | ** ** |
|------------------------------------------------------------------|------------|--------------------------|------------|
| ** **                                                       | ** ** | **($ in millions)** | ** ** |
| **Corvina**                                                      | ** ** | ** **               | ** ** |
| Drilling and development                                         |       | $                        | 16.4       |   |
| Platform construction and refurbishment                          |       | 10.4                     |       |
| Other facilities and activities                                  |       | 13.6                     |       |
|                                                             |       | 40.4                     |       |
| **Albacora**                                                     |       |                     |       |
| Drilling and development                                         |       | 60.0                     |       |
| Platform construction and refurbishment                          |       | 0.6                      |       |
| Other facilities and activities                                  |       | 3.7                      |       |
| ** **                                                       |       | 64.3                     |       |
| **Other Drilling Areas and  Activities**                         |       |                     |       |
| Block XIX                                                        |       | 17.3                     |       |
| Block XXIII                                                      |       | 11.7                     |       |
| Other facilities and activities                                  |       | 0.8                      |       |
| ** **                                                       |       | 29.8                     |       |
| **Marine Support Operations**                                    |       |                     |       |
| Barges and vessels                                               |       | 3.8                      |       |
| Infrastructure improvements and other facilities  and activities |       | 8.8                      |       |
| ** **                                                       |       | 12.5                     |       |
| **Power Generation**                                             |       |                     |       |
| Turbines                                                         |       | 35.2                     |       |
|                                                             |       |                     |       |
| Total estimated capital budget                                   |       | $                        | 182.2      |   |
|                                                             |       |                     |       |
| **Seismic expenses***                                            |       | $                        | 18.0       |   |
|                                                             |       |                     |       |
| **Total**                                                        |       | $                        | 200.2      |   |

 

----

* Seismic costs are expensed under the successful efforts method ofaccounting

 

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

 

63

----

Table of Contents

 

*Liquidity Outlook*

 

Our2009 net revenue decreased by $10.5 million to $52.5 million from $63.0 millionin 2008. The decrease in net revenue is primarily due to the depressed oilprices during the first half of 2009. Oil sales from the Corvina field during2009 was approximately 963,000 barrels or approximately 137,000 barrels morethan what was sold in 2008.  However,average oil prices received from our oil sales to the Talara Refinery decreasedby approximately 29% to approximately $54.49 per barrel compared to the 2008average price of $76.23 per barrel.

 

Our major sources of funding to date have beenthrough oil sales, equity raises, convertible debt issuances and, to a lesserextent, debt financing activities.  Withour current cash balance, current and prospective Corvina and Albacora Oildevelopment cash flow, our recent convertible debt issuance, other potentialthird-party financing and potential financing from future equity raises, webelieve we will have sufficient capital resources to execute our currentCorvina and Albacora oil development projects as well as service our currentdebt obligations and plan to continue pursuing our gas-to-power project onceproject funding becomes available. However, the timing and execution of ourproject is dependent on a variety of factors, including the technical design offacilities, permitting approval, availability of equipment, time and costsrequired for delivery of materials and construction operations, performance bycontractors and the success of planned financing, many of which factors areoutside our control and cannot be assured.

 

64

----

Table of Contents

 

**Off-BalanceSheet Arrangements**

 

As of December 31, 2009, we had no transactions,agreements or other contractual arrangements with unconsolidated entities orfinancial partnerships, often referred to as special purpose entities, whichgenerally are established for the purpose of facilitating off-balance sheetarrangements.

 

**Contractual Obligations**

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

 

----

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

 

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

 

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

 

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

 

Includes capital lease for two production and storage barges, the Namokuand the Nu’uanu, whose lease was amended in May 2009 and is currently setto expire in April 2014. Lease payments are variable based on the workingstatus of the barges. The amended lease agreement contains a $3.0 millionpurchase option after the third year of the lease, a $2.0 million purchaseoption after the fourth year of the lease and a mandatory $1.0 million purchaseobligation by us after the fifth year of the lease. Commencing on November 2010,the daily charter rate for the use of both vessels will be based on a tieredstructure with the daily rate dependent upon the amount of the previous month’saverage daily per barrel price of WTI, as indicated on the New York MercantileExchange. Any amount paid by us after November 2010 over the initial dailyrate as a result of the escalated tiered structure based on the price of WTIwill be considered contingent rental payments.

 

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

 

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

 

65

----

Table of Contents

 

(3)                   Includes the debt andinterest payments related to the $15.0 million reserve-based lending facilityagreement with IFC through our subsidiaries BPZ Exploracion &Produccion S.R.L and BPZ Marine Peru S.R.L as borrowers.  The reserve-based lending facility bearsinterest at an approximate rate of LIBOR plus 2.75%, currently equivalent to3.19% based on the six month LIBOR rate of 0.44% at December 31,2009.  The maximum amount available under this facility will begin at$15.0 million and will be reduced by $2.5 million beginning on December 16,2010 and every six months thereafter during the term of the LoanAgreement.  As we intend to refinancethis facility with a long term obligation, the $2.5 million due December 16,2010 has not been included in the 2010 payments.

 

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

 

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

 

**Critical Accounting Policies**

 

The discussion and analysis of our financial conditionand results of operations is based on our consolidated financial statements,which have been prepared in accordance with U.S. generally accepted accountingprinciples (“GAAP” or “U.S. GAAP”). Management uses estimates and assumptionsin 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 thefollowing as critical accounting policies directly related to our business andoperations, and the understanding of our financial statements:

 

***Successful Efforts Method of Accounting***

 

We follow the successful efforts method ofaccounting for our investments in oil and gas properties. Under this method,oil and gas lease acquisition costs and intangible drilling costs associatedwith exploration efforts that result in the discovery of proved reserves andcosts associated with development drilling, whether or not successful, arecapitalized when incurred. Certain costs of exploratory wells are capitalizedpending determinations that proved reserves have been found. If thedetermination is dependent upon the results of planned additional wells andrequired capital expenditures to produce the reserves found, the drilling costswill be capitalized as long as sufficient reserves have been found to justifycompletion of the exploratory well and additional wells are underway or firmlyplanned to complete the evaluation of the well. All costs related tounsuccessful exploratory wells are expensed when such wells are determined tobe non-productive or at the one year anniversary of completion of the well ifproved reserves have not been attributed and capital expenditures as describedin the preceding sentence are not required. We assess our capitalizedexploratory wells pending evaluation each quarter to determine whether costsshould remain capitalized or should be charged to earnings. Other explorationcosts, including geological and geophysical costs, are expensed as incurred. Wewill recognize gains or losses on the sale of properties, should they occur, ona field-by-field basis.

 

The application of the successful efforts method of accountingrequires management’s judgment to determine the proper designation of wells aseither developmental or exploratory, which will ultimately determine the properaccounting treatment of the costs incurred. The results from a drillingoperation can take considerable time to analyze, and the determination thatcommercial reserves have been discovered requires both judgment and applicationof industry experience. Wells may be completed that are assumed to beproductive and actually deliver oil and gas in quantities insufficient to beeconomic, which may result in the abandonment of the wells at a later date. Theevaluations of oil and gas leasehold acquisition costs requires management’sjudgment to estimate the fair value of exploratory costs related to drillingactivity in a given area.

 

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

 

66

----

Table of Contents

 

***Oil and Gas Accounting Reserves Determination***

 

The successfulefforts method of accounting depends on the estimated reserves we believe arerecoverable from our oil and gas reserves. The process of estimating reservesis complex. It requires significant judgments and decisions based on availablegeological, geo-physical, engineering and economic data.

 

To estimate theeconomically recoverable oil and natural gas reserves and related future netcash flows, we incorporate many factors and assumptions including:

 

·                                         expected reservoir characteristics basedon geological, geophysical and engineering assessments;

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

·                                         future oil and gas quality differentials;

·                                         assumed effects of regulation bygovernmental agencies; and

·                                         future development and operating costs.

 

We believe ourassumptions are reasonable based on the information available to us at the timewe prepare our estimates. However, these estimates may change substantiallygoing forward as additional data from development activities and productionperformance becomes available and as economic conditions impacting oil and gasprices and costs change.

 

Management isresponsible for estimating the quantities of proved oil and natural gasreserves and for preparing related disclosures. Estimates and relateddisclosures are prepared in accordance with SEC requirements and generallyaccepted industry practices in the US as prescribed by the Society of PetroleumEngineers. Reserve estimates are independently evaluated at least annually byindependent qualified reserves engineers, NSAI.

 

Our board ofdirectors oversees the review of our oil and gas reserves and relateddisclosures by the Company’s appointed independent reserve engineers. The Boardmeets with management periodically to review the reserves process, results, andto confirm that the independent reserve engineers have had access to sufficientinformation, including the nature and satisfactory resolution of any materialdifferences of opinion between the Company and the reserve engineers.

 

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

 

·                                         Determining whether or not an exploratorywell has found economically producible reserves;

·                                         Calculating our unit-of-productiondepletion rates. Proved reserves estimates are used to determine rates that areapplied to each unit-of-production in calculating our depletion expense; and

·                                         Assessing, when necessary, our oil andgas assets for impairment. Estimated future cash flows are determined usingproved reserves. The critical estimates used to assess impairment, includingthe impact of changes in reserves estimates, are discussed below.

 

***Revenue Recognition***

 

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

 

We sell our oil productionin the Peruvian domestic market on a contract basis.  Revenue is recorded net of royalties when thepurchaser takes delivery of the oil.  Atthe end of the period, oil that has been produced but not sold is recorded asinventory 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 thecarrying value of our long-lived assets and identifiable intangibles bymonitoring and evaluating changes in circumstances that may indicate that thecarrying amount of the asset may not be recoverable. Examples of events orchanges in circumstances that indicate the recoverability of the carryingamount of an asset should be assessed include, but are not limited to, (a) asignificant decrease in the market value of an asset, (b) a significantchange in the extent or manner in which an asset is used or a significantphysical change in an asset, (c) a significant adverse change in legalfactors or in the business climate that could affect the value of an asset oran adverse action or assessment by a regulator, (d) an accumulation ofcosts significantly in excess of the amount originally expected to acquire orconstruct an asset,

 

67

----

Table of Contents

 

and/or(e) a current period operating or cash flow loss combined with a historyof operating or cash flow losses or a projection or forecast that demonstratescontinuing losses associated with an asset used for the purpose of producingrevenue.

 

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

 

***Future Dismantlement, Restoration, and AbandonmentCosts***

 

The accounting for future development andabandonment costs changed on January 1, 2003, with the issuance of ASCTopic 410, “Asset Retirement and Environmental Liabilities”, previously knownas SFAS No. 143, “Accounting for Asset Retirement Obligation” (“ARO”),which requires the fair value of a liability for an asset retirement obligationto be recognized in the period in which it is incurred if a reasonable estimateof fair value can be made. The associated asset retirement costs arecapitalized as part of the carrying amount of the long-lived asset. The accrualis based on estimates of these costs for each of our properties based upon thetype of production structure, reservoir characteristics, depth of thereservoir, market demand for equipment, currently available procedures andconsultations with construction and engineering consultants. Because thesecosts typically extend many years into the future, estimating these costs is difficultand requires management to make estimates and judgments that are subject tofuture revisions based on numerous factors, including changing technology, thepolitical and regulatory environment and estimates as to the proper discountrate to use and timing of abandonment.

 

Our plan of operations includes the drilling of wellsand the construction of an electric power generation plant. We will be requiredto plug and abandon those wells and restore the well sites and power generationsite upon abandonment if they are abandoned prior to the end of the contractperiod.  See Note 8 “Asset RetirementObligation” to the consolidated financial statements provided herein forfurther detail.

*** ***

***Principles ofConsolidation***

*** ***

Our consolidated financialstatements include the accounts of BPZ and its wholly-owned subsidiaries andbranch offices. All intercompany balances and transactions have beeneliminated. Managementhas evaluated all subsequent events through March 31, 2010, the date thefinancial statements were available to be issued.

 

Our accounting policyregarding partnership or joint venture interests in oil and gas properties isto consolidate such interests on a pro-rata basis in accordance with acceptedpractice in the oil and gas industry. However, we have not been able to receivetimely information to allow us to proportionately consolidate the minoritynon-operated working interest owned by our consolidated subsidiary, SMC Ecuador,Inc. See Note 6 “Investment inEcuador Property” to the consolidated financial statements for furtherdiscussion regarding the investment in our Ecuador property. Accordingly, weaccount for this investment under the cost method. As such, we record our shareof cash received or paid attributable to this investment as other income orexpense and amortizesour investment into income over the remaining term of the licenseagreement, which expires in May 2016.

 

***Stock Based Compensation***

** **

We account for stock-basedcompensation at fair value in accordance with the provisions of ASC Topic 718, “StockCompensation” (“ASC Topic 718”), previously accounted for  underSFAS 123(R), “Share—BasedPayment”, which establishes accounting for stock-based payment transactions foremployee services and goods and services received from non-employees. Under theprovisions of ASC Topic 718,stock-based compensation cost is measured at the date of grant, based on thecalculated fair value of the award, and is recognized as expense in theConsolidated Statements of Operations ratably over the employee’s or non-employee’s requisite service period,which is generally the vesting period of the equity grant. The fair value of stock option awards isdetermined using the Black-Scholes option-pricing model. Restricted stockawards and units are valued using the market price of our common stock on thegrant date. Additionally,stock-based compensation cost is recognized based on awards that are ultimatelyexpected to vest, therefore, the compensation cost recognized on stock-based payment transactions is reduced forestimated forfeitures based on our historical forfeiture rates. Additionally, no stock-based compensationcosts were capitalized for the years ended December 31, 2009, 2008 and2007. We provide compensation benefits to employees and non-employee directorsunder share-based payment arrangements, including various employee stock optionplans.

 

ASC Topic 230, “Statement of Cash Flows”, requires thecash flows resulting from tax deductions in excess of the compensation costrecognized for equity awards (excess tax benefits) to be classified asfinancing cash flows. However, as 

 

68

----

Table of Contents

 

we are not able to use these tax deductions (see Note14, “Income Taxes” for further information), we have no excess tax benefits tobe classified as financing cash flows.

*** ***

***Foreign Exchange***

*** ***

The U.S. Dollar is the functional currency for ouroperations in both Peru and Ecuador. Ecuador has adopted the U.S. Dollar as itsofficial currency. Peru, however, still uses its local currency, Nuevo Sol, inaddition to the U.S. Dollar and therefore our financial results are subject tofavorable or unfavorable fluctuations in the exchange rate and inflation ofthat country. We have adopted ASC Topic 830, “Foreign Currency Matters”,previously SFAS No. 52, “Foreign Currency Translation,” which requiresthat the translation of the applicable foreign currency into U.S. dollars beperformed for balance sheet monetary accounts using current exchange rates ineffect at the balance sheet date, non-monetary accounts using historicalexchange rates in effect at the time the transaction occurs, and for revenueand expense accounts using a weighted average exchange rate during the periodreported. Accordingly, the gains or losses resulting from such translation areincluded in other income and expense in the consolidated Statements ofOperations.

 

**Recent Accounting Pronouncements**

 

In June 2009, the Financial Accounting StandardsBoard (“FASB”) issued SFAS No. 168, now codified as ASC Topic 105, “GenerallyAccepted Accounting Principles” (“ASC Topic 105”).   ASC Topic 105provides the FASB ASC as the single source of authoritative GAAP recognized bythe FASB to be applied by nongovernmental entities. The FASB ASC changes GAAPfrom a standards based model, with thousands of standards, to a topically basedmodel. Rules and interpretive releases of the Securities and ExchangeCommission (“SEC”) under authority of federal securities laws are also sourcesof authoritative GAAP for SEC registrants. On the effective date of ASC Topic105 the ASC supersedes all then-existing non-SEC accounting and reportingstandards. All other nongrandfathered non-SEC accounting literature not includedin the ASC will become nonauthoritative.   The provisions of FASB ASCTopic 105 are effective for interim and annual periods ending after September 15,2009 and, accordingly, are effective for us for the current fiscal reportingperiod. The adoption of the ASC did not have an impact on our financialposition, results of operations or cash flows.

 

In May 2009, the FASB issued SFAS No. 165, “SubsequentEvents” (“SFAS No. 165”), now codified as ASC Topic 855, “SubsequentEvents” (“ASC Topic 855”). This standard establishes the accounting for anddisclosure of events that occur after the balance sheet date but beforefinancial statements are issued or are available to be issued. It requires thedisclosure of the date through which an entity has evaluated subsequent eventsand the basis for that date, that is, whether that date represents the date thefinancial statements were issued or were available to be issued. We adopted ASCTopic 855 in the second quarter of 2009. The adoption of ASC Topic 855 did nothave a material impact on our consolidated financial position, results ofoperations or cash flows. See Note 1, “Basis of Presentation and SignificantAccounting Policies”, to the accompanying consolidated financial statements forthe related disclosure.

 

In December 31, 2008, the SEC adopted the final rules regardingamendments to current Oil and Gas reporting requirements. The amendments aredesigned to modernize and update the oil and gas disclosure requirements toalign them with current practices and changes in technology and include thefollowing:

 

·                                         Requiring companies to report oil and gasreserves using an average first-day-of-the month price based upon the prior12-month period rather than year-end prices;

·                                         Enabling companies to additionallydisclose their probable and possible reserves;

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

·                                         Requiring companies to report theindependence and qualifications of a preparer or auditor, based on currentSociety of Petroleum Engineers criteria;

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

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

 

The amendments are effective for registrationstatements filed on or after January 1, 2010, and for annual reports on Form 10-Kand for fiscal years ending on or after December 31, 2009. Early adoptionis not permitted in either annual or quarterly reports before the first annualreport in which the revised disclosures are required.

 

69

----

Table of Contents

 

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

 

In addition, in January 2010, the FASB issuedAccounting Standards Update 2010-03, “Oil and Gas Reserve Estimation andDisclosures”, to provide consistency with the new SEC rules. The Update amendsexisting standards to align the reserves calculation and disclosurerequirements under U.S. GAAP with the requirements in the SEC rules. We adoptedthe new standards effective December 31, 2009. The new standards areapplied prospectively as a change in estimate.  See also Supplemental Oiland Gas Information (Unaudited).

 

In May 2008, the FASB issued FASB Staff Position(“FSP”) No. APB 14-1, “Accounting for Convertible Debt Instruments That May BeSettled in Cash Upon Conversion (Including Partial Cash Settlement)” which iscodified under ASC Topic 470, “Debt”. Under the accounting guidance,convertible debt instruments that may be settled entirely or partially in cashupon conversion will be required to separately account for the liability andequity components of the instrument in a manner that reflects the issuer’snonconvertible debt borrowing rate. The FSP is effective for fiscal yearsbeginning after December 15, 2008. This rule requires retrospectiveapplication to all periods presented. The cumulative effect ofthe change in accounting principle on periods prior to those presented shall berecognized as of the beginning of the first period presented. However, theprovisions of this FSP need not be applied to immaterial items. Subsequent to December 31,2009, the Company issued $170.9 million of convertible debt due in 2015 that isimpacted by this accounting standard. See Convertible Debt due 2015 under Financing Activities of ITEM7.,  “Management’s Discussion andAnalysis of Financial Conditions and Results of Operations”,  for theexpected impact of this accounting standard on the Company’s convertible debtissued in February 2010 and March 2010.

 

**ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK**

 

The objective of the following information is toprovide forward-looking quantitative and qualitative information about ourpotential exposure to market risks. The term “market risk” refers to the riskof loss arising from adverse changes in interest rates, oil and natural gasprices and foreign currency exchange rates. The disclosures are not meant to beprecise indicators of expected future losses, but rather indicators ofreasonable possible losses. This forward-looking information providesindicators of how we view and manage our ongoing market risk exposures. All ofour market risk sensitive instruments were entered into for purposes other thanspeculative trading.

 

*Interest Rate Risk.*

 

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

 

The $15.0million reserve-based lending facility is variable rate debt and bears interestat an approximate rate of LIBOR plus 2.75%. The variable rate debt exposes us to the risk ofincreased interest expense in the event of increases in short-term interestrates. If the variable interest rate were to increase by 1% from December 2009levels, interest expense would increase by approximately $0.2 millionannually. The carrying value of the variable interest rate debt approximatesfair value as it bears interest at current market rates.

 

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

 

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

 

70

----

Table of Contents

 

guidance, the lease agreement is accounted for as acapital lease and the imputed interest rate necessary to reduce the net minimumlease payments to present value over the lease term is 22.4%.

 

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

 

*Commodity Price Risk*

 

With respect to our oil and gas business, anyrevenues, cash flow, profitability and future rate of growth we achieve will begreatly dependent upon prevailing prices for oil and gas.  Our ability tomaintain or increase our borrowing capacity and to obtain additional capital onattractive terms is also expected to be dependent on oil and gas prices. Historically, oil and gas prices and markets have been volatile and are likelyto continue to be volatile in the future.  Prices for oil and gas aresubject to potentially wide fluctuations in response to relatively minorchanges in supply of and demand for oil and gas, market uncertainty, and avariety of additional factors that are beyond our control.

 

Lower oil and natural gas prices may not only decreaseour revenues on a per unit basis, but may also reduce the amount of oil andnatural gas we can produce economically, if any.  A substantial orextended decline in oil and natural gas prices may materially affect our futurebusiness, financial condition, results of operations, liquidity and borrowingcapacity, and we may require a reduction in the carrying value of our oil andgas properties.  While our revenues may increase if prevailing oil and gasprices increase significantly, exploration and production costs and acquisitioncosts for additional properties and reserves may also increase.

 

With respect to our planned electricity generationbusiness, the price we can obtain for the sale of power may not rise at thesame rate, or may not rise at all, to match a rise in the Company’s cost toproduce and transport gas reserves to our initial 135MW power plant in CaletaCruz.  Prices for both electricity and natural gas have been very volatilein the past year and have increased significantly over the past twoyears.  The profitability of this business depends in large part on thedifference between the price of power and the price of fuel used to generatepower, or “spark spread.”

 

*Foreign Currency Exchange Rate Risk*

 

The U.S. Dollar is the functional currency for ouroperations in both Peru and Ecuador.  Ecuador has adopted the U.S. Dollaras its official currency.  Peru, however, uses its local currency, NuevoSol, in addition to the U.S. Dollar, and therefore, our financial results aresubject to favorable or unfavorable fluctuations in the exchange rate andinflation in that country.  Transaction differences have been nominal to-datebut are expected to increase as our activities in Peru continue toescalate.  During the year ended December 31, 2009, we recognized anexchange rate loss of approximately $0.1 million. During the year ended December 31,2008, and 2007 we recognized exchange rate gains of approximately $0.1 millionand $0.2 million, respectively.

 

71

----

Table of Contents

 

**ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA**

 

BPZ Resources, Inc.and SubsidiariesIndex to Consolidated Financial Statements

 
| Report of Independent Registered Public Accounting  Firm                                                        | 73     |
|-----------------------------------------------------------------------------------------------------------------|--------|
|                                                                                                            |   |
| Consolidated  Balance Sheets as of December 31, 2009 and 2008                                              | 74     |
|                                                                                                            |   |
| Consolidated Statements of Operations for the Years  Ended December 31, 2009, 2008 and 2007                | 75     |
|                                                                                                            |   |
| Consolidated Statements of Stockholders’ Equity for  the Years Ended December 31, 2009, 2008 and 2007 | 76     |
|                                                                                                            |   |
| Consolidated Statements of Cash Flows for the Years  Ended December 31, 2009, 2008 and 2007                | 77     |
|                                                                                                            |   |
| Notes to Consolidated Financial Statements                                                                      | 78     |
|                                                                                                            |   |
| Supplemental Oil and Gas Disclosures (Unaudited)                                                                | 110    |

 

72

----

Table of Contents

 

**Report of Independent RegisteredPublic Accounting Firm**

 

Tothe Board of Directors and StockholdersBPZ Resources, Inc. and Subsidiaries

Houston,Texas

 

Wehave audited the accompanying consolidated balance sheets of BPZ Resources, Inc.and Subsidiaries as of December 31, 2009 and 2008, and the relatedconsolidated statements of operations, stockholders’ equity, and cash flows foreach of the three years in the period ended December 31, 2009. Thesefinancial statements are the responsibility of the Company’s management. Ourresponsibility is to express an opinion on these financial statements based onour audits.

 

Weconducted our audits in accordance with the standards of the Public CompanyAccounting Oversight Board (United States). Those standards require that weplan and perform the audit to obtain reasonable assurance about whether thefinancial statements are free of material misstatement. An audit includes examining,on a test basis, evidence supporting the amounts and disclosures in thefinancial statements, assessing the accounting principles used and significantestimates made by management, as well as evaluating the overall financialstatement presentation. We believe that our audits provide a reasonable basisfor our opinion.

 

Asdiscussed in Note 11 to the consolidated financial statements, the Company hasrestated its previously issued consolidated financial statements to reflectcertain adjustments associated with the issuance of Merger Earn-Out Shares in2007 and 2005.

 

Inour opinion, the consolidated financial statements referred to above presentfairly, in all material respects, the financial position of BPZ Resources, Inc.and Subsidiaries at December 31, 2009 and 2008, and the results of theiroperations and their cash flows for each of the three years in the period endedDecember 31, 2009, in conformity with accounting principles generallyaccepted in the United States of America.

 

Wealso have audited, in accordance with the standards of the Public CompanyAccounting Oversight Board (United States), BPZ Resources, Inc. andSubsidiaries’ internal control over financial reporting as of December 31,2009, based on criteria established in Internal Control — Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission(COSO) and our report dated March 31, 2010, expressed an unqualifiedopinion thereon.

 

/s/Johnson Miller & Co., CPA’s PC 

Midland,Texas

March 31,2010

 

73

----

Table of Contents

 

**BPZ Resources, Inc. andSubsidiaries**

**Consolidated BalanceSheets**

**(Inthousands, except share par value amounts)**

 
| ** **                                                                                                                                                            | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                                            | ** ** | **2009**              | ** ** | **2008** | ** ** |
| ** **                                                                                                                                                            | ** ** | ** **            | ** ** | **(Restated) (1)** | ** ** |
| **ASSETS**                                                                                                                                                            |       |                  |       |   |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Current assets:                                                                                                                                                       |       |                  |       |   |   |
| Cash and cash equivalents                                                                                                                                             |       | $                     | 18,147     |   | $ | 5,317 |   |
| Accounts receivable                                                                                                                                                   |       | 2,867                 |       | 5,276 |   |
| Value added tax receivable                                                                                                                                            |       | 26,152                |       | 12,110 |   |
| Inventory                                                                                                                                                             |       | 12,507                |       | 4,054 |   |
| Prepaid and other current assets                                                                                                                                      |       | 1,580                 |       | 3,268 |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Total current assets                                                                                                                                                  |       | 61,253                |       | 30,025 |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Property, equipment and construction in progress,  net                                                                                                                |       | 262,517               |       | 193,934 |   |
| Restricted cash                                                                                                                                                       |       | 5,720                 |       | 5,153 |   |
| Other non-current assets                                                                                                                                              |       | 1,559                 |       | — |   |
| Investment in Ecuador property, net                                                                                                                                   |       | 1,195                 |       | 1,382 |   |
| Deferred tax asset                                                                                                                                                    |       | 16,928                |       | 4,871 |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Total assets                                                                                                                                                          |       | $                     | 349,172    |   | $ | 235,365 |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| **LIABILITIES AND STOCKHOLDERS’ EQUITY**                                                                                                                         |       |                  |       |   |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Current liabilities:                                                                                                                                                  |       |                  |       |   |   |
| Accounts payable                                                                                                                                                      |       | $                     | 32,698     |   | $ | 35,286 |   |
| Accrued liabilities                                                                                                                                                   |       | 14,155                |       | 9,920 |   |
| Other liabilities                                                                                                                                                     |       | 1,235                 |       | 720 |   |
| Current income taxes payable                                                                                                                                          |       | 322                   |       | 6,841 |   |
| Accrued interest payable                                                                                                                                              |       | 106                   |       | — |   |
| Current maturity of long-term debt and capital  lease obligations                                                                                                     |       | 5,352                 |       | 7,820 |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Total current liabilities                                                                                                                                             |       | 53,868                |       | 60,587 |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Asset retirement obligation                                                                                                                                           |       | 766                   |       | 580 |   |
| Long-term debt and capital lease obligations                                                                                                                          |       | 22,581                |       | 15,018 |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Total long-term liabilities                                                                                                                                           |       | 23,347                |       | 15,598 |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Commitments and contingencies (Note 16)                                                                                                                               |       |                  |       |   |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Stockholders’ equity:                                                                                                                                            |       |                  |       |   |   |
| Preferred stock, no par value, 25,000 authorized;  none issued and outstanding                                                                                        |       | —                |       | — |   |
| Common stock, no par value, 250,000 authorized;  115,224 and 78,748 shares issued and outstanding at December 31, 2009  and December 31, 2008, respectively |       | 513,145               |       | 364,566 |   |
| Accumulated deficit                                                                                                                                                   |       | (241,188              | )          | (205,386 | ) |
|                                                                                                                                                                  |       |                  |       |   |   |
| Total stockholders’ equity                                                                                                                                       |       | 271,957               |       | 159,180 |   |
|                                                                                                                                                                  |       |                  |       |   |   |
| Total liabilities and stockholders’ equity                                                                                                                       |       | $                     | 349,172    |   | $ | 235,365 |   |

 

----

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

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

 

74

----

Table of Contents

 

**BPZ Resources, Inc.and Subsidiaries**

**Consolidated Statementsof Operations**

**(Inthousands, except per share data)**

 
| ** **                                                       | ** ** | **Year Ended December 31,** | ** ** |
|------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                       | ** ** | **2009**                         | ** ** | **2008** | ** ** | **2007** | ** ** |
| ** **                                                       | ** ** | ** **                       | ** ** | ** ** | ** ** | **(Restated) (1)** | ** ** |
| Revenue                                                          |       | $                                | 52,454     |   | $ | 62,955 |   | $ | 2,350 |   |
|                                                             |       |                             |       |   |   |   |   |
| Operating and administrative expenses:                           |       |                             |       |   |   |   |   |
| Lease operating expense                                          |       | 28,113                           |       | 11,649 |   | 755 |   |
| General and administrative expense                               |       | 33,258                           |       | 42,094 |   | 18,548 |   |
| Geological, geophysical and engineering expense                  |       | 7,768                            |       | 794 |   | 4,045 |   |
| Depreciation, depletion and amortization expense                 |       | 25,803                           |       | 16,062 |   | 793 |   |
|                                                             |       |                             |       |   |   |   |   |
| Total operating expenses                                         |       | 94,942                           |       | 70,599 |   | 24,141 |   |
|                                                             |       |                             |       |   |   |   |   |
| Operating loss                                                   |       | (42,488                          | )          | (7,644 | ) | (21,791 | ) |
|                                                             |       |                             |       |   |   |   |   |
| Other income (expense):                                          |       |                             |       |   |   |   |   |
| Income from investment in Ecuador property, net of  amortization |       | 1,208                            |       | 718 |   | 264 |   |
| Interest income                                                  |       | 215                              |       | 319 |   | 855 |   |
| Other income (expense)                                           |       | (1,312                           | )          | 102 |   | 201 |   |
|                                                             |       |                             |       |   |   |   |   |
| Total other income, net                                          |       | 111                              |       | 1,139 |   | 1,320 |   |
|                                                             |       |                             |       |   |   |   |   |
| Loss before income taxes                                         |       | (42,377                          | )          | (6,505 | ) | (20,471 | ) |
|                                                             |       |                             |       |   |   |   |   |
| Income tax expense (benefit)                                     |       | (6,575                           | )          | 3,141 |   | 39 |   |
|                                                             |       |                             |       |   |   |   |   |
| Net loss                                                         |       | $                                | (35,802    | ) | $ | (9,646 | ) | $ | (20,510 | ) |
|                                                             |       |                             |       |   |   |   |   |
| Basic and diluted net loss per share                             |       | $                                | (0.35      | ) | $ | (0.12 | ) | $ | (0.33 | ) |
| Weighted average common shares outstanding                       |       | 103,362                          |       | 77,390 |   | 61,660 |   |

 

----

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

 

The accompanying notes are an integral part of these consolidated financialstatements.

 

75

----

Table of Contents

 

**BPZ Resources, Inc.and Subsidiaries**

**Consolidated Statementsof Stockholders’ Equity**

**Years Ended December 31,2009, 2008 and 2007**

**(Inthousands)**

 
| ** **                                                  | ** ** | **Common  Stock** | ** ** | **Additional Paid-  in** | ** ** | **Stock  Subscription** | ** ** | **Accumulated** | ** ** | ** **  | ** ** |
|-------------------------------------------------------------|------------|------------------------|------------|--------------------------|------------|-------------------------|------------|-----------------|------------|-------------|------------|
| ** **                                                  | ** ** | **Shares**             | ** ** | **Amount**               | ** ** | **Capital**             | ** ** | **Receivable**  | ** ** | **Deficit** | ** ** | **Total** | ** ** |
|                                                        |       |                   | ** ** | ** **               | ** ** | ** **              |       |            | ** ** | ** **  |       |   |   |
| Balances at January 1, 2007 (1)                        |       | 54,144                 |       | $                        | 136,175    |                    | $          | 5,092           |       | $           | (231       | ) | $ | (77,400 | ) | $ | 63,636 |   |
|                                                        |       |                   |       |                     |       |                    |       |            |       |        |       |   |   |
| Stock-based compensation                                    |       | 5                      |       | 19                       |       | (25                     | )          | —          |       | —      |       | (6 | ) |
| Exercise of stock options assumed in merger                 |       | 379                    |       | 647                      |       | (647                    | )          | —          |       | —      |       | — |   |
| Exercise of stock options                                   |       | 1,868                  |       | 3,426                    |       | —                  |       | —          |       | —      |       | 3,426 |   |
| Long-term incentive compensation plan, net of  forfeitures  |       | 1,348                  |       | 12,020                   |       | (6,757                  | )          | —          |       | —      |       | 5,263 |   |
| Incentive earn-out shares                                   |       | —                 |       | —                   |       | 1,782                   |       | —          |       | —      |       | 1,782 |   |
| Common stock sold for cash, net of offering costs           |       | 7,170                  |       | 37,717                   |       | (799                    | )          | 231             |       | —      |       | 37,149 |   |
| Common stock dividend (merger earn-out shares) (1)          |       | 9,000                  |       | 97,830                   |       | —                  |       | —          |       | (97,830     | )          | — |   |
| Adjustment for negative APIC - deferred stock  compensation |       | —                 |       | (1,354                   | )          | 1,354                   |       | —          |       | —      |       | — |   |
| Net loss                                                    |       | —                 |       | —                   |       | —                  |       | —          |       | (20,510     | )          | (20,510 | ) |
|                                                        |       |                   |       |                     |       |                    |       |            |       |        |       |   |   |
| Balances at December 31, 2007                          |       | 73,914                 |       | 286,480                  |       | —                  |       | —          |       | (195,740    | )          | 90,740 |   |
|                                                        |       |                   |       |                     |       |                    |       |            |       |        |       |   |   |
| Exercise of stock options assumed in merger                 |       | 325                    |       | 422                      |       | —                  |       | —          |       | —      |       | 422 |   |
| Exercise of stock options                                   |       | 567                    |       | 2,046                    |       | —                  |       | —          |       | —      |       | 2,046 |   |
| Long-term incentive compensation plan, net of  forfeitures  |       | —                 |       | 18,464                   |       | —                  |       | —          |       | —      |       | 18,464 |   |
| Common stock sold for cash, net of offering costs           |       | 2,200                  |       | 40,904                   |       | —                  |       | —          |       | —      |       | 40,904 |   |
| IFC debt conversion (1)                                     |       | 1,492                  |       | 15,500                   |       | —                  |       | —          |       | —      |       | 15,500 |   |
| Stock subscription agreement                                |       | 250                    |       | 750                      |       | —                  |       | —          |       | —      |       | 750 |   |
| Net loss                                                    |       | —                 |       | —                   |       | —                  |       | —          |       | (9,646      | )          | (9,646 | ) |
|                                                        |       |                   |       |                     |       |                    |       |            |       |        |       |   |   |
| Balances at December 31, 2008                          |       | 78,748                 |       | 364,566                  |       | —                  |       | —          |       | (205,386    | )          | 159,180 |   |
|                                                        |       |                   |       |                     |       |                    |       |            |       |        |       |   |   |
| Exercise of stock options assumed in merger                 |       | —                 |       | —                   |       | —                  |       | —          |       | —      |       | — |   |
| Exercise of stock options                                   |       | 164                    |       | 602                      |       | —                  |       | —          |       | —      |       | 602 |   |
| Long-term incentive compensation plan, net of  forfeitures  |       | 188                    |       | 13,055                   |       | —                  |       | —          |       | —      |       | 13,055 |   |
| Common stock sold for cash, net of offering costs           |       | 36,124                 |       | 134,922                  |       | —                  |       | —          |       | —      |       | 134,922 |   |
| Net loss                                                    |       | —                 |       | —                   |       | —                  |       | —          |       | (35,802     | )          | (35,802 | ) |
|                                                        |       |                   |       |                     |       |                    |       |            |       |        |       |   |   |
| Balances at December 31, 2009                          |       | 115,224                |       | $                        | 513,145    |                    | $          | —          |       | $           | —     |   | $ | (241,188 | ) | $ | 271,957 |   |

 

----

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

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

76

----

Table ofContents

 

**BPZ Resources, Inc.and Subsidiaries**

**Consolidated Statementsof Cash Flows**

**(Inthousands)**

 
| ** **                                                                                 | ** ** | **For the Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------|------------|------------------------------------------|------------|
| ** **                                                                                 | ** ** | **2009**                                 | ** ** | **2008** | ** ** | **2007** | ** ** |
| ** **                                                                                 | ** ** | ** **                               | ** ** | ** ** | ** ** | **(Restated)** | ** ** |
| Cash flows from operating activities:                                                      |       |                                     |       |   |   |   |   |
| Net loss                                                                                   |       | $                                        | (35,802    | ) | $ | (9,646 | ) | $ | (20,510 | ) |
| Adjustments to reconcile net loss to net cash  provided by (used in) operating activities: |       |                                     |       |   |   |   |   |
| Stock-based compensation                                                                   |       | 13,055                                   |       | 18,464 |   | 7,040 |   |
| Depreciation, depletion and amortization                                                   |       | 25,803                                   |       | 16,062 |   | 793 |   |
| Amortization of investment in Ecuador property                                             |       | 187                                      |       | 188 |   | 188 |   |
| Deferred income taxes                                                                      |       | (12,057                                  | )          | (4,872 | ) | — |   |
| Net loss on the sale of asset                                                              |       | —                                   |       | — |   | 9 |   |
| Amortization of deferred financing fees                                                    |       | —                                   |       | — |   | 2 |   |
| Changes in operating assets and liabilities:                                               |       |                                     |       |   |   |   |   |
| Decrease (increase) in accounts receivable                                                 |       | 2,409                                    |       | (2,326 | ) | (2,950 | ) |
| Increase in value added tax receivable                                                     |       | (14,042                                  | )          | (4,613 | ) | (4,337 | ) |
| Increase in inventory                                                                      |       | (7,619                                   | )          | (661 | ) | (1,200 | ) |
| Decrease (increase) in other assets                                                        |       | 1,531                                    |       | 240 |   | (299 | ) |
| (Decrease) increase in accounts payable                                                    |       | (2,588                                   | )          | 23,512 |   | 4,398 |   |
| Increase in accrued liabilities                                                            |       | 4,341                                    |       | 5,078 |   | 1,535 |   |
| (Decrease) increase in income taxes payable                                                |       | (6,519                                   | )          | 6,841 |   | — |   |
| Increase in other liabilities                                                              |       | 516                                      |       | 455 |   | 160 |   |
| Net cash provided by (used in) operating activities                                        |       | (30,785                                  | )          | 48,722 |   | (15,171 | ) |
|                                                                                       |       |                                     |       |   |   |   |   |
| Cash flows from investing activities:                                                      |       |                                     |       |   |   |   |   |
| Property and equipment additions                                                           |       | (89,438                                  | )          | (99,867 | ) | (55,766 | ) |
| Increase in restricted cash                                                                |       | (567                                     | )          | (2,318 | ) | (2,698 | ) |
| Net cash used in investing activities                                                      |       | (90,005                                  | )          | (102,185 | ) | (58,464 | ) |
|                                                                                       |       |                                     |       |   |   |   |   |
| Cash flows from financing activities:                                                      |       |                                     |       |   |   |   |   |
| Borrowings                                                                                 |       | 6,533                                    |       | 17,819 |   | 15,500 |   |
| Repayments of borrowings                                                                   |       | (8,437                                   | )          | (10,451 | ) | (17 | ) |
| Deferred loan fees                                                                         |       | —                                   |       | (225 | ) | (233 | ) |
| Proceeds from exercise of warrants, net                                                    |       | —                                   |       | 750 |   | — |   |
| Proceeds from exercise of stock options, net                                               |       | 602                                      |       | 2,469 |   | 3,426 |   |
| Proceeds from sale of common stock, net                                                    |       | 134,922                                  |       | 40,904 |   | 37,149 |   |
| Net cash provided by financing activities                                                  |       | 133,620                                  |       | 51,266 |   | 55,825 |   |
|                                                                                       |       |                                     |       |   |   |   |   |
| Net increase (decrease) in cash and cash  equivalents                                      |       | 12,830                                   |       | (2,197 | ) | (17,810 | ) |
| Cash and cash equivalents at beginning of period                                           |       | 5,317                                    |       | 7,514 |   | 25,324 |   |
| Cash and cash equivalents at end of period                                                 |       | $                                        | 18,147     |   | $ | 5,317 |   | $ | 7,514 |   |
|                                                                                       |       |                                     |       |   |   |   |   |
| Supplemental cash flow information:                                                        |       |                                     |       |   |   |   |   |
| **Cash paid for:**                                                                         |       |                                     |       |   |   |   |   |
| Interest                                                                                   |       | $                                        | 4,259      |   | $ | 4,678 |   | $ | 470 |   |
| Income tax                                                                                 |       | 12,525                                   |       | 1,165 |   | 39 |   |
| **Non — cash items:**                                                                 |       |                                     |       |   |   |   |   |
| Purchase and additions to equipment with the  issuance of a capital lease obligation       |       | $                                        | 7,000      |   | $ | 9,243 |   | $ | 6,170 |   |
| Conversion of long-term debt to common stock                                               |       | —                                   |       | 15,500 |   | 458 |   |
| Accrued interest capitalized to construction in  progress                                  |       | 54                                       |       | 230 |   | 458 |   |
| Depletion allocated to production inventory                                                |       | 834                                      |       | 19 |   | 227 |   |
| Depreciation on support equipment capitalized to  construction in progress                 |       | 1,415                                    |       | 977 |   | 474 |   |
| Asset retirement obligation capitalized to property  and equipment                         |       | 112                                      |       | 269 |   | 269 |   |
| Property and equipment transferred to other  non-current assets                            |       | (1,456                                   | )          | — |   | — |   |
| Recapitalization of Merger Earn-out Shares. See  Note 11                                   |       |                                     |       |   |   | 97,830 |   |

 

The accompanyingnotes are an integral part of these consolidated financial statements.

 

77

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTES TOCONSOLIDATED FINANCIAL STATEMENTS**

 

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

**Note 1 — Basis ofPresentation and Significant Accounting Policies**

** **

**Organization**

** **

BPZ Resources, Inc., (together with itssubsidiaries, collectively referred to as the “Company” or “BPZ” unless thecontext requires otherwise) a Texas corporation, is based in Houston, Texaswith offices in Lima, Peru and Quito, Ecuador. The Company is focused on theexploration, development and production of oil and natural gas in Peru and to alesser extent Ecuador. The Company also intends to utilize part of its plannedfuture natural gas production as a supply source for the complementarydevelopment of a gas-fired power generation facility which is expected to bewholly or partially owned by the Company.

 

The Company maintains a subsidiary, BPZ Exploración &Producción S.R.L. (“BPZ E&P”), registered in Peru through its wholly-ownedsubsidiary BPZ Energy, LLC, a Texas limited liability company, formerlyBPZ Energy, Inc., and its subsidiary BPZ Energy International Holdings,L.P., a British Virgin Islands limited partnership. Currently, the Company,through BPZ E&P, has exclusive rights and license contracts for oil and gasexploration and production covering a total of approximately 2.2 million acres,in four blocks, in northwest Peru. The Company’s license contracts cover 100%ownership of the following properties: Block Z-1 (0.6 million acres), Block XIX(0.5 million acres), Block XXII (0.9 million acres) and Block XXIII (0.2million acres). The Block Z-1 contract was signed in November 2001, theBlock XIX contract was signed in December 2003 and Blocks XXII and XXIIIcontracts were signed in November 2007. Generally, according to theOrganic Hydrocarbon Law No. 26221 and the regulations thereunder (the “OrganicHydrocarbon Law”) the seven  year termfor the exploration phase can be extended in each  contract by up to an additional three yearsto a maximum of ten years. However, specific provisions of each licensecontract can vary the exploration phase of the contract as established by the hydrocarbonlaw. The license contracts require the Company to conduct specified activitiesin the respective blocks during each exploration period in the explorationphase. If the exploration activities are successful, the Company may decide toenter the exploitation phase and the total contract term can extend up to 30years for oil exploration and production and up to 40 years for gas explorationand production. In the event a block contains both oil and gas, as is the casein the Company’s Block Z-1 contract, the 40 year term may apply to oilexploration and production as well.

 

Additionally, through its wholly-owned subsidiary, SMCEcuador Inc., a Delaware corporation, and its registered branch in Ecuador, theCompany owns a 10% non-operated working interest in an oil and gas producingproperty, Block 2, located in the southwest region of Ecuador (the “Santa ElenaProperty”). The license agreement covering the property extends through May 2016.

 

The Company is in the process of developing its oiland natural gas reserves.  The Companyhas been producing and selling oil from the CX-11 platform in the Corvina fieldof Block Z-1 under a well testing program and is in the process of satisfyingthe conditions to transition to commercial production in Corvina. From the timethe Company first began producing from the CX-11 platform in the Corvina fieldin November of 2007, through December 31, 2009, it has producedapproximately 1.9 MMBbls of oil. The Company is also in the initial stages ofappraising, exploring and developing the potential oil and natural gas reservesfrom the A platform in the Albacora field of Block Z-1, and has drilled andcompleted its first well in December 2009. Additionally, the Company’sactivities in Peru include analysis and evaluation of technical data onits  other properties, preparation of the development plans for theproperties, refurbishment of and designs for platforms, procuring machinery andequipment for an extended drilling campaign, obtaining all necessaryenvironmental and operating permits, bringing additional production on-line,seismic acquisition, obtaining detailed engineering and design of the powerplant and gas processing facilities, executing a contract to purchase three LM6000 gas fired turbines  and securing the required capital and financingto conduct the current plan of operation.

 

**Basis of Presentation and****Principlesof Consolidation**

 

The consolidated financial statements include theaccounts of BPZ Resources, Inc. and its wholly-owned subsidiaries andbranch offices. All intercompany balances and transactions have beeneliminated. Management has evaluated all subsequent events through March 31,2010, the date the financial statements were available to be issued.

 

The Company’s accounting policy regarding partnershipor joint venture interests in oil and gas properties is to consolidate suchinterests on a pro-rata basis in accordance with accepted practice in the oiland gas industry. However, the Company has not been able to receive timelyinformation to allow it to proportionately consolidate the minoritynon-operated

 

78

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

working interest owned by its consolidated subsidiary,SMC Ecuador Inc. See Note 6 “Investment in Ecuador Property” to theconsolidated financial statements for further discussion regarding the Company’sinvestment in its Ecuador property. Accordingly, the Company accounts for thisinvestment under the cost method. As such, the Company records its share ofcash received or paid attributable to this investment as other income orexpense and amortizes its investment into income over the remaining term of thelicense agreement, which expires in May 2016.

** **

**Useof Estimates**

** **

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

 

Estimates of crude oil reserves are the mostsignificant of the Company’s estimates. All of the reserves data in this Form 10-Kare estimates. Reservoir engineering is a subjective process of estimatingunderground accumulations of crude oil and natural gas. There are numerousuncertainties inherent in estimating quantities of proved crude oil and naturalgas reserves. The accuracy of any reserves estimate is a function of thequality of available data and of engineering and geological interpretation andjudgment. As a result, reserves estimates may be different from the quantitiesof crude oil and natural gas that are ultimately recovered.

 

Other items subject to estimates and assumptionsinclude the carrying amounts of property, plant and equipment includingimpairment and asset retirement obligation and deferred income tax assets.Management evaluates estimates and assumptions on an ongoing basis usinghistorical experience and other factors, including the current economic andcommodity price environment. Current credit market conditions combined withvolatile commodity prices have resulted in increased uncertainty inherent insuch estimates and assumptions. As future events and their effects cannot bedetermined accurately, actual results could differ significantly from management’sestimates.

 

**Restatement and Reclassification**

 

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

 

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

 

**Revenue Recognition**

 

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

 

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

 

**Reporting andFunctional Currency**

** **

TheU.S. Dollar is the functional currency for the Company’s operations in bothPeru and Ecuador. Ecuador has adopted the U.S. Dollar as its official currency.Peru, however, uses its local currency, Nuevo Sol, in addition to the U.S.Dollar and therefore its financial results are subject to foreign currencygains and losses. The Company has adopted Accounting Standard Codification  (“ASC”) Topic 830, “ForeignCurrency Matters”, previously Statement of Financial Accounting Standards (“SFAS”) No. 52,“Foreign Currency Translation,” which requires that the translation of theapplicable 

 

79

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

foreigncurrency into U.S. dollars be performed for balance sheet monetary accountsusing current exchange rates in effect at the balance sheet date, non-monetaryaccounts using historical exchange rates in effect at the time the transactionoccurs, and for revenue and expense accounts using a weighted average exchangerate during the period reported. Accordingly, the gains or losses resultingfrom such translation are included in other income and expense in theconsolidated statements of operations. Due to the relatively low level ofactivity to-date and the relatively steady exchange rate in Peru, a translationloss of approximately$0.1 million was recognized during the year ended December 31, 2009and a translation gain of approximately $0.1 million and $0.2 million was recognized during the year ended December 31,2008 and 2007, respectively.

 

**Cashand Cash Equivalents**

** **

The Company considers cash on hand, cash in banks,money market mutual funds and highly liquid debt instruments purchased with anoriginal maturity of three months or less to be cash equivalents. Certain ofthe Company’s cash balances are maintained in foreign banks which are notcovered by deposit insurance. The cash balance in the Company’s U.S. bankaccounts may exceed federally insured limits.

 

**RestrictedCash**

** **

As discussed in Note 7, “Restricted Cash”, the Companyhas secured various performance bonds, collateralized by certificates ofdeposit, to guarantee its obligations and commitments in connection with itsexploratory properties in Peru. All of the performance bonds have been issuedby Peruvian banks and their terms are dictated by the corresponding LicenseContract or Agreement.

 

****Allowance for Doubtful Accounts****

 

Currently,the Company’s contract terms regarding oil sales have a relatively shortsettlement period.  However, the Companyregularly reviews all aged accounts receivables for collectability andestablishes an allowance as necessary for balances greater than 90 daysoutstanding.  Currently all receivablesare current or were outstanding less than thirty days.  It is the Company’s belief that there are nobalances in accounts receivable that will not be collected and that anallowance was not necessary at December 31, 2009 and December 31,2008, respectively.

** **

**Property,Equipment and Construction in Progress**

** **

The Company follows the “successful efforts” method ofaccounting of its costs of acquisition, exploration and development of oil andgas properties. Under this method, oil and gas lease acquisition costs andintangible drilling costs associated with exploration efforts that result inthe discovery of proved reserves and costs associated with developmentdrilling, whether or not successful, are capitalized when incurred. Certaincosts of exploratory wells are capitalized pending determinations that provedreserves have been found. If the determination is dependent upon the results ofplanned additional wells and required capital expenditures to produce the reservesfound, the drilling costs will be capitalized as long as sufficient reserveshave been found to justify completion of the exploratory well and additionalwells are underway or firmly planned to complete the evaluation of the well.All costs related to unsuccessful exploratory wells are expensed when suchwells are determined to be non-productive or at the one year anniversary ofcompletion of the well if proved reserves have not been attributed and capitalexpenditures as described in the preceding sentence are not required.

 

The Company assesses its capitalized exploratory wellspending evaluation each quarter to determine whether costs should remaincapitalized or should be charged to earnings. Other exploration costs,including geological, geophysical and engineering costs, are expensed asincurred. 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 oramortized until placed in service. For assets the Company constructs, itcapitalizes direct costs, such as labor and materials, and indirect costs, suchas overhead and interest. As of December 31, 2009, property and equipmentconsists of office equipment, vehicles and leasehold improvements made to theCompany’s offices. All such values are stated at cost and are depreciated on astraight-line basis over the estimated useful life of the assets which rangesbetween three and ten years, or the term of the lease. Barges and relatedequipment are depreciated on a straight-line basis over the estimated usefullife of the asset which is between five and fifteen years.  

 

80

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

Maintenance and repairs are expensed as incurred.Replacements, upgrades or expenditures which improve and extend the life of theassets are capitalized. When assets are sold, retired or otherwise disposed,the applicable costs and accumulated depreciation and amortization are removedfrom the appropriate accounts and the resulting gain or loss is recorded.

 

**Oil and Gas Accounting Reserves Determination**

 

The successfulefforts method of accounting depends on the estimated reserves the Companybelieves recoverable from our oil and gas reserves. The process of estimatingreserves is complex. It requires significant judgments and decisions based onavailable geological, geophysical, engineering and economic data.

 

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

 

·                                          expected reservoir characteristics basedon geological, geophysical and engineering assessments;

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

·                                          future oil and gas quality differentials;

·                                          assumed effects of regulation bygovernmental agencies; and

·                                          future development and operating costs.

 

The Companybelieves its assumptions are reasonable based on the information available toit at the time it prepare the estimates. However, these estimates may changesubstantially going forward as additional data from development activities andproduction performance becomes available and as economic conditions impactingoil and gas prices and costs change.

 

Management isresponsible for estimating the quantities of proved oil and natural gasreserves and for preparing related disclosures. Estimates and relateddisclosures are prepared in accordance with the Security and ExchangeCommission (“SEC”) requirements and generally accepted industry practices inthe U.S. as prescribed by the Society of Petroleum Engineers. Reserve estimatesare independently evaluated at least annually by independent qualified reservesengineers, Netherland, Sewell & Associates, Inc (“NSAI”).

 

The Company’sBoard of Directors oversees the review of our oil and gas reserves and relateddisclosures by the Company’s appointed independent reserve engineers. The Boardmeets with management periodically to review the reserves process, results, andto confirm that the independent reserve engineers have had access to sufficientinformation, including the nature and satisfactory resolution of any materialdifferences of opinion between the Company and the reserve engineers.

 

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

 

·                                         Determining whether or not an exploratorywell has found economically producible reserves;

·                                         Calculating our unit-of-productiondepletion rates. Proved reserves estimates are used to determine rates that areapplied to each unit-of-production in calculating our depletion expense; and

·                                         Assessing, when necessary, our oil andgas assets for impairment. Estimated future cash flows are determined usingproved reserves. The critical estimates used to assess impairment, includingthe impact of changes in reserves estimates, are discussed below.

 

**Impairmentof Long-Lived Assets**

 

The Company periodically evaluates the recoverabilityof the carrying value of its long-lived assets, goodwill and identifiableintangibles by monitoring and evaluating changes in circumstances that mayindicate that the carrying amount of the asset may not be recoverable. Examplesof events or changes in circumstances that indicate that the recoverability ofthe carrying amount of an asset should be assessed include but are not limited tothe following: a significant decrease in the market value of an asset, asignificant change in the extent or manner in which an asset is used or asignificant physical change in an asset, a significant adverse change in legalfactors or in the business climate that could affect the value of an asset oran adverse action or assessment by a regulator, an accumulation of costssignificantly in excess of the amount 

 

81

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

originally expected to acquire or construct an asset,and/or a current period operating or cash flow loss combined with a history ofoperating or cash flow losses or a projection or forecast that demonstratescontinuing losses associated with an asset used for the purpose of producingrevenue.

 

The Company considershistorical performance and anticipated future results in its evaluation ofpotential impairment. Accordingly, when indicators of impairment are present,the Company evaluates the carrying value of these assets in relation to theoperating performance of the business and future discounted and non-discountedcash flows expected to result from the use of these assets. Impairment lossesare recognized when the expected future cash flows from an asset are less thanits carrying value. For the years ended December 31, 2009, 2008 and 2007,there was no impairment losses recognized by the Company.

 

**StockBased Compensation**

 

The Company accounts forstock-based compensation at fair value in accordance with the provisions of ASCTopic 718, “Stock Compensation” (“ASC Topic 718”),  previously accounted for  under SFAS 123(R), “Share—Based Payment”, which establishes accounting forstock-based payment transactions for employee services and goods and servicesreceived from non-employees. Under the provisions of ASC Topic 718, stock-based compensation cost is measured at the date ofgrant, based on the calculated fair value of the award, and is recognized asexpense in the Consolidated Statements of Operations  ratably over the employee’s or non-employee’srequisite service period, which is generally the vesting period of the equitygrant. The fair valueof stock option awards is determined using the Black-Scholes option-pricingmodel. Restricted stock awards and units are valued using the market price ofthe Company’s common stock on the grant date. Additionally,stock-based compensation cost is recognized based on awards that are ultimatelyexpected to vest, therefore, the compensation cost recognized on stock-based payment transactions is reduced forestimated forfeitures based on the Company’s historical forfeiture rates. Additionally, no stock-based compensationcosts were capitalized for the years ended December 31, 2009, 2008 and2007. The Company provides compensation benefits to employees and non-employeedirectors under share-based payment arrangements, including various employeestock option plans. See Note 10, “Stockholders’ Equity” for furtherdiscussion of the Company’s stock-based compensation plans.

 

ASC Topic 230, “Statement of Cash Flows”, requires thecash flows resulting from tax deductions in excess of the compensation costrecognized for equity awards (excess tax benefits) to be classified asfinancing cash flows. However, as the Company is not able to use these taxdeductions (see Note 14, “Income Taxes” for further information), it has noexcess tax benefits to be classified as financing cash flows.

 

**Capitalized Interest**

 

Certain interest costs have been capitalized as partof the cost of oil and gas properties under development, including wells inprogress and related facilities.  Totalinterest costs capitalized during the year ended December 31, 2009, 2008and 2007 was $4.4 million, $4.2 million and $0.9 million, respectively.

 

**FairValue of Financial Instruments**

 

The Company’s financial instruments consist  of cash, trade receivables, trade payablesand debt. The book values of cash, trade receivables and trade payables areconsidered to be representative of their respective fair values due to theshort-term maturity of those instruments. The fair value of debt at December 31,2009 and 2008 approximates the carrying value because the interest rates arebased on floating rates identified by reference to market rates and because theinterest rates charged are at rates at which the Company can currently borrow.

** **

**IncomeTaxes**

** **

The Company accounts for income taxes in accordancewith SFAS 109, “Accounting for Income Taxes, which was codified into ASC Topic740, “Income Taxes”. Under ASC Topic 740, deferred tax assets and liabilitiesare determined based on differences between the financial reporting and taxbasis of assets and liabilities, and are measured using the enacted tax ratesand laws that will be in effect when the differences are expected to reverse.Valuation allowances are established when necessary to reduce deferred taxassets to the amount expected to be realized.

 

82

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

**Environmental**

** **

The Company is subject to environmental laws andregulations of various U.S. and international jurisdictions. These laws andregulations, which are subject to change, regulate the discharge of materialsinto the environment and may require the Company to remove or mitigate theenvironmental effects of the disposal or release of petroleum or chemicalsubstances at various sites.

 

Environmental costs that relate to current operationsare expensed or capitalized as appropriate. Costs are expensed when they relateto an existing condition caused by past operations and will not contribute tocurrent or future revenue generation. Liabilities related to environmentalassessments and/or remedial efforts are accrued when property or services areprovided and when such costs can be reasonably estimated. The Company’s costfor these studies and assistance related to the Company’s properties forthe  year ended December 31, 2009,2008 and 2007 were approximately $1.2 million, $0.5 million and $0.3 million,respectively.

 

**Lossper Common Share**

** **

In accordance with provisions of ASC Topic 260, “Earningsper Share”, previously known as SFAS No. 128, “Earnings per Share”, basicearnings per share is computed on the basis of the weighted-average number ofcommon shares outstanding during the periods. Diluted earnings per share iscomputed based upon the weighted-average number of common shares outstandingplus the assumed issuance of common shares for all potentially dilutivesecurities. Diluted earnings per share equals basic earnings per share for theperiods presented because the effects of potentially dilutive securities areantidilutive.

 

**Recent Accounting Pronouncements**

 

In June 2009, the Financial Accounting StandardsBoard (“FASB”) issued SFAS No. 168, now codified as ASC Topic 105, “GenerallyAccepted Accounting Principles” (“ASC Topic 105”).   ASC Topic 105provides the FASB ASC as the single source of authoritative GAAP recognized bythe FASB to be applied by nongovernmental entities. The FASB ASC changes GAAPfrom a standards based model, with thousands of standards, to a topically basedmodel. Rules and interpretive releases of the SEC under authority offederal securities laws are also sources of authoritative GAAP for SECregistrants. On the effective date of ASC Topic 105 the ASC supersedes allthen-existing non-SEC accounting and reporting standards. All othernongrandfathered non-SEC accounting literature not included in the ASC will becomenonauthoritative.   The provisions of FASB ASC Topic 105 are effective forinterim and annual periods ending after September 15, 2009 and,accordingly, are effective for the Company for the current fiscal reportingperiod. The adoption of the ASC did not have an impact on the Company’sfinancial position, results of operations or cash flows.

 

In May 2009, the FASB issued SFAS No. 165, “SubsequentEvents” (“SFAS No. 165”), now codified as ASC Topic 855, “SubsequentEvents” (“ASC Topic 855”). This standard establishes the accounting for anddisclosure of events that occur after the balance sheet date but beforefinancial statements are issued or are available to be issued. It requires thedisclosure of the date through which an entity has evaluated subsequent eventsand the basis for that date, that is, whether that date represents the date thefinancial statements were issued or were available to be issued. The Companyadopted ASC Topic 855 in the second quarter of 2009. The adoption of ASC Topic855 did not have a material impact on the Company’s consolidated financialposition, results of operations or cash flows. See Note 1, “Basis ofPresentation and Significant Accounting Policies”, to the accompanyingconsolidated financial statements for the related disclosure.

 

On December 31, 2008 the SEC adopted the final rules regardingamendments to current oil and gas reporting requirements. The amendments aredesigned to modernize and update the oil and gas disclosure requirements toalign them with current practices and changes in technology and include thefollowing:

 

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

·                 Enabling companies to additionallydisclose their probable and possible reserves;

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

 

83

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

·                 Requiring companies to report theindependence and qualifications of a preparer or auditor, based on currentSociety of Petroleum Engineers criteria;

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

·                 Permitting the use of newtechnologies to determine proved reserves if those technologies have beendemonstrated empirically to lead to reliable conclusions about reservesvolumes.

 

The amendments are effective for registrationstatements filed on or after January 1, 2010, and for annual reports onForms 10-K and for fiscal years ending on or after December 31, 2009.Early adoption is not permitted in either annual or quarterly reports beforethe first annual report in which the revised disclosures are required. TheCompany adopted the rules effective December 31, 2009. SeeSupplemental Oil and Gas Information (Unaudited) for impact of adoption on oiland gas reserves.

 

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

 

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

 

**Note 2— Value Added Tax Receivable**

 

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

 

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

 

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

 

**Note 3— Inventory**

 

Inventories consist primarily of crude oil, tubulargoods, accessories and spare parts for production equipment, stated at thelower of average cost or market. The balance of inventory at December 31,2009 and December 31, 2008 was $12.5 million and $4.1 million,respectively.

 

84

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

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

 

The Company maintains crude oil inventories in storagebarges until the inventory quantities are at a sufficient level that therefinery in Talara will accept delivery.  These inventories are alsostated at the lower of average cost or market value. Cost is determined on aweighted average basis based on production costs. The crude oil inventory at December 31,2009 consisted of approximately 40,108 barrels at an estimated cost of $2.0million or $50.55 per barrel. The crude oil inventory at December 31, 2008consisted of approximately 11,656 barrels at an estimated cost of $0.4 millionor $37.56 per barrel.

 

**Note4 — Prepaid and Other Current Assets**

 

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

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

 

Prepaid expenses and other are primarily related toprepayments for drilling services, equipment rental and material procurement.Deposits are primarily rent deposits in connection with the Company’s officesin Houston and Peru. Prepaid insurance consists of premiums related to theCompany’s operations as well as general liability and directors and officer’sinsurance policies. Insurance receivable is related to the barge incident whichoccurred in early August 2006. The Company incurred an operational delayof approximately three weeks resulting from a navigation incident which causedthe BPZ-01 barge to be grounded on a sand bank in Talara Bay in northwest Peruduring the second mobilization trip to the Corvina platform. As of December 31,2009, the Company has an insurance receivable of approximately $0.7 million forthe estimated insurance repair claims of $0.8 million expected to be filed withthe insurance carrier. A deductible of $75,000 will be applied to thisinsurance claim when reimbursed.  The hull claim will be finalized uponthe dry docking of the vessel, which is expected to occur during the thirdquarter of 2010.

 

**Note5 — Property, Equipment and Construction in Progress**

 

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

 
| ** **                                             | ** ** | **2009**           | ** ** | **2008** | ** ** |
|--------------------------------------------------------|------------|--------------------|------------|----------|------------|
|                                                   |       | **(in thousands)** |       |
| Construction in progress:                              |       |               |       |     |       |
| Power plant and related equipment                      |       | $                  | 23,144     |     | $          | 17,484 |   |
| Platforms and wells                                    |       | 20,899             |       | 34,768   |       |
| Pipelines and processing facilities                    |       | 5,373              |       | 5,108    |       |
| Producing properties                                   |       | 200,647            |       | 110,230  |       |
| Producing equipment                                    |       | 18,057             |       | 18,399   |       |
| Barge and related equipment                            |       | 30,852             |       | 24,927   |       |
| Office equipment, leasehold improvements and  vehicles |       | 10,466             |       | 1,960    |       |
| Accumulated depletion, depreciation and  amortization  |       | (46,921            | )          | (18,942  | )          |
|                                                   |       |               |       |     |       |
| Net property, equipment and construction in process    |       | $                  | 262,517    |     | $          | 193,934 |   |

 

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

 

85

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

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

 

Of the incurred costs mentioned above, the Companyincurred capital expenditures related to the drilling and testing of theCX11-15D, CX11-19D, CX11-17D and CX11-20XD in the Corvina field ofapproximately, $23.5 million, $12.8 million, $3.0 million and $1.0 millionrespectively, as well as for the A-14D well of approximately $20.6 million inthe Albacora field during the year ended December 31, 2009 in addition to$5.1 million in standby, installation and mobilization costs during the sameperiod.  For the year ended December 31, 2008 the Companyincurred capital expenditures related to the drilling and testing of theCX11-18XD, the CX11-20XD, CX11-15D wells of approximately $19.0 million, $31.2million, and $11.2 million, respectively. Approximately $86.6 million and $52.3 million was transferred fromconstruction in progress to producing properties for the year ended December 31,2009 and 2008, respectively.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

86

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

**Note6 — Investment in Ecuador Property**

 

The Company has a 10% net investment interest in anoil and gas property in Ecuador (the “Santa Elena Property”) totaling $1.2million and $1.4 million as of December 31, 2009 and December 31,2008, respectively. The Company accounts for this investment under the costmethod and records its share of cash received or paid as other income orexpense. Since the Company’s investment represents ownership of an oil and gasproperty, which is a depleting asset, the Company is amortizing the cost of theinvestment on a straight-line basis over the remaining term of the licenseagreement which expires in May 2016.  Investment income from theCompany’s investment in Ecuador property was $1.2 million, $0.7 million and$0.3 million for each of the years ended December 31, 2009, 2008 and 2007,respectively. For theyears ended December 31, 2009, 2008 and 2007, the Company received $1.4million, $0.9 million and $0.5 million of cash, respectively, from itsinvestment in Ecuador property and recorded amortization expense of $0.2million in each of the three years, respectively.

 

**Note7 — Restricted Cash**

 

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

 

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

 

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

 

**Note8 —Asset Retirement Obligation**

** **

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

 

Activity related to the Company’s asset retirementobligation (“ARO”) for December 31, 2009 and December 31, 2008 is asfollows:

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

 

87

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

The 2009 revision inestimate is due to the shift in timing of cash flows associated with expectedpayment of the ARO liabilities.  As theexpected timing to settle the liabilities was extended in the current year, thepresent value of the liabilities was decreased and, as a result, the Companyreduced both the liability and capitalized asset by approximately $0.2 millionin accordance with ofASC Topic 410.

 

**Note 9 —Long-Term Debt and Capital Lease Obligations**

 

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

 
| ** **                                                             | ** ** | **December 31,  2009** | ** ** | **December 31,  2008** | ** ** |
|------------------------------------------------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                                             | ** ** | **(in thousands)**          | ** ** |
|                                                                   |       |                        |       |                        |       |
| $15 million IFC Senior Note, Libor plus 2.75%, due  2012               |       | $                           | 15,000     |                        | $          | 15,000 |   |
| Capital Lease Obligations                                              |       | 11,910                      |       | 7,838                       |       |
| Other                                                                  |       | 1,023                       |       | —                      |       |
|                                                                   |       | 27,933                      |       | 22,838                      |       |
| Less: Current Portion of Long-Term Debt and Capital  Lease Obligations |       | 5,352                       |       | 7,820                       |       |
|                                                                   |       | $                           | 22,581     |                        | $          | 15,018 |   |

 

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

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

 

The following is a summaryof scheduled minimum lease payments under capital lease obligations by year (inthousands):

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

 

**$170.9 MillionConvertible Notes due 2015**

 

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

 

88

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

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

 

The 2015 Convertible Notes are the Company’s generalsenior unsecured obligations and rank equally in right of payment with all ofthe Company’s other existing and future senior unsecured indebtedness. The 2015 Convertible Notes are effectively subordinated to all of theCompany’s secured indebtedness to the extent of the value of the assetscollateralizing such indebtedness.  The 2015 Convertible Notes are notguaranteed by the Company’s subsidiaries.

 

The Company will pay interest on the 2015 ConvertibleNotes at a rate of 6.50% per year on March 1 and September 1 of eachyear, beginning on September 1, 2010.  The 2015 Convertible Notesmature on March 1, 2015. The initial conversion rate is 148.3856 sharesper $1,000 principal amount of the 2015 Convertible Notes (equal to an initialconversion price of approximately $6.74 per share of common stock), subject toadjustment. Upon conversion, the Company must deliver, at its option, either (1) anumber of shares of its common stock determined as set forth in the Indenture, (2) cash,or (3) a combination of cash and shares of its common stock (but not toexceed 19.99% of the Company’s outstanding shares at the time of such delivery).

 

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

 

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

 

(1) during any fiscal quarter (and only duringsuch fiscal quarter) commencing after March 31, 2010, if the last reportedsale price of the Company’s common stock is greater than or equal to 130% ofthe conversion price of the Notes for at least 20 trading days in the period of30 consecutive trading days ending on the last trading day of the precedingfiscal quarter;

 

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

 

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

 

(4) upon the occurrence of one of specifiedcorporate transactions. Holders may also convert the 2015 Convertible Notes attheir option at any time beginning on February 1, 2015, and ending at theclose of business on the second business day immediately preceding the maturitydate.

 

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

 

If the Company experiences any one of the certainspecified types of corporate transactions, holders may require the Company topurchase all or a portion of their 2015 Convertible Notes. Any repurchase ofthe notes pursuant to these provisions will be for cash at a price equal to100% of the principal amount of the notes to be purchased plus any accrued andunpaid interest to, but excluding, the purchase date.

 

89

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDEDDECEMBER 31, 2009, 2008 and 2007**

 

The Indenture contains customary terms and covenantsand events of default. If an event of default (as defined therein) occurs andis continuing, the Trustee by notice to the Company, or the holders of at least25% in aggregate principal amount of the 2015 Convertible Notes thenoutstanding by notice to the Company and the Trustee, may declare the principalof and accrued and unpaid interest (including additional interest or premium,if any) on the 2015 Convertible Notes to be due and payable. In the case of anevent of default arising out of certain bankruptcy events (as set forth in theIndenture), the principal of and accrued and unpaid interest (includingadditional interest or premium, if any), on the notes will automatically becomedue and payable.

 

Net proceeds from the sale of the 2015 ConvertibleNotes, after deducting the discounts and commissions and any offering expensespayable by the Company, were approximately $165.4 million.  The initialpurchaser received commissions of approximately $5.5 million in connection withthe sale of the Notes.  The Company intends to use the net proceeds forgeneral corporate purposes, including without limitation, capital expendituresand working capital, reduction or refinancing of debt, or other corporateobligations.

 

As a result of the Company’s adoption of the newaccounting standard for convertible debt that may be settled in cash uponconversion, it is required to separately account for the liability and equitycomponents in a manner that reflects  theCompany’s nonconvertible borrowing rate when interest cost is recognized insubsequent periods. The value assigned to the liability component is determinedby measuring the fair value of a similar liability that does not have an equityconversionfeature. Thevalue assigned to the equity component is determined by deducting the fairvalue of the liability component from the initial proceeds. The excess of theprincipal amount of the liability component over its carrying amount (thenon-cash discount) is amortized to interest cost using the effective interestmethod over the term of the debt agreement. In addition, transaction costsincurred that directly relate to the issuance of convertible debt instrumentsmust be allocated to the liability and equity components in proportion to theallocation of proceeds and accounted for as debt issuance costs and equityissuance costs, respectively. The accounting standard requires retrospectiverestatement of all periods presented back to the date of debt issuance with acumulative effect of the change in accounting principle on all prior periodsbeing recognized as of the beginning of the first period.

 

The Company estimates its nonconvertible borrowingrate at the date of issuance of its 2015 Convertible Notes to be 12%.  The 12% nonconvertible borrowing raterepresents the borrowing rate of similar companies with the same credit qualityas the Company and was obtained through a quote from the initial purchaser.Using the income method and discounting the principal and interest payments ofthe 2015 Convertible Notes using the 12% nonconvertible borrowing rate, theCompany estimates the fair value of the $170.9 million 2015 Convertible Notesto be approximately $136.3 million with the discount being approximately $34.6million. The discount will be amortized as non-cash interest expense intoincome over the life of the notes using the interest method. In addition, theCompany plans to record approximately $4.4 million of the $5.5 million of feesand commissions as debt issue costs that will be amortized over time using theinterest method as interest expense. The remaining $1.1 million of fees andcommissions will be treated as an original issue discount against the value ofthe equity component. The Company estimates the cash payments related to the2015 Convertible Notes, assuming no conversion, for the years ended 2010, 2011,2012, 2013, 2014 and thereafter to be approximately $6.4 million, $11.1million, $11.1million, $11.1million, $11.1million and $176.5 million,respectively

 

**$15.0 Million IFCReserve-Based Credit Facility**

 

OnAugust 15, 2008, the Company entered into a****$15.0 million reserve-based lending facility (“IFCFacility”) agreement (the “Loan Agreement”) with IFC through our subsidiariesBPZ E&P and BPZ Marine Peru S.R.L. as co-borrowers. The reserve-basedlending facility was to originally mature in December 2012, however, asresult of the $170.9 million Convertible Debt issuance by the Company in February andMarch 2010 , the Company expects to use a portion of the proceeds to repaythe amount outstanding to the IFC in 2010. Therefore $2.5 million of the $15.0 million that was originally due at December 31,2010 and that would have been classified as a current liability at December 31,2009 is being classified as a long term liability, in accordance with ASC Topic470, “Debt”, as the Company intends to refinance the obligationon a long-term basis.

 

The reserve-based lending facility bears interest atan approximate rate of LIBOR plus 2.75%, currently equivalent to 3.19% based onthe six month LIBOR rate of 0.44% at December 31, 2009.  The maximumamount available under this facility begins at $15.0 million and will bereduced by $2.5 million beginning on December 16, 2010 and every sixmonths 

 

90

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

thereafter during the term of the LoanAgreement.  The amount available under the Loan Agreement is subject to asemi-annual borrowing base determination based on the value of oilreserves.  In addition, the Company is subject to various financialcovenants calculated as of the last day of each quarter, including a life offield coverage ratio, life of loan coverage ratio, debt to equity ratio andinterest coverage ratio. Additionally, the Company requested and received a waiverand amendment from IFC which extended the period of time to assign a firstpriority lien on Empresa Electrica Nueva Esperanza S.R.L.’s interest in theAgreement with GE to purchase three gas fired turbines to IFC until December 2010.Accordingly, the Company was in compliance with all material covenants of theLoan Agreement as of December 31, 2009.

 

The Loan Agreement provides forevents of default customary for agreements of this type, including, among otherthings, payment breaches under any of the finance documents for the first andsecond tranche of the senior debt; failure to comply with obligations;representation and warranty breaches; expropriation of the assets, business oroperations of any borrower; insolvencies of any borrower; certain attachmentsagainst the assets of any borrower; failure to maintain certain authorizationswith respect to any financing documents with the IFC, the development andoperation of the Corvina field in Block Z-1, any additional petroleum assetsunder license contracts with Perupetro S.A. (“Perupetro”), a corporationowned by the Peruvian government empowered to become a party in the contractsfor the exploration and/or exploitation of hydrocarbons in order to promotethese activities in Peru. Perupetro is empowered to enter into contracts forthe exploration and exploitation of hydrocarbons on behalf of Peru, or certain other key agreements; revocation of anyfinancing or security documents with the IFC or certain key agreements;defaults on certain liabilities; certain judgments against the borrower or anysubsidiary; abandonment or extended business interruption of the Corvina fieldor certain other petroleum assets; engagement in certain sanctionablepractices; or restrictions are enacted in Peru that could inhibit any payment aborrower is required to make under the financing documents with the IFC.

 

If an event of default occurs, IFCand any additional facility agent may (i) terminate all or part of therelevant facility; (ii) declare all or part of the principal amount of theloan, together with accrued interest, immediately due and payable;  (iii) declareall or part of the principal amount of the loan, together with accruedinterest, payable on demand; or (iv) declare any and all of the securitydocuments under the facility enforceable and exercise its rights under suchdocuments. In addition, if any borrower is liquidated or declared bankrupt, allloans and interest accrued on it or any other amounts due, will becomeimmediately due and payable without notice.

 

**Other**

 

In July 2009, theCompany, through its subsidiary, BPZ E&P, entered into a $5.1 millionshort-term loan agreement to finance the purchase of casing and accessories foruse in its current and future operations. The $5.1 million short-term loan bearsan annual interest rate of 5.45% and is to be repaid in five monthlyinstallments of approximately $1.0 million starting September 2009. In connection with the $5.1 million short-term loan agreement, the Companywas  required to deposit $1.0 million withthe lending institution as a guaranty for the loan.  The $1.0 million willbe applied to the last installment of the loan repayments. As of December 31,2009, the remaining principal amount was approximately $1.0 million and, alongwith the accrued interest due, was repaid with the $1.0 million deposit andcash in January 2010.

 

**Note Payable**

 

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

 

**Capital Leases**

 

In November 2009, the Company entered into a capitallease agreement for a construction barge, the Don Fernando, to assist it in itsoffshore construction projects. The capital lease asset and correspondingliability was recorded at $7.0 million, which represents the present value ofthe minimum lease payments, or the aggregate fair market value of theassets.  At the end of the two year lease,the title to the barge transfers to the Company.  The Company accounted for the lease agreementin accordance with ASC Topic 840, “Leases”, previously accounted for under SFASNo. 13, “Accounting for Leases (As Amended)”. Under the guidance, thelease agreement is accounted for as a capital lease and the imputed interestrate necessary to reduce the net minimum lease payments to present value overthe lease term is 22.4%.

 

91

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

In June 2007, the Company entered into a capitallease agreement, with an option to purchase, for two barges, the Namoku and theNu’uanu, to assist in the development of the Corvina oil. The capital leaseassets were recorded at $6.2 million, which represents the present value of theminimum lease payments, or the aggregate fair market value of the assets.

 

In May 2009, the Company entered into anamendment of its lease agreement for two barges currently under charter, theNamoku and the Nu’uanu. Under the terms of the amended lease agreement, thecurrent charter, originally set to expire in November 2009, is extendedfor five years commencing on May 1, 2009.  During the first 18 monthsof the amended lease term, the daily charter rate for the use of both barges isfixed. Commencing on November 2010, the daily charter rate for theuse of both vessels will be based on a tiered structure with the daily ratedependent upon the amount of the previous month’s average daily per barrelprice of West Texas Intermediate Crude Oil (“WTI”), as indicated on the NewYork Mercantile Exchange. Any amount paid by the Company after November 2010over the initial daily rate, as a result of the escalated tiered structurebased on the price of WTI, will be considered contingent rental payments. The amended lease agreement contains a $3.0 million purchase option after thethird year of the lease, a $2.0 million purchase option after the fourth yearof the lease and a mandatory $1.0 million purchase obligation by the Companyafter the fifth year of the lease.The Company accounted for the amended lease agreementin accordance with ASC Topic 840, “Leases”, previously accounted for under SFASNo. 13, “Accounting for Leases (As Amended)”. Under the guidance, the leaseagreement continues to be accounted for as a capital lease and the imputedinterest rate necessary to reduce the net minimum lease payments to presentvalue over the lease term is 34.9%.

 

In June 2008, the Company entered into a two yearcapital lease agreement to acquire the production equipment used on board theNamoku resulting in additional capital assets of approximately $2.4 million.Further the Company capitalized an additional $2.8 million of productionequipment in order to have the FPSO ready to receive and treat oil receivedfrom the CX-11 platform. The FPSO lease contains two bargain purchase options;therefore, depreciation of the leased asset was over its useful life. The leasecontains a bargain purchase option of $1.0 million at the end of the first yearof the lease and a $0.5 million bargain purchase option at the end of thesecond year of the lease.  The Companyaccounted for the lease agreement in accordance with ASC Topic 840, “Leases”,previously accounted for under SFAS No. 13, “Accounting for Leases (AsAmended)”. Under the guidance, the lease agreement is accounted for as acapital lease and the imputed interest rate necessary to reduce the net minimumlease payments to present value over the lease term is 28.3%.

 

In March 2008, the Company entered into alease-purchase agreement to acquire the BPZ-02 barge resulting in additionalcapital assets of approximately $7.0 million. In February 2009, theCompany made the final lease payment on the BPZ-02 deck barge at which pointtitle to the barge was transferred to it.

 

In 2007, the Company entered into two capital loansfor the purchase of office furniture.  Both loans have a term of 60months, bearing interest at 5.94% and 9.44%, respectively, with principal andinterest payments due on a monthly basis.

 

**Note10 — Stockholders’ Equity**

** **

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

 

**September 2009 Private Placementof Common Stock**

 

On September 15, 2009, the Company closed aprivate placement of approximately 1.6 million shares of common stock, no parvalue, to IFC pursuant to a Subscription Agreement dated September 15,2009. This private placement was related to the Company’s registered directoffering of approximately 18.8 million shares of Common Stock at a price of$4.66 per share that closed on June 30, 2009. Pursuant to the SubscriptionAgreement dated December 16, 2006 (the “Subscription Agreement”) by andbetween IFC and the Company, IFC has the right, within 45 days of notice of theoffering, to purchase shares of the Company’s Common Stock for the same priceand terms as the participants in an offering to retain its proportionateownership in the Company. IFC exercised its pre-emptive right to purchaseapproximately 1.6 million shares of Common Stock at the offering price of $4.66per share to which it was entitled under the Subscription Agreement, resultingin gross proceeds to the Company of approximately $7.6 million. The transactionwas submitted to and approved by the shareholders of the Company at a SpecialMeeting of Shareholders on August 24, 2009. No warrants or dilutivesecurities were issued to IFC in connection with the private placement. Theshares were placed directly by the Company. The Company 

 

92

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

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

 

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

 

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

 

**June 2009 Registered DirectOffering of Common Stock**

 

On June 30, 2009, the Company closed its sale ofapproximately 18.8 million shares of its common stock, no par value, in aregistered direct offering under an effective shelf registrationstatement.  The shares of common stock were priced at $4.66 per shareresulting in net proceeds to the Company, after placement agent fees and otherfees, of approximately $82.9 million. In connection with the registered directoffering, the Company entered into a placement agency agreement with CanaccordAdams Inc. as lead placement agent for the offering along with PritchardCapital Partners, LLC, and Raymond James and Associates, Inc. In addition,Rodman & Renshaw, LLC, and Wunderlich Securities, Inc. assistedas agents in the transaction. The Company paid approximately $4.4 million as a5% placement agency fee of the gross proceeds received by the Company inaccordance with the terms of the placement agency agreement. The Company usedthe proceeds of this offering to develop its properties under its existinglicense contracts and other general corporate purposes consistent with theCompany’s operating plans.

 

**February 2009 Private Placementof Common Stock**

 

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

 

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

 

93

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

**March 2008 Public Offering ofCommon Stock**

 

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

 

**Contingent Incentive Earn-OutShares**

 

During2005, the Company’s Board of Directors awarded a total of 485,000 shares ofincentive stock awards to three of the Company’s officers. The incentive stockawards vest and the earn-out shares are issuable once the Company is entitledto receive as its proportionate share from gross production from any oil andgas wells owned or operated by the Company not less than 2,000 barrels of oilper day or its equivalent (approximately 12 million cubic feet of gas per day)prior to December 28, 2007, the same target applicable to the Mergerearn-out shares. However, one of the Company’s officers entitled to receiveearn-out shares resigned from the Company and its subsidiaries effective June 15,2006, and as a result 225,000 of the unvested contingent incentive stockawards, representing $990,000 of future possible compensation expense, wereforfeited. Subsequently, 190,000 shares of those 225,000 shares were awarded tothe officer’s successor to supplement a previous award of 35,000 shares. The secondearn-out target provided for in the original merger agreement related to itsmerger with Navidec, Inc.  In November 2007,the production target in the Merger Agreement dated July 8, 2004 wasachieved. The determination was made by the Company’s Board of Directors basedon certification by the independent engineering firm that the Company’sproduction in Peru has met or exceeded the required level of production.

 

Theachievement of the required level of production resulted in the issuance of450,000 shares.  For accounting purposes,during the year ended December 31, 2007, $1,980,000 was recorded ascompensation expense.

 

**November 2007 Convertible Debt**

 

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

 

**PotentiallyDilutive Securities**

** **

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

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

 

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

 

94

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

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

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

 

----

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

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

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

 

**StockOption and Restricted Stock Plans**

 

The Company has in effect the 2007 Long-Term IncentiveCompensation Plan (the “2007 LTIP”) and the 2007 Directors’ CompensationIncentive Plan (the “Directors’ Plan”). The 2007 LTIP and Directors’ Planprovides for awards of options, stock appreciation rights, restricted stock,restricted stock units, performance awards, other stock-based awards andcash-based awards to any of the Company’s officers, employees, consultants andthe employees of certain of the Company’s affiliates as well as non-employeedirectors. The number of shares authorized under the 2007 LTIP and Directors’Plan is 4.0 million and 2.5 million, respectively. As of December 31,2009, 163,900 shares remain available for future grants under the 2007 LTIP and1,375,000 shares remain available for future grants under the Directors’ Plan.

 

**RestrictedStock Awards and Performance Shares**

 

At December 31,2009, there were approximately 787,900 shares of restricted stock awardsoutstanding to officers, directors and employees all of which generally vestwith the passage of time on the second or third anniversary of the date ofgrant. Restricted stock is subject to certain restrictions on ownership andtransferability when granted. The fair value of restricted stock awards isbased on the market price of the Common Stock on the date of grant.  Compensation cost for suchawards is recognized ratably over the vesting or service period, net offorfeitures; however, compensation cost related to performance shares will notbe recorded or will be reversed if the Company does not believe it is probablethat such performance criteria will be met or if the service provider (employeeor otherwise) fails to meet such criteria.

 

Asummary of the Company’s restricted stock award activity for the year ended December 31, 2009 and relatedinformation is presented below:

 

95

----

Table of Contents

 

**BPZRESOURCES, INC AND SUBSIDIARIES**

**NOTESTO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

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

 

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

 

**StockOptions**

 

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

 

Thefair value of each stock option granted is estimated on the date of grant usinga Black-Scholes option pricing model. The Black-Scholes option valuation modelwas developed for use in estimating the fair value of traded options, whichhave no vesting restrictions and are fully transferable and negotiable in afree trading market. This model does not consider the employment, transfer orvesting restrictions that are inherent in the Company’s stock options.

 

Useof an option valuation model includes highly subjective assumptions based onlong-term predictions, including the expected stock price volatility andexpected option term of each stock option grant.

 

Thefollowing table presents the weighted-average assumptions used in the optionpricing model for options granted during the year ended December 31,:

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

 

----

(a)         The expected life was derivedbased on a weighting between (a) the Company’s historical exercise andforfeiture activity and (b) the average midpoint between vesting and thecontractual term and (c) from the analysis of other companies of a similarsize and operational life cycle.

(b)         The volatility is based onthe historical volatility of our stock for a period approximating the expectedlife.

(c)         The risk-free interest rateis based on the observed U.S.  Treasury yield curve in effect at the timethe options were granted.

(d)        The dividend yield is basedon the fact the Company does not anticipate paying any dividends.

 

96

----

Table ofContents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

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

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

 

Asof December 31, 2009, there was $4.5 million of unrecognizedcompensation cost related to non-vestedstock options that is expected to be recognized over a weightedaverage period of 1.1 years. The total intrinsic value of stock options(defined as the amount by which the market price of the Common Stock on thedate of exercise exceeds the exercise price of the stock option) exercisedduring the years ended December 31, 2009, 2008 and 2007  was $0.7 million,$16.0 million and $9.7 million, respectively. Cash received fromstock option exercises for the years ended December 31, 2009, 2008 and2007 was $0.6 million, $2.4 million and $3.4 million,respectively.

 

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

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

 

**Note 11**— Restatementof Merger Earn-Out Shares

** **

OnSeptember 10, 2004, BPZ Energy, Inc., a Texas corporation (“BPZ-Texas”),consummated a reverse merger with Navidec, Inc. (“Navidec”) wherebyBPZ-Texas became a wholly owned subsidiary of Navidec (the “Merger”). As aresult of the Merger, the shareholders of BPZ-Texas received the majority ofthe voting interest control of the Board of Directors and management of thecombined entity and on February 4, 2005, Navidec changed its name to BPZEnergy, Inc. (now known as BPZ Resources, Inc.). For accountingpurposes, BPZ-Texas was treated as the acquiring entity. The Merger Agreementprovided for the immediate issuance by Navidec of 9,000,000 shares of itscommon stock to the shareholders of BPZ-Texas and the future issuance ofadditional merger consideration of 18,000,000 shares on an earn-out basis ifthe Company achieved certain reserve and production goals. The first 9,000,000earn-out shares were contingent on achieving certain reserve targets, whichwere achieved in December 2004. However, the contingent earn-out sharescould only be issued after the shareholders approved an increase in the numberof authorized common shares of the Company. The shareholders approved anincrease in the number of authorized shares from 20,000,000 to 250,000,000 atits 2005 Annual Meeting held on July 1, 2005 and the 9,000,000 shares wereissued at that time.  The closing priceof BPZ common stock was $4.40 per share on that day.  The 

 

97

----

Table ofContents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

remaining9,000,000 earn-out shares were contingent on the Company becoming entitled toreceive as its proportionate share from gross production from any oil and gaswells owned or operated by the Company not less than 2,000 barrels of oil perday or its equivalent (approximately 12 million cubic feet of gas per day)prior to December 28, 2007. On November 2, 2007 this productiontarget was achieved, based on certification by an independent engineering firmthat the Company’s production in Peru had met or exceeded the required level ofproduction and the shares were issued. On November 2, 2007, the closing price of the Company’s commonshares was $10.87 per share.

 

Atthe time of each earn-out, for accounting purposes, each earn-out was treatedas a stock dividend because the earn-out was payable to the shareholders of theaccounting acquirer, BPZ-Texas. Accordingly, we disclosed a retroactiveincrease in the number of common shares outstanding for all periods presentedand no accounting entry was recorded upon the issuance of the earn-outshares.  However, upon further analysis,the Company has determined that the presentation of the impact of the earn-outsshould be changed to provide greater clarity concerning the associatedre-allocation of value between the former BPZ-Texas shareholders and the othershareholders of the Company. Therefore, the Company has done the following:

 

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

 

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

 

Thefollowing table shows the adjustment to Stockholders’ Equity in each periodpresented to reflect the fair value of the merger earn-out shares granted ateach issuance date:

 

*As Originally Reported (inthousands):*

** **
| ** **                                                                                                                                                                                    | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| **Stockholders’ Equity**                                                                                                                                                                 | ** ** | **2008**              | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
| Stockholders’ equity:                                                                                                                                                                    |       |                  |       |   |   |   |   |   |   |
| Preferred stock, no par value, 25,000,000  authorized; none issued and outstanding                                                                                                            |       | $                     | —     |   | $ | — |   | $ | — |   | $ | — |   |
| Common stock, no par value, 250,000,000 authorized;  78,748,390, 73,914,471, 54,143,717 and 40,347,979 shares issued and  outstanding at December 31, 2008, 2007, 2006 and 2005, respectively |       | 227,136               |       | 149,050 |   | 96,575 |   | 56,874 |   |
| Additional paid in capital                                                                                                                                                                    |       | —                |       | — |   | 5,092 |   | 2,401 |   |
| Stock subscription receivable                                                                                                                                                                 |       | —                |       | — |   | (231 | ) | (231 | ) |
| Accumulated deficit                                                                                                                                                                           |       | (67,956               | )          | (58,310 | ) | (37,800 | ) | (22,312 | ) |
|                                                                                                                                                                                          |       |                  |       |   |   |   |   |   |   |
| Total stockholders’ equity                                                                                                                                                               |       | $                     | 159,180    |   | $ | 90,740 |   | $ | 63,636 |   | $ | 36,732 |   |

 

98

----

Table ofContents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

*As Adjusted (in thousands):*

* *
| ** **                                                                                                                                                                                    | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-----------------------|------------|
| **Stockholders’ Equity**                                                                                                                                                                 | ** ** | **2008**              | ** ** | **2007** | ** ** | **2006** | ** ** | **2005** | ** ** |
| Stockholders’ equity:                                                                                                                                                                    |       |                  |       |   |   |   |   |   |   |
| Preferred stock, no par value, 25,000,000  authorized; none issued and outstanding                                                                                                            |       | $                     | —     |   | $ | — |   | $ | — |   | $ | — |   |
| Common stock, no par value, 250,000,000 authorized;  78,748,390, 73,914,471, 54,143,717 and 40,347,979 shares issued and  outstanding at December 31, 2008, 2007, 2006 and 2005, respectively |       | 364,566               |       | 286,480 |   | 136,175 |   | 96,474 |   |
| Additional paid in capital                                                                                                                                                                    |       | —                |       | — |   | 5,092 |   | 2,401 |   |
| Stock subscription receivable                                                                                                                                                                 |       | —                |       | — |   | (231 | ) | (231 | ) |
| Accumulated deficit                                                                                                                                                                           |       | (205,386              | )          | (195,740 | ) | (77,400 | ) | (61,912 | ) |
|                                                                                                                                                                                          |       |                  |       |   |   |   |   |   |   |
| Total stockholders’ equity                                                                                                                                                               |       | $                     | 159,180    |   | $ | 90,740 |   | $ | 63,636 |   | $ | 36,732 |   |

 

**Thefollowing table shows the adjustment to the Stockholders’ Equity in each of the2009 and 2008 quarterly periods presented to reflect the fair value of themerger earn-out shares outstanding:**

 

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

 
| **Stockholders’ Equity**                                                                                                                                                                                     | ** ** | **March 31,** | ** ** | **June 30,** | ** ** | **September 30,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|-------------------|------------|------------------------|------------|
| ** **                                                                                                                                                                                                        | ** ** | **(Unaudited)**    | ** ** | **(Unaudited)**   | ** ** | **(Unaudited)**        | ** ** |
| Stockholders’ equity:                                                                                                                                                                                        | ** ** | ** **         | ** ** | ** **        | ** ** | ** **             | ** ** |
| Preferred stock, no par value, 25,000,000  authorized; none issued and outstanding                                                                                                                                |       | $                  | —     |              | $          | —                 |       | $ | — |   |
| Common stock, no par value, 250,000,000 authorized;  94,486,094, 113,399,234 and 115,079,760 shares issued and outstanding at  March 31, 2009, June 30, 2009 and September 30, 2009,  respectively |       | 275,271            |       | 362,235           |       | 372,622                |       |
| Accumulated deficit                                                                                                                                                                                               |       | (75,004            | )          | (84,818           | )          | (93,780                | )          |
|                                                                                                                                                                                                              |       |               |       |              |       |                   |       |
| Total stockholders’ equity                                                                                                                                                                                   |       | $                  | 200,267    |              | $          | 277,417                |       | $ | 278,842 |   |

 

*2009 AsAdjusted (In thousands except share data):*

*** ***
| **Stockholders’ Equity**                                                                                                                                                                                     | ** ** | **March 31,** | ** ** | **June 30,** | ** ** | **September 30,** | ** ** |
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|-------------------|------------|------------------------|------------|
| ** **                                                                                                                                                                                                        | ** ** | **(Unaudited)**    | ** ** | **(Unaudited)**   | ** ** | **(Unaudited)**        | ** ** |
| Stockholders’ equity:                                                                                                                                                                                        |       |               |       |              |       |                   |       |
| Preferred stock, no par value, 25,000,000  authorized; none issued and outstanding                                                                                                                                |       | $                  | —     |              | $          | —                 |       | $ | — |   |
| Common stock, no par value, 250,000,000 authorized;  94,486,094, 113,399,234 and 115,079,760 shares issued and outstanding at  March 31, 2009, June 30, 2009 and September 30, 2009,  respectively |       | 412,701            |       | 499,665           |       | 510,052                |       |
| Accumulated deficit                                                                                                                                                                                               |       | (212,434           | )          | (222,248          | )          | (231,210               | )          |
|                                                                                                                                                                                                              |       |               |       |              |       |                   |       |
| Total stockholders’ equity                                                                                                                                                                                   |       | $                  | 200,267    |              | $          | 277,417                |       | $ | 278,842 |   |

 

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

 
| **Stockholders’ Equity**                                                                                                                                                                                   | ** ** | **March 31,** | ** ** | **June 30,** | ** ** | **September 30,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|-------------------|------------|------------------------|------------|
| ** **                                                                                                                                                                                                      | ** ** | **(Unaudited)**    | ** ** | **(Unaudited)**   | ** ** | **(Unaudited)**        | ** ** |
| Stockholders’ equity:                                                                                                                                                                                      |       |               |       |              |       |                   |       |
| Preferred stock, no par value, 25,000,000  authorized; none issued and outstanding                                                                                                                              |       | $                  | —     |              | $          | —                 |       | $ | — |   |
| Common stock, no par value, 250,000,000 authorized;  76,438,471, 78,251,890 and 78,745,890 shares issued and outstanding at  March 31, 2008, June 30, 2008 and September 30, 2008,  respectively |       | 192,360            |       | 215,783           |       | 222,103                |       |
| Accumulated deficit                                                                                                                                                                                             |       | (65,732            | )          | (70,388           | )          | (61,777                | )          |
|                                                                                                                                                                                                            |       |               |       |              |       |                   |       |
| Total stockholders’ equity                                                                                                                                                                                 |       | $                  | 126,628    |              | $          | 145,395                |       | $ | 160,326 |   |

 

99

----

Table ofContents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

*2008 AsAdjusted (In thousands except share data):*

 
| **Stockholders’ Equity**                                                                                                                                                                                   | ** ** | **March 31,** | ** ** | **June 30,** | ** ** | **September 30,** | ** ** |
|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|-------------------|------------|------------------------|------------|
| ** **                                                                                                                                                                                                      | ** ** | **(Unaudited)**    | ** ** | **(Unaudited)**   | ** ** | **(Unaudited)**        | ** ** |
| Stockholders’ equity:                                                                                                                                                                                      |       |               |       |              |       |                   |       |
| Preferred stock, no par value, 25,000,000  authorized; none issued and outstanding                                                                                                                              |       | $                  | —     |              | $          | —                 |       | $ | — |   |
| Common stock, no par value, 250,000,000 authorized;  76,438,471, 78,251,890 and 78,745,890 shares issued and outstanding at  March 31, 2008, June 30, 2008 and September 30, 2008,  respectively |       | 329,790            |       | 353,213           |       | 359,533                |       |
| Accumulated deficit                                                                                                                                                                                             |       | (203,162           | )          | (207,818          | )          | (199,207               | )          |
|                                                                                                                                                                                                            |       |               |       |              |       |                   |       |
| Total stockholders’ equity                                                                                                                                                                                 |       | $                  | 126,628    |              | $          | 145,395                |       | $ | 160,326 |   |

 

Thefollowing table shows the adjustment to earnings per share for each annualperiod presented to reflect the increase in shares outstanding when issued withoutretroactively increasing the prior periods common shares outstanding:

 

*As Originally Reported (inthousands except per share data):*

** **
| ** **                                 | ** ** | **For the Year Ended December 31,** | ** ** |
|--------------------------------------------|------------|------------------------------------------|------------|
| **Operating Results:**                     | ** ** | **2007**                                 | ** ** | **2006** | ** ** | **2005** | ** ** |
|                                       |       |                                     |       |   |   |   |   |
| Net loss                                   |       | $                                        | (20,510    | ) | $ | (15,487 | ) | $ | (6,407 | ) |
|                                       |       |                                     |       |   |   |   |   |
| Basic and diluted net loss per share       |       | $                                        | (0.30      | ) | $ | (0.29 | ) | $ | (0.16 | ) |
|                                       |       |                                     |       |   |   |   |   |
| Weighted average common shares outstanding |       | 69,156                                   |       | 53,752 |   | 40,899 |   |

* *

*As Adjusted (in thousands exceptper share data):*

* *
| ** **                                 | ** ** | **For the Year Ended December 31,** | ** ** |
|--------------------------------------------|------------|------------------------------------------|------------|
| **Operating Results:**                     | ** ** | **2007**                                 | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                 |       |                                     |       |   |   |   |   |
| Net loss                                   |       | $                                        | (20,510    | ) | $ | (15,487 | ) | $ | (6,407 | ) |
|                                       |       |                                     |       |   |   |   |   |
| Basic and diluted net loss per share       |       | $                                        | (0.33      | ) | $ | (0.35 | ) | $ | (0.23 | ) |
|                                       |       |                                     |       |   |   |   |   |
| Weighted average common shares outstanding |       | 61,660                                   |       | 44,752 |   | 27,399 |   |

 

**Note 12 — Affiliate and Related Party Transactions**

** **

For the years ended December 31, 2009, 2008 and2007, the Company had not entered into any transactions with affiliates orrelated parties.

 

**Note 13 — Revenue**

 

At December 31, 2009, the Company is currentlyproducing oil from five wells in the Corvina field and one well in the Albacorafield under a well testing program. At December 31, 2008, the Company wasproducing oil from four wells in the Corvina field under a well testingprogram.

 

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

 

100

----

Table of Contents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

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

 

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

 

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

 

In 2007 and 2008, the Company had two short-termcontracts for the sale of oil with Petroperu since it began oil production in November 2007. The first contract was for the sale of up to 200,000 barrels of oil to therefinery in Talara.  The contract was fulfilled in June 2008.  During the second half of 2008, the Company’ssales agreement with Petroperu was for the delivery of up to 400,000 barrels ofoil to the Talara refinery whose per barrel sales price was based on NorthwestOil Basket pricing which is comprised of Oman, Fortes and Suez Blendpricing.  The unadjusted sales price was based on the past five dayaverage before the crude oil delivery date.  The price was then discountedfor the quality of the oil delivered.  The determination of quality was basedon the gravity of the oil expressed in degrees, as determined under standardsestablished by the American Petroleum Institute (“API”).  The price wasdiscounted at a rate of 0.53% of the basket price per one degree API lower thanthe benchmark of 33 degrees API as stipulated in the contract.  Inaddition, a fixed premium of $0.75 per barrel was added to the price as aresult of the high diesel content of the crude oil.

 

During the years ended December 31, 2009, 2008 and 2007, the Company producedapproximately 991,003, 826,534 and 40,989 barrels of oil, respectively. For the years ended December 31, 2009, 2008 and 2007, the Company sold962,551, 825,845 and 28,741 barrels of oil at an average per barrel price, netof royalties, of approximately $54.49, $76.23 and $81.78, respectively.

 

The Company’s revenues are reported net of royaltiesowed to the government of Peru. Royalties are assessed by Perupetro asstipulated in the Block Z-1 license agreement based on production. Howevertheir calculation is based on the past five-day average basket of crude oilsprices, as discussed above, before the crude oil delivery date. For the  years ended December 31, 2009, 2008 and2007, the revenues received by the Company are net of royalty costs ofapproximately 5% of gross revenues or $2.9 million, $3.3 million and $0.1million, respectively.

 

**Note 14 — Income Taxes**

 

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

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

 

101

----

Table of Contents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

Theincome tax provision (benefit) for the year ended December 31, consists ofthe following (in thousands)

 
| ** **                           | ** ** | **2009** | ** ** | **2008** | ** ** | **2007** | ** ** |
|--------------------------------------|------------|----------|------------|----------|------------|----------|------------|
| Current Taxes                        |       |     |       |     |       |     |       |
| Federal                              |       | $        | 200        |     | $          | —   |       | $ | 39 |   |
| Foreign                              |       | 6,709    |       | 7,536    |       | —   |       |
| Total Current Taxes                  |       | 6,909    |       | 7,536    |       | 39       |       |
|                                 |       |     |       |     |       |     |       |
| Deferred Taxes                       |       |     |       |     |       |     |       |
| Federal                              |       |     | —     |     |       | —   |       |   | — |   |
| Foreign                              |       | (13,484  | )          | (4,395   | )          | —   |       |
| Total Deferred Taxes                 |       | (13,484  | )          | (4,395   | )          | —   |       |
| Total Income Tax Provision (Benefit) |       | $        | (6,575     | )        | $          | 3,141    |       | $ | 39 |   |

 

Theincome tax expense (benefit) for the year ended December 31, 2009, 2008and 2007 differs from the amount computed by applying the U.S. statutoryfederal income tax rate for the applicable year to consolidated net loss beforeincome taxes as follows (in thousands):

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

 

102

----

Table of Contents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

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

 
| ** **                              | ** ** | **2009** | ** ** | **2008** | ** ** |
|-----------------------------------------|------------|----------|------------|----------|------------|
| Deferred Tax:                           |       |     |       |     |       |
| Asset:                                  |       |     |       |     |       |
| Net Operating Loss                      |       | $        | 16,546     |     | $          | 19,941 |   |
| Deferred Compensation                   |       | 2,514    |       | 1,889    |       |
| Foreign Tax AMT                         |       | 1,647    |       | —   |       |
| Asset Basis Difference                  |       | —   |       | —   |       |
| Exploration Expense                     |       | 7,256    |       | 2,080    |       |
| Depreciation                            |       | —   |       | 12       |       |
| Depletion                               |       | 8,162    |       | 3,340    |       |
| Asset Retirement Obligation             |       | 67       |       | 27       |       |
| Overhead Allocaion to Foreign Locations |       | 2,298    |       | —   |       |
| Other                                   |       | 119      |       | 666      |       |
| Liability:                              |       | —   |       | —   |       |
| Preoperation Expenses                   |       | (295     | )          | (295     | )          |
| Depreciation                            |       | (18      | )          |     |       |
| Asset Basis Difference                  |       | (1,819   | )          | (1,298   | )          |
| Other                                   |       | (1       | )          | (300     | )          |
| Net Deferred Tax Asset                  |       | $        | 36,476     |     | $          | 26,062 |   |
|                                    |       |     |       |     |       |
| Less Domestic Valuation Allowance       |       | (19,548  | )          | (21,191  | )          |
| Deferred Tax Asset                      |       | $        | 16,928     |     | $          | 4,871 |   |

 

As of December 31,2009, the Company had a valuation allowance for the full amount of the domesticdeferred tax asset resulting from the income tax benefit generated from netlosses, as it believes, based on the weight of available evidence, that it ismore likely than not that the deferred tax asset will not be realized prior tothe expiration of net operating loss carryforwards in various amounts through2028. Furthermore, because the Company has no operations within the U.S. taxingjurisdiction, it is likely that a sufficient generation of revenue to offsetthe Company’s deferred tax asset is remote.  As a result, the Company hasa full allowance on its deferred tax asset generated in the U.S.  However, the Company is subject to Peruvianincome tax on its earnings at a statutory rate, as defined in the Block Z-1License Contract, of 22%.  Because the Company is under a well testingprogram from which it will finalize a development plan for Block Z-1, it hasnot moved into the commercial phase of production as defined by the licensecontract.  As such, certain deductions are disallowed by the Peruvian taxregime while the Company operates under the well testing program.  Inaddition, the tax provision is based on taxable Peruvian income that excludescertain U.S. expenses that are not deductible at the Peruvian level. As aresult, the Company recognized a total tax provision for the year ended December 31,2009 of approximately $6.6 million.

 

TheCompany anticipates moving into commercial production in Block Z-1 under thelicense contract in 2010, at which time its full investment in its producingproperties will be eligible to be amortized over five years. The Companyassessed the realizability of the deferred tax asset generated in Peru.  It considered whether it is more likely thannot that some portion or all of the deferred tax asset will not berealized.  The ultimate realization ofthe deferred tax asset is dependent upon the generation of future taxable incomein Peru during the periods in which those temporary differences becomedeductible.  Based upon the level ofhistorical taxable income and projections for future taxable income over theperiods in which the deferred tax assets are deductible, along with thetransition into the commercial phase under the Block Z-1 License Contract, theCompany believes it is more likely than not that it will realize the benefitsof the these deductible differences at December 31, 2009.  As a result, the Company recognized adeferred tax asset of $16.9 million as of December 31, 2009.

 

**Estimatedinterest and penalties related to potential underpayment on unrecognized taxbenefits, if any, are classified as a component of tax expense in theConsolidated Statement of Operations. As of the date of adoption of FIN 48,  codified under ASC Topic 740, “Income Taxes’,the Company did not have any accrued interest or penalties associated with any**

 

103

----

Table of Contents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

**unrecognizedtax benefits, nor was any interest expense recognized during the year.Additionally, the adoption had no effect on the Company’s financial position orresults of operations.  The Company didnot have any uncertain tax positions generated from unrecognized tax benefitsresulting from differences between positions taken in tax returns and amountsrecognized in the financial statements as of December 31, 2009 or December 31,2008.**

 

**Note 15— Business Segment Information**

 

The Company determines and discloses its segments inaccordance with ASC Topic 280, “Segment Reporting” (“ASC Topic 280”) ,previously in accordance with SFAS No. 131 “Disclosures about Segments ofan Enterprise and Related Information”,  which uses a “management”approach for determining segments. The management approach designates theinternal organization that is used by management for making operating decisionsand assessing parlance as the source of the Company’s reportable segments. ASCTopic 280 also requires disclosures about products or services, geographicareas, and major customers. The Company’s management reporting structure providedfor only one segment for the years ended December 31, 2009, 2008 and 2007 andaccordingly, no separate segment information is presented. In addition, theCompany operates only in Peru and has only one customer for its oil production,Petroperu. The majority of the Company’s long-lived assets are located in Peru.

 

**Note 16 — Commitments and Contingencies**

** **

*Extended Well Testing Program*

 

On December 13,2009 new legislation regulating extended well testing in Peru became effectiveby means of a Supreme Decree.  The new regulation provides that all newwells may be placed on production testing for up to six months.  If theoperator believes that additional time for testing is needed to properlyevaluate the productive capacity of the field, and can technically justifysuch need, a request for the well to enter into an Extended Well Test (“EWT”)period must be submitted to the DGH, the agency of the Ministry of Energy andMines responsible for regulating the optimum development of oil and gasfields.  The approval process for an EWT permit requires that the DGHrequest Perupetro’s opinion on the technical justification for the EWT. After the initial six month period or after an approved EWT program expires,the operator will be required to have the necessary gas and water reinjectionequipment in place to continue producing the well according to existingenvironmental regulations.  For wells that have been under testing formore than six months as of the date of publication of the Supreme Decree, thenew regulation provides 30 business days to apply to the DGH for thecorresponding EWT permit.

 

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

 

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

 

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

 

104

----

Table of Contents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

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

 

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

 

*Profit Sharing*

 

The Constitution of Peruand Legislative Decree Nos. 677 and 892 gives Peru employees working in privatecompanies engaged in activities generating income classified as third categoryincome by the Income Tax Law the right to share in the Company’s Peruviansubsidiaries profits. According to Article 3 of the United NationsInternational Standard Industrial Classification, BPZ E&P’s tax category isclassified 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 areincluded under “Companies Performing other Activities” thus Oil and GasCompanies pay profit sharing at a rate of 5%. The 5% of income is determined bycalculating a percentage of the Company’s Peruvian subsidiaries annual totalrevenues subject to income tax less the expenses required to produce revenue ormaintain the source of revenues. The benefit granted by the law to employees iscalculated on the basis of “income subject to taxation” per the Peruvian taxcode and not based on income/(loss) before incomes taxes as reported underGAAP. For the years ended December 31, 2009 and 2008, approximately$1.3 million and $1.9 million of expense related to profit sharing is included in “General andadministrative expense” in the Consolidated Statement of Operations as theCompany’s Peruvian subsidiaries have “income subject to taxation” per thePeruvian tax code.  No profitsharing was incurred by the Company for 2007 as the Company’s Peruvian subsidiaries did not have “incomesubject to taxation” per the Peruvian tax code during this period. The Companywill be subject to profit sharing expense each year its Peruvian subsidiariesare considered profitable under the Peruvian tax code.

 

*Barge Incident*

 

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

 

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

 

*Peru Properties*

 

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

 

105

----

Table of Contents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

** **

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

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

 

*GE Turbine Purchase Agreement**,**Amendment and LetterAgreement*

 

On September 26, 2008, the Company, through itssubsidiary Empresa Electrica Nueva Esperanza S.R.L., entered into a $51.5million contract (the “Agreement”) for the purchase of three LM6000 gas-firedturbines from GE Packaged Power, Inc. and GE International, Inc.Sucursal de Peru (collectively “GE”). The Agreement required an initial downpayment of $5.1 million and monthly progress payments of $1.1 million per unit.In January 2009 BPZ and GE entered into an amendment of the contract.Under the terms of the amendment, both GE and BPZ agreed to a suspension periodunder 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 obligationsunder the Agreement will give rise to a breach of contract or the right toterminate the contract, provided the Company make a $3.4 million progresspayment no later than February 25, 2009 and a $3.5 million progresspayment to GE no later than November 16, 2009. On February 24, 2009,the Company paid the first progress payment of $3.4 million. The Company wasstill in negotiations with GE to modify the terms of the Agreement at the timethe second progress payment was due on November 16, 2009, and GE agreed toa short extension of the deadline for the milestone payment in order toconclude ongoing negotiations with respect to new delivery dates, pricing,payment terms and payment security for the reinstatement of the Agreement.Amended terms were agreed with GE by Letter Agreement on November 20,2009, at which time the Company made the $3.5 million progress payment. Underthe terms of the Letter Agreement, GE and BPZ agreed to a variable monthlypayment plan with a final $20.7 million payment due December 1, 2010 forthe remaining $35.2 million due under the Agreement.  Additionally, should the Company locate ajoint venture partner and obtain financing for the three LM6000 gas-firedturbines and services prior to the December 1, 2010 deadline, the Companyagrees to pay the final payment under the Letter Agreement within 7 days ofobtaining the financing and funding.

 

Should the Company not make the payments in accordancewith the terms of the Letter Agreement, this would result in immediatetermination of the Agreement without any additional notice or cure period. Asof December 31, 2009, the Company has made payments to GE totaling $16.5million. Additionally in March 2010 the Company made a $2.5 millionpayment and plans to meet the remaining payments due throughout 2010 by usingproceeds of the recent convertible debt offering or subsequent projectfinancing. Failure to make any of the remaining progress payments in full wouldresult in a charge-off of all of the previously made progress payments.

 

*Reserve-Based Credit Facility*

 

In July 2009, the Company, through itssubsidiary, BPZ E&P, had secured formal commitments for a $70.0 millionreserve based credit facility, including $15.0 million previously receivedunder the IFC Facility.  The syndication of this facility was led byNatixis, a major French bank.  The other institutions participating in thesyndicate include IFC, Scotiabank and Banco de Crédito del Perú.

 

Subsequent to December 31, 2010, the Company,through its subsidiary, BPZ E&P, elected to terminate negotiations on thepreviously announced $55.0 million portion of the reserve based credit facilitybeing arranged by Natixis.  Withthe proceeds from the 2015 Convertible Notes offering, the termination of thesenegotiations is not expected to impact the Company’s ability to undertake its2010 capital expenditures program, including drilling and continued developmentof the Corvina and Albacora fields as well as payments due under the GE turbinepurchase agreement.

 

*Gas-to-Power Project Financing*

 

The Corvina gas-to-power project entails theinstallation 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.  Theproposed power plant site is located adjacent to anexisting substation and power transmission lines which, after the Peruviangovernment completes their expansion, are expected to be capable of handling upto 320 MW of power. The existing substation and transmission lines are owned andoperated by third parties.

 

The Company currently estimates the gas-to-powerproject will cost approximately $135.0 million, excluding 19% value-added taxwhich will be recovered via early recovery and/or future revenuebillings.  The $135.0 million includes $115.0 million for the estimatedcost of the power plant and $20.0 million for the estimated cost of theconstruction of the

 

106

----

Tableof Contents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

natural gas pipeline. Accordingly, the Company commenced discussionswith potential joint venture partners for the gas-to-power project in anattempt to secure additional equity for the project.  After receivingproposals for the Corvina gas-to-power project, management selected a potentialjoint venture partner in June 2009. The joint venture will be subject tothe satisfactory negotiation of a joint venture agreement and relateddocuments. To date, the Company has not entered into any definitive agreementsand is not currently in ongoing negotiations with a potential partner. In theevent the Company is able to reach agreement with a potential joint venturepartner, it may only retain a minority position in the project. However, theCompany expects to retain the responsibility for the construction of thepipeline as well as retain ownership of the pipeline. If the Company is unableto reach agreement with a potential partner, it is planning to continue movingthe project forward to completion. Decisions regarding project financing willbe determined as the Company moves the project forward to completion.

** **

**Note17 — Legal Proceedings**

** **

*NavyTanker Litigation*

 

On October 24, 2007,Tecnomarine SAC, a contractor to BPZ E&P entered into two short termagreements with the commercial division of the Peruvian Navy to charter twosmall tankers for use in the Company’s offshore oil production operation. On January 30, 2008, one of the tankers, the Supe, sank after catchingfire. Neither of the Peruvian governmental agencies charged withinvestigating the incident found fault with Tecnomarine SAC or the Company’ssubsidiary, BPZ E&P. A lawsuit was nonetheless filed in the 152nd JudicialDistrict Court of Harris County, Texas by two crewmembers and the family andestate of two deceased sailors injured in the incident, claiming negligence andgross negligence on the part of the BPZ Resources, Inc. and BPZ EnergyLLC., parent entities of BPZ E&P that were not parties to the charteroperation.  Based on the Company’s assessment of the available factsincluding the fact that none of the Peruvian government-sanctionedinvestigations into the Supe incident found fault on the part of Tecnomarine orBPZ E&P, the Company does not believe the outcome of the legal proceedingwill have a material adverse effect on its financial condition, results ofoperations or cash flows. The Company intends to vigorously defend this actionbut cautions that there is inherent risk in litigation, which is difficult toquantify, especially at the early stage of litigation proceedings.   TheCompany believes in any event that any monetary damages arising from theincident would be adequately covered by its insurance policies, after acustomary deductible.

 

*DisputedContract Settlement*

 

Towardsthe end of the first quarter of 2009, the Company was notified of an allegedbreach of a contractual obligation to a former consultant of the Companyrelated to services provided to both the Company and its predecessor at thetime the Company became publicly traded.  The Company has settled thisdispute and, as a result of the settlement, the Company agreed to pay $0.8million in exchange for a release of all claims against the Company for damagesrelated to the disputed contract obligation.  The payment is included in “Otherincome/(expense)” in the Consolidated Statements of Operations.  TheCompany paid the $0.8 million settlement in April 2009.

 

107

----

Table of Contents

 

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**YEARS ENDED DECEMBER 31, 2009, 2008 and 2007**

 

**Note18 — Operating Leases and Purchase Obligations**

** **

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

 

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

 

For Year Ending December 31,

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

 

Includesoperating leases for our executive office in Houston, Texas, and our branchoffices in Lima, Peru and warehouses in Peru, respectively, including therenting of current office space and warehouse space in Peru on a month-to-monthbasis through March 2010 and new office space and warehouse space in Peruthrough 2013, respectively.  Theoperating lease amounts also exclude $0.2 million of sublease rentals from ourHouston, Texas office due in the future under noncancelable subleases.

 

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

 

Includesthe monthly lease expense for one of our oil transportation vessels whose leaseis set to expire in March 2010.

 

Includesthe remaining amounts due for purchase of three LM6000 gas-fired turbines fromGE whose total purchase price is $51.5 million. 

 

**Note19 — Subsequent Events**

 

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

 

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

 

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

 

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

 

108

----

Tableof Contents

** **

**BPZ RESOURCES, INC AND SUBSIDIARIES**

**NOTES TO CONSOLIDATED FINANCIAL STATEMENTS**

 

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

** **

**Note20 — Quarterly Results of Operations (Unaudited)**

 
| ** **                                                    | ** ** | **Three Months Ended**         | ** ** |
|---------------------------------------------------------------|------------|------------------------------------------|------------|
| ** **                                                    | ** ** | **March 31,**                       | ** ** | **June 30,** | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
| ** **                                                    | ** ** | **(in thousands except per share data)** | ** ** |
| **2009**                                                      |       |                                     |       |   |   |   |   |   |   |
| Revenue,  net                                                 |       | $                                        | 13,225     |   | $ | 11,049 |   | $ | 13,088 |   | $ | 15,092 |   |
| Operating  loss                                               |       | (7,462                                   | )          | (10,885 | ) | (11,155 | ) | (12,986 | ) |
| Other  income (expense)                                       |       | (794                                     | )          | (584 | ) | 401 |   | 1,088 |   |
| Net  loss                                                     |       | $                                        | (7,048     | ) | $ | (9,813 | ) | $ | (8,963 | ) | $ | (9,978 | ) |
| ** **                                                    | ** ** | ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic  net income (loss) per share                            |       | $                                        | (0.08      | ) | $ | (0.10 | ) | $ | (0.08 | ) | $ | (0.09 | ) |
| Diluted  net income (loss) per share                          | ** ** | ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| ** **                                                    | ** ** | ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic and diluted weighted average common shares  outstanding |       | 88,620                                   |       | 95,347 |   | 113,929 |   | 115,135 |   |

 
| ** **                                         | ** ** | **Three Months Ended**         | ** ** |
|----------------------------------------------------|------------|------------------------------------------|------------|
| ** **                                         | ** ** | **March 31,**                       | ** ** | **June 30,** | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
| ** **                                         | ** ** | **(in thousands except per share data)** | ** ** |
| **2008**                                           |       |                                     |       |   |   |   |   |   |   |
| Revenue,  net                                      |       | $                                        | 4,367      |   | $ | 7,035 |   | $ | 33,440 |   | $ | 18,113 |   |
| Operating  loss                                    |       | (7,539                                   | )          | (5,225 | ) | 13,567 |   | (8,447 | ) |
| Other  income (expense)                            |       | 209                                      |       | 717 |   | 95 |   | 118 |   |
| Net  income (loss)                                 |       | $                                        | (7,422     | ) | $ | (4,656 | ) | $ | 8,611 |   | $ | (6,179 | ) |
| ** **                                         | ** ** | ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic  net income (loss) per share                 |       | $                                        | (0.10      | ) | $ | (0.06 | ) | $ | 0.11 |   | $ | (0.08 | ) |
| Diluted  net income (loss) per share               |       | $                                        | (0.10      | ) | $ | (0.06 | ) | $ | 0.11 |   | $ | (0.08 | ) |
| ** **                                         | ** ** | ** **                               | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Basic weighted average common shares outstanding   |       | 74,525                                   |       | 77,681 |   | 78,575 |   | 78,748 |   |
| Diluted weighted average common shares outstanding |       | 74,525                                   |       | 77,681 |   | 80,323 |   | 78,748 |   |

 

109

----

Table of Contents

 

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

 

**YEARSENDED DECEMBER 31, 2009, 2008 and 2007**

 

**Supplemental Oil and Gas Disclosures (Unaudited)**

** **

**Oil and Natural Gas Producing Activities**

 

The following disclosures for the Company aremade in accordance with ASC Topic 932, “Extractive Activities —Oil and Gas” andSEC rules for oil and gas reporting disclosures. Users of this informationshould be aware that the process of estimating quantities of proved, proveddeveloped and proved undeveloped crude oil and natural gas reserves is verycomplex, requiring significant subjective decisions in the evaluation of allavailable geological, engineering and economic data for each reservoir. Thedata for a given reservoir may also change substantially over time as a resultof numerous factors including, but not limited to, additional developmentactivity, evolving production history and continual reassessment of theviability 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 estimatesreported represent the most accurate assessments possible, the significance ofthe subjective decisions required and variances in available data for variousreservoirs make these estimates generally less precise than other estimatespresented in connection with financial statement disclosures. Accordingly,reserve estimates are often different from the quantities of crude oil andnatural gas ultimately recovered.

 

**SEC and FASBUpdates on Oil and Gas reporting**

 

On December 31, 2008 the SEC adopted the final rules regardingamendments to current oil and gas reporting requirements. See Recent Accountingpronouncements under Note 1, “Basis of Presentation and SignificantAccounting Policies*”* for further information. The amendments aredesigned to modernize and update the oil and gas disclosure requirements toalign them with current practices and changes in technology.  Additionally in January 2010 the FASBissued Accounting Standard Update 2010-3, “Oil and Gas Reserve Estimation andDisclosures”, to align its reporting guidance with the new SEC rules. TheCompany adopted these rules effective December 31, 2009 and thechanges, including those related to pricing, are included in the Company’sreserve estimates.

 

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

 

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

 

·                  Requiring companies to report theindependence and qualifications of a preparer or auditor, based on currentSociety of Petroleum Engineers criteria;

 

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

 

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

 

**Reserves**

 

Proved reserves represent estimatedquantities of crude oil and natural gas that geological and engineering datademonstrate, with reasonable certainty, to be recoverable in future years fromknown reservoirs under economic and operating conditions existing at the timethe estimates were made.

 

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

 

Proved undeveloped reserves are reserves thatare expected to be recovered from new wells on undrilled acreage or fromexisting wells where a relatively major expenditure is required forrecompletion. Reserves on undrilled acreage are limited to those drilling unitsoffsetting productive units that are reasonably certain of production whendrilled. Proved reserves for other undrilled units can be claimed only where itcan be demonstrated with certainty that there is continuity of 

 

110

----

Table of Contents

 

production from the existing productive formation. Estimates for provedundeveloped reserves are not attributed to any acreage for which an applicationof fluid injection or other improved recovery technique is contemplated, unlesssuch techniques have been proved effective by actual tests in the area and inthe same reservoir.

 

The Company’s relevant management controlsover proved reserve attribution, estimation and evaluation include:

 

·                  controls over and processes for thecollection and processing of all pertinent operating data and documents neededby our independent reservoir engineers to estimate our proved reserves;

 

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

 

·                  review by our senior reservoirengineer and his staff of the independent reservoir engineers’ reserves reportsfor completion and accuracy.

 

In 2009, an average of the first-day-of-the monthprice based upon the prior 12-month period will be used for future salesof natural gas, crude oil and natural gas liquids. Future operating costs,production taxes and capital costs will be based on current costs as of eachyear-end, with no escalation. There are numerous uncertainties inherent inestimating quantities of proved reserves and in projecting the future rates ofproduction and timing of development expenditures. Reserve data representestimates only and should not be construed as being exact. Moreover, thestandardized measure should not be construed as the current market value of theproved oil and natural gas reserves or the costs that would be incurred toobtain equivalent reserves. A market value determination would include manyadditional factors including (a) anticipated future changes in natural gasand crude oil prices, production and development costs, (b) an allowancefor return on investment, (c) the value of additional reserves, notconsidered proved at present, which may be recovered as a result of furtherexploration and development activities, and (d) other business risk.

 

***Capitalized Costs Relating to Oil and Gas ProducingActivities***

 

The following table sets forth thecapitalized costs relating to the Company’s natural gas and crude oil producingactivities at December 31, 2009 and 2008:

 
| ** **                                                                                                          | ** ** | **2009**           | ** ** | **2008** | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|--------------------|------------|----------|------------|
| ** **                                                                                                          | ** ** | **(in thousands)** | ** ** |
| Proved properties                                                                                                   |       | $                  | 226,299    |     | $          | 154,827 |   |
| Unproved properties                                                                                                 |       | 13,304             |       | 15,343   |       |
| Total                                                                                                               |       | 239,603            |       | 170,170  |       |
| Less: Accumulated depreciation, depletion and  amortization                                                         |       | (38,991            | )          | (15,946  | )          |
| Net capitalized cost                                                                                                |       | 200,612            |       | 154,224  |       |
|                                                                                                                |       |               |       |     |       |
| Company’s share of cost method investees’ costs of  property acquisition, exploration and development (1) |       | $                  | —     |     | $          | — |   |

 

----

(1)    BPZ Energy purchased theInvestment in Ecuador Property in 2004.

 

111

----

Table of Contents

 

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

 

***Costs Incurred in Oil and NaturalGas Property Acquisition, Exploration and Development Activities***

 

The followingtable sets forth costs incurred related to the Company’s oil and natural gasactivities for the year ended December 31, 2009 and 2008 (in thousands):

 
| ** **                                                                                                          | ** ** | **Total**  | ** ** |
|---------------------------------------------------------------------------------------------------------------------|------------|------------|------------|
| **Year Ended December 31, 2009:**                                                                              | ** ** | ** ** | ** ** |
| Acquisition  costs of properties                                                                                    | ** ** | ** ** | ** ** |
| Proved                                                                                                              |       | $          | —     |   |
| Unproved                                                                                                            |       | —     |       |
|                                                                                                                |       |       |       |
| Total acquisition costs                                                                                             |       | —     |       |
| Exploration  costs                                                                                                  |       | 9,546      |       |
| Development  costs                                                                                                  |       | 78,782     |       |
|                                                                                                                |       |       |       |
| Total                                                                                                               |       | $          | 88,328     |   |
|                                                                                                                |       |       |       |
| Company’s share of cost method investees’ costs of  property acquisition, exploration and development (1) |       | $          | —     |   |
| ** **                                                                                                          | ** ** | ** ** | ** ** |
| **Year Ended December 31, 2008:**                                                                              |       |       |       |
| Acquisition  costs of properties                                                                                    |       |       |       |
| Proved                                                                                                              |       | $          | —     |   |
| Unproved                                                                                                            |       | —     |       |
|                                                                                                                |       |       |       |
| Total acquisition costs                                                                                             |       | —     |       |
| Exploration  costs                                                                                                  |       | 795        |       |
| Development  costs                                                                                                  |       | 82,845     |       |
|                                                                                                                |       |       |       |
| Total                                                                                                               |       | $          | 83,640     |   |
|                                                                                                                |       |       |       |
| Company’s share of cost method investees’ costs of  property acquisition, exploration and development (1) |       | $          | —     |   |

 

----

(1)    BPZ Energy purchased theInvestment in Ecuador Property in 2004.

 

112

----

Table ofContents

 

***Results of Operations for Oil and Natural GasProducing Activities***

 

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

 
| ** **                                                                                             | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|----------------------------------|------------|
| ** **                                                                                             | ** ** | **2009**                         | ** ** | **2008** | ** ** | **2007** | ** ** |
| ** **                                                                                             | ** ** | ** **                       | ** ** | **(in thousands)** | ** ** | ** ** | ** ** |
| Oil  and natural gas production revenues                                                               |       |                             |       |   |   |   |   |
| Third-party                                                                                            |       | $                                | 52,454     |   | $ | 62,955 |   | $ | 2,350 |   |
| Affiliate                                                                                              |       | —                           |       | — |   | — |   |
|                                                                                                   |       |                             |       |   |   |   |   |
| Total revenues                                                                                         |       | 52,454                           |       | 62,955 |   | 2,350 |   |
| Exploration expenses                                                                                   |       | 7,768                            |       | 794 |   | 4,045 |   |
| Production costs                                                                                       |       | 28,113                           |       | 11,649 |   | 755 |   |
| Depreciation, depletion and amortization                                                               |       | 22,224                           |       | 15,141 |   | 538 |   |
| Oil and natural gas impairment                                                                         |       | —                           |       | — |   | — |   |
|                                                                                                   |       |                             |       |   |   |   |   |
| Income (loss) before income taxes                                                                      |       | (5,651                           | )          | 35,371 |   | (2,988 | ) |
| Income tax provision (benefit)                                                                         |       | (1,243                           | )          | 3,141 |   | — |   |
|                                                                                                   |       |                             |       |   |   |   |   |
| Results of continuing operations                                                                       |       | $                                | (4,408     | ) | $ | 32,230 |   | $ | (2,988 | ) |
|                                                                                                   |       |                             |       |   |   |   |   |
| Company’s share of cost method investees’ results  of operations for producing activities(1) |       | $                                | 1,396      |   | $ | 905 |   | $ | 452 |   |

 

----

(1)    Investment in EcuadorProperty

 

113

----

Table of Contents

 

***Net Proved Reserve Summary***

 

The following table sets forth the Company’s netproved developed and undeveloped reserves at December 31, 2009, 2008, 2007and 2006, and the changes in the net proved reserves for each of the threeyears in the period then ended. All of the Company’s proved reserves arelocated in Peru.  The Company’s netprofit interest in the Santa Elena property is located in Ecuador.

 
| ** **                                                                                                                           | ** ** | **Natural gas  (MMcf)(4)** | ** ** | **Natural gas liquids  and crude oil  (MBbls)(1)** | ** ** | **(MBbls)  equivalents(2)** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------|------------|----------------------------|------------|----------------------------------------------------|------------|-----------------------------|------------|
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| Net proved reserves at December 31, 2006                                                                                        |       | —                     |       | —                                             |       | —                      |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| Revisions of previous estimates                                                                                                      |       | —                     |       | —                                             |       | —                      |       |
| Purchases of minerals in place                                                                                                       |       | —                     |       | —                                             |       | —                      |       |
| Extensions, discoveries and other additions (6)                                                                                      |       | —                     |       | 11,981                                             |       | 11,981                      |       |
| Sales in place                                                                                                                       |       | —                     |       | —                                             |       | —                      |       |
| Production (8)                                                                                                                       |       | —                     |       | (41                                                | )          | (41                         | )          |
| Other                                                                                                                                |       | —                     |       | —                                             |       | —                      |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| Net proved reserves at December 31, 2007                                                                                        |       | —                     |       | 11,940                                             |       | 11,940                      |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| Revisions of previous estimates (7)                                                                                                  |       | —                     |       | (1,699                                             | )          | (1,699                      | )          |
| Purchases of minerals in place                                                                                                       |       | —                     |       | —                                             |       | —                      |       |
| Extensions, discoveries and other additions (6)                                                                                      |       | —                     |       | 7,740                                              |       | 7,740                       |       |
| Sales in place                                                                                                                       |       | —                     |       | —                                             |       | —                      |       |
| Production (8)                                                                                                                       |       | —                     |       | (827                                               | )          | (827                        | )          |
| Other                                                                                                                                |       | —                     |       | —                                             |       | —                      |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| Net proved reserves at December 31, 2008                                                                                        |       | —                     |       | 17,154                                             |       | 17,154                      |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| Revisions of previous estimates (7)                                                                                                  |       | —                     |       | (1,552                                             | )          | (1,552                      | )          |
| Purchases of minerals in place                                                                                                       |       | —                     |       | —                                             |       | —                      |       |
| Extensions, discoveries and other additions (6)                                                                                      |       | —                     |       | 22,873                                             |       | 22,873                      |       |
| Sales in place                                                                                                                       |       | —                     |       | —                                             |       | —                      |       |
| Production (8)                                                                                                                       |       | —                     |       | (991                                               | )          | (991                        | )          |
| Other                                                                                                                                |       | —                     |       | —                                             |       | —                      |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| Net proved reserves at December 31, 2009                                                                                        |       | —                     |       | 37,484                                             |       | 37,484                      |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| Company’s proportional interest in reserves of  investees accounted for by the cost method—December 31, 2009 (3) |       | —                     |       | 219                                                |       | 219                         |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| Proved  Developed Reserves as of:                                                                                                    |       |                       |       |                                               |       |                        |       |
| December 31, 2006 (5)                                                                                                           |       | —                     |       | —                                             |       | —                      |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| December 31, 2007                                                                                                               |       | —                     |       | 2,977                                              |       | 2,977                       |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| December 31, 2008                                                                                                               |       | —                     |       | 4,223                                              |       | 4,223                       |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| December 31, 2009                                                                                                               |       | —                     |       | 9,912                                              |       | 9,912                       |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| Proved  Undeveloped Reserves as of:                                                                                                  |       |                       |       |                                               |       |                        |       |
| December 31, 2006 (5)                                                                                                           |       | —                     |       | —                                             |       | —                      |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| December 31, 2007                                                                                                               |       | —                     |       | 8,963                                              |       | 8,963                       |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| December 31, 2008                                                                                                               |       | —                     |       | 12,930                                             |       | 12,930                      |       |
|                                                                                                                                 |       |                       |       |                                               |       |                        |       |
| December 31, 2009                                                                                                               |       | —                     |       | 27,573                                             |       | 27,573                      |       |

 

----

(1)                        Includescrude oil, condensate and natural gas liquids.

(2)                        Naturalgas volumes have been converted to equivalent natural gas liquids and crude oilvolumes using a conversion 

 

114

----

 

factor of six thousand cubic feet of natural gas to one barrel ofnatural gas liquids and crude oil.

(3)        Basedon an independent reservoir engineer’s report provided by the operator of theSanta Elena property.

(4)        TheCompany does not currently have the financial capacity or commitments for adevelopment program of this magnitude for its gas reserves. Accordingly, theCompany has not disclosed amounts of proved gas reserves in its SEC filings. Atsuch time as the Company obtains sufficient financial commitments to proceedwith the full development of the gas-to-power project and all other conditionsnecessary to record proved reserves are met, the Company expects to record SECproved gas reserves as permitted under SEC rules and disclose suchreserves in future SEC filings.

(5)        TheCompany did not have the financial capacity or commitments for a developmentprogram of this magnitude. Accordingly, the Company did not disclose amounts ofproved reserves in its SEC filings for the year ended December 31, 2006.

(6)        The2007 balance represents the initial oil reserves as a result of completing thetwo initial wells drilled and completed by the Company toward the end of 2007.The 2008 additions to the extensions, discoveries and additions of 7.8 MMBblswere due to additional wells drilled in 2008. The 2009 additions to the extensions, discoveries and additions of 22.8MMBbls were due to additional wells drilled in the Corvina field (12. 8 MMBbls)and the discoveries of the Albacora field (10.1 MMBbls).

(7)        The2008 negatives revisions were due to price. The 2007 reserve analysis as prepared by NSAI used  $85.49 per barrel price while the 2008reserve analysis as prepared by NSAI used a $37.80 per barrel price, resultingin a negative revision of 1.7 MMBbls in 2008. The 2009 reserve analysis as prepared by NSAI included negativesrevisions due to performance.  Thenegative revision was due to the lower than expected performance of the CX11-14D,CX11-18XD, and CX11-20XD wells and corresponding revisions of other wellsresulting in a negative revision of 1.6 MMBbls.

(8)        The2007 and 2008 oil production was from the Corvina field. The 2009 oilproduction of 991 MBbls includes 984MBbls from the Corvina field and 7 MBblsfrom the Albacora field.

 

***Standardized Measure of Discounted Future Net CashFlows Relating to Proved Oil and Natural Gas Reserves***

The following information has been developedutilizing procedures prescribed by U.S. GAAP and based on natural gas and crudeoil reserve and production volumes estimated by the independent petroleumreservoir engineers. This information may be useful for certain comparisonpurposes but should not be solely relied upon in evaluating the Company or itsperformance. Further, information contained in the following table should not beconsidered as representative of realistic assessments of future cash flows, norshould the standardized measure of discounted future net cash flows be viewedas representative of the current value of the Company’s oil and natural gasassets.

 

The future cash flows presented below are based onsales prices, cost rates and statutory income tax rates in existence as of thedate of the projections. It is expected that material revisions to someestimates of natural gas and crude oil reserves may occur in the future,development and production of the reserves may occur in periods other thanthose assumed, and actual prices realized and costs incurred may varysignificantly from those used. Income tax expense has been computed usingexpected future tax rates and giving effect to tax deductions and creditsavailable, under current laws, and which relate to oil and natural gasproducing activities.

 

Management does not rely upon the followinginformation in making investment and operating decisions. Such decisions arebased upon a wide range of factors, including estimates of probable as well asproved reserves and varying price and cost assumptions considered morerepresentative of a range of possible economic conditions that may beanticipated.

 

115

----

 

The following table sets forth the standardizedmeasure of discounted future net cash flows from projected production of theCompany’s crude oil reserves for the years ended December 31, 2009, 2008and 2007 (in thousands):

 
| **December 31, 2009**                                                                                                            |       |       |       |
|---------------------------------------------------------------------------------------------------------------------------------------|------------|------------|------------|
| Future cash inflows (3)                                                                                                               |       | $          | 2,147,862  |   |
| Future production costs                                                                                                               |       | (402,673   | )          |
| Future development costs                                                                                                              |       | (402,600   | )          |
| Future income tax expenses                                                                                                            |       | (256,746   | )          |
| Future net cash flows                                                                                                                 |       | 1,085,843  |       |
| Discount to present value at 10% annual rate                                                                                          |       | (347,284   | )          |
|                                                                                                                                  |       |       |       |
| Standardized measure of discounted future net cash  flows relating to proved natural gas, natural gas liquids and crude oil  reserves |       | $          | 738,559    |   |
|                                                                                                                                  |       |       |       |
| Company’s share of cost method investees’  standardized measure of discounted future net cash flows (1)                     |       | $          | 6,898      |   |
|                                                                                                                                  |       |       |       |
| **December 31, 2008**                                                                                                            |       |       |       |
| Future cash inflows (3)                                                                                                               |       | $          | 648,414    |   |
| Future production costs                                                                                                               |       | (103,999   | )          |
| Future development costs                                                                                                              |       | (127,300   | )          |
| Future income tax expenses                                                                                                            |       | (62,240    | )          |
| Future net cash flows                                                                                                                 |       | 354,875    |       |
| Discount to present value at 10% annual rate                                                                                          |       | (55,948    | )          |
|                                                                                                                                  |       |       |       |
| Standardized measure of discounted future net cash  flows relating to proved natural gas, natural gas liquids and crude oil  reserves |       | $          | 298,927    |   |
|                                                                                                                                  |       |       |       |
| Company’s share of cost method investees’  standardized measure of discounted future net cash flows (1)(2)                  |       | $          | 2,756      |   |
|                                                                                                                                  |       |       |       |
| ** **                                                                                                                            | ** ** | ** ** | ** ** |
| **December 31, 2007**                                                                                                            |       |       |       |
| Future cash inflows (3)                                                                                                               |       | $          | 1,020,728  |   |
| Future production costs                                                                                                               |       | (135,263   | )          |
| Future development costs                                                                                                              |       | (79,400    | )          |
| Future income tax expenses                                                                                                            |       | (155,081   | )          |
| Future net cash flows                                                                                                                 |       | 650,984    |       |
| Discount to present value at 10% annual rate                                                                                          |       | (94,302    | )          |
|                                                                                                                                  |       |       |       |
| Standardized measure of discounted future net cash  flows relating to proved natural gas, natural gas liquids and crude oil  reserves |       | $          | 556,682    |   |
|                                                                                                                                  |       |       |       |
| Company’s share of cost method investees’  standardized measure of discounted future net cash flows (1)(2)                  |       | $          | 3,400      |   |

 

----

(1)             Investmentin Ecuador Property

(2)             Basedon an independent reservoir engineer’s report provided by the operator of theSanta Elena property.

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

 

116

----

 

The following table sets forth the principal changes in theaggregate standardized measure of discounted future net cash flows attributableto the Company’s proved crude oil reserves. As 2008 is the first year subsequent to the Company’s initialdevelopment and production of its proved oil reserves, the requiredinformation is presented only for the years ended December 31, 2009 and2008 as follows:

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

 

117

----

 

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

** **

None.

 

**ITEM 9A. CONTROLS ANDPROCEDURES**

** **

**(a)****         Evaluation of DisclosureControls and Procedures**

 

We performed an evaluation, under the supervision andwith the participation of our management, including our principal executiveofficer and principal financial officer, of the effectiveness of the design andoperation of our disclosure controls and procedures as of the end of the periodcovered by this report.  Based on thatevaluation, our principal executive officer and principal financial officerhave concluded that as of December 31, 2009 our disclosure controls andprocedures, as defined in Rule 13a-15(e), are effective to ensure thatinformation we are required to disclose in the reports we file or submit underthe Securities Exchange Act of 1934 is recorded, processed, summarized andreported within the time periods specified in the Securities and ExchangeCommission’s rules and forms. Our disclosure controls and proceduresinclude controls and procedures designed to ensure that information required tobe disclosed in reports filed or submitted under the Exchange Act isaccumulated and communicated to our management, including our principalexecutive officer and principal financial officer, as appropriate, to allowtimely decisions regarding required disclosures.

 

**(b)****         Changes in InternalControl Over Financial Reporting**

 

There was no change in the Company’s internalcontrol over financial reporting during the quarter ended December 31,2009 that has materially affected, or is reasonably likely to materiallyaffect, the Company’s internal control over financial reporting.

 

**(c)****         Management’s Report onInternal Control over Financial Reporting and Report of Independent RegisteredPublic Accounting Firm on Internal Control over Financial Reporting**

 

Management of the Company, including our principal executive officerand principal financial officer, is responsible for establishing andmaintaining adequate internal controls over financial reporting, as defined in Rule 13a-15(f) ofthe Securities Exchange Act of 1934, as amended. Our internal controls aredesigned to provide reasonable assurance as to the reliability of our financialreporting and the preparation and presentation of the consolidated financialstatements for external purposes in accordance with accounting principlesgenerally accepted in the United States, as well as to safeguard assets fromunauthorized use or disposition.

 

Management conducted an evaluation of the effectiveness of our internalcontrols over financial reporting based on the framework in *Internal Control — Integrated Framework*issued by theCommittee of Sponsoring Organizations of the Treadway Commission. Thisevaluation included review of the documentation of controls, evaluation of thedesign effectiveness of controls, testing of the operating effectiveness ofcontrols and a conclusion on this evaluation. We did not identify any materialweaknesses in our internal controls as a result of this evaluation. Based onthis evaluation, management has concluded that our internal controls overfinancial reporting were effective as of December 31, 2009.

 

Johnson Miller & Co., CPA’s PC, the independent registeredpublic accounting firm who also audited our consolidated financial statements,has issued an attestation report on our internal control over financialreporting as of December 31, 2009, which is set forth below under “AttestationReport”.

 

118

----

 

**(d)****          Attestation Report**

 

Report ofIndependent Registered Public Accounting Firm on Internal Control over Financial Reporting

 

To the Board of Directors and Stockholders 

BPZ Resources, Inc. and Subsidiaries

Houston, Texas

 

We have audited BPZ Resources, Inc. and Subsidiaries’ internalcontrol over financial reporting as of December 31, 2009, based oncriteria established in *Internal Control —Integrated Framework*issued by the Committee of SponsoringOrganizations of the Treadway Commission (the COSO criteria). BPZ Resources, Inc.’smanagement is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internalcontrol over financial reporting, included in the accompanying Item 9A, “Management’s Annual Report on Internal Control Over Financial Reporting”. Ourresponsibility is to express an opinion on the Company’s internal control overfinancial reporting based on our audit.

 

We conducted our audit in accordance with the standards of the PublicCompany Accounting Oversight Board (United States). Those standards requirethat we plan and perform the audit to obtain reasonable assurance about whethereffective internal control over financial reporting was maintained in allmaterial respects. Our audit included obtaining an understanding of internalcontrol over financial reporting, assessing the risk that a material weaknessexists, and testing and evaluating the design and operating effectiveness ofinternal control based on the assessed risk. Our audit also included performingsuch other procedures as we considered necessary in the circumstances. Webelieve that our audit provides a reasonable basis for our opinion.

 

A company’s internal control over financial reporting is a process designedto provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes inaccordance with generally accepted accounting principles. A company’s internalcontrol over financial reporting includes those policies and procedures that (1) pertainto the maintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (3) provide reasonable assurance regarding preventionor timely detection of unauthorized acquisition, use, or disposition of thecompany’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financialreporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk thatcontrols may become inadequate because of changes in conditions, or that thedegree of compliance with the policies or procedures may deteriorate.

 

In our opinion, BPZ Resources, Inc. maintained, in all materialrespects, effective internal control over financial reporting as of December 31,2009, based on the COSO criteria*.*

 

We also have audited, in accordance with the standards of the PublicCompany Accounting Oversight Board (United States), the consolidated balancesheets of BPZ Resources, Inc. and Subsidiaries as of December 31,2009 and 2008, and the related consolidated statements of operations,stockholders’ equity and cash flows for each of the three years in the periodended December 31, 2009, and our report dated March 31, 2010,expressed an unqualified opinion thereon.

 

 

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

March 31, 2010

 

**ITEM 9B. OTHER INFORMATION**

 

None.

 

119

----

 

**PART III**

 

**ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATEGOVERNANCE**

** **

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

 

**ITEM 11.  EXECUTIVE COMPENSATION**

 

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

 

**ITEM 12. SECURITYOWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERMATTERS**

** **

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

 

**ITEM 13. CERTAINRELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE**

** **

**Theinformation required by this item is incorporated by reference from ourdefinitive proxy statement to be filed with the SEC within 120 days after theend 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 isincorporated by reference from our definitive proxy statement to be filed withthe SEC within 120 days after the end of our fiscal year covered by this AnnualReport on Form 10-K.

 

120

----

 

**PART IV**

 

**ITEM 15.EXHIBITS AND FINANCIAL STATEMENT SCHEDULES**

 

(a) Thefollowing documents are filed as part of this report:

 
| **1.**     | ** ** | **Financial  Statements.**                                                                                                                                                                                                                                                                                                                                                                                                        | ** ** | ** ** |
|------------|------------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------|
| ** ** | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                                                                        | ** ** | ** ** |
| ** ** | ** ** | **Our  consolidated financial statements are included in Part II, Item 8 of  this report:**                                                                                                                                                                                                                                                                                                                                  | ** ** | **72**     |
| ** ** | ** ** | ** **                                                                                                                                                                                                                                                                                                                                                                                                                        | ** ** | ** ** |
|       |       | Report of  Independent Registered Public Accounting Firm                                                                                                                                                                                                                                                                                                                                                                          |       | 73         |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
|       |       | Consolidated Balance Sheets                                                                                                                                                                                                                                                                                                                                                                                                       |       | 74         |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
|       |       | Consolidated  Statements of Operations                                                                                                                                                                                                                                                                                                                                                                                            |       | 75         |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
|       |       | Consolidated  Statements of Stockholders’ Equity                                                                                                                                                                                                                                                                                                                                                                             |       | 76         |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
|       |       | Consolidated  Statements of Cash Flows                                                                                                                                                                                                                                                                                                                                                                                            |       | 77         |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
|       |       | Notes to  Consolidated Financial Statements                                                                                                                                                                                                                                                                                                                                                                                       |       | 78         |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
|       |       | Supplemental  Oil and Gas Disclosures (Unaudited)                                                                                                                                                                                                                                                                                                                                                                                 |       | 110        |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
|       |       | Management’s  Report on Internal Control Over Financial Reporting                                                                                                                                                                                                                                                                                                                                                            |       | 118        |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
|       |       | Report of  Independent Registered Public Accounting Firm on Internal Control over  Financial Reporting                                                                                                                                                                                                                                                                                                                            |       | 119        |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
| **2.**     | ** ** | **Financial  Statements Schedules and supplementary information required to be submitted:**                                                                                                                                                                                                                                                                                                                                       |       |       |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
|       |       | None.                                                                                                                                                                                                                                                                                                                                                                                                                             |       |       |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
| **3.**     | ** ** | **Exhibits**                                                                                                                                                                                                                                                                                                                                                                                                                      |       |       |
|       |       |                                                                                                                                                                                                                                                                                                                                                                                                                              |       |       |
|       |       | A list of  the exhibits filed or furnished with this report on Form 10-K (or  incorporated by reference to exhibits previously filed or furnished by us) is  provided in the Exhibit Index beginning on page 125 of this report.  Those exhibits incorporated by reference herein are indicated as such by the  information supplied in the parenthetical thereafter. Otherwise, the exhibits  are filed herewith. |       |       |

 

121

----

 

**GLOSSARY OF OIL ANDNATURAL GAS TERMS**

 

The following are abbreviations and definitions ofterms commonly used in the oil and natural gas industry that are used in thisreport.

 

*Bbl*. One stock tank barrel or 42 U.S. gallons liquidvolume.

 

*Bcf*.Billion cubic feet of natural gas.

 

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

 

*Bopd*. Barrels of oil per day.

 

*Boepd*. Barrels of oil equivalent per day

 

*Development well*. A well drilled within the proved area of anoil or natural gas reservoir to the depth of a stratigraphic horizon known tobe productive.

 

*Drill Stem Test*.  Atest of the flow rates of a formation through the drill pipe to determine thefluid and gas content, pressure and estimated production rates of thereservoir.

 

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

 

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

 

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

 

*Field*. An area consisting of a single reservoir ormultiple reservoirs all grouped on or related to the same individual geologicalstructural 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 liquidhydrocarbons.

 

*Mcf*. One thousand cubic feet.

 

*Mcfe*. One thousand cubic feet equivalent, determinedusing the ratio of approximately six Mcf of natural gas to one Bbl of crude oilor other hydrocarbon.

 

*MMBbls*. One million barrels of crude oil or other liquidhydrocarbons.

 

*MMBtu*. One million British thermal units.

 

*MMcf*. One million cubic feet.

 

*MMcfe*. One million cubic feet equivalent, determinedusing a ratio of six Mcf of natural gas to one Bbl of crude oil condensate ornatural gas liquids.

 

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

 

*Oil*. Crude oil, condensate and natural gas liquids.

 

122

----

 

*Productive well*. A well that is found to be capable ofproducing hydrocarbons.

 

*Proved developed reserves*. Reserves that can beexpected to be recovered through existing wells with existing equipment andoperating methods. Additional oil and gas expected to be obtained through theapplication of fluid injection or other improved recovery techniques forsupplementing the natural forces and mechanisms of primary recovery areincluded in “proved developed reserves” only after testing by a pilot projector after the operation of an installed program has confirmed through productionresponse that increased recovery will be achieved. The SEC provides a completedefinition of proved developed reserves in Rule 4-10(a)(3) ofRegulation S-X.

 

*Proved reserves*. Proved oil and gas reserves are theestimated quantities of crude oil, natural gas and natural gas liquids whichgeological and engineering data demonstrates with reasonable certainty to berecoverable in future years from known reservoirs under existing economic andoperating conditions, i.e., prices and cost as of the date the estimate ismade. Prices include consideration of changes in existing prices provided onlyby 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) ofRegulation S-X.

 

*Proved undeveloped reserves*. Proved oil and gasreserves that are expected to be recovered from new wells on undrilled acreageor from existing wells where a relatively major expenditure is required forrecompletion. Reserves on undrilled acreage shall be limited to those drillingunits offsetting productive units that are reasonably certain of productionwhen drilled. Proved reserves for other undrilled units can be claimed onlywhere it can be demonstrated with certainty that there is continuity ofproduction from the existing productive formation. Under no circumstancesshould estimates for proved undeveloped reserves be attributable to any acreagefor which an application of fluid injection or other improved recoverytechnique is contemplated, unless such techniques have been proved effective byactual tests in the area and in the same reservoir. The SEC provides a completedefinition of proved undeveloped reserves in Rule 4-10(a)(4) ofRegulation S-X.

 

*PV-10 value*. The present value of estimated future net revenuesto be generated from the production of proved reserves, determined inaccordance with the rules and regulations of the SEC (using prices andcosts in effect as of the date of estimation) without giving effect tonon-property related expenses such as general and administrative expenses, debtservice and future income tax expenses or to depreciation, depletion andamortization and discounted using an annual discount rate of 10%.

 

*Recompletion*. The completion for production of an existing wellbore in another formation from that which the well has been previouslycompleted.

 

*Reservoir*. A porous and permeable underground formationcontaining a natural accumulation of producible oil and/or natural gas that isconfined by impermeable rock or water barriers and is individual and separate fromother reserves.

 

*Workover*.  A remedialoperation on a completed well to restore, maintain or improve the well’sproduction.

 

123

----

** **

**SIGNATURES**

 

Pursuant to the requirements of Section 13 or 15(d) ofthe Securities Exchange Act of 1934, the Registrant has duly caused this reportto be signed on its behalf by the undersigned, thereunto duly authorized, on March 31,2010.

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

 

Pursuant tothe requirements of the Securities Act of 1934, this report has been signedbelow by the following persons on behalf of the registrant and in thecapacities and on the dates indicated.

 

 
| /s/  MANUEL PABLO ZÚÑIGA-PFLÜCKER |     | /s/  EDWARD  G. CAMINOS                     |
|------------------------------------------------------------|----------|-------------------------------------------------------|
| Manuel  Pablo Zúñiga-Pflücker               |     | Edward  G. Caminos                                    |
| *President, Chief Executive Officer and Director*          | * * | *Chief Financial Officer*                             |
| March 31,  2010                                       | * * | *(Principal Financial Officer)*                       |
|                                                       |     | March 31,  2010                                  |
|                                                       |     |                                                  |
|                                                       |     |                                                  |
| /s/  HEATH  W. CLEAVER                           |     | /s/  DR. FERNANDO ZÚÑIGA Y RIVERO |
| Heath  W. Cleaver                                          |     | Dr. Fernando  Zúñiga y Rivero          |
| *Vice President — Chief Accounting Officer*           | * * | *Director and Chairman of the Board*                  |
| *(Principal Accounting Officer)*                           |     | March 31,  2010                                  |
| March 31,  2010                                       |     |                                                  |
|                                                       |     |                                                  |
|                                                       |     |                                                  |
| /s/  GORDON  GRAY                                |     | /s/  DENNIS  G. STRAUCH                     |
| Gordon  Gray                                               |     | Dennis  G. Strauch                                    |
| *Director*                                                 | * * | *Director*                                            |
| March 31,  2010                                       |     | March 31,  2010                                  |
|                                                       |     |                                                  |
|                                                       |     |                                                  |
| /s/  JOHN  J. LENDRUM, III                  |     | /s/  JAMES  B. TAYLOR                       |
| John  J. Lendrum, III                                 |     | James  B. Taylor                                      |
| *Director*                                                 | * * | *Director*                                            |
| March 31,  2010                                       |     | March 31,  2010                                  |
|                                                       |     |                                                  |
|                                                       |     |                                                  |
| /s/  STEPHEN  C. BEASLEY                         |     |                                                  |
| Stephen  C. Beasley                                        |     |                                                  |
| *Director*                                                 |     |                                                  |
| March 31,  2010                                       |     |                                                  |

 

124

----

Table ofContents

 

**INDEXOF EXHIBITS**

** **
| 2.1    |   | Plan of Conversion for  BPZ Energy, Inc. (incorporated by reference to Exhibit 2.1 to the  Company’s Form 8-K filed on August 24, 2007).                                                                                                                          |
|--------|--------|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                       |
| 3.1    |   | Certificate of  Formation of BPZ Resources, Inc. (incorporated by reference to  Exhibit 3.1 to the Company’s Form 8-K filed on August 24,  2007).                                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                                       |
| 3.2    |   | Bylaws of BPZ  Resources, Inc. (incorporated by reference to Exhibit 3.2 to the  Company’s Form 8-K filed on August 17, 2007).                                                                                                                                    |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.1    |   | Form of  Certificate for Common Stock of BPZ Resources, Inc., a Texas corporation  (incorporated by reference to Exhibit 99.1 to the Company’s  Form 10-Q filed on November 8, 2007).                                                                        |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.2    |   | Indenture for 6.5%  Convertible Senior Notes due 2015 by and among BPZ Resources Inc. and Wells  Fargo Bank National Association, as trustee, dated February 8, 2010  (incorporated by reference to exhibit 4.1 to the Company’s Form 8-K  filed on February  9, 2010) |
|   |   |                                                                                                                                                                                                                                                                                       |
| 4.3    |   | Form of 6.5% Convertible  Senior Note due 2015 (included in Exhibit 4.2)                                                                                                                                                                                                         |
|   |   |                                                                                                                                                                                                                                                                                       |
| 10.1*  |   | BPZ Energy, Inc.  2005 Long-Term Incentive Compensation Plan (incorporated by reference to  Exhibit 4.1 to the Company’s Form S-8 filed on July 5, 2005  (SEC File No. 333- 126388)).                                                                        |
|   |   |                                                                                                                                                                                                                                                                                       |
| 10.2*  |   | BPZ Energy, Inc.  2007 Long-Term Incentive Compensation Plan (incorporated by reference to  Exhibit 10.1 to the Company’s Form 8-K filed on August 24,  2007).                                                                                                    |
|   |   |                                                                                                                                                                                                                                                                                       |
| 10.3*  |   | BPZ Energy, Inc.  2007 Directors Compensation Incentive Plan (incorporated by reference to  Exhibit 10.2 to the Company’s Form 8-K filed on August 24,  2007).                                                                                                    |
|   |   |                                                                                                                                                                                                                                                                                       |
| 10.4   |   | Merger Agreement  between Navidec, Inc. and BPZ Energy, Inc. dated July 8, 2004  (incorporated by reference to Exhibit 10.1 from the Company’s  Form 8-K filed on July 13, 2004).                                                                       |
|   |   |                                                                                                                                                                                                                                                                                       |
| 10.5   |   | Closing Agreement  between Navidec, Inc. and BPZ, Inc. dated September 8,  2004(incorporated by reference to Exhibit 10.1 from the Company’s  Form 8-K filed on September 14, 2004).                                                                    |
|   |   |                                                                                                                                                                                                                                                                                       |
| 10.6   |   | License Contract from  the Government of Peru for Block Z-1 dated November 30, 2001  (incorporated by reference to Exhibit 10.5 to the Company’s  Form SB-2 filed on February 14, 2005 (SEC File  No. 333-122816)).                                          |
|   |   |                                                                                                                                                                                                                                                                                       |
| 10.7   |   | Amendment to License  Contract from the Government of Peru for Block Z-1 dated February 3, 2005  (incorporated by reference to Exhibit 10.5 of the Company’s Annual  Report on Form 10-KSB for the year ended December 31, 2004 filed on  April 15, 2005).   |
|   |   |                                                                                                                                                                                                                                                                                       |
| 10.8   |   | License Contract from  the Government of Peru for Block XIX dated December 12, 2003 (incorporated  by reference to Exhibit 10.6 to the Company’s Form SB-2 filed on  February 14, 2005 (SEC File No. 333-122816)).                                           |
|   |   |                                                                                                                                                                                                                                                                                       |
| 10.9   |   | License Contract from  the Government of Peru for Block XXII dated November 21, 2007  (incorporated by reference to Exhibit 10.9 to the Company’s  Form 10-K filed on March 14, 2008)                                                                             |

 

125

----

Table of Contents

 
| 10.10  |   | License Contract from  the Government of Peru for Block XXIII dated November 21, 2007  (incorporated by reference to Exhibit 10.10 to the Company’s  Form 10-K filed on March 14, 2008).                                                                                                                                                                     |
|--------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.11  |   | Contract  No. 001-2009-Mextipetroperu - Supply of 17,000,000 Barrels of Crude Oil  for Talara Refinery dated January 8, 2009, by and among BPZ  Exploración & Producción S.R.L., and Petroleos del Perú-PETROPERU  S.A.(incorporated by reference to Exhibit 10.1 to the Company’s  Form 8-K filed on January 14, 2009).        |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.12  |   | Contract for Sale of  Equipment and Services dated September 26, 2008 (incorporated by  reference to Exhibit 10.11 to BPZ Resources, Inc.’s Quarterly  Report on Form 10-Q for the quarter ended September 30, 2008 filed  on November 10, 2008).                                                                                                  |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.13  |   | Amendment dated  January 23, 2009 to Contract for Sale of Equipment and Services dated  September 26, 2008 by and among GE Packaged Power, Inc. GE  International, Inc. Sucursal De Peru and Empresa Eléctrica Nueva  Esperanza, SRL (incorporated by reference to Exhibit 10.2 to the Company’s  Form 8-K filed on January 29, 2009).   |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.14  |   | C Loan Agreement  between BPZ Resources, Inc. (formerly BPZ Energy, Inc.) and  International Finance Corporation, dated November 17, 2007 (incorporated  by reference to Exhibit 10.1 to the Company’s Form 8-K filed on  November 26, 2007).                                                                                                      |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.15  |   | Loan Agreement between  BPZ Exploracion & Produccion S.R.L and BPZ Marine Peru S.R.L and  International Finance Corporation dated as of August 15, 2008  (incorporated by reference to exhibit 10.15 to the Company’s Form 10-K  filed on March 2, 2009).                                                                                                |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.16  |   | Common Terms Agreement  between BPZ Exploracion & Produccion S.R.L and BPZ Marine Peru  S.R.L., as borrowers, and International Finance Corporation, as lender, and  the Additional Secured Facility Lenders dated as of August 15, 2008 (incorporated  by reference to exhibit 10.16 to the Company’s Form 10-K filed on  March 2, 2009).               |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.17  |   | Stock Purchase  Agreement by and among BPZ Resources, Inc. and Investors (incorporated  by reference to Exhibit 10.1 to the Company’s Form 8-K filed on February 24,  2009).                                                                                                                                                                                 |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.18  |   | Placement Agency  Agreement and form of the Subscription Agreement by and among BPZ  Resources, Inc. and Investors with Placement Agents dated as of  June 25, 2009 (incorporated by reference to exhibit 1.1 to the Company’s  Form 8-K filed on June 29, 2009)                                                                                             |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.19  |   | Subscription Agreement  by and among BPZ Resources Inc. and International Finance Corporation , as  Investor, to purchase 1,630,776 shares of common stock dated  September 15, 2009 (incorporated by reference to exhibit 10.1 to the  Company’s Form 8-K filed on September 16, 2009)                                                                           |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 10.20  |   | Letter Agreement by and  between the Consortium of GE Packaged Power, Inc. and GE International  Inc. Sucursal de Peru (collectively, “Seller”) and Empresa Electrica Nueva  Esperanza S.R.L. (“Buyer”) dated as of November 20, 2009 (incorporated  by reference to exhibit 10.3 to the Company’s Form 8-K filed on  November 27, 2009) |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 14.1   |   | Code of Ethics for  Executive Officers (incorporated by reference to Exhibit 14.1 to  Form 10-KSB/A filed on September 26, 2006).                                                                                                                                                                                                                                      |
|   |   |                                                                                                                                                                                                                                                                                                                                                                                  |
| 21.1   |   | Subsidiaries of the  Registrant, filed herewith.                                                                                                                                                                                                                                                                                                                                      |

 

126

----

Table of Contents

 
| 23.1   |   | Consent of Independent  Registered Public Accounting Firm, filed herewith.                                                                                        |
|--------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                              |
| 23.2   |   | Consent of Independent  Petroleum Engineers and Geologists, filed herewith.                                                                                       |
|   |   |                                                                                                                                                              |
| 31.1   |   | Certification of the  Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002, filed herewith.                                    |
|   |   |                                                                                                                                                              |
| 31.2   |   | Certification of the  Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002, filed herewith.                                    |
|   |   |                                                                                                                                                              |
| 32.1   |   | Certification of the  Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|   |   |                                                                                                                                                              |
| 32.2   |   | Certification of the  Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted  pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
|   |   |                                                                                                                                                              |
| 99.1   |   | Report of Netherland,  Sewell & Associates, Inc., filed herewith.                                                                                   |

 

----

* - ManagementContract or Compensatory Plan or Arrangement.

 

127

----