Table ofContents

 

 

 

**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,DC 20549**

 

**FORM 10-Q**

 

**(Mark One)**

 

**x****      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934**

 

**For thequarterly period ended: September 30, 2010**

 

**or**

 

**o****         TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THESECURITIES EXCHANGE ACT OF 1934**

 

**For thetransition 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 or Organization) |       | (I.R.S. Employer Identification No.) |

 

**580Westlake Park Blvd., Suite 525Houston, Texas 77079**(Address of Principal Executive Office)

 

Registrant’sTelephone Number, Including Area Code:** (281) 556-6200**

 

**N/A**

(FormerName, Former Address and Former Fiscal Year, If Changed Since Last Report)

 

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

 

Indicate by check markwhether the registrant has submitted electronically and posted on its corporateWeb site, 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

 

Indicateby check mark whether the registrant is a large accelerated filer, an acceleratedfiler, a non-accelerated filer, or a smaller reporting company. See thedefinitions of “large accelerated filer,” “accelerated filer,” and “smallerreporting company” in Rule 12b-2 of the Exchange Act:

 

| Large  accelerated filer o                     |   | Accelerated  filer x         |
|------------------------------------------------|--------|-----------------------------------|
|                                           |   |                              |
| Non-accelerated  filer o                       |   | Smaller  reporting company o |
| (Do  not check if a smaller reporting company) |   |                              |

 

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

 

Indicate the number ofshares outstanding of each of the issuer’s classes of common stock, as of thelatest practicable date:

 

As of November 3, 2010,there were 115,507,866 shares of common stock, no par value, outstanding.

 

 

 

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Table ofContents

 

**TABLE OF CONTENTS**

 
| **PART I**  |
|------------------|
|             |   |   |
| Item 1.          | Financial Statements | 3 |
|             |   |   |
|             | Consolidated Balance Sheets | 3 |
|             |   |   |
|             | Consolidated Statements of  Operations | 4 |
|             |   |   |
|             | Consolidated Statements of  Cash Flows | 5 |
|             |   |   |
|             | Notes to Consolidated  Financial Statements | 6 |
|             |   |   |
| Item 2.          | Management’s  Discussion and Analysis of Financial Condition and Results of Operations | 24 |
|             |   |   |
| Item 3.          | Quantitative  and Qualitative Disclosures About Market Risk | 44 |
|             |   |   |
| Item 4.          | Controls and  Procedures | 46 |
|             |   |   |
| **PART II** |
|             |   |   |
| Item 1.          | Legal Proceedings | 47 |
|             |   |   |
| Item 1A.         | Risk Factors | 47 |
|             |   |   |
| Item 6.          | Exhibits | 47 |
|             |   |   |
| **SIGNATURES**   |

 

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**PART I**

 

**Item 1. Financial Statements**

 

**BPZ Resources, Inc. andSubsidiaries**

**Consolidated Balance Sheets**

**(In thousands,****except share amounts****)**

 
| ** **                                                                                                                                                    | ** ** | **September 30,** | ** ** | **December 31,** | ** ** |
|---------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|------------------------|------------|-----------------------|------------|
| ** **                                                                                                                                                    | ** ** | **2010**               | ** ** | **2009**              | ** ** |
| ** **                                                                                                                                                    | ** ** | **(Unaudited)**        | ** ** | **(Audited)**         | ** ** |
| **ASSETS**                                                                                                                                                    |       |                   |       |                  |       |
|                                                                                                                                                          |       |                   |       |                  |       |
| Current assets:                                                                                                                                               |       |                   |       |                  |       |
| Cash and cash equivalents                                                                                                                                     |       | $                      | 52,916     |                  | $          | 18,147 |   |
| Accounts receivable                                                                                                                                           |       | 14,466                 |       | 2,867                 |       |
| Value added tax receivable                                                                                                                                    |       | 30,975                 |       | 26,152                |       |
| Inventory                                                                                                                                                     |       | 20,577                 |       | 12,507                |       |
| Prepaid and other current assets                                                                                                                              |       | 5,777                  |       | 1,580                 |       |
|                                                                                                                                                          |       |                   |       |                  |       |
| Total current assets                                                                                                                                          |       | 124,711                |       | 61,253                |       |
|                                                                                                                                                          |       |                   |       |                  |       |
| Property, equipment and construction in progress,  net                                                                                                        |       | 309,536                |       | 262,517               |       |
| Restricted cash                                                                                                                                               |       | 5,030                  |       | 5,720                 |       |
| Other non-current assets                                                                                                                                      |       | 8,819                  |       | 1,559                 |       |
| Investment in Ecuador property, net                                                                                                                           |       | 1,054                  |       | 1,195                 |       |
| Deferred tax asset                                                                                                                                            |       | 33,329                 |       | 16,928                |       |
|                                                                                                                                                          |       |                   |       |                  |       |
| Total assets                                                                                                                                                  |       | $                      | 482,479    |                  | $          | 349,172 |   |
|                                                                                                                                                          |       |                   |       |                  |       |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                                                                                                |       |                   |       |                  |       |
|                                                                                                                                                          |       |                   |       |                  |       |
| Current liabilities:                                                                                                                                          |       |                   |       |                  |       |
| Accounts payable                                                                                                                                              |       | $                      | 37,023     |                  | $          | 32,698 |   |
| Accrued liabilities                                                                                                                                           |       | 15,713                 |       | 14,155                |       |
| Other liabilities                                                                                                                                             |       | 1,070                  |       | 1,235                 |       |
| Current income taxes payable                                                                                                                                  |       | 3,083                  |       | 322                   |       |
| Accrued interest payable                                                                                                                                      |       | 1,141                  |       | 106                   |       |
| Current maturity of long-term debt and capital  lease obligations                                                                                             |       | 9,285                  |       | 5,352                 |       |
|                                                                                                                                                          |       |                   |       |                  |       |
| Total current liabilities                                                                                                                                     |       | 67,315                 |       | 53,868                |       |
|                                                                                                                                                          |       |                   |       |                  |       |
| Asset retirement obligation                                                                                                                                   |       | 1,135                  |       | 766                   |       |
| Long-term debt and capital lease obligations                                                                                                                  |       | 153,737                |       | 22,581                |       |
|                                                                                                                                                          |       |                   |       |                  |       |
| Total long-term liabilities                                                                                                                                   |       | 154,872                |       | 23,347                |       |
|                                                                                                                                                          |       |                   |       |                  |       |
| 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;  115,508 and 115,224 shares issued and outstanding at September 30, 2010 and  December 31, 2009, respectively |       | 551,175                |       | 513,145               |       |
| Accumulated deficit                                                                                                                                           |       | (290,883               | )          | (241,188              | )          |
|                                                                                                                                                          |       |                   |       |                  |       |
| Total stockholders’ equity                                                                                                                               |       | 260,292                |       | 271,957               |       |
|                                                                                                                                                          |       |                   |       |                  |       |
| Total liabilities and stockholders’ equity                                                                                                               |       | $                      | 482,479    |                  | $          | 349,172 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

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**BPZ Resources, Inc. andSubsidiaries**

**Consolidated Statements ofOperations (Unaudited)**

**(In thousands, except per share data)**

 
| ** **                                                                 | ** ** | **Three Months  Ended September 30,** | ** ** | **Nine Months  Ended September 30,** | ** ** |
|----------------------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                 | ** ** | **2010**                                             | ** ** | **2009**                                            | ** ** | **2010** | ** ** | **2009** | ** ** |
|                                                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Revenue                                                                    |       | $                                                    | 26,688     |                                                | $          | 13,088 |   | $ | 73,130 |   | $ | 37,362 |   |
|                                                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Operating and administrative expenses:                                     |       |                                                 |       |                                                |       |   |   |   |   |
| Lease operating expense                                                    |       | 10,967                                               |       | 9,591                                               |       | 21,309 |   | 21,445 |   |
| General and administrative expense                                         |       | 8,545                                                |       | 8,474                                               |       | 24,774 |   | 24,956 |   |
| Geological, geophysical and engineering expense                            |       | 6,113                                                |       | 297                                                 |       | 7,016 |   | 1,195 |   |
| Dry hole costs                                                             |       | 32,059                                               |       | —                                              |       | 32,059 |   | — |   |
| Depreciation, depletion and amortization expense                           |       | 6,659                                                |       | 5,881                                               |       | 24,193 |   | 19,267 |   |
| Other expense                                                              |       | 12,738                                               |       | —                                              |       | 12,738 |   | — |   |
|                                                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Total operating expenses                                                   |       | 77,081                                               |       | 24,243                                              |       | 122,089 |   | 66,863 |   |
|                                                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Operating loss                                                             |       | (50,393                                              | )          | (11,155                                             | )          | (48,959 | ) | (29,501 | ) |
|                                                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Other income (expense):                                                    |       |                                                 |       |                                                |       |   |   |   |   |
| Income (expense) from investment in Ecuador  property, net of amortization |       | 305                                                  |       | 172                                                 |       | 611 |   | 79 |   |
| Interest expense                                                           |       | (2,821                                               | )          | —                                              |       | (8,510 | ) | — |   |
| Interest income                                                            |       | 101                                                  |       | 159                                                 |       | 171 |   | 187 |   |
| Other income (expense)                                                     |       | 17                                                   |       | 70                                                  |       | 28 |   | (1,243 | ) |
|                                                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Total other income (expense), net                                          |       | (2,398                                               | )          | 401                                                 |       | (7,700 | ) | (977 | ) |
|                                                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Loss before income taxes                                                   |       | (52,791                                              | )          | (10,754                                             | )          | (56,659 | ) | (30,478 | ) |
|                                                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Income tax benefit                                                         |       | (9,132                                               | )          | (1,792                                              | )          | (6,964 | ) | (4,654 | ) |
|                                                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Net loss                                                                   |       | $                                                    | (43,659    | )                                                   | $          | (8,962 | ) | $ | (49,695 | ) | $ | (25,824 | ) |
|                                                                       |       |                                                 |       |                                                |       |   |   |   |   |
| Basic and diluted net loss per share                                       |       | $                                                    | (0.38      | )                                                   | $          | (0.08 | ) | $ | (0.43 | ) | $ | (0.26 | ) |
| Weighted average common shares outstanding                                 |       | 115,405                                              |       | 113,929                                             |       | 115,321 |   | 99,391 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

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**BPZ Resources, Inc. and Subsidiaries**

**Consolidated Statements of CashFlows (Unaudited)**

**(Inthousands)**

 
| ** **                                                                   | ** ** | **For the Nine Months Ended** | ** ** |
|------------------------------------------------------------------------------|------------|---------------------------------------------------|------------|
| ** **                                                                   | ** ** | **September 30,**                            | ** ** |
| ** **                                                                   | ** ** | **2010**                                          | ** ** | **2009** | ** ** |
|                                                                         |       |                                              |       |   |   |
| Cash flows from operating activities:                                        |       |                                              |       |   |   |
| Net loss                                                                     |       | $                                                 | (49,695    | ) | $ | (25,824 | ) |
| Adjustments to reconcile net loss to net cash used  in operating activities: |       |                                              |       |   |   |
| Stock-based compensation                                                     |       | 4,665                                             |       | 10,342 |   |
| Depreciation, depletion and amortization                                     |       | 24,193                                            |       | 19,267 |   |
| Amortization of investment in Ecuador property                               |       | 141                                               |       | 140 |   |
| Deferred income taxes                                                        |       | (16,401                                           | )          | (8,445 | ) |
| Dry hole costs                                                               |       | 32,059                                            |       | — |   |
| Net loss on abandoned assets                                                 |       | 11,938                                            |       | — |   |
| Amortization of deferred financing fees                                      |       | 3,644                                             |       | — |   |
| Changes in operating assets and liabilities:                                 |       |                                              |       |   |   |
| (Increase) decrease in accounts receivable                                   |       | (11,599                                           | )          | 5,276 |   |
| Increase in value added tax receivable                                       |       | (7,823                                            | )          | (9,144 | ) |
| Increase in inventory                                                        |       | (7,760                                            | )          | (9,874 | ) |
| (Increase) decrease in other assets                                          |       | (4,174                                            | )          | 824 |   |
| Increase in accounts payable                                                 |       | 4,325                                             |       | 436 |   |
| Increase (decrease) in accrued liabilities                                   |       | 2,593                                             |       | (1,744 | ) |
| Increase (decrease) in income taxes payable                                  |       | 2,761                                             |       | (6,841 | ) |
| (Decrease) increase in other liabilities                                     |       | (165                                              | )          | 379 |   |
| Net cash used in operating activities                                        |       | (11,297                                           | )          | (25,208 | ) |
|                                                                         |       |                                              |       |   |   |
| Cash flows from investing activities:                                        |       |                                              |       |   |   |
| Property and equipment additions                                             |       | (114,977                                          | )          | (50,597 | ) |
| Decrease in restricted cash                                                  |       | 690                                               |       | 341 |   |
| Net cash used in investing activities                                        |       | (114,287                                          | )          | (50,256 | ) |
|                                                                         |       |                                              |       |   |   |
| Cash flows from financing activities:                                        |       |                                              |       |   |   |
| Borrowings                                                                   |       | 170,938                                           |       | 6,533 |   |
| Repayments of borrowings                                                     |       | (4,512                                            | )          | (4,879 | ) |
| Deferred loan fees                                                           |       | (6,073                                            | )          | — |   |
| Proceeds from exercise of stock options, net                                 |       | —                                            |       | 113 |   |
| Proceeds from sale of common stock, net                                      |       | —                                            |       | 135,031 |   |
| Net cash provided by financing activities                                    |       | 160,353                                           |       | 136,798 |   |
|                                                                         |       |                                              |       |   |   |
| Net increase in cash and cash equivalents                                    |       | 34,769                                            |       | 61,334 |   |
| Cash and cash equivalents at beginning of period                             |       | 18,147                                            |       | 5,317 |   |
| Cash and cash equivalents at end of period                                   |       | $                                                 | 52,916     |   | $ | 66,651 |   |
|                                                                         |       |                                              |       |   |   |
|                                                                         |       |                                              |       |   |   |
| Supplemental cash flow information:                                          |       |                                              |       |   |   |
| **Cash paid for:**                                                           |       |                                              |       |   |   |
| Interest                                                                     |       | $                                                 | 10,726     |   | $ | 3,137 |   |
| Income tax                                                                   |       | 7,065                                             |       | 12,441 |   |
| **Non — cash items:**                                                   |       |                                              |       |   |   |
| Purchase and additions to equipment with the  issuance of a                  |       |                                              |       |   |   |
| capital lease obligation                                                     |       | $                                                 | 173        |   | $ | — |   |
| Accrued interest capitalized to construction in  progress                    |       | —                                            |       | 41 |   |
| Depletion allocated to production inventory                                  |       | 310                                               |       | 1,045 |   |
| Depreciation on support equipment capitalized to  construction in progress   |       | 1,508                                             |       | 1,098 |   |
| Asset retirement obligation capitalized to property  and equipment           |       | 292                                               |       | 144 |   |
| Property and equipment transferred to other  non-current assets              |       | —                                            |       | (1,428 | ) |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

**Note 1- Basis of Presentation and Significant Accounting Policies**

 

**Organization**

 

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

 

The Company maintains asubsidiary, BPZ Exploración & Producción S.R.L. (“BPZ E&P”),registered in Peru through its wholly-owned subsidiary BPZ Energy, LLC, aTexas limited liability company, formerly BPZ Energy, Inc., and its subsidiaryBPZ Energy International Holdings, L.P., a British Virgin Islands limitedpartnership. The Company, through BPZ E&P, has exclusive rights and licensecontracts for oil and gas exploration and production covering a total ofapproximately 2.2 million acres, in four blocks, in northwest Peru. The Company’slicense 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 millionacres) and Block XXIII (0.2 million acres). The Block Z-1 contract was signedin November 2001, the Block XIX contract was signed in December 2003and the Blocks XXII and XXIII contracts were signed inNovember 2007. Generally, according to the Organic Hydrocarbon LawNo. 26221 and the regulations thereunder (the “Organic Hydrocarbon Law” or“Hydrocarbon Law”), the seven year term for the exploration phase in eachcontract can be extended by an additional three years up to a maximum of tenyears. However, specific provisions of each license contract can vary theexploration phase of the contract as established by the Hydrocarbon Law. Thelicense contracts require the Company to conduct specified activities in therespective blocks during each exploration period in the exploration phase. Ifthe exploration activities are successful, the Company may decide to enter theexploitation phase and the total contract term can extend up to 30 years foroil exploration and production and up to 40 years for gas exploration andproduction. In the event a block contains both oil and gas, as is the case inthe Company’s Block Z-1 contract, the 40 year term may apply to oil explorationand production as well.

 

Additionally, through itswholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and itsregistered branch in Ecuador, the Company owns a 10% non-operated 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.

 

The Company is in theprocess of developing its oil and natural gas reserves.  The Company has been producing and sellingoil from the CX-11 platform in the Corvina field of Block Z-1 under a welltesting program and is in the process of satisfying the conditions totransition to commercial production in Corvina. The Company is also in theinitial stages of appraising, exploring and developing the oil and potentialnatural gas reserves from the A platform in the Albacora field of Block Z-1 andbegan selling oil from the Albacora field under a well testing program duringthe second quarter of 2010.  The Companydrilled and completed its first Albacora well in December 2009.  From the time the Company first beganproducing from the CX-11 platform in the Corvina field in November of 2007and the Albacora field in December 2009, through September 30, 2010, it hasproduced approximately 3.0 MMBbls of oil. Additionally, the Company’sactivities in Peru include analysis and evaluation of technical data onits other properties, preparation of the development plans for theproperties, designs for platforms, procuring machinery and equipment for anextended oil and gas exploration and development campaign, obtaining allnecessary environmental and operating permits, bringing additional productionon-line, seismic data acquisition, obtaining detailed engineering and design ofthe planned power plant and gas processing facilities, executing a contract topurchase three LM 6000 gas-fired turbines and securing the required capital andfinancing to conduct the current plan of operation.

 

**Basis of Presentation and Principles of Consolidation**

 

Theaccompanying consolidated financial statements of BPZ Resources, Inc. and itssubsidiaries have been prepared in accordance with accounting principlesgenerally accepted in the United States of America (“GAAP” or “U.S. GAAP”) forinterim financial information and with the instructions to Form 10-Q andArticle 10 of Regulation S-X. Accordingly,certain information and footnote disclosures normally included in financialstatements prepared in accordance with GAAP have been condensed or omittedpursuant to such rules and regulations. The unaudited financial statementsreflect all adjustments which are, in the opinion of management, necessary fora fair presentation of the financial position and results of operations for theinterim periods presented on a basis consistent with the annual auditedfinancial statements.  All suchadjustments are of a normal, recurring nature. All significanttransactions between BPZ and its consolidated subsidiaries have beeneliminated. Certain prior period amounts have been reclassified to conform tocurrent year presentation. Results of operations for interim periods are notnecessarily indicative of the results of 

 

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operationsthat may be expected for the entire year. The balance sheet atDecember 31, 2009 has been derived from the audited financial statementsat that date but does not include all of the information and footnotes requiredby GAAP for complete financial statements. These interim financial statementsshould be read in conjunction with the audited financial statements and notesthereto included in the Company’s Annual Report on Form 10-K, as amended, forthe year ended December 31, 2009.

 

**Use of Estimates**

 

Thepreparation of the consolidated financial statements in accordance with U.S.GAAP requires management to make certain estimates and assumptions. Theseestimates and assumptions affect the reported amounts of assets, liabilities,revenues and expenses in the consolidated financial statements, and thedisclosure of contingent assets and liabilities. Actual results could differfrom these estimates.

 

Estimates of crude oilreserves are the most significant of the Company’s estimates. All of theCompany’s reserves data are estimates. Reservoir engineering is a subjectiveprocess of estimating underground accumulations of crude oil and natural gas.There are numerous uncertainties inherent in estimating quantities of provedcrude oil and natural gas reserves. The accuracy of any reserves estimate is afunction of the quality of available data and of engineering and geologicalinterpretation and judgment. As a result, reserves estimates may be differentfrom the quantities of crude oil and natural gas that are ultimately recovered.

 

Other items subject toestimates and assumptions include the carrying amounts of property, plant andequipment including impairment and asset retirement obligations and deferredincome tax assets. Management evaluates estimates and assumptions on an ongoingbasis using historical experience and other factors, including the currenteconomic and commodity price environment and future expectations regardingestimates and assumptions. As future events and their effects cannot bedetermined accurately, actual results could differ significantly frommanagement’s estimates.

 

**Summaryof Significant Accounting Policies**

 

TheCompany has provided a summary discussion of significant accounting policies,estimates and judgments in Note 1 to the Notes to Consolidated FinancialStatements included in its Annual Report on Form 10-K, as amended, for theyear ended December 31, 2009.

 

**Recent Accounting Pronouncements**

 

InFebruary 2010, the Financial Accounting Standards Board (“FASB”) issuedAccounting Standards Update (“ASU”) No. 2010-09, “Subsequent Events,”which amends Accounting Standards Codification (“ASC”) Topic 855 to eliminatethe requirement to disclose the date through which management has evaluatedsubsequent events in the financial statements. ASU No. 2010-09 waseffective upon issuance and its adoption had no impact on the Company’s financialposition, results of operations or cash flows.

 

In January 2010, the Companypartially adopted the provisions of FASB ASU No. 2010-06, “ImprovingDisclosures about Fair Value Measurements,” which amends ASC Topic 820 torequire new disclosures concerning (1) transfers into and out of Levels 1and 2 of the fair value measurement hierarchy, and (2) activity in Level 3measurements. In addition, ASU No. 2010-06 clarifies certain existingdisclosure requirements regarding the level of disaggregation and inputs andvaluation techniques and makes conforming amendments to the guidance onemployers’ disclosures about postretirement benefit plans assets. Therequirements to disclose separately purchases, sales, issuances, andsettlements in the Level 3 reconciliation are effective for fiscal yearsbeginning after December 15, 2010 (and for interim periods within suchyears). The Company will apply the disclosure requirements relative to theLevel 3 reconciliation in the first quarter of 2011. There was no impact on theCompany’s financial position, results of operations or cash flows as a resultof the partial adoption of ASU No. 2010-06. For further information,please see Note 11, “Fair Value Measurements and Disclosures”.

 

**Note 2 —Value-Added Tax Receivable**

 

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

 

Peru currently has an IGVearly recovery program for oil and gas companies during the exploration phase.Under this program, IGV paid on the acquisition of certain goods and servicesused directly in hydrocarbon exploration activities can be recovered prior to acommercial discovery taking place or the initiation of production and revenuebillings. Because the Company has oil sales in the Corvina and Albacora fieldsunder a well testing program, it is no longer eligible for the IGV earlyrecovery program. 

 

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Accordingly, the Company isrecovering its IGV receivable with IGV payables associated with future oilsales under the normal IGV recovery process.

 

TheCompany’s current portion of value-added tax receivable as of September 30,2010 and December 31, 2009 was $31.0 million and $26.2 million,respectively. For the nine months ended September 30, 2010, the Company accruedapproximately $27.7 million for IGV related to expenditures reduced byapproximately $19.9 million for IGV related to the sale of oil for the sameperiod.  In addition, during the thirdquarter of 2010, the Company reclassified $3.0 million of its current portionof value-added tax receivable to long-term. See Note 4, “Prepaid and OtherCurrent Assets and Other Non-Current Assets” for further information.

 

**Note 3 — Inventories**

 

Inventories consistprimarily of crude oil, tubular goods, accessories and spare parts forproduction equipment, stated at the lower of average cost or market. Thebalance of inventory at September 30, 2010 and December 31, 2009 was $20.6million and $12.5 million, respectively.

 

Inventory associated withtubular goods, accessories and spare parts inventory at September 30, 2010 andDecember 31, 2009 was $16.3 million and $10.5 million, respectively.

 

For oil produced from theCorvina and Albacora fields, the Company maintains crude oil inventories instorage vessels until the inventory quantities are at a sufficient level, ormeet certain specifications required under the sales contracts, that therefinery in Talara will accept delivery

 

Oil inventory is stated atthe lower of average cost or market value. Cost is determined on a weightedaverage basis based on production costs. The crude oil inventory at September30, 2010 consisted of approximately 107 MBbls at an estimated cost of $4.3million or $39.88 per barrel. The crude oil inventory at December 31, 2009consisted of approximately 40 MBbls at an estimated cost of $2.0 million or$50.55 per barrel.

 

**Note 4 — Prepaid and Other Current Assets and OtherNon-Current Assets**

 

Below is a summary ofprepaid and other current assets as of September 30, 2010 and December 31,2009:

 
| ** **                 | ** ** | **September 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|----------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                 | ** ** | **(in thousands)**      | ** ** |
| Prepaid expenses and other |       | $                            | 4,535      |                        | $          | 296 |   |
| Deposits                   |       | 122                          |       | 92                          |       |
| Prepaid insurance          |       | 508                          |       | 580                         |       |
| Insurance receivable       |       | 612                          |       | 612                         |       |
|                       |       | $                            | 5,777      |                        | $          | 1,580 |   |

 

Prepaid expenses and otherare related to prepayments for drilling services, equipment rental and materialprocurement. Deposits are primarily rent deposits in connection with theCompany’s offices in Houston and Peru. Prepaid insurance consists of premiumsrelated to the Company’s operations as well as general liability and directorsand officer’s insurance policies. Insurance receivable is related to the bargeincident which occurred in early August 2006.  As of September 30, 2010, the Company has aninsurance receivable of approximately $0.7 million for the estimated insurancerepair claims of $0.8 million expected to be filed with the insurance carrier.A deductible of $75,000 will be applied to this insurance claim whenreimbursed.  The hull claim will be finalized upon the dry docking of thevessel, which is expected to occur during the last quarter of 2010 or the firstquarter of 2011.

 

Below is a summary of othernon-current assets as of September 30, 2010 and December 31, 2009:

 

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| ** **                 | ** ** | **September 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|----------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                 | ** ** | **(in thousands)**      | ** ** |
| Debt issue costs           |       | $                            | 4,388      |                        | $          | 104 |   |
| Other receivable           |       | 1,431                        |       | 1,455                       |       |
| Value-added tax receivable |       | 3,000                        |       | —                      |       |
|                       |       | $                            | 8,819      |                        | $          | 1,559 |   |

 

Other non-current assetsconsist of (i) direct transaction costs incurred by the Company in connectionwith its debt capital raising efforts and (ii) claims related to an incidentinvolving a small tanker that one of our marine transportation contractors waschartering from the Peruvian Navy’s commercial branch in 2008. As of September30, 2010, the Company is currently seeking recovery of these amounts from thePeruvian Navy’s commercial branch. The Company expects to recover the majorityof these amounts from either the Peruvian Navy or its insurance carrier.  Due to the uncertainty in timing of resolvingthe claims, the Company has classified the amount as a non-current asset.

 

In connection with the $15.0million International Finance Corporation (“IFC”) Reserve-Based CreditFacility, the Company incurred approximately $0.2 million of debt issue coststhat are being amortized over the life of the loan agreement, due December2012. In connection with the $170.9 million Convertible Notes due 2015, theCompany incurred approximately $4.8 million of debt issue costs that are beingamortized over the life of the indenture agreement, due March 2015.   For the three and nine months endedSeptember 30, 2010, the Company amortized into interest expense $0.2 millionand $0.5 million of debt issue costs. For the same periods in 2009, theamortization of debt issue costs were not material. For further informationregarding the Company’s debt, see Note 9, “Long-TermDebt and Capital Lease Obligations”.

 

During the third quarter of2010, the Company reclassified $3.0 million of its value-added tax receivablebalance to a long-term asset as it believes it will be longer than one year toreceive the benefit of this portion of the value-added tax receivable.

 

**Note 5— Property, Equipment and Construction in Progress**

 

Below is a summary ofproperty, equipment and construction in progress as of September 30, 2010 andDecember 31, 2009:

 
| ** **                                             | ** ** | **September 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|--------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                             | ** ** | **(in thousands)**      | ** ** |
| Construction in progress:                              |       |                         |       |                        |       |
| Power plant and related equipment                      |       | $                            | 33,931     |                        | $          | 28,113 |   |
| Platforms and wells                                    |       | 19,637                       |       | 16,726                      |       |
| Pipelines and processing facilities                    |       | 13,060                       |       | 5,537                       |       |
| Other                                                  |       | 1,604                        |       | 8,181                       |       |
| Producing properties                                   |       | 241,783                      |       | 199,686                     |       |
| Producing equipment                                    |       | 13,262                       |       | 13,160                      |       |
| Barge and related equipment                            |       | 56,449                       |       | 35,842                      |       |
| Office equipment, leasehold improvements and  vehicles |       | 2,665                        |       | 2,193                       |       |
| Accumulated depletion, depreciation and  amortization  |       | (72,855                      | )          | (46,921                     | )          |
| Net property, equipment and construction in process    |       | $                            | 309,536    |                        | $          | 262,517 |   |

 

During the nine months ended September 30, 2010, theCompany incurred net capital expenditures of approximately $73.0 millionassociated with its development initiatives for the exploration and productionof oil and natural gas reserves and the complementary development of aproprietary gas-fired power generation facility in Peru.

 

Of the costs mentionedabove, the Company incurred capital expenditures related to the drilling andtesting of the CX11-15D, CX11-23D, CX11-17D and CX11-22D wells in the Corvinafield of approximately $0.5 million, $12.9 million, $7.4 million and $19.5million, respectively. In the Albacora field, the Company incurred capitalexpenditures related to the drilling of the A-15D, A-16D and A-17D wells ofapproximately $8.4 million, $6.5 million and $17.2 million, respectively.During the three months ended September 30, 2010, the costs of the A-17D wellwere written off as dry hole costs as well as the costs for two previouslydrilled wells, the A-15D and A-16D, as those wells were intended to follow thesame trajectory and reach the same location as the A-17D well but neitherreached the target due to mechanical problems and both wells were junked andabandoned.

 

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In 2009, the Company enteredinto a lease-purchase agreement to acquire the Don Fernando barge to serve asthe Company’s construction lay barge, as well as the tender assist barge fordrilling and construction operations, and may be fitted to lay subsea pipe forthe gas-to-power project.  During thenine months ended September 30, 2010, the Company capitalized an additional$3.0 million in order to have the barge ready to support its operations.

 

For the further developmentof the planned gas-fired power generation facility, during the nine monthsended September 30, 2010, BPZ incurred costs of approximately $11.9 million aspart of its agreement to purchase three LM 6000 gas-fired turbines.

 

For the nine months endedSeptember 30, 2010, the Company incurred approximately $2.6 million forupgrades to its existing platforms as well as costs incurred in theconstruction of new platforms. In addition, the Company incurred $6.8 millionin equipment for its production facilities at the A platform in Albacora andthe CX-11 platform in Corvina. The Company incurred $10.4 million for thepurchase of machinery and equipment used in operations in Peru, $0.4 millionfor the Caleta La Cruz dock refurbishment, $0.3 million in assets in transit,$0.5 million in furniture and improvements related to the new offices in Peru,$0.6 million in other barge improvements and $0.3 million related to the assetretirement obligation for the CX11-17D, CX11-22D and CX11-23D wells.

 

For the three and ninemonths ended September 30, 2010, the Company wrote-off approximately $11.9million of property and equipment associated with its gas-to-power project andcertain costs for the abandonment of two platforms. For further informationregarding these write-offs, see Note 13, “Otherexpense”.

 

Forthe three and nine months ended September 30, 2010, in accordance with the “successfulefforts” method of accounting, the Company capitalized approximately $0.6million and $1.5 million of depreciation expense, respectively, mainly relatedto the tender assist barges serving as support equipment, and $2.5 million and$6.9 million of interest expense, respectively, to construction in progress.For the same periods in 2009, the Company capitalized approximately $0.4million and $1.1 million of depreciation expense, respectively, and $1.2million and $3.3 million of interest expense, respectively, to construction inprogress.

 

For the three and ninemonths ended September 30, 2010, the Company recognized $6.7 million and $24.2million of depreciation, depletion and amortization expense, respectively. Forthe same periods in 2009, the Company recognized $5.9 million and $19.3 millionof depreciation, depletion and amortization expense, respectively.

 

**Note 6— Asset Retirement Obligation**

 

An obligation was recordedfor the future plug and abandonment of the producing oil wells in the Corvinaand Albacora fields, in accordance with the provisions of ASC Topic 410, “AssetRetirement and Environmental Obligations”.

 

Activity related to theCompany’s asset retirement obligation (“ARO”) for September 30, 2010 andDecember 31, 2009 is as follows:

 
| ** **                            | ** ** | **September 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|---------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                            | ** ** | **(in thousands)**      | ** ** |
| ARO as of the beginning of the period |       | $                            | 766        |                        | $          | 580 |   |
| Liabilities incurred during period    |       | 292                          |       | 296                         |       |
| Accretion expense                     |       | 77                           |       | 74                          |       |
| Revisions in estimates during period  |       | —                       |       | (184                        | )          |
|                                  |       | —                       |       | —                      |       |
| ARO as of the end of the period       |       | $                            | 1,135      |                        | $          | 766 |   |

 

**Note 7 — Investment in Ecuador Property**

 

The Company has a 10% netinvestment interest in an oil and gas property in Ecuador (the “Santa ElenaProperty”) totaling $1.1 million and $1.2 million as of September 30, 2010 andDecember 31, 2009, respectively. The Company accounts for this investmentunder the cost method and records its share of cash received or paid as otherincome or expense. Since the Company’s investment represents ownership of anoil and gas property, which is a depleting asset, the Company is amortizing thecost of the investment on a straight-line basis over the remaining term of thelicense agreement which expires in May 2016.  For the three and ninemonths ended September 30, 2010, the Company received $0.4 million and$0.8 million from its investment in Ecuador property, respectively. For boththe three and nine months ended September 30, 2009, the Company received $0.2million from its investment in

 

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Ecuador property. For boththe three and nine months ended September 30, 2010, and 2009, the Companyrecorded investment amortization expense of approximately $47,000 and $141,000,respectively.

 

**Note 8— Restricted Cash and Performance Bonds**

 

As of September 30,2010, the Company has restricted cash deposits of $5.0 million. In connectionwith the Company’s properties in Peru, it obtained four performance bonds totaling$5.3 million that are partially collateralized by restricted cash deposits of$3.1 million to insure certain performance obligations and commitments underthe license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally, theCompany has $1.3 million of restricted cash to collateralize insurance bondsfor import duties related to the Don Fernando barge and $0.6 million ofrestricted cash to insure certain performance obligations and commitments atthe Company’s gas-to-power project site near Tumbes. In addition the Companyhas an unsecured performance bond of $0.1 million to guarantee its performanceunder an office lease agreement in Peru.

 

As of December 31,2009, the Company had restricted cash deposits of $5.7 million. In connectionwith the Company’s properties in Peru, it obtained four performance bondstotaling $5.3 million that were partially collateralized by restricted cashdeposits of $3.1 million to insure certain performance obligations andcommitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII.Additionally, the Company had $1.6 million of restricted cash to collateralizeinsurance bonds for import duties related to the BPZ-01 barge and crane onboard the BPZ-01. The Company also had $1.0 million of restricted cash held ina trust account in order to secure financing to support its operations. InJanuary 2010, the $1.0 million of restricted cash held in a trust accountwas released in order to make the final payment on the Company’s short-termloan agreement. Furthermore, the Company had an unsecured performance bond of$0.1 million to guarantee its performance under its new office lease agreementin Peru.

 

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

 

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

 

AtSeptember 30, 2010 and December 31, 2009, long-term debt and capitallease obligations consist of the following:

 
| ** **                                                                            | ** ** | **September 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                                            | ** ** | **(in thousands)**      | ** ** |
|                                                                                  |       |                         |       |                        |       |
| $15 million IFC Senior Note, Libor plus 2.75%, due  2012                              |       | $                            | 15,000     |                        | $          | 15,000 |   |
| $170.9 million Convertible Notes, 6.5%, due 2015,  net of discount of ($31.5) million |       | 139,428                      |       | —                      |       |
| Capital Lease Obligations                                                             |       | 8,594                        |       | 11,910                      |       |
| Other                                                                                 |       | —                       |       | 1,023                       |       |
|                                                                                  |       | 163,022                      |       | 27,933                      |       |
| Less: Current Portion of Long-Term Debt and Capital  Lease Obligations                |       | 9,285                        |       | 5,352                       |       |
|                                                                                  |       | $                            | 153,737    |                        | $          | 22,581 |   |

 

**$170.9million Convertible Notes due 2015**

 

During the first quarter of2010, the Company closed on a private offering for an aggregate of $170.9million convertible notes due 2015 (the “2015 Convertible Notes”). The 2015Convertible Notes offering was comprised of (i) the initial $140.0 million of2015 Convertible Notes sold in an initial private offering, (ii) the exerciseby the initial purchaser of a 30- day option to purchase an additional $21.0million of 2015 Convertible Notes, and (iii) IFC’s election, pursuant to acontractual right, to participate in the offering for an additional $9.9million of 2015 Convertible Notes, bringing the total proceeds of the privateoffering to $170.9 million. The 2015 Convertible Notes were sold to an initialpurchaser who then sold the notes to qualified institutional buyers pursuant toRule 144A of the Securities Act of 1933. The $170.9 million of 2015Convertible Notes were issued pursuant to an indenture dated February 8,2010, between the Company and Wells Fargo Bank, National Association, astrustee (“the Indenture”).

 

The 2015 Convertible Notesare the Company’s general senior unsecured obligations and rank equally inright of payment with all of the Company’s other existing and future seniorunsecured indebtedness.  The 2015 Convertible Notes are effectively 

 

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subordinate 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 payinterest on the 2015 Convertible Notes at a rate of 6.50% per year onMarch 1st and September 1st of each year, beginning on September 1,2010.  The 2015 Convertible Notes mature on March 1, 2015. Theinitial conversion rate is 148.3856 shares per $1,000 principal amount of the2015 Convertible Notes (equal to an initial conversion price of approximately$6.74 per share of common stock), subject to adjustment. Upon conversion, theCompany must deliver, at its option, either (1) a number of shares of itscommon stock determined as set forth in the Indenture, (2) cash, or(3) a combination of cash and shares of its common stock (but not to exceed19.99% of the Company’s outstanding shares at the time of such delivery).

 

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

 

Holders may convert their2015 Convertible Notes at their option at any time prior to the close ofbusiness on the second business day immediately preceding the maturity dateunder the following circumstances:

 

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

 

(2) prior toJanuary 1, 2015, during the five business-day period after any tenconsecutive trading-day period in which the trading price of $1,000 principalamount of the 2015 Convertible Notes for each trading day in the measurementperiod was less than 97% of the product of the last reported sale price of theCompany’s common stock and the conversion rate on such trading day;

 

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

 

(4) upon the occurrenceof one of the specified corporate transactions. Holders may also convert the2015 Convertible Notes at their option at any time beginning onFebruary 1, 2015, and ending at the close of business on the secondbusiness day immediately preceding the maturity date.

 

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

 

If the Company experiencesany one of the certain specified types of corporate transactions, holders mayrequire the Company to purchase all or a portion of their 2015 ConvertibleNotes. Any repurchase of the notes pursuant to these provisions will be forcash at a price equal to 100% of the principal amount of the notes to bepurchased plus any accrued and unpaid interest to, but excluding, the purchasedate.

 

The Indenture containscustomary terms and covenants and events of default. If an event of default (asdefined therein) occurs and is continuing, the Trustee by notice to theCompany, or the holders of at least 25% in aggregate principal amount of the2015 Convertible Notes then outstanding by notice to the Company and theTrustee, may declare the principal and accrued and unpaid interest (includingadditional interest or premium, if any) on the 2015 Convertible Notes to be dueand payable. In the case of an event of default arising out of certainbankruptcy events (as set forth in the Indenture), the principal and accruedand unpaid interest (including additional interest or premium, if any), on thenotes will automatically become due and payable.

 

Net proceeds from the saleof the 2015 Convertible Notes, after deducting the discounts and commissionsand any offering expenses payable by the Company, were approximately $164.9million.  The initial purchaser received commissions of approximately $5.5million in connection with the sale of the 2015 Convertible Notes and theCompany incurred approximately $0.6 million of direct expenses in connection withthe offering.  The Company intends to use the net proceeds for generalcorporate purposes, including without limitation, capital expenditures andworking capital, reduction or refinancing of debt, or other corporateobligations.

 

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Asa result of the Company’s adoption of the accounting standard for convertibledebt that may be settled in cash upon conversion, it is required to separatelyaccount for the liability and equity components in a manner that reflects theCompany’s non-convertible 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 equityconversion feature. The value assigned to the equity component is determined bydeducting the fair value of the liability component from the initial proceeds.The excess of the principal amount of the liability component over its carryingamount (the non-cash discount) is amortized to interest expense using theeffective interest method over the term of the debt agreement. In addition,transaction costs incurred that directly relate to the issuance of convertibledebt instruments must be allocated to the liability and equity components inproportion to the allocation of proceeds and accounted for as debt issuancecosts and equity issuance costs, respectively. The accounting standard requiresretrospective restatement of all periods presented back to the date of debtissuance with a cumulative effect of the change in accounting principle on allprior periods being recognized as of the beginning of the first period.

 

TheCompany estimated its non-convertible borrowing rate at the date of issuance ofits 2015 Convertible Notes to be 12%. The 12% non-convertible borrowing rate represents the borrowing rate ofsimilar companies with the same credit quality as the Company and was obtainedthrough a quote from the initial purchaser. Using the income method anddiscounting the principal and interest payments of the 2015 Convertible Notesusing the 12% non-convertible borrowing rate, the Company estimated the fairvalue of the $170.9 million 2015 Convertible Notes to be approximately $136.3million with the discount being approximately $34.6 million. The discount willbe amortized as non-cash interest expense into income over the life of thenotes using the interest method. In addition, the Company recordedapproximately $4.8 million of the $6.1 million of fees and commissions as debtissue costs that will be amortized over time using the interest method asinterest expense. The remaining $1.3 million of fees and commissions is treatedas an original issue discount against the value of the equity component. TheCompany estimates 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 $6.3 million, $11.1 million, $11.1 million,$11.1 million, $11.1 million and $176.5 million, respectively.

 

Asof September 30, 2010, the net amount of $139.4 million includes the $170.9million of principal reduced by $31.5 million of the remaining unamortizeddiscount. The net amount of the equity component is $33.3 million whichincludes the initial discount of $34.6 million reduced by $1.3 million ofdirect transaction costs. The remaining unamortized discount of $31.5 millionwill be amortized into interest expense, using the effective interest method,over the remaining life of the loan agreement, whose term expires in March2015.  At September 30, 2010, using thecurrent conversion rate of 148.3856 shares per $1,000 principal amount of the2015 Convertible Notes, if the $170.9 million of principal were converted intoshares of common stock, the notes would convert into 25,364,737 shares ofcommon stock. In accordance with New York Stock Exchange (“NYSE”) rules, theCompany received shareholder approval to issue shares in excess of 19.99% ofshares outstanding at the time of the offering (23,031,663 shares) should theCompany need to issue shares in order to satisfy its obligation under the 2015Convertible Notes.  As of September 30,2010, there is no excess if-converted value to the holders of the 2015Convertible Notes as the price of the Company’s common stock at September 30,2010, $3.83 per share, is less than the conversion price.

 

 For both the three and nine months endedSeptember 30, 2010, the effective interest rate for the 2015 Convertible Notesis 12%; including the amortization of debt issue costs, the effective interestrate is 12.6%.

 

Theamount of interest expense related to the 2015 Convertible Notes for the threemonths ended September 30, 2010 is $4.3 million, disregarding capitalizedinterest considerations, including $2.8 million of interest expense related tothe contractual interest coupon, $1.3 million of non-cash interest expenserelated to the amortization of the discount and $0.2 million of interestexpense related to the amortization of debt issue costs.  There were no similar expenses for the sameperiod in 2009.

 

Theamount of interest expense related to the 2015 Convertible Notes for the ninemonths ended September 30, 2010 is $10.9 million, disregarding capitalizedinterest considerations, including $7.3 million of interest expense related tothe contractual interest coupon, $3.1 million of non-cash interest expenserelated to the amortization of the discount and $0.5 million of interestexpense related to the amortization of debt issue costs.  There were no similar expenses for the sameperiod in 2009.

 

**$15.0Million IFC Reserve-Based Credit Facility**

 

OnAugust 15, 2008, the Company entered into 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. asco-borrowers. The reserve-based lending facility matures inDecember 2012.

 

The reserve-based lendingfacility bears interest at an approximate rate of LIBOR plus 2.75%, currentlyequivalent to 3.5% based on the six month LIBOR rate of 0.75% at June 30,2010.  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 

 

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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.  The Company hasa waiver and amendment from IFC which extended the period of time to assign afirst priority lien on Empresa Electrica Nueva Esperanza S.R.L.’s interest inthe Agreement with GE to purchase three gas-fired turbines to IFC untilDecember 2010. The Company was in compliance with all material covenantsof the Loan Agreement as of September 30, 2010.

 

The Loan Agreement provides for eventsof 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 contracts forthe exploration 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, or certain other key agreements; revocation of anyfinancing or security documents with the IFC or certain key agreements;defaults on certain liabilities; the incurrence of certain judgments againstthe borrower or any subsidiary; abandonment or extended business interruptionof the Corvina field or certain other petroleum assets; engagement in certainsanctionable practices; or the enactment of restrictions in Peru that couldinhibit any payment a borrower is required to make under the financingdocuments 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**

 

InJuly 2009, the Company, through its subsidiary, BPZ E&P, entered intoa $5.1 million short-term loan agreement to finance the purchase of casing andaccessories for use in its current and future operations. The $5.1 millionshort-term loan bore an annual interest rate of 5.45% and was to be repaid infive monthly installments of approximately $1.0 million startingSeptember 2009.  In connection with the $5.1 million short-term loanagreement, the Company was required to deposit $1.0 million with the lendinginstitution as a guaranty for the loan.  The $1.0 million was to beapplied to the last installment of the loan repayments. In January 2010, theremaining principal amount of approximately $1.0 million, along with theaccrued interest due, was repaid with the $1.0 million deposit and cash.

 

**CapitalLeases**

 

The Company is party toseveral capital lease agreements, as more fully described in its Form 10-K, asamended, for the year ended December 31, 2009. Generally, the Company enters into capital lease agreements in order tosecure marine vessels in order to support its operations in Peru and to obtain furnitureand fixtures for its offices located in Houston and Peru. The contractual termof the capital lease agreements range between two to five years and theeffective interest rate of the capital lease agreements range between 5.94% and34.9%.

 

In July 2010, the Companyexercised the second year purchase option and purchased the capital leaseproduction equipment used on board the Company’s floating production, storageand offloading facility (“FPSO”), the Namoku.

 

Forthe three and nine months ended September 30, 2010, the Company recognizedapproximately $2.8 million and $8.5 million of net interest expense,respectively, which includes $5.3 million and $15.4 million of interestexpense, respectively, reduced by $2.5 million and $6.9 million of capitalizedinterest expense, respectively. For the same periods in 2009, the Company didnot recognize any interest expense as it capitalized all interest expense of$1.2 million and $3.3 million, respectively, to construction in progress.

 

**Note 10 — Stockholders’ Equity**

 

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

 

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**September 2009Private Placement of Common Stock**

 

On September 15, 2009,the Company closed a private placement of approximately 1.6 million shares ofcommon stock, no par value, to IFC pursuant to a Subscription Agreement datedSeptember 15, 2009. This private placement was related to the Company’sregistered direct offering of approximately 18.8 million shares of common stockat a price of $4.66 per share that closed on June 30, 2009. Pursuant tothe Subscription Agreement dated December 16, 2006 (the “SubscriptionAgreement”) by and between IFC and the Company, IFC has the right, within 45days of notice of an offering, to purchase shares of the Company’s common stockfor the same price and terms as the participants in the offering to retain itsproportionate ownership in the Company. IFC exercised its pre-emptive right topurchase approximately 1.6 million shares of common stock to which it wasentitled under the Subscription Agreement at the offering price of $4.66 pershare, resulting in gross proceeds to the Company of approximately $7.6million. In compliance with NYSE requirements, the transaction was submitted toand approved by the shareholders of the Company at a Special Meeting ofShareholders on August 24, 2009. No warrants or dilutive securities wereissued to IFC in connection with the private placement. The shares were placeddirectly by the Company. The Company used the proceeds of this offering todevelop its properties under its existing license contracts and other generalcorporate purposes consistent with the Company’s operating plans.

 

Under the September 15,2009 Subscription Agreement, the Company committed to file a registrationstatement with the Securities and ExchangeCommission (“SEC”) covering the shares no later than 45 days after the closingwith respect to such shares. On October 21, 2009, the Company filed aregistration statement with the SEC covering the shares. In May 2010, theCompany filed an amended registration statement with the SEC and the amendedregistration statement was declared effective during the month. There were nopenalty payments were associated with the delay in obtaining effectiveness ofthe registration statement.

 

**Potentially Dilutive Securities**

 

In addition to the shares issuedand outstanding, the Company had the following potentially dilutive securitiesat September 30, 2010 and September 30, 2009. None of these potentially dilutive shares have been included in the calculationof earnings per share, for the three and nine months ended September 30, 2010or September 30, 2009, as the effect would be anti-dilutive.

 

The potentially dilutive shares areas follows:

 
| ** **                                                           | ** ** | **September 30,  2010** | ** ** | **September 30,  2009** | ** ** |
|----------------------------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|
| ** **                                                           | ** ** | **(in thousands)**      | ** ** |
| Stock options outstanding                                            |       | 5,337                        |       | 4,657                        |       |
| Shares issuable under convertible debt agreement                     |       | 25,365                       |       | —                       |       |
| Total potentially dilutive securities issued                         |       | 30,702                       |       | 4,657                        |       |
| Shares available pursuant to Long-Term Incentive  Compensation Plans |       | 4,463                        |       | 1,571                        |       |

 

The Company has in effectthe 2007 Long-Term Incentive Compensation Plan, as amended in 2010 to increasethe number of shares available (the “2007 LTIP”), and the 2007 Directors’Compensation Incentive Plan (the “Directors’ Plan”). The 2007 LTIP andDirectors’ Plan provides for awards of options, stock appreciation rights,restricted stock, restricted stock units, performance awards, other stock-basedawards and cash-based awards to any of the Company’s officers, employees,consultants and the employees of certain of the Company’s affiliates as well asnon-employee directors. The number of shares authorized under the amended 2007LTIP and Directors’ Plan is 8.0 million and 2.5 million, respectively. Asof September 30, 2010, approximately 3.3 million shares remain available forfuture grants under the 2007 LTIP and 1.1 million shares remain available forfuture grants under the Directors’ Plan.

 

The following tablesummarizes stock-based compensation costs recognized under ASC Topic 718, “StockCompensation” for the three and nine months ended September 30, 2010 and 2009,respectively, and is generally included in “General and administrative expense”on the Consolidated Statements of Operations:

 
| ** **                                           | ** ** | **Three Months Ended** | ** ** | **Nine Months Ended** | ** ** |
|------------------------------------------------------|------------|----------------------------------|------------|---------------------------------|------------|
| ** **                                           | ** ** | **September 30,**           | ** ** | **September 30,**          | ** ** |
| ** **                                           | ** ** | **2010**                         | ** ** | **2009**                        | ** ** | **2010** | ** ** | **2009** | ** ** |
| ** **                                           | ** ** | **(in thousands)**          | ** ** | **(in thousands)**         | ** ** |
| Employee stock—based compensation costs         |       | $                                | 1,047      |                            | $          | 1,984 |   | $ | 3,417 |   | $ | 5,909 |   |
| Director stock—based compensation costs (a) (b) |       | 314                              |       | 895                             |       | 1,248 |   | 4,433 |   |
|                                                 |       | $                                | 1,361      |                            | $          | 2,879 |   | $ | 4,665 |   | $ | 10,342 |   |

 

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| (a)    | For the nine months ended  September 30, 2009 approximately $0.4 million of stock-based  compensation is included in “Other income (expense)” on the Consolidated  Statements of Operations. The amount relates to 100,000 stock options awarded  to a former member of the Board of Directors to purchase the Company’s common  stock. The grant date fair value of the award was recognized upon issuance of  the award. |
|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |                                                                                                                                                                                                                                                                                                                                                                                                                                           |
| (b)    | For the nine months ended  September 30, 2009 additional stock-based compensation of approximately  $0.7 million was recognized primarily related to the accelerated vesting for  certain restricted stock and stock option awards granted to a former member  of the Board of Directors.                                                                                                                                                 |

 

**RestrictedStock Awards and Performance Shares**

 

On July 1, 2010, the Company’sBoard of Directors awarded 120,750 shares of restricted stock to officers andother key employees under the Company’s 2007 LTIP.  These awards were subject to the approval ofan amendment of the 2007 Long-Term Incentive Compensation Plan by theaffirmative vote of the holders of a majority of the votes cast at the Company’sAnnual Meeting of Shareholders (the “Annual Meeting”), which was approved atthe Annual Meeting in August 2010. For the nine months ended September 30,2010, the Company and the Company’s Board of Directors awarded 283,940 totalshares, including the 120,750 shares mentioned above, to officers, directorsand other key employees under the Company’s 2007 LTIP. The restricted stockawards generally vest on the second anniversary of the grant date.

 

**StockOptions**

 

On July 1, 2010, the Company’sBoard of Directors awarded officers and other key employees a total of 362,124options to purchase the Company’s common stock under the Company’s 2007LTIP.  These awards were subject to theapproval of an amendment of the 2007 Long-Term Incentive Compensation Plan bythe affirmative vote of the holders of a majority of the votes cast at theAnnual Meeting, which was approved at the Annual Meeting in August 2010. Forthe nine months ended September 30, 2010, the Company and the Company’s Boardof Directors awarded 592,124 total options, including the 362,134 optionsmentioned above, to officers and other key employees under the Company’s 2007LTIP.  These options generally vest inequal annual installments over a three-year period from the grant date. Duringthe nine months ended September 30, 2010, the weighted average exercise priceper share of the options awards granted and the weighted average fair value pershare of the options awards granted was $4.78 and $3.26, respectively.

 

For the nine months endedSeptember 30, 2010, the Company awarded its non-employee directors a total of200,000 options to purchase the Company’s common stock under the Directors’Plan.  These options generally vest inequal annual installments over a two-year period from the grant date. Theexercise price of these awards is based on the closing market price on the dateof Board approval of the grant, June 25, 2010.

 

**Note 11**—******Fair Value Measurements and Disclosures**

 

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

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

 

Thefollowing describes the valuation methodologies the Company uses for its fairvalue measurements.

 

**Assets and Liabilities Measured at Fair Value on a RecurringBasis**

 

*Cash and Cash Equivalents*

 

Cashand cash equivalents include all cash balances and any highly liquidinvestments with an original maturity of 90 days or less. The carryingamount approximates fair value because of the short maturity of theseinstruments.

 

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*Restricted Cash*

 

Restrictedcash includes all cash balances which are classified as long-term as they areassociated with the Company’s long-term assets. The carrying amountapproximates fair value because the nature of the restricted cash balance isthe same as cash.

 

**Non-Financial Assets and Liabilities**

 

TheCompany discloses or recognizes its non-financial assets and liabilities, suchas asset retirement obligations and impairments of long-lived assets, at fairvalue on a non-recurring basis. As none of the Company’s non-financial assetsand liabilities were impaired as of September 30, 2010 and December 31,2009, and no other fair value measurements were required to be recognized on anon-recurring basis, additional disclosures were not provided.

 

**Additional Fair Value Disclosures**

 

*$15.0 Million IFC Reserve-Based Credit Facility*

 

Thefair value of the Company’s IFC Facility at September 30, 2010 and December 31,2009 approximates the carrying value because the interest rates are based onfloating rates identified by reference to market rates, and because theinterest rates charged are at rates at which the Company can currently borrowunder similar terms.

 

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

 
| ** **                                                                                | ** ** | **September 30,  2010** | ** ** | **December 31,  2009**  | ** ** |
|-------------------------------------------------------------------------------------------|------------|------------------------------|------------|------------------------------|------------|
| ** **                                                                                | ** ** | **Carrying Amount**     | ** ** | **Fair Value (2)** | ** ** | **Carrying Amount** | ** ** | **Fair Value** | ** ** |
| ** **                                                                                | ** ** | **(in thousands)**      | ** ** | **(in thousands)**      | ** ** |
|                                                                                      |       |                         |       |                         |       |   |   |   |   |
| $170.9 million Convertible Notes, 6.5%, due 2015,  net of discount of ($31.5) million (1) |       | $                            | 139,428    |                         | $          | 151,674 |   | $ | — |   | $ | — |   |
|                                                                                           |            |                              |            |                              |            |  |  |  |  |  |  |  |  |

 

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(1)                  Excludesobligations under capital lease arrangements and variable rate debt

 

(2)                  The Company estimated thefair value of the $170.9 million 2015 Convertible Notes to be approximately$151.7 million based on observed market prices for the same or similar typeissues.

 

**Note 12**—**Revenue**

 

At September 30, 2010, theCompany has developed nine oil wells in the Corvina field and one well in theAlbacora field.  All wells are operatedunder a well testing program.

 

Theoil is delivered by tank vessel to the Petroperu (the Peruvian national oilcompany, Petroleos del Peru - PETROPERU S.A. (“Petroperu”)) refinery in Talara,located approximately 100 miles south of the platform.  Produced oil iskept in production inventory until the Company increases the inventoryquantities to a sufficient level that the refinery in Talara will acceptdelivery.

 

In January 2009, theCompany, through its wholly-owned subsidiary BPZ E&P, entered into along-term oil supply agreement with Petroperu. Under the terms of the contract,the Company agrees to sell, and Petroperu agrees to purchase the Company’scrude oil production originating from the Corvina oilfield in Block Z-1. Thecontract term is for approximately seven years or until 17 MMBbls of crude oilhave been delivered to the Petroperu refinery located in Talara, whichevercomes first. The price per barrel of oil under the agreement is determinedusing a basket of crude oils based on a 15-day average of Forties, Oman, andSuez blend crude oil prices, as quoted in the Spot Crude Prices Assessmentpublished in Platt’s Crude Oilgram Price Report, minus $1 per barrel and othercustomary purchase price adjustments.

 

In May 2010, theCompany, through its wholly-owned subsidiary BPZ E&P, entered into ashort-term 400 MBbls oil supply agreement with Petroperu. Under the terms ofthe contract, the Company agrees to sell, and Petroperu agrees to purchase the

 

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Company’s crude oilproduction originating from the Albacora oilfield in Block Z-1. The price perbarrel of oil under the agreement is determined using a basket of crude oilsbased on a 15-day average of Forties, Oman, and Suez blend crude oil prices, asquoted in the Spot Crude Prices Assessment published in Platt’s Crude OilgramPrice Report, minus $3 per barrel and other customary purchase priceadjustments. As part of the price adjustments the Company is allowed to selloil under the contract as long as the salt content is less than 25 pounds perthousand barrels of oil.  There is nopurchase price adjustment associated with the oil sales if the salt content isless than 10 pounds per thousand barrels.

 

In July 2010, theCompany, through its wholly-owned subsidiary BPZ E&P, entered into a secondshort-term 110 MBbls oil supply agreement with Petroperu. Under the terms ofthe contract, the Company agrees to sell, and Petroperu agrees to purchase theCompany’s crude oil production originating from the Albacora oilfield in BlockZ-1. The price per barrel of oil under the agreement is determined using abasket of crude oils based on a 15-day average of Forties, Oman, and Suez blendcrude oil prices, as quoted in the Spot Crude Prices Assessment published inPlatt’s Crude Oilgram Price Report, minus $4.30 per barrel and other customarypurchase price adjustments. As part of the purchase price adjustments, theCompany is allowed to sell oil under the contract as long as the salt contentis less than 60 pounds per thousand barrels of oil.  There is an incremental purchase priceadjustment associated with the oil sales if the salt content is between 25pounds and 60 pounds per thousand barrels. All 110 MBbls under this supplyagreement were delivered and sold to Petroperu during the month of July 2010.

 

In September 2010, theCompany, through its wholly-owned subsidiary BPZ E&P, entered into a secondshort-term 80 MBbls oil supply agreement with Petroperu. Under the terms of thecontract, the Company agrees to sell, and Petroperu agrees to purchase theCompany’s crude oil production originating from the Albacora oilfield in BlockZ-1. The price per barrel of oil under the agreement is determined using abasket of crude oils based on a 15-day average of Forties, Oman, and Suez blendcrude oil prices, as quoted in the Spot Crude Prices Assessment published inPlatt’s Crude Oilgram Price Report, minus $4.30 per barrel and other customarypurchase price adjustments. As part of the purchase price adjustments, theCompany is allowed to sell oil under the contract as long as the salt contentis less than 60 pounds per thousand barrels of oil.  There is an incremental purchase priceadjustment associated with the oil sales if the salt content is between 25pounds and 60 pounds per thousand barrels. Approximately 50 MBbls under thissupply agreement were delivered and sold to Petroperu during the month ofSeptember 2010 and the remaining 30 MBbls was delivered during October 2010.

 

During the three and ninemonths ended September 30, 2010, the Company produced approximately 279 MBblsand 1,113 MBbls of oil, respectively.  For the same periods in 2009, theCompany produced approximately 214 MBbls and 779 MBbls of oil, respectively.For the three and nine months ended September 30, 2010, the Company sold399  MBbls and 1,046  MBbls of oil at an average per barrel price,net of royalties, of approximately $66.84, and $69.88, respectively. For thesame periods in 2009 the Company sold 207 MBbls and 744 MBbls of oil at anaverage per barrel price, net of royalties, of approximately $63.10, and$50.21, respectively.

 

The Company’s revenues arereported net of royalties owed to the government of Peru. Royalties areassessed by Perupetro as stipulated in the Block Z-1 license agreement based onproduction. However, their calculation is based on the past five-day averagebasket of crude oils prices, as discussed above, before the crude oil deliverydate. For the three and nine months ended September 30, 2010, the revenuesreceived by the Company are net of royalty costs of approximately 5% of grossrevenues or $1.7 million and $4.3 million, respectively. For the same periodsin 2009, the revenues received by the Company were net of royalty costs ofapproximately 5% of gross revenues or $0.7 million and $2.1 million, respectively.

 

**Note 13**—**Other Expense**

 

Duringthe three and nine months ended September 30, 2010, the Company is reporting$12.7 million of charges in the Consolidated Statements of Operations as “Otherexpense”. These charges include $10.7 million of charges related tocertain engineering, consulting, environmental and legal costs for the Company’splanned gas plant, pipeline and gas-to-power project and $2.0 million ofcharges related to the abandonment of two platforms. With respect to the $10.7million of charges related to the planned gas plant, pipeline and gas-to-powerproject, during the third quarter of 2010, management determined that there isno future benefit of these engineering and development costs associated withthe Company’s current gas plant, pipeline and gas-to-power project plans. Accordingly, the Company has decided to write-off these costs. With respect tothe $2.0 million of platform abandonment costs, the Company has determined thattwo previously built platforms, one located in the Piedra Redonda field and theCX-13 platform located in the eastern part of the Corvina field, both of whichwere in existence when the Company acquired the rights to the offshore BlockZ-1 in northwest Peru, are not suitable for the Company’s future oildevelopment plans. Accordingly, the Company is writing-off the $1.2 million ofcosts incurred to evaluate the feasibility of refurbishing and using theseplatforms. In addition, the Company is accruing $0.8 million of abandonmentcosts related to the platform in the Piedra Redonda field as it is obligated toensure the platform does not cause a threat to marine vessels operating in thearea or marine wildlife.

 

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**Note 14 — Income Tax**

 

Forthe three and nine months ended September 30, 2010, the Company recognized anincome tax benefit of approximately $9.1 million and $7.0 million,respectively, on a net loss before income tax of approximately $52.8 millionand $56.7 million, respectively.  For thesame periods in 2009, the Company recognized an income tax benefit ofapproximately $1.8 million and $4.7 million, respectively, on a net loss beforeincome tax of approximately $10.8 million and $30.5 million, respectively.  The difference between the effective tax raterecognized and the 22% statutory rate provided for under the Block Z-1 LicenseContract is due to:

 

·                  The Company hasa 100% allowance on its net operating losses generated in the United States -The Company has a valuation allowance for the full amount of the domesticdeferred tax asset resulting from the income tax benefit generated from netlosses in the U.S., as it believes, based on the weight of available evidence,that it is more likely than not that the deferred tax asset will not berealized prior to the expiration of net operating loss carryforwards in variousamounts through 2027.

 

·                  Certain U.S.expenses are not deductible in Peru - The tax benefit is based on a taxablePeruvian loss that excludes certain U.S. expenses that are not deductible atthe Peruvian level.

 

·                  The increase inthe Company’s deferred tax asset balance is primarily due to the inability todeduct, for Peruvian income tax purposes, the amortization associated with itstotal investment, including both intangible drilling as well as explorationcosts associated with Block Z-1. As a result, the Company is subject to taxprepayments on a taxable income even though the Company incurred a book loss.This will continue until the Company transitions into the commercial stage ofproduction as defined under the Block Z-1 License Contract.

 

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. For the three and nine months endedSeptember 30, 2010 and 2009, respectively, the Company did not have any accruedinterest or penalties associated with any unrecognized tax benefits, nor wasany interest expense recognized during those periods.

 

**Note 15 — Business Segment Information**

 

The Company determines anddiscloses its segments in accordance with ASC Topic 280, “Segment Reporting” (“ASCTopic 280”), previously in accordance with SFAS No. 131 “Disclosures aboutSegments of an 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, geographic areas,and major customers. The Company’s management reporting structure provided foronly one segment for the three and nine months ended September 30, 2010 and2009 and accordingly, no separate segment information is presented. Inaddition, the Company operates only in Peru and has only one customer for itsoil production, Petroperu. The majority of the Company’s long-lived assets arelocated in Peru.

 

**Note 16 — Commitments and Contingencies**

 

*ExtendedWell Testing Regulation*

 

OnDecember 13, 2009, new legislation regulating extended well testing inPeru became effective under a Supreme Decree.  The new regulation providesthat all new wells may be placed on production testing for up to sixmonths.  If the operator believes that additional time for testing is neededto properly evaluate the productive capacity of the field, and cantechnically justify such need, a request for the well to enter into an ExtendedWell Test (“EWT”) period must be submitted to the General Directorate ofHydrocarbons (“DGH”), the agency of the Ministry of Energy and Minesresponsible for regulating the optimum development of oil and gas fields. The approval process for a 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 re-injection 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.Additionally, during both the initial six month testing period and any extendedperiod that may be granted, the Company must also obtain gas flaring permitsfor each well in order for it to be in compliance with Peruvian environmentallegislation.

 

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*Transition to CommercialProduction*

 

OnDecember 29, 2009, the Company received approval from Perupetro for itsproposed First Date of Commercial Production (“FDCP”), as set forth in thecurrent Field Development Plan (“FDP”) for the Corvina field in Block Z-1, ofMay 31, 2010.

 

However,due to the delayed delivery of certain equipment for the gas and waterre-injection facilities at the CX-11 platform, the Company applied for arevised FDCP of November 30, 2010 and received approval of the revised datefrom Perupetro in May 2010.  Unless EWTperiods are approved, upon expiration of such periods, all production willcease until the Company meets the requirements, including installation of waterand gas re-injection facilities, to transition to commercial production. Withrespect to the Corvina field, the Company expects to have the necessary gas andwater re-injection facilities and permits in place and installed at the CX-11platform on or around November 30, 2010.

 

*Extended Well Testing Program*

 

Pendingtransition to commercial production, the Company has been producing oil in theCorvina and Albacora fields subject to the new EWT regulations as describedbelow.

 

OnJanuary 25, 2010, the Company applied for an extended well testing permit forthe first five producing wells in Corvina (the CX11-21XD, CX11-14D, CX11-20XD,CX11-18XD and the CX11-15D wells, collectively the “first five Corvina wells”)to continue gathering data to fully understand the drive mechanisms that arepresent in Corvina.  On March 23, 2010,the Company received a decision from the DGH notifying the Company of approvalto continue extended well testing on its first five Corvina wells until theoriginal FDCP date of May 31, 2010, subject to specific limits on the amount ofnatural gas flared from each of the first five Corvina wells.

 

  The first five Corvina wells were closed dueto the expiration of the EWT period on or about May 31, 2010 and the CX11-19Dwell has been closed since June 2010. In July, 2010, the Company receivedinitial notice that its applications for the first five Corvina wells and theCX11-19D well to enter an extended well testing period were denied by the DGH.  The Company requested the DGH reconsider itsdenial of the Company’s applications. In September 2010, the Company receivednotice that its application for reconsideration for the CX11-19D well to enteran extended well testing period was denied by the DGH. Likewise, in October2010, the Company was notified that its applications for reconsideration forthe first five Corvina wells to continue an extended well testing period haveagain been denied by the DGH. The CX11-19D well and the first five Corvinawells are expected to remain closed until the gas and water re-injectionfacilities are installed and commissioned at the CX-11 platform, which isexpected to be completed on or around November 30, 2010.

 

TheCompany commenced drilling the CX11-23D well in July 2010.  The CX11-23D well in Corvina began theinitial testing phase in mid-September 2010. This is the final well to be drilled from the existing CX-11 platformand the drilling rig has been removed from the platform in order to completethe installation of production and gas and water re-injection equipment.

 

InJuly 2010, the Company suspended production from the A-14XD well forapproximately two weeks because the initial six month testing periodexpired.  However, the Company received asix month extended well testing permit and a six month gas flaring permit thatshould allow it to continue oil production of this well at or near the samelevel as the well’s initial six month production for most, if not all, of thepermitted period.

 

AtSeptember 30, 2010, the Company was producing oil under a testing program fromthe CX11-23D, CX11-17D and A-14XD wells. The Company’s current view is that itmay only be able to produce its new wells for up to six months under the newwell testing regulations.  Testing ofthese wells beyond the initial six month period will require application to theMinistry of Energy and Mines, which may not grant approval.

 

Withrespect to the Corvina field, the Company expects to have the necessary gas andwater re-injection facilities and permits in place and installed at the CX-11platform on or around November 30, 2010.

 

Withrespect to the Albacora field, the Company intends to request additional EWT andgas flaring permits for the A-14D well until the appropriate gas and waterre-injection facilities are installed and operational at the A platform. TheCompany can give no assurance that the DGH or the Ministry of Energy and Mineswill grant approval of any future EWT permits requested by it. The Company hasdecided to suspend drilling operations at the A platform in the Albacora fielduntil it conducts its planned three dimensional (“3-D”) seismic survey of thearea, currently planned for 2011.  Duringthe drilling downtime, the Company will move forward to fabricate and installpermanent production and injection facilities on the Albacoraplatform. This should allow for continued production testing from thefield once drilling operations resume by avoiding gas flaring and associatedpermitting issues.

 

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*EcuadorianHydrocarbon Law*

 

In July, 2010, the Companywas notified of changes to the Ecuadorian hydrocarbon law that includedprovisions that will allow the Ecuadorian government to nationalize oil fieldsif a private operator does not agree to contractual changes mandated by the newhydrocarbon laws.  The new law went into effect on July 26,2010.  Besides allowing for the nationalization of private companies thatdo not comply with new laws, the legislation aims to change currentproduction-sharing arrangements to service contracts in which the governmentowns the oil and natural gas produced.  The Company is still reviewing theimpact of this new law, if any, as it pertains to its 10% net investmentinterest in an oil and gas property in Ecuador. For further information seeNote 7 — “Investment in Ecuador Property”.  However, the Company does notbelieve any such impact on its Ecuadorian investment will have a materialimpact on the Company’s overall financial position.

 

*SECComments*

 

In connection with aregistration statement filed on October 21, 2009 to register shares issuedto IFC in a private transaction during September 2009, the Companyreceived comments from the SEC pertaining to its registration statement, Form 10-Kfor the year ended December 31, 2008, Definitive Proxy Statement filed on April 30,2009, and Form 10-Q for the period ended September 30, 2009 and therelated earnings press release. In general, the questions or comments from theSEC related to: (i) clarifications in several of the Company’sdisclosures; (ii) the basis for the assumptions underlying its SEC oilreserves reported for 2008 in light of its actual production performance in2009; (iii) the reasons its 2009 production fell short of 2008projections; (iv) the consideration the Company gave to the reasonablecertainty of its assumptions underlying its SEC oil reserves and the relatedaccounting reported in its financial statements; and (v) how the Companyis taking into consideration certain items and uncertainties for its 2009reserves report. The Company promptly responded to the SEC’s requests and,where appropriate, made clarifications to its disclosures. On April 14,2010, the SEC notified the Company that they had no further comments at thattime.

 

*ProfitSharing*

 

TheConstitution of Peru and Legislative Decree Nos. 677 and 892 gives Peruemployees working in private companies engaged in activities generating incomeclassified as third category income by the Income Tax Law the right to share inthe Company’s Peruvian subsidiaries’ profits. According to Article 3 ofthe United Nations International Standard Industrial Classification, BPZE&P’s tax category is classified under the “mining companies” section,which sets the rate at 8%. However, in Peru, the Hydrocarbon Law states, andthe Supreme Court ruled, that hydrocarbons are not related to miningactivities. Hydrocarbons are included under “Companies Performing OtherActivities”, thus Oil and Gas Companies pay profit sharing at a rate of 5%. The5% of income is determined by calculating a percentage of the Company’sPeruvian subsidiaries’ annual total revenues subject to income tax less theexpenses required to produce revenue or maintain the source of revenues. Thebenefit granted by the law to employees is calculated on the basis of “incomesubject to taxation” per the Peruvian tax code, and not based on income/(loss)before incomes taxes as reported under GAAP. For the three and nine monthsended September 30, 2010, approximately $0.7 million and $2.3 million ofexpense related to profit sharing is included in “General and administrativeexpense” in the Consolidated Statement of Operations as the Company’s Peruviansubsidiaries have “income subject to taxation” per the Peruvian tax code. Forthe same periods in 2009, the Company incurred profit sharing expense of $0.3million and $0.9 million, respectively. The Company is subject to profitsharing expense each year its Peruvian subsidiaries are considered profitableunder the Peruvian tax code.

 

*BargeIncident*

 

InAugust 2006, the Company incurred an operational delay resulting from anavigation incident which caused the BPZ-01 barge to be grounded on a sand barin Talara Bay in northwest Peru.  The Company expects to file an insuranceclaim after the dry docking of the vessel, which is scheduled for the lastquarter of 2010 or the first quarter of 2011.  As of September 30,2010, the Company has not presented a final claim to its insurance carrier forthe barge repairs.

 

TheCompany believes the majority of the costs associated with the groundingincident will be reimbursed through insurance or through a third party. No assurances can be given, however, that any such recoveries will besufficient to cover all costs associated with the incident or to the timing ofany such recoveries.  The Company intends to file an insurance claim withits underwriters after it has fully assessed the damages in dry dock andcompletes repairs as well as finalized the reimbursement agreement with thethird party.

 

*Barges*

 

InMay 2009, the Company entered into an amendment of its lease agreement fortwo barges currently under charter, the Namoku (the” FPSO”) and the Nu’uanu(the Company’s floating, storage and offloading vessel, “FSO”). Under the termsof the amended lease agreement, the current charter, originally set to expirein November 2009, is extended for five years commencing on

 

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May 1,2009.  During the first 18 months of the amended lease term, the dailycharter rate for the use of both barges is fixed. Commencing onNovember 2010, the daily charter rate for the use of both vessels will bebased on a tiered structure with the daily rate dependent upon the amount ofthe previous month’s average daily per barrel price of West Texas IntermediateCrude Oil (“WTI”), as indicated on the New York Mercantile Exchange. Any amountpaid by the Company after November 2010 over the initial daily rate, as aresult of the escalated tiered structure based on the price of WTI, will beconsidered contingent rental payments.  The amended lease agreement containsa $3.0 million purchase option after the third year of the lease, a $2.0million purchase option after the fourth year of the lease and a mandatory $1.0million purchase obligation by the Company after the fifth year of the lease.

 

*PerformanceBonds and Obligations*

 

Asof September 30, 2010, the Company has restricted cash deposits of $5.0million. In connection with the Company’s properties in Peru, it obtained fourperformance bonds totaling $5.3 million that are partially collateralized byrestricted cash deposits of $3.1 million to insure certain performanceobligations and commitments under the license contracts for Blocks Z-1, XIX,XXII and XXIII. Additionally, the Company has $1.3 million of restricted cashto collateralize insurance bonds for import duties related to the Don Fernandobarge and $0.6 million of restricted cash to insure certain performanceobligations and commitments at the Company’s gas-to-power project site nearTumbes. In addition, the Company has an unsecured performance bond of $0.1million to guarantee its performance under an office lease agreement in Peru.

 

*GETurbine Purchase Agreement**,**Amendmentand Letter Agreement*

 

On September 26, 2008,the Company, through its subsidiary Empresa Electrica Nueva Esperanza S.R.L.,entered into a $51.7 million contract (the “Agreement”) for the purchase ofthree LM 6000 gas-fired turbines from GE Packaged Power, Inc. and GEInternational, Inc. Sucursal de Peru (collectively “GE”). The Agreementrequired an initial down payment of $5.1 million and monthly progress paymentsof $1.1 million per unit. In January 2009, BPZ and GE entered into anamendment of the Agreement. Under the terms of the amendment, both GE and BPZagreed to a suspension period under the Agreement from and including December 15,2008 through November 15, 2009, whereby no failure on the part of BPZ orGE to perform any obligations under the Agreement would give rise to a breachof contract or the right to terminate the Agreement, provided the Company makesa $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. OnFebruary 24, 2009, the Company paid the first progress payment of $3.4million. 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 no later than five daysafter receiving the notice of issuance to ship,   The Company expects to receive the notice ofissuance to ship for two units on December 1, 2010 and expects payment dueof $12.7 million five days thereafter. The Company expects to receive the notice of issuance to ship for oneunit on December 14, 2010 and expects payment due of $8.0 million fivedays thereafter.  Additionally, shouldthe Company locate a joint venture partner and obtain financing for the threeLM 6000 gas-fired turbines and services prior to the December 1, 2010deadline, the Company agreed to pay the final payment under the LetterAgreement within 7 days of obtaining the financing and funding.

 

Should the Company fail tomake the payments in accordance with the terms of the Letter Agreement, thiswould result in immediate termination of the Agreement without any additionalnotice or cure period. As of September 30, 2010, the Company has madepayments to GE totaling $25.0 million. Additionally, through November 1,2010 the Company made additional payments of $6.0 million and plans to meet theremaining payments due throughout 2010 by using proceeds of the convertibledebt offering or subsequent financing. Failure to make any of the remainingprogress payments in full would result in a charge-off of all of the previouslymade progress payments.

 

*Gas-to-Power Project Financing*

 

The gas-to-power projectentails the installation of an approximately 10-mile gas pipeline from theCX-11 platform to shore, the construction of gas processing facilities and thebuilding of an approximately 135 megawatt (“MW”) simple-cycle electricgenerating plant.  The proposed 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 ownedand operated by third parties.

 

TheCompany currently estimates the gas-to-power project will cost approximately$150.0 million, excluding 19% value-added tax which will be recovered viafuture revenue billings. The $150.0 million includes $130.0 million for theestimated cost of the power plant and $20.0 million for the estimated cost ofthe construction of the natural gas pipeline. While the Company has heldinitial discussions with several potential joint venture partners for thegas-to-power project, in an attempt to secure additional financing and otherresources for the project, the Company has not entered into any definitiveagreements with a potential partner. In the event the Company is able toidentify and reach an agreement with a potential joint venture partner, it mayonly retain a minority position in the

 

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project.However, the Company expects to retain the responsibility for the constructionof the pipeline as well as retain ownership of the pipeline. If the Company isunable to identify and reach an agreement with a potential partner, it plans tocontinue moving the project forward to completion without a partner. TheCompany is currently in the process of identifying and securing the additionalfinancing necessary to move the project forward. The Company is currently in discussions with a financial institution toprovide short term financing related to our turbine acquisitions. No firmagreements, offers or commitments are in place as the Company discussespossible terms and conditions.

 

**Note 17 —Legal Proceeding**

 

*NavyTanker Litigation*

 

On October 24, 2007,Tecnomarine SAC, a contractor to BPZ E&P, entered into two short-termagreements with the Peruvian Navy’s commercial branch to charter two smalltankers for use in the Company’s offshore oil production operation.  OnJanuary 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 BPZ Resources, Inc. and BPZ Energy LLC.,parent entities of BPZ E&P, that were not parties to the charter agreementand were not involved in the operations.  Based on the Company’sassessment of the available facts, including the fact that none of the Peruviangovernment-sanctioned investigations into the Supe incident found fault on thepart of Tecnomarine or BPZ E&P, the Company does not believe the outcome ofthe legal proceeding will have a material adverse effect on its financialcondition, results of operations or cash flows. The Company intends tovigorously defend this action but cautions that there is inherent risk inlitigation, which is difficult to quantify, especially at the early stage oflitigation proceedings. In any event, the Company believes that any monetarydamages arising from the incident would be adequately covered by its insurancepolicies, after a customary deductible.

 

**Note 18 — Subsequent Events**

 

Thefollowing events took place subsequent to September 30, 2010:

 

The Company received noticeregarding the denial of its reconsideration requests for EWT permits for thefirst five Corvina wells. For further information see Note 16, “Commitments andContingencies”.

 

TheCompany has hired a financial advisor to assist management and the Board of Directorsin pursuing joint venture partnerships and/or, farm-outs for some or all of theCompany’s assets and options for financing its operations in northwest Peru.

 

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**Item 2. Management’s Discussion and Analysis of Financial Condition andResults of Operations**

 

**Overview**

 

Youshould read the following discussion and analysis together with ourconsolidated financial statements and notes thereto and the discussioncontained in Item 7. “Management’s Discussion and Analysis of FinancialCondition and Results of Operations,” Item 7A, “Quantitative and QualitativeDisclosures About Market Risk” and Item 1A.  “Risk Factors” includedin our Annual Report on Form 10-K, as amended, for the year endedDecember 31, 2009.  The followinginformation contains forward-looking statements that involve risks,uncertainties and assumptions.  Shouldone or more of these risks or uncertainties materialize, our actual results maydiffer from those expressed or implied by the forward-looking statements.  See “Disclosure Regarding Forward-LookingStatements” below.

 

BPZResources, Inc., a Texas corporation, is based in Houston, Texas with officesin Lima, Peru and Quito, Ecuador. We are focused on the exploration,development and production of oil and natural gas in Peru and to a lesserextent Ecuador. We also intend to utilize part of our planned future naturalgas production as a supply source for the complementary development of agas-fired power generation facility in Peru which we expect to wholly- orpartially-own.

 

Wemaintain a subsidiary, BPZ Exploración & Producción S.R.L. (“BPZE&P”),  registered in Peru through our wholly-owned subsidiary BPZEnergy International Holdings, L.P., a British Virgin Islands limitedpartnership, and its subsidiary BPZ Energy, LLC, a Texas limited liabilitycompany. Currently, we, through BPZ E&P, have exclusive rights and licensecontracts for oil and gas exploration and production covering a total ofapproximately 2.2 million acres, in four blocks, in northwest Peru. Our licensecontracts cover 100% ownership of the following properties: Block Z-1 (0.6million 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 inNovember 2001, the Block XIX contract was signed in December 2003 andBlocks XXII and XXIII contracts were signed in November 2007. Generally,according to the Organic Hydrocarbon Law No. 26221 and the regulationsthereunder (the “Organic Hydrocarbon Law” or “Hydrocarbon Law”), the seven-yearterm for the exploration phase can be extended in each contract by anadditional three years up to a maximum of ten years. However, specificprovisions of each license contract can vary the exploration phase of thecontract as established by the Hydrocarbon Law. The license contracts requireus to conduct specified activities in the respective blocks during eachexploration period in the exploration phase. If the exploration activities aresuccessful, we may decide to enter the exploitation phase and our totalcontract term can extend up to 30 years for oil exploration and production andup to 40 years for gas exploration and production. In the event a blockcontains both oil and gas, as is the case in our Block Z-1, the 40-year termmay 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.

 

Weare in the process of developing our oil and natural gas reserves. We have beenproducing and selling oil from the CX-11 platform in the Corvina field of BlockZ-1 under a well testing program and are in the process of satisfying theconditions to transition to commercial production in Corvina.  We are also in the initial stages ofappraising, exploring and developing our potential oil and natural gas reservesfrom the A platform in the Albacora field of Block Z-1 and began selling oilfrom the A-14D well under a well testing program during the second quarter of2010.  From the time we began producingfrom the CX-11 platform in the Corvina field in November 2007 and theAlbacora field in December 2009, through September 30, 2010, we haveproduced approximately 3.0 MMBbls of oil.

 

AtDecember 31, 2009, we had estimated net proved oil reserves of 37.5MMBbls, of which 27.5 MMBbls were in the Corvina field and 10.0 MMBblswere from the Albacora field; both fields are located in Block Z-1, locatedoffshore of northwest Peru. Of our total proved reserves, 9.9 MMBbls(26.4%) are classified as proved developed reserves consisting of 10 wellsand 27.6 MMBbls (73.6%) are classified as proved undeveloped reservesconsisting of 22 future wells. The process of estimating oil and natural gasreserves is complex and requires many assumptions that may turn out to beinaccurate.

 

Our current activities andrelated planning are focused on the following objectives:

 

·                              Transition ofthe Corvina field in Block Z-1 from extended well testing to commercialproduction, which involves the installation of equipment necessary to complywith Peruvian environmental and other regulatory requirements.  The anticipated date of First Date ofCommercial Production (“FDCP”) is on or around November 30, 2010;

 

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·                              Analysis anddevelopment of the Albacora field in Block Z-1 where we have commenced drillingand begun initial production well testing. We have currently decided tosuspended drilling operations at the A platform until we conduct a threedimensional (“3-D”) seismic survey of the area, currently planned for2011.  During the time we are performingthe 3-D seismic survey, we plan to move forward to fabricate and install thenecessary gas and water re-injection facilities in order to transition the fieldinto commercial production once drilling operations resume. In addition we intend to request additionalEWT and gas flaring permits for the A-14D well until the appropriate gas andwater re-injection facilities are installed and operational at the A platform.

 

·                              Continueddevelopment of our gas-to-power project to monetize our natural gas reserves,which we have identified in Corvina, but for which no market has yet beendeveloped and related financing has yet to be obtained, preventing us fromreporting volumes of gas reserves for Securities and ExchangeCommission (“SEC”) reporting purposes;

 

·                              Continuedacquisition of seismic and well testing data to better understand thecharacteristic and potential of our properties and build our reportable assetvalues;

 

·                              Commencement ofan on-shore drilling campaign to develop our on-shore properties and meet ourapplicable license requirements; and

 

·                              Securing therequired capital and financing to conduct the current plan of operation.

 

Ouractivities in Peru also include analysis and evaluation of technical data onour properties, preparation of the development plans for the properties,engineering and designs for platforms to perform our drilling campaigns in theCorvina and Albacora fields in Block Z-1, procuring machinery and equipment foran extended drilling campaign, obtaining all necessary environmental andoperating permits, bringing additional production on-line, seismic acquisition,obtaining detailed engineering and design of the planned power plant and gasprocessing facilities, executing a contract to purchase three LM 6000 gas-firedturbines and securing the required capital and financing to conduct the currentplan of operation.

 

Wehave determined our reporting structure provides for only one operating segmentas we currently only operate in Peru and have only one customer for ourproduction.

 

**Our Business Plan**

 

Ourbusiness plan is to enhance shareholder value through application of ourknowledge of our targeted areas in Peru and leveraging management’s experiencewith the local suppliers and regulatory authorities to effectively and efficiently(i) identify, and quantify the potential value of our oil and gas holdingsin Peru; (ii) develop and increase production and cash flows from ouridentified holdings; and (iii) create a revenue stream throughimplementation of our gas-to-power project, thus increasing shareholder value.

 

Ourmanagement team has extensive engineering, geological, geophysical, technicaland operational experience and extensive knowledge of oil and gas operationsthroughout Latin America and in particular, Peru.

 

Ourfocus is to re-appraise and develop properties in northwest Peru that have beenexplored by other companies and have reservoirs that appear to containcommercially productive quantities of oil and gas, as well as other areas thathave geological formations that we believe potentially contain commercialamounts of hydrocarbons. Additionally, we are advancing our gas-to-powerproject to bring future natural gas production to market and monetize ournatural gas holdings.

 

Twoof the four blocks (Block Z-1 and Block XXIII) contain structures drilled byprevious operators who encountered hydrocarbons. However, at the time the wellswere drilled, the operators did not consider it economically feasible toproduce those hydrocarbons.  Having tested oil in our offshore Block Z-1in both of our first wells in the Corvina field in 2007, and our first well inAlbacora in December 2009, we are focusing on development of the provedoil reserves in those fields.

 

Inaddition, our business plan includes a gas-to-power project, which entails theinstallation of a 10-mile gas pipeline from the CX-11 platform to shore, theconstruction of gas processing facilities and the building of an approximately135 megawatt (“MW”) simple cycle electric generating plant using three LM 6000gas-fired turbines. The proposed power plant site is located adjacent to anexisting substation and power transmission lines which, with certain upgrades,are expected to be capable of handling up to 320 MW of power. We currently planto wholly- or partially-own this power generation facility. The gas-to-powerproject is planned to generate a revenue stream by creating a market for thegas discovered in our Corvina field that is currently shut-in.  This project has not yet been financed and wecontinue to consider the best financing alternatives for the project.

 

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In the near term management is focused on deliveringfirst commercial production in Corvina on or about November 30, 2010,obtaining the appropriate permitting to allow for our 3-D seismic shoot inBlock Z-1 to optimize our future activities in that location, obtainappropriate financing for our spending programs and maximize the value of theacreage we hold for exploration.  To help achieve this last deliverable,we have a hired a financial advisor to assist us in pursuing joint venturepartnerships and/or, farm-outs for some or all of our assets and options for financingour operations in northwest Peru.

 

**ExtendedWell Testing Regulation**

 

OnDecember 13, 2009, new legislation regulating well testing in Peru becameeffective under a Supreme Decree.  The new regulation provides that allnew wells may be placed on production testing for up to six months.  Ifthe operator 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 General Directorate of Hydrocarbons (“DGH”),the agency of the Ministry of Energy and Mines responsible for regulating theoptimum development of oil and gas fields.  The approval process for a EWTpermit requires that the DGH request Perupetro S.A’s (“Perupetro”), acorporation owned by the Peruvian government empowered to become a party in thecontracts for the exploration and/or exploitation of hydrocarbons in order topromote these activities in Peru, opinion on the technical justification forthe EWT.  After the initial six month period or after an approved EWTprogram expires, the operator will be required to have the necessary gas andwater re-injection equipment in place to continue producing the well accordingto existing environmental regulations.  For wells that have been undertesting for more than six months as of the date of publication of the SupremeDecree, the new regulation provides 30 business days to apply to the DGH forthe corresponding EWT permit. Additionally, during both the initial six monthtesting period and any extended period that may be granted, we must also obtaingas flaring permits for each well in order for us to be in compliance withPeruvian environmental legislation.

 

**Transition to CommercialProduction**

 

OnDecember 29, 2009, we received approval, from Perupetro, of our proposedFDCP, as set forth in the current Field Development Plan (“FDP”) for theCorvina field in Block Z-1, which was May 31, 2010.

 

However,due to the delayed delivery of certain equipment gas and water re-injectionfacilities at the CX-11 platform, we applied for a revised FDCP of November 30,2010 and received approval of the revised date from Perupetro in May 2010.  UnlessEWT periods are approved, upon expiration of such periods, all production willcease until we meet the requirements, including installation of water and gasre-injection facilities, to transition to commercial production. Withrespect to the Corvina field, we expect to have the necessary gas and waterre-injection facilities and permits in place and installed at the CX-11platform on or around November 30, 2010.

 

**Extended Well Testing Program**

 

Pendingtransition to commercial production, we have been producing oil in the Corvinaand Albacora fields subject to the new EWT regulations as described below.

 

On January 25, 2010, we applied for an extendedwell testing permit for the first five producing wells in Corvina (theCX11-21XD, CX11-14D, CX11-20XD, CX11-18XD and the CX11-15D wells, collectivelythe “first five Corvina wells”) to continue gathering data to fully understandthe drive mechanisms that are present in Corvina.  On March 23, 2010, we received adecision from the DGH notifying us of approval to continue extended welltesting on our first five Corvina wells, until the original FDCP date of May 31,2010, subject to specific limits on the amount of natural gas flared from eachof the first five Corvina wells.

 

Thefirst five Corvina wells were closed due to the expiration of EWT period andthe CX11-19D well has been closed since June 2010. In July 2010, wereceived initial notice that our applications for the first five Corvina wellsand CX11-19D well to enter an extended well testing period were denied by theDGH.  We requested the DGH reconsider itsdenial of our applications. In September 2010, we received notice that ourapplication for the CX11-19D well to enter an extended well testing period wasagain denied by the DGH. Likewise, in October 2010, we were notified thatour applications for the first five Corvina wells to continue an extended welltesting period have again been denied by the DGH. The CX11-19D well and thefirst five Corvina wells are expected to remain closed until the gas and waterre-injection facilities are installed and commissioned at the CX-11 platform,which is expected to be completed on or around November 30, 2010.

 

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Wecommenced drilling the CX11-23D well in July 2010.  The CX11-23D well in Corvina began theinitial testing phase in mid-September 2010.  This is the final well to be drilled from theexisting CX-11 platform and the drilling rig has been removed from the platformin order to complete the installation of production and gas and waterre-injection equipment.

 

InJuly 2010, we suspended production from the A-14XD well for approximatelytwo weeks because the initial six month testing period expired.  However, in July 2010, we received a sixmonth extended well testing permit and a six month gas flaring permit thatshould allow us to continue oil production of this well at the same level asthe well’s initial six month production for most, if not all, of the permittedperiod.

 

AtSeptember 30, 2010, we are producing oil from the CX11-23D, CX11-17D andthe A-14XD wells.  Our current view isthat we may be able to produce our new wells for at least six months, under thenew well testing regulations.  Testing ofthese wells beyond the initial six month period will require application to theMinistry of Energy and Mines, which may not grant approval.

 

Withrespect to the Corvina field, we expect to have the necessary gas and waterre-injection facilities and permits in place and installed at the CX-11platform on or around November 30, 2010.

 

Withrespect to the Albacora field, we intend to request additional EWT and gasflaring permits for the A-14D well until the appropriate gas and waterre-injection facilities are installed and operational at the A platform. We cangive no assurance that the DGH or the Ministry of Energy and Mines will grantapproval of any future permits requested by us. We have decided to suspend thedrilling operations at the A platform in the Albacora field until we conduct a3-D seismic survey of the area, currently planned for 2011. During the drillingdowntime, we will move forward to fabricate and install permanent productionand injection facilities on the Albacora platform. This should allow forcontinued production testing from the field once drilling operations resume byavoiding gas flaring and associated permitting issues.

 

**Oil Development**

 

***General***

 

We will conduct additional drilling activitiesbased in part on an ongoing assessment of economic efficiencies, licensecontract requirements, likely success and logistical issues such as scheduling,required maintenance and replacement of equipment.  This assessment couldresult in increased emphasis and activities on a given prospect and conversely,could result in decreased emphasis on a given prospect for a period oftime.  In particular, we will assess allocation of our current resourcesamong the Corvina, Albacora, and other Block Z-1 prospects and certain onshoreprospects as they develop, as well as our gas-to-power project.

 

***Seismic Data Acquisition***

 

We are in the process ofreapplying for the required environmental permits and acquiring seismic data toassist us in exploring, appraising and developing certain areas of interest withinour blocks located in northwest Peru. The purpose of the seismic survey is toimprove the subsurface imaging of certain areas within the blocks in order tobetter define the position of future wells as well as to comply with ourexploration commitments under our license contracts.

 

For Block Z-1, we intend toacquire approximately 1,500 square kilometers of 3-D seismic data.  The3-D seismic data survey will include areas of interest within the Corvina,Albacora, and Delfin fields as well as certain prospects and leads locatedwithin the Mero and Piedra Redonda regions and certain deep water leads locatedwithin Block Z-1. Additionally, the 3-D seismic survey will include dataunderneath four existing platforms in the Albacora, Corvina and Piedra Redondafields.  The seismic data survey will fulfill our commitments under thefourth exploration period of the Block Z-1 license contract if conducted withinthe allowed contractual time frame.  Weinitially attempted to conduct this seismic survey in late 2009, but suspendedthe survey as directed by the Ministry of Energy and Mines, because of issuesrelating to our stakeholders in the area of operations.  We are currently working on a new seismicenvironmental permit and we estimate the 3-D seismic data survey to becompleted in 2011.

 

For Block XXIII, our plan isto acquire approximately 360 square kilometers of 3-D seismic data and 290kilometers of two dimensional (“2-D”) seismic data which will include certainareas of interest within the Palo Santo region and four other prospects thatare part of the Mancora gas play.  The seismic survey was initiated in July 2010and we expect the 3-D and 2-D seismic data survey, including data processing,to be completed by the first quarter of 2011.

 

For Block XXII, our plan isto acquire approximately 260 kilometers of 2-D seismic data on four potentialprospects. We expect the 2-D seismic data survey to begin during the fourthquarter of 2010 and be completed, including data processing, by the firstquarter of 2011.

 

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***Corvina Field***

 

Weare producing oil from the CX-11 platform, located in the Corvina field withinthe offshore Block Z-1 in northwest Peru, under a well testing program thatstarted on November 1, 2007.  The Corvina field consists ofapproximately 47,000 acres in water depths of less than 300 feet.  We arecurrently concentrating our drilling efforts on West Corvina, which consists of3,500 acres and have completed a total of nine oil wells, the CX11-23D,CX11-22D, the CX11-17D, the CX11-19D, the CX11-15D, the CX11-21XD, theCX11-20XD, the CX11-18XD and the CX11-14D wells.  The oil is delivered byvessel in storage tanks to the Petroperu (the Peruvian national oil company,Petroleos del Peru - PETROPERU S.A. (“Petroperu”)) refinery in Talara, located100 miles south of the platform.  Produced oil is kept in productioninventory until such time it is delivered to the refinery.

 

In February 2010, wecompleted the CX11-17D well in the Corvina field. The CX11-17D well is theseventh oil well from the CX-11 platform and has been placed into theproduction well testing program. The CX11-17D well was drilled and successfullycompleted into a proved undeveloped area of the Corvina field, targeting sandsproduced by our other wells.

 

In late June 2010, wecompleted a minor workover to the CX11-19D well to isolate a zone that wasproducing a high rate of gas and to access the lower oil bearing sands notpreviously tested. Testing still needs to be performed to evaluate the resultsof the workover.

 

In late June 2010, wecompleted the testing of the CX11-22D well in the Corvina field and placed thewell into the well testing program in July 2010. The CX11-22D well wasdrilled in an up dip location of the Corvina field to continue appraising itsoil and gas potential.  The well has two production strings to allow it tosimultaneously produce oil and re-inject formation water as part of our plan totransition to commercial production in Corvina. The long string of the dualcompletion targets one set of oil sands while the short string will be used forwater re-injection. The well tested oil but with high gas rates due to gascoming from one of the higher intervals that was opened to help define thegas-oil contact.  The well failed to achieve a consistent initialproduction rate because of the resulting high gas-to-oil ratios.  Welltest data indicates that this is not the gas channeling issue that occurred inprevious wells.  To avoid any delays in transitioning Corvina tocommercial production, we plan to evaluate a possible work over this well toisolate the gas sands when we bring a workover rig to the platform in 2011.

 

In July 2010, we begandrilling the CX11-23D well. This well is was the last well drilled from theCX-11 platform prior to installation of the gas and water re-injectionfacilities. We completed the testing of the CX11-23D well in the Corvina fieldin offshore Block Z-1 in northwest Peru and placed the well into the welltesting program in September 2010.

 

Currently, all wells in theCorvina field that are being tested are being tested and produced under the newwell testing regulation, which gives companies six months to evaluate a wellbefore applying for the extended well testing program. We initially planned tohave the needed gas and water re-injection facilities at the CX-11 platform bythe initial approved FDCP of May 31, 2010. However, due to the delayed delivery of certain equipment, we appliedfor a revised FDCP of November 30, 2010 and received approval for therevised date from Perupetro.

 

At September 30, 2010,we are producing oil from the CX11-23D and CX11-17D wells.  The first five Corvina wells were closed atthe end of May 2010 and the CX11-19D well was closed after the workover inJune 2010.  These wells are expectedto remain closed until the gas and water re-injection facilities are installedand commissioned at the CX-11 platform. We plan to have all gas and waterre-injection equipment in place by November 30, 2010, as well as have allother requirements complied with, at which time all wells in the Corvina fieldwould be placed into commercial production. Any delays in delivering orcommissioning re-injection equipment or delays in other permitting aspects mayforce us to keep our Corvina wells closed, until we are ready to transitionfrom exploration to exploitation, unless we obtain approval for extended welltesting and associated gas flaring for each well as required by Peruregulations.

 

Many of the Corvina oilwells have seen initial production declines rates of approximately 50% duringthe first year of production before stabilizing. Although each of the Corvinawells has declined differently, partly due to the fact that these wells werecompleted in different zones and some of the wells encountered mechanicalproblems, they have all initially shown typical solution gas drive behaviorwhich can lead to significant production declines during the first year beforeleveling off to sustainable rates. We believe these results are influenced bytechnical/mechanical problems encountered with our initial wells; however, itis possible we will see similar production declines with new Corvina wells. Therepresentative rates of production decline remain to be determined, because theeffective production mechanism in the Corvina field has yet to be fullyunderstood, hence the need to continue testing these initial wells. Further,our ability to produce indicated reserves in Corvina depends on our ability tofinance our continued operations, install the necessary gas and waterre-injection equipment and get our produced oil to market. While we do notforesee difficulties in meeting these requirements, any failure to do so couldnegatively affect our indicated reserves and their value as reported under SECrules. Therefore, in the evaluation of reserves, we attempt to account for allpossible delays we can reasonably predict and their impact on the production forecastand remaining reserves to be produced.

 

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***Albacora Field***

 

TheAlbacora field is located in the northern part of our offshore Block Z-1 innorthwest Peru.  The current area of interest within the Albacora field isa mapped structure of approximately 7,500 acres and is located in water depthsof less than 200 feet. In December 2009, we completed our first oil wellin the Albacora field, the A-14XD well, under a well testing program pursuantto the new regulations. The A-14XD well has an EWT and gas flaring permit validthrough mid-January 2011.

 

In January 2010, wecommenced drilling the A-15D well, the second Albacora well, which was to bedrilled to approximately 13,000 feet vertical depth and intended to testprospective sands below the lowest known oil sands tested or produced to datein the field. In mid-January 2010, we stopped oil production and drillingactivities in order to install certain production equipment on the Aplatform.  In February 2010, weresumed drilling of the A-15D well as well as resumed testing the A-14XD well.

 

In March 2010, whiledrilling the A-15D and preparing to run our 9 5/8” casing to the top of theZorritos formation, we found that the 13 3/8” casing section had been damaged,forcing us to abandon the well. The failure of the 13 3/8” casing wasapparently caused by the tilting of the drilling rig, which in turn wasevidently caused when one of the main beams supporting the top deck of theplatform bent due to the concentration of stresses at the base of the drillingrig.  The platform was temporarilyrepaired and subsequently, we began drilling the A-16D well, a follow up to theA-15D well, in April 2010.

 

TheA-16D well was originally intended to follow the same trajectory as the A-15Dwell with the same two targets and the same objectives.  However, in May 2010, due to the lack ofdrilling progress as a result of obstructions present under the seabed, weabandoned the A-16D.  Accordingly, in May 2010,we began drilling the A-17D well and in July 2010 permanent repairs to theA platform were completed.

 

Towardsthe end of September 2010, we completed the testing of the A-17D well anddeemed the well to be a dry hole. Because the target area of the A-17D well was an exploratory section ofthe Albacora field, we are writing-off the costs of this well as well as thecosts for two previously drilled wells, the A-15D and A-16D, as those wellswere intended to follow the same trajectory and reach the same location as theA-17D well but neither reached the target due to mechanical problems and bothwells were junked and abandoned. Accordingly, while we do not expect the resultof these wells to have a material impact, if any, on proved reserves inAlbacora as estimated by Netherland Sewell and Associates, Inc. (“NSAI”),we do believe they will result in a downward revision of the probable (“P2”)reserves while the possible (“P3”) reserves may not be materially impacted.

 

Consequentlywe have decided to suspend the drilling operations in the Albacora field untilwe conduct and complete a 3-D seismic survey of the area in order to betterdefine the position of future wells as well as to comply with our explorationcommitments under our license contracts. We are completing additionalgovernment requested environmental studies to obtain the permit to begin theseismic acquisition program. Current indications are that permits shouldbe granted and acquisition could begin in the first half of 2011. Duringthe drilling downtime, we will move forward to fabricate and install permanentproduction and injection facilities on the Albacora platform. This shouldallow for continued production testing from the field once drilling operationsresume by avoiding gas flaring and associated permitting issues.  Meanwhile, we have placed the rig at the Aplatform on standby until we are ready to commence drilling the onshoreexploration well in Block XIX.

 

Consistentwith our methodology for Corvina, we have requested our independent petroleumengineers, NSAI, to evaluate the reserves of the Albacora oil field using whatwe believe are reasonably conservative estimates of known uncertainties, suchas the scheduling for drilling and installation of necessary productionequipment and the time required to apply for and receive the necessaryregulatory permits. Thus, in evaluating our reserves, we conservativelyestimated these issues and their affects on potential production timetables.

 

*AlbacoraShort-Term Oil Sales Contracts*

 

In May 2010, we,through our wholly-owned subsidiary BPZ E&P, entered into a short-term 400MBbls oil supply agreement with Petroperu. Under the terms of the agreementPetroperu agrees to purchase up to 400 MBbls of crude oil productionoriginating from the Albacora oilfield in Block Z-1. The price per barrel ofoil under the agreement is determined using a basket of crude oils based on a15-day average of Forties, Oman, and Suez blend crude oil prices, as quoted inthe Spot Crude Prices Assessment published in Platt’s Crude Oilgram PriceReport, minus $3 per barrel and other customary purchase price adjustments. Aspart of the price adjustments we are allowed to sell oil under the contract aslong as the salt content is less than 25 pounds per thousand barrels ofoil.  There is no purchase priceadjustment associated with salt content if the salt content is less than 10pounds per thousand barrels.

 

InAugust 2010, we completed the installation of specialized oil desaltingequipment in order to supplement the chemical oil treatment process we areutilizing to allow us to sell oil under the requirement of the original 400MBbls oil sales contract with

 

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Petroperu.  Current indications are that the equipmentwill allow us to reduce the salt content level on current oil production tolevels acceptable under our oil sales contract with Petroperu.  In addition, we entered into separate smalleroil sales contracts with Petroperu in order to reduce the amount of Albacoraoil being stored on vessels as follows:

 

In July 2010 we,through our wholly-owned subsidiary BPZ E&P, entered into a secondshort-term 110 MBbls oil supply agreement with Petroperu. Under the terms ofthe agreement, Petroperu agrees to purchase the oil production originating fromthe Albacora oilfield in Block Z-1. The price per barrel of oil under the agreementuses the same basket of crude oils as the 400,000 barrel oil supply agreement,however, the per barrel price is minus $4.30 and other customary purchase priceadjustments. We are allowed to sell oil under the contract as long as the saltcontent is less than 60 pounds per thousand barrels of oil.  There is an incremental price adjustmentassociated with salt content if it is between 25 pounds and 60 pounds of saltper thousand barrels. All 110 MBbls is under this supply agreement weredelivered and sold to Petroperu during the month of July 2010.

 

In September 2010 we,through our wholly-owned subsidiary BPZ E&P, entered into a thirdshort-term 80 MBbls oil supply agreement with Petroperu. Under the terms of theagreement, Petroperu agrees to purchase the oil production originating from theAlbacora oilfield in Block Z-1. The price per barrel of oil under the agreementuses the same basket of crude oils as the 400,000 barrel oil supply agreement,however, the per barrel price is minus $4.30 and other customary purchase priceadjustments. We are allowed to sell oil under the contract as long as the saltcontent is less than 60 pounds per thousand barrels of oil.  There is an incremental price adjustmentassociated with salt content if it is between 25 pounds and 60 pounds of saltper thousand barrels. Approximately 50 MBbls under this supply agreement weredelivered and sold to Petroperu during the month of September 2010 and theremaining 30 MBbls was delivered during October 2010.

 

**FinancingActivities**

 

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

 

On September 15, 2009,we closed a private placement of approximately 1.6 million shares of commonstock, no par value, to the International Finance Corporation (“IFC”) pursuantto a Subscription Agreement dated September 15, 2009. This privateplacement was related to our registered direct offering of approximately 18.8million shares of common stock at a price of $4.66 per share that closed onJune 30, 2009. Pursuant to the Subscription Agreement datedDecember 16, 2006 (the “Subscription Agreement”) by and between IFC and us, IFChas the right, within 45 days of notice of an offering, to purchase shares ofour common stock for the same price and terms as the participants in theoffering to retain its proportionate ownership in us. IFC exercised itspre-emptive right to purchase approximately 1.6 million shares of common stockto which it was entitled under the Subscription Agreement, at the offeringprice of $4.66 per share, resulting in gross proceeds to us of approximately$7.6 million. In compliance with New York Stock Exchange (“NYSE”) requirements,the transaction was submitted to and approved by the shareholders of BPZ at aSpecial Meeting of Shareholders on August 24, 2009. No warrants ordilutive 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.

 

Under the September 15,2009 Subscription Agreement, we committed to file a registration statement withthe SEC covering the shares no later than 45 days after the closing withrespect to such shares, and used our reasonable best efforts to obtain itseffectiveness. On October 21, 2009, we filed a registration statement withthe SEC covering the shares. Subsequently, we received comments from the SECpertaining to our 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 as described below under “SEC Comments”. Wepromptly responded to the SEC’s requests. In May 2010, we filed an amendedregistration statement with the SEC and the amended registration statement wasdeclared effective later that month. No penalty payments were associated withthe delay in obtaining effectiveness of the registration statement.

 

**Gas-to-PowerProject**

 

Thegas-to-power project entails the installation of an approximately 10-mile gaspipeline from the CX-11 platform to shore, the construction of gas processingfacilities and a 135 megawatt (“MW”) simple-cycle power generation facility. The proposed power plant site is located adjacent to an existing substation andpower transmission lines which, after the Peruvian government completes itsexpansion, are expected to be capable of handling up to 320 MW of power. Theexisting substation and transmission lines are owned and operated by thirdparties.

 

In order to support ourproposed electric generation project, we commissioned an independent powermarket analysis for the region. The Peruvian electricity market is deregulatedand power is transported through an interconnected national grid managed by theCommittee for Economic Dispatching of Electricity (known as “COES”). Based onthis study, we believe we will be able to sell economic quantities ofelectricity from the initial 135 MW power plant. The market study alsoindicates that there may be future

 

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opportunities for us togenerate and sell significantly greater volumes of power into the Peruvian andpossibly Ecuadorian power markets.  Accordingly, the revenues from thenatural gas delivered to the power plant will be derived from the sale ofelectricity.

 

Wecurrently estimate the gas-to-power project will cost approximately $150.0million, excluding 19% value-added tax which will be recovered via future revenuebillings.  The $150.0 million includes $130.0 million for the estimatedcost of the power plant and $20.0 million for the natural gas pipeline. Whilewe have held initial discussions with several potential joint venture partnersfor the gas-to-power project, in an attempt to secure additional financing andother resources for the project, we have not entered into any definitiveagreements with a potential partner.  Inthe event we are able to identify and reach an agreement with a potential jointventure partner, we may only retain a minority position in the project.However, we expect to retain the responsibility for the construction andownership of the pipeline. If we are unable to identify and reach an agreementwith a potential partner, we plan to continue moving the project forward tocompletion without a partner. We are currently in the process of identifyingand securing the additional financing necessary to move the project forward. We are currently in discussions with afinancial institution to provide short term financing related to our turbineacquisitions. No firm agreements, offers or commitments are in place as wediscuss possible terms and conditions.

 

**SECComments**

 

In connection with aregistration statement filed on October 21, 2009 to register shares issuedto IFC in a private transaction during September 2009, we receivedcomments 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 questions orcomments from the SEC related 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 taking intoconsideration certain items and uncertainties for our 2009 reserves report. Wepromptly responded to the SEC’s requests and, where appropriate, madeclarifications to our disclosures. On April 14, 2010, the SEC notified usthat they had no further comments at that time.

 

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**Results ofOperations**

 

The following table setsforth revenues and operating expenses for the three and months ended September 30,2010 and 2009:

 
| ** **                                       | ** ** | **Three Months Ended**                                       | ** ** | ** **    | ** ** | **Nine Months Ended**                                        | ** ** | ** **    | ** ** |
|--------------------------------------------------|------------|------------------------------------------------------------------------|------------|---------------|------------|------------------------------------------------------------------------|------------|---------------|------------|
| ** **                                       | ** ** | **September 30,**                                                 | ** ** | **Increase/** | ** ** | **September 30,**                                                 | ** ** | **Increase/** | ** ** |
| ** **                                       | ** ** | **2010**                                                               | ** ** | **2009**      | ** ** | **(Decrease)**                                                         | ** ** | **2010**      | ** ** | **2009** | ** ** | **(Decrease)** | ** ** |
| ** **                                       | ** ** | **(in thousands except per bbl information)** | ** ** | ** **    | ** ** | **(in thousands except per bbl information)** | ** ** | ** **    | ** ** |
| Net sales volume:                                |       |                                                                   |       |          |       |                                                                   |       |          |       |   |   |   |   |
| Oil (MBbls)                                      |       | 399                                                                    |       | 207           |       | 192                                                                    |       | 1,046         |       | 744 |   | 302 |   |
|                                             | ** ** | ** **                                                             | ** ** | ** **    |       |                                                                   | ** ** | ** **    | ** ** | ** ** |   |   |   |
| Net revenue:                                     |       |                                                                   |       |          |       |                                                                   |       |          |       |   |   |   |   |
| Oil and condensate                               |       | $                                                                      | 26,688     |          | $          | 13,088                                                                 |       | $             | 13,600     |   | $ | 73,130 |   | $ | 37,362 |   | $ | 35,768 |   |
|                                             | ** ** | ** **                                                             | ** ** | ** **    |       |                                                                   | ** ** | ** **    | ** ** | ** ** |   |   |   |
| Average sales price (approximately):             | ** ** | ** **                                                             | ** ** | ** **    |       |                                                                   | ** ** | ** **    | ** ** | ** ** |   |   |   |
| Oil (per Bbl)                                    |       | $                                                                      | 66.84      |          | $          | 63.10                                                                  |       | $             | 3.74       |   | $ | 69.88 |   | $ | 50.21 |   | $ | 19.67 |   |
|                                             | ** ** | ** **                                                             | ** ** | ** **    |       |                                                                   | ** ** | ** **    | ** ** | ** ** |   |   |   |
| Operating expenses                               | ** ** | ** **                                                             | ** ** | ** **    |       |                                                                   | ** ** | ** **    | ** ** | ** ** |   |   |   |
| Lease operating expense                          |       | 10,967                                                                 |       | 9,591         |       | 1,376                                                                  |       | 21,309        |       | 21,445 |   | $ | (136 | ) |
| General and administrative expense               |       | 8,545                                                                  |       | 8,474         |       | 71                                                                     |       | 24,774        |       | 24,956 |   | (182 | ) |
| Geological, geophysical and engineering expense  |       | 6,113                                                                  |       | 297           |       | 5,816                                                                  |       | 7,016         |       | 1,195 |   | 5,821 |   |
| Dry hole costs                                   |       | 32,059                                                                 |       | —        |       | 32,059                                                                 |       | 32,059        |       | — |   | 32,059 |   |
| Depreciation, depletion and amortization expense |       | 6,659                                                                  |       | 5,881         |       | 778                                                                    |       | 24,193        |       | 19,267 |   | 4,926 |   |
| Other expense                                    |       | 12,738                                                                 |       | —        |       | 12,738                                                                 |       | 12,738        |       | — |   | 12,738 |   |
| Total operating expenses                         |       | $                                                                      | 77,081     |          | $          | 24,243                                                                 |       | $             | 52,838     |   | $ | 122,089 |   | $ | 66,863 |   | $ | 55,226 |   |
|                                             |       |                                                                   |       |          |       |                                                                   |       |          |       |   |   |   |   |
| Operating loss                                   |       | $                                                                      | (50,393    | )             | $          | (11,155                                                                | )          | $             | (39,238    | ) | $ | (48,959 | ) | $ | (29,501 | ) | $ | (19,458 | ) |

 

*NetRevenue*

 

For both the three and ninemonths ended September 30, 2010 and 2009, all oil sales were from oilproduced under the Peruvian well testing regulations.

 

For the three months ended September 30,2010, our net revenue increase by $13.6 million to $26.7 million from $13.1million for the same period in 2009. The increase in net revenue is due to anincrease in the amount of oil sold, 192 MBbls and an increase of $3.74, or 6%,in the average per barrel sales price received.

 

Forthe three months ended September 30, 2010, we had oil production from twoproducing wells in the Corvina field and one producing well in the Albacorafield compared to five producing wells in the Corvina field during the sameperiod in 2009. Total oil production for the three months ended September 30,2010 was 279 MBbls compared to 214 MBbls for the same period in 2009. Totalsales for the three months ended September 30, 2010 was 399 MBbls comparedto 207 MBbls for the same period in 2009.

 

Althoughthe number of wells contributing to production decreased in 2010 compared tothe same period in 2009, the wells contributing to oil production, the CX11-17Dand the A-14D wells have had continuous stable production during the quarter.Additionally the CX11-23D well was completed and put onto production in September 2010and has performed similarly to the A-14D and CX11-17D wells during its firstmonth of production. Although we had five producing wells during the threemonths ended September 30, 2009, oil production from the CX11-21XD and theCX11-15D wells were at various times and intervals partially or fully suspendeddue to workovers and maintenance of the wells.  The workovers andmaintenance programs were done to help resolve certain gas channeling and waterproduction issues encountered in the operation of the wells. The CX11-15Dproduced for approximately two of the three months in the period and theCX11-21XD produced for approximately one of the three months in the period.

 

Forthe three months ended September 30, 2010, the oil sales of 399 MBblsincreased over both prior years’ quarter sales of 207 MBbls and current quarteroil production, 279 MBbls, due to sales of the Albacora oil in storage to theTalara refinery under short-term oil sales contracts with Petroperu.

 

For the nine months endedSeptember 30, 2010, our net revenue increased by $35.8 million to $73.1million from $37.4 million for the same period in 2009. The increase in netrevenue is due to an increase of $19.67, or 39%, in the average per barrelsales price received and an increase in the amount of oil sold, 302 MBbls.During the nine months ended September 30, 2010, oil prices

 

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have remained consistent at$70 - $80 per barrel compared to steadily increasing prices in 2009, which rosesteadily from $34 -$74 per barrel.

 

Forthe nine months ended September 30, 2010, we had partial to full oilproduction from eight producing wells in the Corvina field and one producingwell in the Albacora field compared to five producing wells in the Corvinafield during the same period in 2009. Total oil production for the nine monthsended September 30, 2010 was 1,113 MBbls compared to 779 MBbls for thesame period in 2009. Total sales for the nine months ended September 30,2010 was 1,046 MBbls compared to 744 MBbls for the same period in 2009.

 

Althoughwe suspended oil production from five of our wells as required under theextended well testing regulation in May 2010 and the CX11-19D well in June 2010,we have been able to produce more oil than during the same period in 2009.  During the nine months endedSeptember 30, 2009, each of our five wells had stopped production for oneto two months for workovers and maintenance.

 

Weare currently planning to have all the required Corvina gas and waterre-injection equipment in place by November 30, 2010, as well as have allother requirements complied with, at which time all wells in the Corvina fieldwould be placed into commercial production. Although we plan to request additionalEWT and gas flaring permits for all wells completed in the Albacora field untilthe appropriate gas and water re-injection facilities are installed andoperational, there can be no assurance that the Ministry of Energy and Mineswill grant approval of these permits or any future EWT permits requested by us.Under the current Peruvian well testing regulation, new wells may be tested fora period of six months. Testing of these wells beyond the initial six monthperiod will require application to the Ministry of Energy and Mines, which maynot grant approval. We may also be required to obtain corresponding gas flaringpermits from the DGH, which may not grant them.

 

The revenues above arereported net of royalties owed to the government of Peru. Royalties areassessed by Perupetro as stipulated in the Block Z-1 license agreement based onproduction levels. However, the royalty calculation is based on the priorfive-day average of a blend of crude oil prices before the crude oil deliverydate, as opposed to the price we receive for oil which is based on the priortwo-week average of a blend of crude oil prices before the crude oil deliverydate. For both the three and nine months ended September 30, 2010, therevenues received by us are net of royalty costs of approximately 5% of grossrevenues or $1.7 million and $4.3 million, respectively. For the same periodsin 2009, the revenues received by us are net of royalty costs of approximately5% of gross revenues or $0.7 million and $2.1 million, respectively.

 

*LeaseOperating*

 

Lease operating expensesinclude costs incurred to operate and maintain wells and related equipment andfacilities. These costs include, among others, workover expenses, operatorfees, processing fees, insurance and transportation.  For the three months ended September 30,2010, lease operating expenses increased by $1.4 million to $11.0 million($27.47 per Bbl) from $9.6 million ($46.24 per Bbl) for the same period in2009. The increase in the lease operating expenses is due to increases in suppliesused in operations of $0.4 million, increased equipment rental expense of $0.1million, increased crude oil transportation costs of $0.6 million, increasedlab fees of $0.3 million, increased contract labor of $0.1 million, increasedrepair and maintenance expenses of $1.1 million, increased fuel costs of $0.7million, increased insurance and other costs of $0.2 million and increasedexpenses transferred from oil inventory of $2.6 million.  Partially offsetting these increases toexpense are decreases in workover expenses of $4.9 million.

 

For the three months ended September 30,2010, the reason for the increase in expenses other than workover costs is thatwe are operating in two fields in 2010, while we were operating only one fieldduring the same period in 2009.  Withrespect to workovers, during the three months ended September 30, 2010, weperformed two workovers on the CX11-19D and the CX11-22D wells for a total costof $0.8 million.  During the same periodin 2009, we performed three workovers related to the CX11-20XD, CX11-21XD andCX11-15D wells for $5.7 million. The reason for the decrease in the per Bblamounts at September 30, 2010 compared to September 30, 2009 is dueto increased sales.

 

For the nine months endedSeptember 30, 2010, lease operating expenses slightly decreased by $0.1million to $21.3 million ($20.36 per Bbl) from $21.4 million ($28.82 per Bbl)for the same period in 2009. The decrease in lease operating expenses is due todecreased workover expenses of $6.5 million and increased expenses transferredto oil inventory of $0.9 million. Partially offsetting these decreases to expense are increases inexpenses related to supplies of $0.7 million, increased equipment rentalexpense of $0.3 million, increased crude oil transportation costs of $2.6million, increased contract labor charges of $0.1 million, increased lab feesof $0.6 million, increased maintenance and barge repairs of $0.4 million,increased pumping service costs of $0.2 million, increased fuel costs of $1.9million and increased other expenses of $0.4 million.

 

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For the nine months ended September 30,2010, the reason for the increase in expenses other than workover costs is thatwe are operating in two fields in 2010, while we were operating only one fieldduring the same period in 2009.  Withrespect to workovers, during the nine months ended September 30, 2010, weperformed four small workovers on four wells for a total cost of $2.0million.  During the same period in 2009,we performed three workovers related to the CX11-20XD, CX11-21XD and CX11-15XDwells for $8.5 million. The reason for the decrease in the per Bbl amounts at September 30,2010 compared to September 30, 2009 is due to increased sales.

 

*Generaland Administrative*

 

General and administrativeexpenses are overhead-related expenses, including employee compensation, legal,consulting and accounting fees, insurance, and investor relations expenses.

 

For the three months endedSeptember 30, 2010, general and administrative expenses remained flat at$8.5 million from $8.5 million for the same period in 2009.  Stock-basedcompensation expense, a subset of general and administrative expenses,decreased by $1.5 million to $1.4 million for the three months endedSeptember 30, 2010 from $2.9 million for the same period in 2009. Thedecrease in stock-based compensation expense is due to the vesting of themajority of awards granted in 2007 and 2008, which were granted at times whenthe grant date fair value of the awards was higher due to the high price of ourcommon stock. Other general and administrative expenses increased $1.5 millionto $7.1 million from $5.6 million for the same period in 2009. The $1.5 millionincrease is due to increased salary and salary related expenses of $0.9million, increased travel and travel related expenses of $0.3 million andincreased professional fees of $0.3 million.

 

For the three months endedSeptember 30, 2010, the increase in salary and salary related expensesresults from increased profit sharing expense, increase salary and salaryrelated expenses as result of (1) salary reinstatements in 2010 that werevoluntarily reduced in 2009 for certain executives and other key personnel; and(2) an increase in salary and salary related expenses as a result ofannual salary increased awarded during the three months ended September 30,2010 and an increase in the number of employees in 2010 compared to the sameperiod in 2009. The $0.3 million of increase in professional fees is due to$0.8 million increased reserve engineering analysis and consulting for vesselleasing activities and increased reserve engineering analysis for two fields in2010, increased consulting for employee recruiting and increased consulting forcommunity service relationship programs. Partially offsetting the increase inprofessional fees are $0.5 million of reduced legal fees.

 

For the nine months endedSeptember 30, 2010, general and administrative expenses decreased $0.2million to $24.8 million from $25.0 million for the same period in 2009. Stock-based compensation expense, a subset of general and administrativeexpenses, decreased by $5.2 million to $4.7 million for the nine months endedSeptember 30, 2010 from $9.9 million for the same period in 2009. Thedecrease in stock-based compensation expense is due to the decrease in fairmarket value of awards granted in 2010 as a result of the decline in the stockprice of BPZ and we are no longer recognizing as much stock compensationexpense as a result of awards granted in previous years, with high grant datefair values, as these awards have vested. Also contributing to the decrease instock based compensation is approximately $0.7 million of stock-basedcompensation expense related to the accelerated vesting for certain restrictedstock and stock option awards granted to a former member of the Board ofDirectors and that occurred during the second quarter of 2009, which did notoccur during 2010. Other general and administrative expenses increased $5.1million to $20.1 million from $15.0 million for the same period in 2009. The$5.1 million increase is due to increased salary and salary related expenses of$2.9 million, increased professional fees of $1.3 million, increasedmaintenance and repair expense of $0.4 million, increased rent expense of $0.5million, increased travel and travel related expenses of $0.5 million andincreased training and development costs of $0.1 million. Partially offsettingthese increases are decreases in equipment rental charges of $0.3 million anddecreased bank fees of $0.3 million.

 

For the nine months endedSeptember 30, 2010, the increase in salary and salary related expensesresults from an aggregate bonus of $1.3 million awarded to certain executiveand other key personnel during the second quarter of the current year with nocorresponding bonuses awarded during the same periods in 2009, increased profitsharing expense, increase salary and salary related expenses as result of (1) salaryreinstatements in 2010 that were voluntarily reduced in 2009 for certainexecutives and other key personnel; and (2) an increase in salary andsalary related expenses as a result of annual salary increased awarded duringthe three months ended September 30, 2010 and an increase in the number ofemployees in 2010 compared to the same period in 2009. The $1.3 million ofincrease in professional fees is due to $1.7 million increased reserveengineering analysis and consulting for vessel leasing activities and increasedreserve engineering analysis for two fields in 2010, increased consulting foremployee recruiting and increased consulting for community service relationshipprograms. Partially offsetting the increase in professional fees are $0.4million of reduced legal fees. The increase in maintenance and repair expenseis due to operating more vessels and equipment in the current year compared tothe same period in prior year. The increase in rent expense is due to therental of new office space for our Peru office in the current year.  The decrease in equipment rental expense isdue renting less equipment in the current year. The decrease in bank fees is due to improved payments and fess feesincurred in the current year compared to the same period in prior year.

 

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*Geological,Geophysical and Engineering*

 

Geological, geophysical andengineering expenses include laboratory, environmental and seismic acquisitionrelated expenses. For the three months ended September 30, 2010,geological, geophysical and engineering expenses increased $5.8 million to $6.1million compared to $0.3 million for the same period in 2009. For the ninemonths ended September 30, 2010 and 2009, geological, geophysical andengineering expenses increased $5.8 million to $7.0 million compared to $1.2million for the same period in 2009.

 

For both the three and ninemonth period ended September 30, 2010, the reason for the increase ingeological, geophysical and engineering expense is due to $5.8 million ofseismic acquisition expenses related to our seismic data acquisition plan forBlock XXIII which is expected to be completed during the first quarter of 2011.During the same period in 2009, we did not incur a significant amount of costsrelated to seismic acquisition.

 

*Dry HoleCosts*

 

Forboth the three and nine months ended September 30, 2010, we wrote-off$17.2 million of exploratory dry hole costs related to the A-17D well inthe Albacora field which, in September 2010, was determined to have nocommercial quantities of hydrocarbons and was abandoned.  In addition, we wrote-off $14.9 million ofsuspended well costs for two previously drilled wells, the A-15D and A-16D, asthose wells were intended to follow the same trajectory and reach the samelocation as the A-17D well but neither reached the target due to mechanicalproblems and both wells were junked and abandoned.  There were no similar expenses for the sameperiods in 2009.

 

*Depreciation,Depletion and Amortization*

 

For the three months endedSeptember 30, 2010, depreciation, depletion and amortization expenseincreased $0.8 million to $6.7 million from $5.9 million for the same period in2009. For the nine months ended September 30, 2010, depreciation,depletion and amortization expense increased $4.9 million to $24.2 million from$19.3 million for the same period in 2009.

 

For the three months endedSeptember 30, 2010, approximately half of depletion expense came from oilsold from the Albacora field and half came from oil originating from theCorvina field.  During the same period in2009, all of the depletion expense came from oil sales originating from theCorvina field. As the depletion rate for the Albacora field is less than thatof the Corvina field, depreciation, depletion and amortization increased byonly 13% while the number of barrels sold increased 93%.

 

For the nine months endedSeptember 30, 2010, approximately 75% of depletion expense came from oilsold from the Corvina field and approximately 25% came from oil sold from theAlbacora field. During the same period in 2009, all of the depletion expensecame from oil sales originating from the Corvina field. For the nine monthsended September 30, 2010, the increase in depreciation, depletion andamortization expense is due to increased sales and production compared to thesame period in 2009.  As the depletionrate for the Albacora field is less than that of the Corvina field,depreciation, depletion and amortization increased by only 26% while the numberof barrels sold increased 41%.

 

For both the three and ninemonths ended September 30, 2010, contributing to depletion expense is anegative revision due to the result of a reduction in the reserve base in 2009that is partially offset by a decrease in the average costs being amortized asthe newer wells being brought onto production have cost less to drill andcomplete than the previous wells. The 2009 reserve analysis as prepared by NSAIincluded a 1.6 MMBbls negative revision in reserves due to the lower thanexpected performance of the CX11-14D, CX11-18XD, and CX11-20XD wells.

 

*OtherExpense*

 

Duringthe three and nine months ended September 30, 2010, we are reporting$12.7 million of charges as “Other expense”. These charges include$10.7 million of charges related to certain engineering, consulting,environmental and legal costs for our planned gas plant, pipeline and gas-to-powerproject and $2.0 million of charges related to the abandonment of twoplatforms. With respect to the $10.7 million of charges related to the plannedgas plant, pipeline and gas-to-power project, during the third quarter of 2010,management determined that there is no future benefit of these engineering anddevelopment costs associated with our current gas plant, pipeline andgas-to-power project plans.  Accordingly, we have decided to write-offthese costs. With respect to the $2.0 million of platform abandonment costs, wehave determined that two previously built platforms, one located in the PiedraRedonda field and the CX-13 platform located in the eastern part of the Corvinafield, both of which were in existence when we acquired the rights to the offshoreBlock Z-1 in northwest Peru, are not suitable for our future oil developmentplans. Accordingly, we are writing-off the $1.2 million costs incurred toevaluate the feasibility of refurbishing and using these platforms. Inaddition, we are accruing $0.8 million of abandonment costs related to thePiedra Redonda platform as we are obligated to ensure the platform does notcause a threat to marine vessels operating in the area or marine wildlife.There were no similar expenses for the same periods in 2009.

 

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*OtherIncome (Expense)*

 

For the three months endedSeptember 30, 2010, income from our investment in Ecuador property, net ofinvestment amortization, increased by $0.1 million to income of $0.3 millionfrom income of $0.2 million in 2009.  Forthe nine months ended September 30, 2010, income from our investment inEcuador property, net of investment amortization, increased by $0.5 million toincome of $0.6 million from income of $0.1 million in 2009. For the three andnine months ended September 30, 2010, we received payments of $0.4 millionand $0.8 million, respectively, from our investment.  During both the three and nine months ended September 30,2009, we received payments of $0.2 million. For both the three and nine months ended September 30, 2010 and2009, investment income / (expense) includes amortization expense ofapproximately $47,000 and $141,000, respectively.

 

Forthe three months ended September 30, 2010, we recognized approximately$2.8 million of net interest expense which includes $5.3 million of interestexpense reduced by $2.5 million of capitalized interest expense. For the sameperiod in 2009, we did not recognize any interest expense as we capitalized allinterest expense of $1.2 million to construction in progress. For the ninemonths ended September 30, 2010, we recognized approximately $8.5 millionof net interest expense which includes $15.4 million of interest expensereduced by $6.9 million of capitalized interest expense. For the same period in2009, we did not recognize any interest expense as we capitalized all interestexpense of $3.3 million to construction in progress.  For both the three and nine months endedSeptember 30, 2010, the increase in interest expense is due to the $170.9million of 2015 Convertible Notes issued in the current year.

 

For the three months endedSeptember 30, 2010, interest income decreased by $0.1 million to income of$0.1 million from income of $0.2 million in 2009.  For the nine months ended September 30,2010, interest income remained relatively flat at $0.2 million compared to thesame period in 2009.

 

For the both the threemonths ended September 30, 2010 and 2009, other expense was not material.For the nine months ended September 30, 2010, other expense decreased by$1.3 million to income of approximately $30,000 from an expense of $1.2 millionin 2009. The reason for the decrease in other expense is due to approximately$1.3 million of expense incurred in 2009 that was not repeated in 2010.Approximately $0.8 million of the $1.3 million was incurred during the firstquarter of 2009 and related to the settlement of a disputed contractual obligationwith a former consultant concerning services provided to both BPZ and itspredecessor at the time BPZ became publicly traded.  An additional $0.4 million of the $1.3million was recognized during the second quarter of 2009 and relates to stockoptions awarded to a former member of the Board of Directors that wasrecognized upon issuance of the award.

 

*IncomeTaxes*

 

Forthe three and nine months ended September 30, 2010, we recognized anincome tax benefit of approximately $9.1 million and $7.0 million, respectively,on a net loss before income tax of approximately $52.8 million and $56.7million, respectively. For the same periods in 2009, we recognized an incometax benefit of approximately $1.8 million and $4.7 million, respectively, on anet loss before income tax of approximately $10.8 million and $30.5 million,respectively. The difference between the effective tax rate recognized and the22% statutory rate provided for under the Block Z-1 License Contract is due to:

 

·                  We have a 100%allowance on our net operating losses generated in the United States - We havea valuation allowance for the full amount of the domestic deferred tax assetresulting from the income tax benefit generated from net losses in the U.S., 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 2027.

 

·                  Certain U.S.expenses are not deductible in Peru - The tax benefit is based on a taxablePeruvian loss that excludes certain U.S. expenses that are not deductible atthe Peruvian level.

 

·                  The increase inour deferred tax asset balance is primarily due to the inability to deduct, forPeruvian income tax purposes, the amortization associated with our totalinvestment, including both intangible drilling as well as exploration costsassociated with Block Z-1.  As a result,we are subject to tax prepayments on a taxable income even though we incurred abook loss.  This will continue until wetransition into the commercial stage of production as defined under the BlockZ-1 License Contract.

 

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. For both the three and nine months endedSeptember 30, 2010 and 2009, we did not have any accrued interest orpenalties associated with any unrecognized tax benefits, nor was any interestexpense recognized during those periods.

 

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For the three months endedSeptember 30, 2010, our net loss increased $34.7 million to a net loss of$43.7 million or ($0.38) per basic and diluted share from net loss of $9.0million or ($0.08) per basic and diluted share for the same period in 2009. Forthe nine months ended September 30, 2010, our net loss increased $23.9million to $49.7 million or ($0.43) per basic and diluted share from $25.8million or ($0.26) per basic and diluted share for the same period in 2009.

 

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**Liquidity, CapitalResources and Capital Expenditures**

 

At September 30, 2010,we had cash and cash equivalents of $52.9 million and current accountsreceivable related to our September oil sales of $14.5 million, all ofwhich was collected in October 2010. We also had $31.0 million in thecurrent portion of our value-added tax receivable, which we will collect overtime as we invoice our oil sales.

 

AtSeptember 30, 2010, we had trade accounts payable and accrued liabilitiesof $52.7 million.

 

AtSeptember 30, 2010, our outstanding long-term debt and short-term debtconsisted of a $15.0 million IFC Facility bearing interest at LIBOR plus 2.75%due December 31, 2012 and 2015 Convertible Notes whose net amount of$139.4 million includes the $170.9 million of principal reduced by $31.5million of the remaining unamortized discount. At September 30, 2010, thecurrent and long-term portions of our capital lease obligations, primarily relatedto the barges used in our marine operations were $4.3 million and $4.3 million,respectively.

 
| ** **                  | ** ** | **For the Nine Months Ended** | ** ** |
|-----------------------------|------------|---------------------------------------------------|------------|
| ** **                  | ** ** | **September 30,**                            | ** ** |
| **Cash Flows**         | ** ** | **2010**                                          | ** ** | **2009** | ** ** |
| ** **                  | ** ** | **(in thousands)**                           | ** ** |
| Cash provided by (used in): |       |                                              |       |   |   |
| Operating activities        |       | $                                                 | (11,297    | ) | $ | (25,208 | ) |
| Investing activities        |       | (114,287                                          | )          | (50,256 | ) |
| Financing activities        |       | 160,353                                           |       | 136,798 |   |
|                             |            |                                                   |            |  |  |  |  |

 

*Operating Activities*

 

Cash used in operatingactivities decreased by $13.9 million to a use of cash of $11.3 million for thenine months ended September 30, 2010 from a use of cash of $25.2 millionfor the same period in 2009. The change in cash flow before changes inoperating assets and liabilities increased by $15.1 million as a result ofhigher non-cash charges during 2010 compared to 2009. Changes in operatingassets and liabilities provided a use of cash of $1.2 million.  The increase in the use of cash is due to:(1) decrease in the change in accounts receivable due to the timing of oildeliveries and payments of those deliveries, $16.9 million; (2) increasein the change of prepaid and other assets to secure additional pipe, casing andaccessories, $5.0 million; (3) decrease in the change to other liabilitiesbalances due the timing of payments of certain Peruvian taxes, $0.5 million.  Offsetting these uses of cash are changes inoperating assets and liabilities providing sources of cash including:(1) increase in the change of taxes payables as a result of increasedrevenues, $9.6 million; (2) increases in the change to accounts payablesand other current liabilities, $8.2 million; and (3) decrease in thechange to value-added taxes and inventory as we had less expenses subject toVAT and used less inventory in 2010 compared to the same period in 2009, $3.3million.

 

*Investing Activities*

 

Netcash used in investing activities increased by $64.0 million to cash usedin investing activities of $114.3 million for the nine months endedSeptember 30, 2010 from $50.3 million in 2009.  The increase is due to increased capitalexpenditures of $64.4 million in 2010 as our operations included two fields in2010, the Corvina and Albacora fields, as opposed to operating only one fieldduring the same period in 2009, the Corvina field. Also contributing to thechange in investing activities are changes in restricted cash providing a useof cash of $0.3 million.

 

*2010Equipment Activity*

 

During the nine months ended September 30, 2010, weincurred net capital expenditures of approximately $73.0 millionassociated with our development initiatives for the exploration and productionof oil and natural gas reserves and the complementary development of aproprietary gas-fired power generation facility in Peru.

 

Of the costs mentionedabove, we incurred capital expenditures related to the drilling and testing ofthe CX11-15D, CX11-23D, CX11-17D and CX11-22D wells in the Corvina field ofapproximately $0.5 million, $12.9 million, $7.4 million and $19.5 million,respectively. In the Albacora field, we incurred capital expenditures relatedto the drilling of the A-15D, A-16D and A-17D of approximately $8.4 million,$6.5 million and $17.2 million, respectively. During the three months ended September 30,2010, the costs of the A-17D well were written-off as dry hole costs as well asthe costs for two previously drilled wells, the A-15D and A-16D, as those wellswere intended to follow the same trajectory and reach the same location as theA-17D well but neither reached the target due to mechanical problems and bothwells were junked and abandoned.

 

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In 2009, we entered into alease-purchase agreement to acquire the Don Fernando barge to serve as ourconstruction lay barge, as well as tender assist barge for drilling andconstruction operations, and it may be fitted to lay subsea pipe for thegas-to-power project.  During the ninemonths ended September 30, 2010, we capitalized an additional $3.0 millionin order to have the barge ready to support its operations.

 

For the further developmentof the planned gas-fired power generation facility, we incurred costs ofapproximately $11.9 million as part of its agreement to purchase three LM 6000gas-fired turbines.

 

For the nine months ended September 30,2010, we incurred approximately $2.6 million for upgrades to our existingplatforms as well as costs incurred in the construction of new platforms. Inaddition, we incurred $6.8 million in equipment for our production facilitiesat the A platform in Albacora and the CX-11 platform in Corvina. We incurred$10.4 million for the purchase of machinery and equipment used in operations inPeru, $0.4 million for the Caleta La Cruz dock refurbishment, $0.3 million inassets in transit, $0.5 million in furniture and improvements related to thenew offices in Peru, $0.6 million in other barge improvements and $0.3 millionrelated to the asset retirement obligation for the CX11-17D, CX11-22D andCX11-23D wells.

 

For the three and ninemonths ended September 30, 2010, we wrote-off approximately $11.9 millionof property and equipment associated with its gas-to-power project and certaincosts for the abandonment of two platforms.

 

Forthe three and nine months ended September 30, 2010, in accordance with the“successful efforts” method of accounting, we capitalized approximately $0.6million and $1.5 million of depreciation expense, respectively, mainly relatedto the tender assist barges serving as support equipment, and $2.5 million and$6.9 million of interest expense, respectively, to construction in progress.For the same periods in 2009, we capitalized approximately $0.4 million and$1.1 million of depreciation expense, respectively, and $1.2 million and $3.3million of interest expense, respectively, to construction in progress.

 

For the three and ninemonths ended September 30, 2010, we recognized $6.7 million and $24.2million of depreciation, depletion and amortization expense, respectively. Forthe same periods in 2009, we recognized $5.9 million and $19.3 million ofdepreciation, depletion and amortization expense, respectively.

 

*FinancingActivities*

 

Cash provided by financingactivities increased by $23.6 million to $160.4 million for the nine monthsended September 30, 2010 comparedto $136.8 million for the same period in 2009. The increase in cash provided byfinancing activities is due to increased borrowings of $164.4 million and lowerrepayments of borrowings of $0.4 million that is partially offset by anincrease in cash paid for debt issue costs of $6.1 million and a lesser amountof cash raised through equity issuances in 2009 of $135.1 million.

 

*ShelfRegistration*

 

To finance our operations wemay sell additional shares of our common stock. Our certificate of formationdoes not provide for pre-emptive rights, although we may grant similar rightsby contract from time to time. We currently have approximately $134.6 millionin common stock available under an effective shelf registration statement,which we may sell from time to time in one or more offerings pursuant tounderwritten public offerings, negotiated transactions, block trades or acombination of these methods. This registration statement is set to expire onDecember 7, 2010.

 

*Long-TermDebt and Capital Lease Obligations*

 

At September 30, 2010 and December 31,2009, long-term debt and capital lease obligations consisted of the following:

 
| ** **                                                                            | ** ** | **September 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|---------------------------------------------------------------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                                                                            | ** ** | **(in thousands)**      | ** ** |
|                                                                                  |       |                         |       |                        |       |
| $15 million IFC Senior Note, Libor plus 2.75%, due  2012                              |       | $                            | 15,000     |                        | $          | 15,000 |   |
| $170.9 million Convertible Notes, 6.5%, due 2015,  net of discount of ($31.5) million |       | 139,428                      |       | —                      |       |
| Capital Lease Obligations                                                             |       | 8,594                        |       | 11,910                      |       |
| Other                                                                                 |       | —                       |       | 1,023                       |       |
|                                                                                  |       | 163,022                      |       | 27,933                      |       |
| Less: Current Portion of Long-Term Debt and Capital  Lease Obligations                |       | 9,285                        |       | 5,352                       |       |
|                                                                                  |       | $                            | 153,737    |                        | $          | 22,581 |   |

 

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*$170.9million Convertible Notes due 2015*

 

In February andMarch 2010, we closed on the private offering for an aggregate $170.9million convertible notes due 2015 (the “2015 Convertible Notes”). The 2015Convertible Notes offering was comprised of (i) the initial $140.0 millionof 2015 Convertible Notes sold in an initial private offering, (ii) theexercise, by the initial purchaser, of a 30-day option to purchase anadditional $21.0 million of 2015 Convertible Notes, and (iii) IFC’selection to participate in the offering, pursuant to a contractual right, foran additional $9.9 million of 2015 Convertible Notes, bringing the totalproceeds of the private offering to $170.9 million. The 2015 Convertible Noteswere sold to an initial purchaser who then sold the notes to qualifiedinstitutional buyers pursuant to Rule 144A of the Securities Act of 1933.The $170.9 million of 2015 Convertible Notes were issued pursuant to anindenture dated February 8, 2010, between us and Wells Fargo Bank,National Association, as trustee (“the Indenture”).

 

The 2015 Convertible Notesare general senior unsecured obligations and rank equally in right of paymentwith all of our other existing and future senior unsecured indebtedness. The 2015 Convertible Notes are effectively subordinate to all of oursecured indebtedness to the extent of the value of the assets collateralizingsuch indebtedness.  The 2015 Convertible Notes are not guaranteed by oursubsidiaries.

 

We will pay interest on the2015 Convertible Notes at a rate of 6.50% per year on March 1st andSeptember 1st of each year, beginning on September 1,2010.  The 2015 Convertible Notes mature on March 1, 2015. Theinitial conversion rate is 148.3856 shares per $1,000 principal amount of the2015 Convertible Notes (equal to an initial conversion price of approximately$6.74 per share of common stock), subject to adjustment. Upon conversion, wemust deliver, at our option, either (1) a number of shares of our commonstock determined as set forth in the Indenture, (2) cash, or (3) acombination of cash and shares of our common stock (but not to exceed 19.99% ofour outstanding shares at the time of such delivery).

 

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

 

Holders may convert their2015 Convertible Notes at their option at any time prior to the close ofbusiness on the second business day immediately preceding the maturity dateunder the following circumstances:

 

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

 

(2) prior to January 1,2015, during the five business-day period after any ten consecutive trading-dayperiod in which the trading price of $1,000 principal amount of the 2015Convertible Notes for each trading day in the measurement period was less than97% of the product of the last reported sale price of our common stock and theconversion rate on such trading day;

 

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

 

(4) upon the occurrenceof one of the specified corporate transactions. Holders may also convert the2015 Convertible Notes at their option at any time beginning onFebruary 1, 2015, and ending at the close of business on the secondbusiness day immediately preceding the maturity date.

 

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

 

If we experience any one ofthe certain specified types of corporate transactions, holders may require usto purchase 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.

 

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The Indenture containscustomary terms and covenants and events of default. If an event of default (asdefined therein) occurs and is continuing, the Trustee by notice to us, or theholders of at least 25% in aggregate principal amount of the 2015 ConvertibleNotes then outstanding by notice to us and the Trustee, may declare theprincipal and accrued and unpaid interest (including additional interest orpremium, if any) on the 2015 Convertible Notes to be due and payable. In thecase of an event of default arising out of certain bankruptcy events (as setforth in the Indenture), the principal and accrued and unpaid interest(including additional interest or premium, if any), on the notes willautomatically become due and payable.

 

Net proceeds from the saleof the 2015 Convertible Notes, after deducting the discounts and commissionsand any offering expenses payable by us, was approximately $164.9million.  The initial purchaser received commissions of approximately $5.5million in connection with the sale of the 2015 Convertible Notes and weincurred approximately $0.6 million of direct expenses in connection with theoffering.  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.

 

Asa result of our adoption of the new accounting standard for convertible debtthat may be settled in cash upon conversion, we are required to separatelyaccount for the liability and equity components in a manner that reflects ournon-convertible borrowing rate when interest cost is recognized in subsequentperiods. The value assigned to the liability component is determined bymeasuring the fair value of a similar liability that does not have an equityconversion feature. The value assigned to the equity component is determined bydeducting the fair value of the liability component from the initial proceeds.The excess of the principal amount of the liability component over its carryingamount (the non-cash discount) is amortized to interest expense using theeffective interest method over the term of the debt agreement. In addition,transaction costs incurred that directly relate to the issuance of convertibledebt instruments must be allocated to the liability and equity components inproportion to the allocation of proceeds and accounted for as debt issuancecosts and equity issuance costs, respectively. The accounting standard requiresretrospective restatement of all periods presented back to the date of debtissuance with a cumulative effect of the change in accounting principle on allprior periods being recognized as of the beginning of the first period.

 

Weestimated our non-convertible borrowing rate at the date of issuance of our2015 Convertible Notes to be 12%.  The12% non-convertible borrowing rate represents the borrowing rate of similarcompanies with the same credit quality as ours and was obtained through a quotefrom the initial purchaser. Using the income method and discounting theprincipal and interest payments of the 2015 Convertible Notes using the 12%non-convertible borrowing rate, we estimated the fair value of the $170.9million 2015 Convertible Notes to be approximately $136.3 million with thediscount being approximately $34.6 million. The discount will be amortized asnon-cash interest expense into income over the life of the notes using theinterest method. In addition, we recorded approximately $4.8 million of the$6.1 million of fees and commissions as debt issue costs that will be amortizedover time using the interest method as interest expense. The remaining $1.3million of fees and commissions will be treated as an original issue discountagainst the value of the equity component. We estimate the cash paymentsrelated to the 2015 Convertible Notes, assuming no conversion, for the yearsended 2010, 2011, 2012, 2013, 2014 and thereafter to be approximately $6.3 million,$11.1 million, $11.1 million, $11.1 million, $11.1 million and $176.5 million,respectively.

 

Asof September 30, 2010, the net amount of $139.4 million includes the$170.9 million of principal reduced by $31.5 million of the remainingunamortized discount. The net amount of the equity component is $33.3 millionwhich includes the initial discount of $34.6 million reduced by $1.3 million ofdirect transaction costs. The remaining unamortized discount of $31.5 millionwill be amortized into interest expense, using the effective interest method,over the remaining life of the loan agreement, whose term expires inMarch 2015.  At September 30,2010, using the current conversion rate of 148.3856 shares per $1,000 principalamount of the 2015 Convertible Notes, if the $170.9 million of principal wereconverted into shares of common stock, the notes would convert into 25,364,737shares of common stock.  In accordancewith NYSE rules, we received shareholder approval to issue shares in excess of19.99% of shares outstanding at the time of the offering (23,031,663 shares)should we need to issue shares in order to satisfy our obligation under the2015 Convertible Notes.  As ofSeptember 30, 2010, there is no excess if-converted value to the holdersof the 2015 Convertible Notes as the price of our common stock atSeptember 30, 2010, $3.83 per share, is less than the conversion price.

 

Forboth the three and nine months ended September 30, 2010, the effectiveinterest rate for the 2015 Convertible Notes is 12%; including the amortizationof debt issue costs, the effective interest rate is 12.6%.

 

Theamount of interest expense related to 2015 Convertible Notes for the threemonths ended September 30, 2010 is $4.3 million, disregarding capitalizedinterest considerations, and includes $2.8 million of interest expense relatedto the contractual interest coupon, $1.3 million of non-cash interest expenserelated to the amortization of the discount and $0.2 million of interestexpense related to the amortization of debt issue costs.  There were no similar expenses for the sameperiod in 2009.

 

Theamount of interest expense related to 2015 Convertible Notes for the ninemonths ended September 30, 2010 is $10.9 million, disregarding capitalizedinterest considerations, and includes $7.3 million of interest expense relatedto the contractual interest

 

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coupon,$3.1 million of non-cash interest expense related to the amortization of thediscount and $0.5 million of interest expense related to the amortization ofdebt issue costs.  There were no similarexpenses for the same period in 2009.

 

*$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 matures in December 2012.

 

The reserve-based lendingfacility bears interest at an approximate rate of LIBOR plus 2.75%, currentlyequivalent to 3.5% based on the six month LIBOR rate of 0.75% at June 30,2010.  The maximum amount available under this facility begins at $15.0 millionand will be reduced by $2.5 million beginning on December 16, 2010 andevery six months thereafter during the term of the Loan Agreement.  Theamount available under the Loan Agreement is subject to a semi-annual borrowingbase determination based on the value of oil reserves.  In addition, weare subject to various financial covenants calculated as of the last day ofeach quarter, including a life of field coverage ratio, life of loan coverageratio, debt to equity ratio and interest coverage ratio. We have a waiver andamendment from IFC which extended the period of time to assign a first prioritylien on Empresa Electrica Nueva Esperanza S.R.L.’s interest in the Agreementwith GE for three gas-fired turbines to IFC until December 2010.Accordingly, we were in compliance with all material covenants of the LoanAgreement as of September 30, 2010.

 

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 or certain other key agreements;revocation of any financing or security documents with the IFC or certain keyagreements; defaults on certain liabilities; the incurrence of 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 the enactment of restrictionsin Peru that could inhibit any payment a borrower is required to make under thefinancing documents with the IFC.

 

If an event of defaultoccurs, IFC and any additional facility agent may (i) terminate allor 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) declare any and all of the security documents under the facilityenforceable and exercise its rights under such documents. In addition, if anyborrower is liquidated or declared bankrupt, all loans and interest accrued onit or any other amounts due, will become immediately due and payable withoutnotice.

 

*Other*

 

InJuly 2009 we, through our subsidiary, BPZ E&P, entered into a $5.1million short-term loan agreement to finance the purchase of casing andaccessories for use in our current and future operations. The $5.1 millionshort-term loan bore an annual interest rate of 5.45% and was to be repaid infive monthly installments of approximately $1.0 million startingSeptember 2009.  In connection with the $5.1 million short-term loanagreement, we were required to deposit $1.0 million with the lendinginstitution as a guaranty for the loan.  The $1.0 million was to beapplied to the last installment of the loan repayments. In January 2010,the remaining principal amount of approximately $1.0 million, along with theaccrued interest due, was repaid with the $1.0 million deposit and cash.

 

*CapitalLeases*

 

We are party to severalcapital lease agreements, as more fully described in our Form 10-K, asamended, for the year ended December 31, 2009.  Generally, we enter into capital leaseagreements in order to secure marine vessels in order to support our operationsin Peru and to obtain furniture and fixtures for our offices located in Houstonand Peru. The contractual term of the capital lease agreements range betweentwo to five years and the effective interest rate of the capital leaseagreements range between 5.94% and 34.9%.

 

In July, 2010, we exercisedthe second year purchase option and purchased the capital lease productionequipment used on board our floating production, storage and offloading vessel(“FPSO”), the Namoku.

 

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Forthe three and nine months ended September 30, 2010, we recognizedapproximately $2.8 million and $8.5 million of net interest expense,respectively, which includes $5.3 million and $15.4 million of interestexpense, respectively, reduced by $2.5 million and $6.9 million of capitalizedinterest expense, respectively. For the same periods in 2009, we did notrecognize any interest expense as we capitalized all interest expense of $1.2million and $3.3 million, respectively, to construction in progress.

 

*PerformanceBonds*

 

As of September 30,2010, we have restricted cash deposits of $5.0 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$1.3 million of restricted cash to collateralize insurance bonds for importduties related to the Don Fernando barge and $0.6 million of restricted cash toinsure certain performance obligations and commitments at our gas-to-powerproject site near Tumbes. In addition, we have an unsecured performance bond of$0.1 million to guarantee our performance under an office lease agreement inPeru.

 

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

 

**LiquidityOutlook**

 

Weestimate for the remaining term of 2010 our required principal and interestpayments for our outstanding debt to be approximately $2.8 million, ourrequired principal and interest payments for our capital leaseobligations to be approximately $1.6 million, our operating leasepayments to be approximately $12.7 million and capital expenditures to beapproximately $43.1 million (which includes $13.1 million for the drilling,development and production in the Corvina field and Albacora field, both fieldsare located in Block Z-1 in northwest Peru, $2.1 million in other capitalizedcosts, $1.2 million for additional marine support operations and $26.7 millionfor the three LM 6000 gas-fired turbines). In addition, we expect to incurapproximately $10.6 million in seismic acquisition costs for Blocks XXII andXXIII.

 

Ourmajor sources of funding to date have been through oil sales, equity raises, convertibledebt issuances and, to a lesser extent, debt financing activities.  With our current cash balance, current andprospective Corvina and Albacora oil development cash flow, our recentconvertible debt issuance, other potential third-party financing and potentialfinancing from future equity raises, we believe we will have sufficient capitalresources to execute our planned Corvina and Albacora oil development projectsas well as service our current obligations. We plan to continue pursuing ourgas-to-power project once project funding becomes available. We are currently in discussions with afinancial institution to provide short term financing related to our turbineacquisitions. No firm agreements, offers or commitments are in place as wediscuss possible terms and conditions. However, the timing and executionof our project is dependent on a variety of factors, including the technicaldesign of facilities, permitting approval, timely installation of re-injection equipment and transition to commercialproduction, availability of equipment, time and costs required fordelivery of materials and construction operations, performance by contractorsand the success of planned financing, many of which factors are outside ourcontrol and cannot be assured.

 

Wehave hired a financial advisor to help us in pursuing joint venturepartnerships and/or, farm-outs for some or all of our assets and options forfinancing our operations in northwest Peru. While there will be optionsdiscussed that could provide us with additional liquidity or funding, theoutcome of this exercise cannot be predicted.

 

**Off-Balance SheetArrangements**

 

As of September 30, 2010, wehad no transactions, agreements or other contractual arrangements withunconsolidated entities or financial partnerships, often referred to as specialpurpose entities, which generally are established for the purpose offacilitating off-balance sheet arrangements.

 

**Critical Accounting Estimates**

 

Inour annual report on Form 10-K for the year ended December 31, 2009,as amended, we identified our most critical accounting policies. In preparingthe financial statements, we make assumptions, estimates and judgments thataffect the amounts reported. We periodically evaluate our estimates andjudgments that are the most critical in nature which are related to oilreserves, successful efforts method of accounting, revenue recognition,impairment of long-lived assets, future dismantlement, restoration, andabandonment costs, as well as stock-based compensation. Our estimates are basedon historical experience and on our future expectations that we believe arereasonable. Those estimates and assumptions affect the reported amounts ofassets, liabilities,

 

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revenuesand expenses in the consolidated financial statements, and the disclosure ofcontingent assets and liabilities. Actual results are likely to differfrom our current estimates and those differences may be material.

 

In February 2010, theFinancial Accounting Standards Board (“FASB”) issued Accounting StandardsUpdate (“ASU”) No. 2010-09, “Subsequent Events,” which amends ASC Topic855 to eliminate the requirement to disclose the date through which managementhas evaluated subsequent events in the financial statements. ASUNo. 2010-09 was effective upon issuance and its adoption had no impact onour financial position, results of operations or cash flows.

 

In January 2010, we partiallyadopted the provisions of FASB ASU No. 2010-06, “Improving Disclosuresabout Fair Value Measurements,” which amends ASC Topic 820 to require newdisclosures concerning (1) transfers into and out of Levels 1 and 2 of thefair value measurement hierarchy, and (2) activity in Level 3measurements. In addition, ASU No. 2010-06 clarifies certain existingdisclosure requirements regarding the level of disaggregation and inputs andvaluation techniques and makes conforming amendments to the guidance on employers’disclosures about postretirement benefit plans assets. The requirements todisclose separately purchases, sales, issuances, and settlements in the Level 3reconciliation are effective for fiscal years beginning after December 15,2010 (and for interim periods within such years). We will apply the disclosurerequirements relative to the Level 3 reconciliation in the first quarter of2011. There was no impact on our financial position, results of operations orcash flows as a result of the partial adoption of ASU No. 2010-06. Forfurther information, please see Note 11, “Fair Value Measurements andDisclosures”.

 

**Disclosure Regarding Forward-Looking Statements**

 

We caution that this document containsforward-looking statements within the meaning of the Private SecuritiesLitigation Reform Act of 1995, Section 27A of the Securities Act of 1933and Section 21E of the Securities Exchange Act of 1934.  All statements, other than statements ofhistorical facts, included in or incorporated by reference into thisForm 10-Q which address activities, events or developments which weexpect, believe or anticipate will or may occur in the future areforward-looking statements.  The words “believes,”“intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” “plans”and similar expressions, or the negative thereof, are also intended to identifyforward-looking statements.  Inparticular, statements, expressed or implied, concerning future operatingresults, the ability to replace or increase reserves, or to increaseproduction, or the ability to generate income or cash flows are by nature,forward-looking statements.  Thesestatements are based on certain assumptions and analyses made by the managementof BPZ in light of its experience and its perception of historical trends,current conditions and expected future developments as well as other factors itbelieves are appropriate in the circumstances. However, forward-looking statements are not guarantees of performanceand no assurance can be given that these expectations will be achieved.

 

Important factors that could cause actual resultsto differ materially from the expectations reflected in the forward-lookingstatements include, but are not limited to, any of the following in thejurisdictions in which BPZ or its subsidiaries are doing business:  Market conditions, uncertainties inherent inoil and gas production operations and estimating reserves, unexpected futurecapital expenditures, the timing and extent of changes in commodity prices forcrude oil, natural gas and related products, currency exchange rates, interestrates, inflation, the availability of goods and services, drilling and otheroperational risks, satisfaction of well testing period requirements, successfulinstallation of required permanent processing facilities, receipt of allrequired permits, successful installation ofre-injection equipment and transition to commercial production, successful installation and operation of the new turbines, availabilityof capital resources, success of our operational risk management activities,governmental relations, legislative or regulatory changes, politicaldevelopments, acts of war and terrorism. A more detailed discussion on risks relating to the oil and natural gasindustry and to our Company is included in our Annual Report on Form 10-Kfor the year ended December 31, 2009, as amended.

 

In light of these risks, uncertainties andassumptions, we caution the reader that these forward-looking statements aresubject to risks and uncertainties, many of which are beyond our control, whichcould cause actual events or results to differ materially from those expressedor implied by the statements.  Allsubsequent written and oral forward-looking statements attributable to us orpersons acting on our behalf are expressly qualified in their entirety by thecautionary statements.  We undertake noobligations to update or revise our forward-looking statements, whether as aresult of new information, future events or otherwise.

 

**Item 3. Quantitative and Qualitative Disclosures About Market Risk**

 

The primary objective of thefollowing information is to provide forward-looking quantitative andqualitative information about our potential exposure to market risks.  The term “market risk” refers to the risk of lossarising from adverse changes in interest rates, oil and natural gas prices andforeign currency exchange rates.  Thedisclosures are not meant to be precise indicators of expected future losses,but rather indicators of reasonable possible losses.  This forward-looking information providesindicators of how we view and manage our ongoing market risk exposures.  All of our market risk sensitive instrumentswere entered into for purposes other than speculative trading.

 

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*InterestRate Risk*

 

As of September 30,2010, we had long-term debt and capital lease obligations of approximately$153.7 million and current maturities of long-term debt and capital leaseobligations of approximately $9.3 million, consisting of the current portion ofour IFC loan, capital lease obligations for barges and production equipment andloans for office furniture.

 

The $15.0 million reserve-based lending facility is variablerate debt and bears interest at an approximate rate of LIBOR plus 2.75%. The variablerate debt exposes us to the risk of increased interest expense in the event ofincreases in short-term interest rates. If the variable interest rate were toincrease by 1% from September 2010 levels, interest expense would increaseby approximately $0.2 million annually. The carrying value of the variableinterest rate debt approximates fair value as it bears interest at currentmarket rates.

 

The $170.9 million of 2015Convertible Notes are our general senior unsecured obligations and bear a fixedinterest rate of 6.50% per year and whose interest payments are due onMarch 1 and September 1 of each year, beginning on September 1,2010.  The 2015 Convertible Notes mature on March 1, 2015. As theinterest rate on this debt is fixed, we do not expect a significant change inthe market interest rate to impact the interest on this term debt.

 

Thecapital lease obligation for the FPSO and transportation barges began inAugust 2007 and is set to expire in May 2014. Lease payments arevariable based on the working status of the barges, with a purchase option of$3.0 million in May 2012, $2.0 million in May 2013, and required tobe purchased by us for $1.0 million in May 2014.  The imputedinterest rate necessary to reduce the net minimum lease payments to presentvalue over the lease term is 34.9%.  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.

 

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 inaccordance 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%.

 

We do not expect asignificant change in the market interest rate to impact the interest on ourdebt or capital lease obligations.  However, significant changes in marketinterest rates may significantly affect the level of financing that will bestructured with respect to our projects in Peru.

 

*CommodityPrice Risk*

 

With respect to our oil andgas business, any revenues, cash flow, profitability and future rate of growthwe achieve will be greatly dependent upon prevailing prices for oil andgas.  Our ability to maintain or increase our borrowing capacity and toobtain additional capital on attractive terms is also expected to be dependenton oil and gas prices.  Historically, oil and gas prices and markets havebeen volatile and are likely to continue to be volatile in the future. Prices for oil and gas are subject to potentially wide fluctuations in responseto relatively minor changes in supply of and demand for oil and gas, marketuncertainty, and a variety of additional factors that are beyond our control.

 

Lower oil and natural gasprices may not only decrease our revenues on a per unit basis, but may alsoreduce the amount of oil and natural gas we can produce economically, ifany.  A substantial or extended decline in oil and natural gas prices maymaterially affect our future business, financial condition, results ofoperations, liquidity and borrowing capacity, and may require a reduction inthe carrying value of our oil and gas properties.  While our revenues mayincrease if prevailing oil and gas prices increase significantly, explorationand production costs and acquisition costs for additional properties andreserves may also increase.

 

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

 

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*ForeignCurrency Exchange Rate Risk*

 

The U.S. Dollar is thefunctional currency for our operations in both Peru and Ecuador.  Ecuadorhas adopted the U.S. Dollar as its official currency.  Peru, however, usesits local currency, the Nuevo Sol, in addition to the U.S. Dollar, andtherefore, our financial results are subject to favorable or unfavorablefluctuations in the exchange rate and inflation in that country. Transaction differences have been nominal to-date but are expected to increaseas our activities in Peru continue to escalate.  For the three and ninemonths ended September 30, 2010 and 2009, exchange rate gains and losseswere not material.

 

**Item 4. Controls and Procedures**

 

**(a) Evaluationof Disclosure Controls and Procedures**

 

Asof the end of the period covered by this report, we carried out an evaluation,under the supervision and with the participation of our management, includingour Chief Executive Officer and Chief Financial Officer, of the effectivenessof our disclosure controls and procedures as defined inRule 13a-15(e) of the Exchange Act. Based upon that evaluation our Chief Executive Officer and ChiefFinancial Officer concluded that our disclosure controls and procedures asdefined in Rule 13a-15(e) of the Exchange Act were effective as ofthe end of the period covered by this report to ensure that information requiredto be disclosed by the Company in the reports that the Company files or submitsunder the Exchange Act is recorded, processed, summarized and reported withinthe time periods specified in the SEC’s rules and forms.  Our disclosure controls and procedures includecontrols and procedures designed to ensure that information required to bedisclosed in reports filed or submitted under the Exchange Act is accumulatedand communicated to our management, including our principal executive officerand principal financial officer, as appropriate, to allow timely decisionsregarding required disclosure.

 

**(b) Changesin Internal Control over Financial Reporting**

 

Duringthe quarter ended September 30, 2010, there was no change in internalcontrol over financial reporting that materially affected, or is reasonablylikely to materially affect, our internal control over financial reporting.

 

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**PART II**

 

**Item 1. Legal Proceedings**

 

See Note 17, “Legal Proceedings”, of the Notes to UnauditedConsolidated Financial Statements included in this Form 10-Q andItem 3 of Part I of our Annual Report on Form 10-K for the yearended December 31, 2009, as amended, for a discussion of legalproceedings, which are incorporated into this Part II, Item 1. “LegalProceedings” by reference.

 

**Item 1A. Risk Factors**

 

Item1A, “Risk Factors” of our Annual Report on Form 10-K for the year endedDecember 31, 2009, as amended, includes a detailed discussion of our riskfactors.  For the three and nine monthsended September 30, 2010, there were no material changes in our riskfactors as previously described in our Annual Report on Form 10-K.

 

**Item 6. Exhibits**

 
| 31.1   |   | Certification  of Chief Executive Officer pursuant to Section 302 of the Sarbanes -  Oxley Act of 2002. (Filed herewith)                                                     |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   |   |                                                                                                                                                                              |
| 31.2   |   | Certification  of Chief Financial Officer pursuant to Section 302 of the Sarbanes -  Oxley Act of 2002. (Filed herewith)                                                     |
|   |   |                                                                                                                                                                              |
| 32.1   |   | Certification  of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted  pursuant to Section 906 of the Sarbanes - Oxley Act of 2002. (Filed  herewith) |
|   |   |                                                                                                                                                                              |
| 32.2   |   | Certification  of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted  pursuant to Section 906 of the Sarbanes - Oxley Act of 2002. (Filed  herewith) |

 

**SIGNATURES**

 

Pursuant to the requirements of theSecurities Exchange Act of 1934, the registrant has duly caused this report tobe signed on its behalf by the undersigned thereunto duly authorized.

 
|                         | BPZ  RESOURCES, INC.                                  |
|------------------------------|------------------------------------------------------------|
|                         |                                                       |
| Date:  November 9, 2010 | /s/  MANUEL PABLO ZÚÑIGA-PFLÜCKER |
|                         | Manuel Pablo  Zúñiga-Pflücker               |
| * *                     | *President,  Chief Executive Officer and Director*         |

 

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