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 THESECURITIES EXCHANGE ACT OF 1934**

** **

**For thequarterly period ended: June 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, anaccelerated filer, a non-accelerated filer, or a smaller reporting company. Seethe definitions 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 August 9, 2010,there were 115,309,116 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 |   | 25 |
|             |   |   |   |
| Item 3.          | Quantitative  and Qualitative Disclosures About Market Risk |   | 42 |
|             |   |   |   |
| Item 4.          | Controls and Procedures |   | 44 |
|             |   |   |   |
| **PART II** |
|             |   |   |   |
| Item 1.          | Legal Proceedings |   | 45 |
|             |   |   |   |
| Item 1A.         | Risk Factors |   | 45 |
|             |   |   |   |
| Item 6.          | Exhibits |   | 45 |
|             |   |   |   |
| **SIGNATURES**   |

 

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Tableof Contents

 

**PART I**

 

**Item 1. Financial Statements**

 

**BPZ Resources, Inc. andSubsidiaries**

**Consolidated Balance Sheets**

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

 
| ** **                                                                                                                                                                     | ** ** | **June 30,** | ** ** | **December 31,** | ** ** |
|--------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|------------|-------------------|------------|-----------------------|------------|
| ** **                                                                                                                                                                     | ** ** | **2010**          | ** ** | **2009**              | ** ** |
| ** **                                                                                                                                                                     | ** ** | **(Unaudited)**   | ** ** | **(Audited)**         | ** ** |
| **ASSETS**                                                                                                                                                                     |       |              |       |                  |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Current assets:                                                                                                                                                                |       |              |       |                  |       |
| Cash and cash equivalents                                                                                                                                                      |       | $                 | 93,225     |                  | $          | 18,147 |   |
| Accounts receivable                                                                                                                                                            |       | 2,524             |       | 2,867                 |       |
| Value added tax receivable                                                                                                                                                     |       | 30,958            |       | 26,152                |       |
| Inventory                                                                                                                                                                      |       | 24,642            |       | 12,507                |       |
| Prepaid and other current assets                                                                                                                                               |       | 5,626             |       | 1,580                 |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Total current assets                                                                                                                                                           |       | 156,975           |       | 61,253                |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Property, equipment and construction in progress,  net                                                                                                                         |       | 318,890           |       | 262,517               |       |
| Restricted cash                                                                                                                                                                |       | 4,530             |       | 5,720                 |       |
| Other non-current assets                                                                                                                                                       |       | 6,089             |       | 1,559                 |       |
| Investment in Ecuador property, net                                                                                                                                            |       | 1,101             |       | 1,195                 |       |
| Deferred tax asset                                                                                                                                                             |       | 21,466            |       | 16,928                |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Total assets                                                                                                                                                                   |       | $                 | 509,051    |                  | $          | 349,172 |   |
|                                                                                                                                                                           |       |              |       |                  |       |
| **LIABILITIES  AND STOCKHOLDERS’ EQUITY**                                                                                                                                 |       |              |       |                  |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Current liabilities:                                                                                                                                                           |       |              |       |                  |       |
| Accounts payable                                                                                                                                                               |       | $                 | 23,542     |                  | $          | 32,698 |   |
| Accrued liabilities                                                                                                                                                            |       | 11,217            |       | 14,155                |       |
| Other liabilities                                                                                                                                                              |       | 1,329             |       | 1,235                 |       |
| Current income taxes payable                                                                                                                                                   |       | 1,731             |       | 322                   |       |
| Accrued interest payable                                                                                                                                                       |       | 4,594             |       | 106                   |       |
| Current maturity of long-term debt and capital  lease obligations                                                                                                              |       | 9,493             |       | 5,352                 |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Total current liabilities                                                                                                                                                      |       | 51,906            |       | 53,868                |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Asset retirement obligation                                                                                                                                                    |       | 985               |       | 766                   |       |
| Long-term debt and capital lease obligations                                                                                                                                   |       | 153,570           |       | 22,581                |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Total long-term liabilities                                                                                                                                                    |       | 154,555           |       | 23,347                |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Commitments and contingencies (Note 15)                                                                                                                                        |       |              |       |                  |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Stockholders’ equity:                                                                                                                                                     |       |              |       |                  |       |
| Preferred stock, no par value, 25,000,000  authorized; none issued and outstanding                                                                                             |       | —            |       | —                |       |
| Common stock, no par value, 250,000,000  authorized; 115,309,000 and 115,224,000 shares issued and outstanding at  June 30, 2010 and December 31, 2009, respectively |       | 549,814           |       | 513,145               |       |
| Accumulated deficit                                                                                                                                                            |       | (247,224          | )          | (241,188              | )          |
|                                                                                                                                                                           |       |              |       |                  |       |
| Total stockholders’ equity                                                                                                                                                |       | 302,590           |       | 271,957               |       |
|                                                                                                                                                                           |       |              |       |                  |       |
| Total liabilities and stockholders’ equity                                                                                                                                |       | $                 | 509,051    |                  | $          | 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 June 30,** | ** ** | **Six Months  Ended June 30,** | ** ** |
|----------------------------------------------------------------------------|------------|---------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                 | ** ** | **2010**                              | ** ** | **2009**                            | ** ** | **2010** | ** ** | **2009** | ** ** |
|                                                                       |       |                                  |       |                                |       |   |   |   |   |
| Revenue                                                                    |       | $                                     | 22,397     |                                | $          | 11,049 |   | $ | 46,442 |   | $ | 24,274 |   |
|                                                                       |       |                                  |       |                                |       |   |   |   |   |
| Operating and administrative expenses:                                     |       |                                  |       |                                |       |   |   |   |   |
| Lease operating expense                                                    |       | 5,578                                 |       | 7,876                               |       | 10,342 |   | 11,854 |   |
| General and administrative expense                                         |       | 8,203                                 |       | 7,998                               |       | 16,229 |   | 16,481 |   |
| Geological, geophysical and engineering expense                            |       | 402                                   |       | 553                                 |       | 903 |   | 899 |   |
| Depreciation, depletion and amortization expense                           |       | 8,045                                 |       | 5,508                               |       | 17,534 |   | 13,386 |   |
|                                                                       |       |                                  |       |                                |       |   |   |   |   |
| Total operating expenses                                                   |       | 22,228                                |       | 21,935                              |       | 45,008 |   | 42,620 |   |
|                                                                       |       |                                  |       |                                |       |   |   |   |   |
| Operating income (loss)                                                    |       | 169                                   |       | (10,885                             | )          | 1,434 |   | (18,346 | ) |
|                                                                       |       |                                  |       |                                |       |   |   |   |   |
| Other income (expense):                                                    |       |                                  |       |                                |       |   |   |   |   |
| Income (expense) from investment in Ecuador  property, net of amortization |       | 353                                   |       | (47                                 | )          | 306 |   | (94 | ) |
| Interest expense                                                           |       | (3,749                                | )          | —                              |       | (5,689 | ) | — |   |
| Interest income                                                            |       | 6                                     |       | 3                                   |       | 70 |   | 28 |   |
| Other income (expense)                                                     |       | 5                                     |       | (540                                | )          | 11 |   | (1,312 | ) |
|                                                                       |       |                                  |       |                                |       |   |   |   |   |
| Total other expense, net                                                   |       | (3,385                                | )          | (584                                | )          | (5,302 | ) | (1,378 | ) |
|                                                                       |       |                                  |       |                                |       |   |   |   |   |
| Loss before income taxes                                                   |       | (3,216                                | )          | (11,469                             | )          | (3,868 | ) | (19,724 | ) |
|                                                                       |       |                                  |       |                                |       |   |   |   |   |
| Income tax expense (benefit)                                               |       | 1,046                                 |       | (1,656                              | )          | 2,168 |   | (2,863 | ) |
|                                                                       |       |                                  |       |                                |       |   |   |   |   |
| Net loss                                                                   |       | $                                     | (4,262     | )                                   | $          | (9,813 | ) | $ | (6,036 | ) | $ | (16,861 | ) |
|                                                                       |       |                                  |       |                                |       |   |   |   |   |
| Basic and diluted net loss per share                                       |       | $                                     | (0.04      | )                                   | $          | (0.10 | ) | $ | (0.05 | ) | $ | (0.18 | ) |
| Weighted average common shares outstanding                                 |       | 115,309                               |       | 95,347                              |       | 115,286 |   | 92,002 |   |

 

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 Six Months Ended** | ** ** |
|--------------------------------------------------------------------------------------|------------|------------------------------|------------|
| ** **                                                                           | ** ** | **June 30,**            | ** ** |
| ** **                                                                           | ** ** | **2010**                     | ** ** | **2009** | ** ** |
|                                                                                 |       |                         |       |   |   |
| Cash flows from operating activities:                                                |       |                         |       |   |   |
| Net loss                                                                             |       | $                            | (6,036     | ) | $ | (16,861 | ) |
| Adjustments to reconcile net loss to net cash used  in operating activities:         |       |                         |       |   |   |
| Stock-based compensation                                                             |       | 3,304                        |       | 7,463 |   |
| Depreciation, depletion and amortization                                             |       | 17,534                       |       | 13,386 |   |
| Amortization of investment in Ecuador property                                       |       | 94                           |       | 94 |   |
| Deferred income taxes                                                                |       | (4,537                       | )          | (5,230 | ) |
| Amortization of deferred financing fees                                              |       | 2,070                        |       | — |   |
| Changes in operating assets and liabilities:                                         |       |                         |       |   |   |
| Decrease in accounts receivable                                                      |       | 343                          |       | 2,590 |   |
| Increase in value added tax receivable                                               |       | (4,806                       | )          | (6,259 | ) |
| Increase in inventory                                                                |       | (10,465                      | )          | (2,420 | ) |
| Decrease (increase) in other assets                                                  |       | (4,058                       | )          | 10 |   |
| (Decrease) increase in accounts payable                                              |       | (9,156                       | )          | 4,151 |   |
| Increase (decrease) in accrued liabilities                                           |       | 1,550                        |       | (3,907 | ) |
| Increase (decrease) in income taxes payable                                          |       | 1,409                        |       | (6,653 | ) |
| Increase in other liabilities                                                        |       | 93                           |       | 231 |   |
| Net cash used in operating activities                                                |       | (12,661                      | )          | (13,405 | ) |
|                                                                                 |       |                         |       |   |   |
| Cash flows from investing activities:                                                |       |                         |       |   |   |
| Property and equipment additions                                                     |       | (75,314                      | )          | (30,433 | ) |
| Decrease in restricted cash                                                          |       | 1,190                        |       | 902 |   |
| Net cash used in investing activities                                                |       | (74,124                      | )          | (29,531 | ) |
|                                                                                 |       |                         |       |   |   |
| Cash flows from financing activities:                                                |       |                         |       |   |   |
| Borrowings                                                                           |       | 170,938                      |       | 1,000 |   |
| Repayments of borrowings                                                             |       | (3,003                       | )          | (3,307 | ) |
| Deferred loan fees                                                                   |       | (6,072                       | )          | — |   |
| Proceeds from exercise of stock options, net                                         |       | —                       |       | 11 |   |
| Proceeds from sale of common stock, net                                              |       | —                       |       | 127,625 |   |
| Net cash provided by financing activities                                            |       | 161,863                      |       | 125,329 |   |
|                                                                                 |       |                         |       |   |   |
| Net increase in cash and cash equivalents                                            |       | 75,078                       |       | 82,393 |   |
| Cash and cash equivalents at beginning of period                                     |       | 18,147                       |       | 5,317 |   |
| Cash and cash equivalents at end of period                                           |       | $                            | 93,225     |   | $ | 87,710 |   |
|                                                                                 |       |                         |       |   |   |
| Supplemental cash flow information:                                                  |       |                         |       |   |   |
| **Cash paid for:**                                                                   |       |                         |       |   |   |
| Interest                                                                             |       | $                            | 3,478      |   | $ | 1,900 |   |
| Income tax                                                                           |       | 5,695                        |       | 10,804 |   |
| **Non — cash items:**                                                           |       |                         |       |   |   |
| Purchase and additions to equipment with the  issuance of a capital lease obligation |       | $                            | 43         |   | $ | — |   |
| Accrued interest capitalized to construction in  progress                            |       | —                       |       | 36 |   |
| Depletion allocated to production inventory                                          |       | 1,670                        |       | 814 |   |
| Depreciation on support equipment capitalized to  construction in progress           |       | 892                          |       | 690 |   |
| Asset retirement obligation capitalized to  property and equipment                   |       | 172                          |       | 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 itssubsidiary BPZ Energy International Holdings, L.P., a British Virgin Islandslimited partnership. The Company, through BPZ E&P, has exclusive rights andlicense contracts for oil and gas exploration and production covering a totalof approximately 2.2 million acres, in four blocks, in northwest Peru. TheCompany’s license contracts cover 100% ownership of the following properties:Block Z-1 (0.6 million acres), Block XIX (0.5 million acres), Block XXII (0.9million acres) and Block XXIII (0.2 million acres). The Block Z-1 contract wassigned in November 2001, the Block XIX contract was signed inDecember 2003 and the Blocks 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 in each contract can be extended 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 requirethe Company to conduct specified activities in the respective blocks duringeach exploration period in the exploration phase. If the exploration activitiesare successful, the Company may decide to enter the exploitation phase and thetotal contract term can extend up to 30 years for oil exploration andproduction and up to 40 years for gas exploration and production. In the eventa block contains both oil and gas, as is the case in the Company’s Block Z-1contract, the 40 year term may apply to oil exploration and 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 during the second quarter of 2010.  The Company drilled and completed its firstAlbacora well in December 2009 and is currently drilling the A-17D well.  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 June 30, 2010, it has producedapproximately 2.7 MMBbls of oil. Additionally, the Company’s activities in Peruinclude analysis and evaluation of technical data on its other properties,preparation of the development plans for the properties, refurbishment of anddesigns for platforms, procuring machinery and equipment for an extended drillingcampaign, obtaining all necessary environmental and operating permits, bringingadditional production on-line, seismic acquisition, obtaining detailedengineering and design of the planned power plant and gas processingfacilities, executing a contract to purchase three LM 6000 gas-fired turbinesand securing the required capital and financing to conduct the current plan ofoperation.

 

**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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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

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’sfinancial position, 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). As such, the Company will apply the disclosure requirements relative tothe Level 3 reconciliation in the first quarter of 2011. There was no impact onthe Company’s financial position, results of operations or cash flows as aresult of the partial adoption of ASU No. 2010-06. For furtherinformation, please see Note 11, “Fair Value Measurements and Disclosures”.

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

**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. Accordingly, the Company is recovering its IGV receivablewith IGV payables associated with future oil sales under the normal IGVrecovery process.

 

The Company’s value-addedtax receivable balance as of June 30, 2010 and December 31, 2009 was $31.0million and $26.2 million, respectively. For the six months ended June 30, theCompany accrued approximately $17.6 million for IGV related to expendituresreduced by approximately $12.8 million for IGV related to the sale of oil forthe same period.

 

**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 June 30, 2010 and December 31, 2009 was $24.6million and $12.5 million, respectively.

 

Inventory associated withtubular goods, accessories and spare parts inventory at June 30, 2010 andDecember 31, 2009 was $16.4 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.  As of June 30, 2010, most of the oil produced from the Albacora field,193,186 barrels, was being held in storage vessels due to the oil’s high saltcontent. Subsequent to June 30, 2010, the Company obtained a short-termcontract to allow it to sell up to 110,000 barrels of the Albacora oil with ahigher salt content to Petroleos del Peru - PETROPERU S.A. (“Petroperu” aprivate law state company engaged in the refining, transportation, distributionand trading of petroleum products to meet Peru’s domestic energy needs).  The Company is in the process of installingspecialized oil desalting equipment in order to supplement the chemical oiltreatment process the Company is utilizing to allow it to sell oil under therequirement of the original 400,000 barrels oil sales contract withPetroperu.  For further informationregarding the Albacora oil sales contracts, see Note 12, “Revenue”.

 

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 June 30,2010 consisted of approximately 227,246 barrels at an estimated cost of $8.2million or $36.13 per barrel. The crude oil inventory at December 31, 2009consisted of approximately 40,108 barrels at an estimated cost of $2.0 millionor $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 June 30, 2010 and December 31,2009:

 
| ** **                 | ** ** | **June 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|----------------------------|------------|--------------------|------------|------------------------|------------|
| ** **                 | ** ** | **(in thousands)** | ** ** |
| Prepaid expenses and other |       | $                  | 4,352      |                   | $          | 296 |   |
| Deposits                   |       | 100                |       | 92                     |       |
| Prepaid insurance          |       | 562                |       | 580                    |       |
| Insurance receivable       |       | 612                |       | 612                    |       |
|                       |       | $                  | 5,626      |                   | $          | 1,580 |   |

 

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Table of Contents

 

**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

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. The Company incurred anoperational delay of approximately three weeks resulting from a navigationincident which caused the BPZ-01 barge to be grounded on a sand bank in TalaraBay in northwest Peru during the second mobilization trip to the Corvinaplatform. As of June 30, 2010, the Company has an insurance receivable ofapproximately $0.7 million for the estimated insurance repair claims of $0.8million expected to be filed with the insurance carrier. A deductible of$75,000 will be applied to this insurance claim when reimbursed.  The hullclaim will be finalized upon the dry docking of the vessel, which is expectedto occur during the first quarter of 2011.

 

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

 
| ** **       | ** ** | **June 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|------------------|------------|--------------------|------------|------------------------|------------|
| ** **       | ** ** | **(in thousands)** | ** ** |
| Debt issue costs |       | $                  | 4,623      |                   | $          | 104 |   |
| Other receivable |       | 1,466              |       | 1,455                  |       |
|             |       | $                  | 6,089      |                   | $          | 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 June 30,2010, the Company is currently seeking recovery of these amounts from thePeruvian Navy’s commercial branch.  Dueto the uncertainty in timing of resolving the claims, the Company hasclassified 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 six months ended June 30,2010, the Company amortized into interest expense $0.2 million and $0.3 millionof debt issue costs. For the same periods in 2009, the amortization of debtissue costs were not material. For further information regarding the Company’sdebt, see Note 9, “Long-TermDebt and Capital Lease Obligations”.

 

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

 

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

 
| ** **                                             | ** ** | **June 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|--------------------------------------------------------|------------|--------------------|------------|------------------------|------------|
| ** **                                             | ** ** | **(in thousands)** | ** ** |
| Construction in progress:                              | ** ** | ** **         | ** ** | ** **             | ** ** |
| Power plant and related equipment                      |       | $                  | 37,337     |                   | $          | 28,113 |   |
| Platforms and wells                                    |       | 22,281             |       | 16,726                 |       |
| Pipelines and processing facilities                    |       | 8,894              |       | 5,537                  |       |
| Other                                                  |       | 4,863              |       | 8,181                  |       |
| Producing properties                                   |       | 246,268            |       | 199,686                |       |
| Producing equipment                                    |       | 13,173             |       | 13,160                 |       |
| Barge and related equipment                            |       | 50,567             |       | 35,842                 |       |
| Office equipment, leasehold improvements and  vehicles |       | 2,477              |       | 2,193                  |       |
| Accumulated depletion, depreciation and  amortization  |       | (66,970            | )          | (46,921                | )          |
|                                                   |       |               |       |                   |       |
| Net property, equipment and construction in  process   |       | $                  | 318,890    |                   | $          | 262,517 |   |

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

During the six months ended June 30, 2010, the Companyincurred capital expenditures of approximately $76.4 million associatedwith its development initiatives for the exploration and production of oil andnatural gas reserves and the complementary development of a proprietarygas-fired power generation facility in Peru.

 

Of the incurred costsmentioned above, the Company incurred capital expenditures related to thedrilling and testing of the CX11-15D, CX11-23D, CX11-17D and CX11-22D in theCorvina field of approximately $0.5 million, $0.2 million, $7.3 million and$18.4 million, respectively. In the Albacora field, the Company incurredcapital expenditures related to the drilling of the A-15D, A-16D and A-17D ofapproximately $8.6 million, $6.5 million and $7.3 million, respectively.

 

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 tender assist barge fordrilling and construction operations, and may be fitted to lay subsea pipe forthe gas-to-power project.  During the sixmonths ended June 30, 2010, the Company capitalized an additional $2.9 millionin order to have the barge ready to support its operations.

 

For the further developmentof the planned gas-fired power generation facility, BPZ incurred costs ofapproximately $5.6 million as part of its agreement to purchase three LM6000gas-fired turbines.

 

For the six months endedJune 30, 2010, the Company incurred approximately $1.8 million for upgrades toits existing platforms as well as costs incurred in the construction of newplatforms. In addition, the Company incurred $2.9 million in equipment for itsproduction facilities at the A platform in Albacora and the CX-11 platform inCorvina. The Company incurred $5.1 million for the purchase of machinery andequipment used in operations in Peru, $0.3 million for the Caleta La Cruz dockrefurbishment, $3.5 million in assets in transit, $0.5 million in furniture andimprovements related to the new offices in Peru and $0.2 million related to theasset retirement obligation for the CX11-17D and CX11-22D wells.

 

Forthe three and six months ended June 30, 2010, in accordance with the “successfulefforts” method of accounting, the Company capitalized approximately $0.5million and $0.9 million of depreciation expense, respectively, mainly relatedto the tender assist barges serving as support equipment, and $2.9 million and$4.3 million of interest expense, respectively, to construction in progress.For the same periods in 2009, the Company capitalized approximately $0.4million and $0.7 million of depreciation expense, respectively, and $1.2million and $2.2 million of interest expense, respectively, to construction inprogress.

 

For the three and six monthsended June 30, 2010, the Company recognized $8.0 million and $17.5 million ofdepreciation, depletion and amortization expense, respectively. For the sameperiods in 2009, the Company recognized $5.5 million and $13.4 million ofdepreciation, 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 June 30, 2010 andDecember 31, 2009 is as follows:

*** ***
| ** **                            | ** ** | **June 30,  2010** | ** ** | **December 31,  2009** | ** ** |
|---------------------------------------|------------|--------------------|------------|------------------------|------------|
| ** **                            | ** ** | **(in thousands)** | ** ** |
| ARO as of the beginning of the period |       | $                  | 766        |                   | $          | 580 |   |
| Liabilities incurred during period    |       | 172                |       | 296                    |       |
| Accretion expense                     |       | 47                 |       | 74                     |       |
| Revisions in estimates during period  |       | —             |       | (184                   | )          |
|                                  |       |               |       |                   |       |
| ARO as of the end of the period       |       | $                  | 985        |                   | $          | 766 |   |

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

**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 June 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 both the three andsix months ended June 30, 2010, the Company received $0.4 million from itsinvestment in Ecuador property. During the same periods in 2009, the Companydid not receive any income from its investment in Ecuador property. For boththe three and six months ended June 30, 2010, and 2009, the Companyrecorded investment amortization expense of approximately $47,000 and $94,000,respectively.

 

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

 

As of June 30, 2010,the Company has restricted cash deposits of $4.5 million. In connection withthe 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 $0.8 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.

 

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** **

**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

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

 

AtJune 30, 2010 and December 31, 2009 long-term debt and capital leaseobligations consist of the following:

 
| ** **                                                                            | ** ** | **June 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 ($32.8) million |       | 138,090             |       | —                 |       |
| Capital Lease Obligations                                                             |       | 9,973               |       | 11,910                 |       |
| Other                                                                                 |       | —              |       | 1,023                  |       |
|                                                                                  |       | 163,063             |       | 27,933                 |       |
| Less: Current Portion of Long-Term Debt and  Capital Lease Obligations                |       | 9,493               |       | 5,352                  |       |
|                                                                                  |       | $                   | 153,570    |                   | $          | 22,581 |   |

 

**$170.9million Convertible Notes due 2015**

 

During the first quarter of2010, the Company closed on the 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 senior unsecuredindebtedness.  The 2015 Convertible Notes are effectively subordinate toall of the Company’s secured indebtedness to the extent of the value of theassets collateralizing such indebtedness.  The 2015 Convertible Notes arenot guaranteed 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 toexceed 19.99% 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 June 30, 2010,if the last reported sale price of the Company’s common stock is greater thanor equal 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;

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

(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, theredemption date, plus a “make-whole” payment if: (1) for at least 20trading days in any consecutive 30 trading days ending within 5 trading daysimmediately before the date the Company mails the redemption notice, the “lastreported sale price” of its common stock exceeded 175% of the conversion pricein effect on that trading day, and (2) there is no continuing default withrespect to the notes that has not been cured or waived on or before theredemption 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 connectionwith the 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.

 

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, transactioncosts incurred that directly relate to the issuance of convertible debtinstruments 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

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

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 $6.4 million, $11.1 million, $11.1 million,$11.1 million, $11.1 million and $176.5 million, respectively.

 

Asof June 30, 2010, the net amount of $138.1 million includes the $170.9 millionof principal reduced by $32.8 million of the remaining unamortized discount.The net amount of the equity component is $33.3 million which includes theinitial discount of $34.6 million reduced by $1.3 million of direct transactioncosts. The remaining unamortized discount of $32.8 million will be amortizedinto interest expense, using the effective interest method, over the remaininglife of the loan agreement, whose term expires in March 2015.  At June 30, 2010, using the currentconversion rate of 148.3856 shares per $1,000 principal amount of the 2015Convertible 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.  However, the Company iscurrently limited, by NYSE rules, to issuing no more than 23,031,663 shares(19.99% of the stock outstanding at the time of the issuance of the 2015Convertible Notes) in satisfaction of conversion of the 2015 Convertible Notes.Should the Company need to issue shares in excess of the 19.99% limit, it wouldneed approval by the affirmative vote of the majority of shareholders in orderto issue the shares in excess of the 19.99% limit. As of June 30, 2010, thereis no excess if-converted value to the holders of the 2015 Convertible Notes asthe price of the Company’s common stock at June 30, 2010, $4.15 per share, isless than the conversion price.

 

 For both the three and six months ended June30, 2010, the effective interest rate for the 2015 Convertible Notes is 12%;including the amortization of debt issue costs, the effective interest rate is12.6%.

 

Theamount of interest expense related to the 2015 Convertible Notes for the threemonths ended June 30, 2010 is $5.1 million, disregarding capitalized interestconsiderations, including $3.6 million of interest expense related to thecontractual interest coupon, $1.3 million of non-cash interest expense relatedto the amortization of the discount and $0.2 million of interest expenserelated 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 sixmonths ended June 30, 2010 is $6.5 million, disregarding capitalized interestconsiderations, including $4.5 million of interest expense related to thecontractual interest coupon, $1.7 million of non-cash interest expense relatedto the amortization of the discount and $0.3 million of interest expenserelated 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.  Theamount available under the Loan Agreement is subject to a semi-annual borrowingbase determination based on the value of oil reserves.  In addition, theCompany is subject to various financial covenants calculated as of the last dayof each quarter, including a life of field coverage ratio, life of loancoverage ratio, debt to equity ratio and interest coverage ratio. In February2010, the Company received a waiver from IFC for the life of field coverageratio and life of loan coverage ratio through August 2010. Additionally, theCompany requested and received a waiver and amendment from IFC which extendedthe period of time to assign a first priority lien on Empresa Electrica NuevaEsperanza S.R.L.’s interest in the Agreement with GE to purchase threegas-fired turbines to IFC until December 2010. The Company was incompliance with all material covenants of the Loan Agreement as of June 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 S.A. (“Perupetro”), a corporationowned by the Peruvian government empowered to become a party in the contractsfor the exploration and/or exploitation of hydrocarbons in order to promotethese activities in Peru. Perupetro is

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

empoweredto enter into contracts for the exploration and exploitation of hydrocarbons onbehalf of Peru, orcertain other key agreements; revocation of any financing or security documentswith the IFC or certain key agreements; defaults on certain liabilities; theincurrence of certain judgments against the borrower or any subsidiary;abandonment or extended business interruption of the Corvina field or certainother petroleum assets; engagement in certain sanctionable practices; or theenactment of restrictions in Peru that could inhibit any payment a borrower isrequired to make under the financing documents with the IFC.

 

If an event of default occurs, IFCand any additional facility agent may (i) terminate all or part of therelevant facility; (ii) declare all or part of the principal amount of theloan, together with accrued interest, immediately due and payable; (iii) declare all or part of the principal amount of the loan, togetherwith accrued interest, payable on demand; or (iv) declare any and all ofthe security documents under the facility enforceable and exercise its rightsunder such documents. In addition, if any borrower is liquidated or declaredbankrupt, all loans and interest accrued on it or any other amounts due, willbecome immediately due and payable without notice.

 

**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 obtainfurniture and fixtures for its offices located in Houston and Peru. Thecontractual term of the capital lease agreements range between two to fiveyears and the effective interest rate of the capital lease agreements rangebetween 5.94% and 34.9%.

 

Subsequent to June 30, 2010,the Company exercised the second year purchase option and purchased the capitallease production equipment used on board the Company’s FPSO, the Namoku.

 

Forthe three and six months ended June 30, 2010, the Company recognizedapproximately $3.7 million and $5.7 million of net interest expense,respectively, which includes $6.6 million and $10.0 million of interestexpense, respectively, reduced by $2.9 million and $4.3 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 $2.2 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.

 

**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 the offering, to purchase shares of the Company’s commonstock for the same price and terms as the participants in an offering to retainits proportionate ownership in the Company. IFC exercised its pre-emptive rightto purchase approximately 1.6 million shares of common stock at the offeringprice of $4.66 per share to which it was entitled under the SubscriptionAgreement, resulting in gross proceeds to the Company of approximately $7.6million. The transaction was submitted to and approved by the shareholders ofthe Company at a Special Meeting of Shareholders on August 24, 

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

2009. No warrants ordilutive securities were issued to IFC in connection with the privateplacement. The shares were placed directly by the Company. The Company used theproceeds of this offering to develop its properties under its existing licensecontracts and other general corporate purposes consistent with the Company’soperating 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 has the following potentially dilutive securitiesat June 30, 2010 and June 30, 2009.  Noneof these potentially dilutive shares have been included in the calculation ofearnings per share, for the three and six months ended June 30, 2010 or June30, 2009, as the effect would be anti-dilutive.

 

The potentially dilutive shares areas follows:

 
| ** **                                                           | ** ** | **June 30,  2010** | ** ** | **June 30,  2009** | ** ** |
|----------------------------------------------------------------------|------------|--------------------|------------|--------------------|------------|
| ** **                                                           | ** ** | **(in thousands)** | ** ** |
| Stock options outstanding                                            |       | 4,610              |       | 4,582              |       |
| Shares issuable under convertible debt agreement                     |       | 25,365             |       | —             |       |
| Total potentially dilutive securities issued                         |       | 29,975             |       | 4,582              |       |
|                                                                 |       |               |       |               |       |
| Shares available pursuant to Long-Term Incentive  Compensation Plans |       | 1,389              |       | 1,671              |       |

 

The Company has in effectthe 2007 Long-Term Incentive Compensation Plan (the “2007 LTIP”) and the 2007Directors’ Compensation Incentive Plan (the “Directors’ Plan”). The 2007 LTIPand Directors’ 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 2007 LTIP andDirectors’ Plan is 4.0 million and 2.5 million, respectively. As of June30, 2010, 73,900 shares remain available for future grants under the 2007 LTIPand 1,314,810 shares remain available for future grants under the Directors’Plan.

 

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

 
| ** **                                           | ** ** | **Three Months Ended** | ** ** | **Six Months Months Ended** | ** ** |
|------------------------------------------------------|------------|----------------------------------|------------|---------------------------------------|------------|
| ** **                                           | ** ** | **June 30,**                     | ** ** | **June 30,**                          | ** ** |
| ** **                                           | ** ** | **2010**                         | ** ** | **2009**                              | ** ** | **2010** | ** ** | **2009** | ** ** |
| ** **                                           | ** ** | **(in thousands)**               | ** ** | **(in thousands)**                    | ** ** |
| Employee stock—based compensation costs         |       | $                                | 1,064      |                                  | $          | 1,999 |   | $ | 2,370 |   | $ | 3,925 |   |
| Director stock—based compensation costs (a) (b) |       | 385                              |       | 2,190                                 |       | 934 |   | 3,538 |   |
|                                                 |       | $                                | 1,449      |                                  | $          | 4,189 |   | $ | 3,304 |   | $ | 7,463 |   |

 

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| (a) | For the three and six  months ended June 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. |
|-----|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 
| (b) | For the three and six  months ended June 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.   The restricted stock awards generally veston the second anniversary of the grant date. As these awards are 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 these awards have not been considered granted for accountingpurposes.

 

**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 options generally vest inequal annual installments over a three-year period from the grant date. Asthese awards are subject to the approval of an amendment of the 2007 Long-TermIncentive Compensation Plan by the affirmative vote of the holders of amajority of the votes cast at the Annual Meeting these awards have not beenconsidered granted for accounting purposes.

 

On July 1, 2010 the Companyawarded its non-employee directors a total of 200,000 options to purchase theCompany’s common stock under the Directors’ Plan.  These options generally vest in equal annualinstallments over a two-year period from the grant date. The exercise price ofthese awards is based on the closing market price on the date of Board approvalof 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.

 

*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.

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

**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 June 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 June 30, 2010 and December 31, 2009approximates 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 our fixed rate debt is as follows:

* *
| ** **                                                                                | ** ** | **June 30,  2010**  | ** ** |
|-------------------------------------------------------------------------------------------|------------|---------------------|------------|
| ** **                                                                                | ** ** | **Carrying Amount** | ** ** | **Fair Value (2)** | ** ** |
| ** **                                                                                | ** ** | **(in thousands)**  | ** ** |
| $170.9 million Convertible Notes, 6.5%, due 2015,  net of discount of ($32.8) million (1) |       | $                   | 138,090    |   | $ | 157,632 |   |
|                                                                                           |            |                     |            |  |  |  |  |

 

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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$157.6 million based on observed market prices for the same or similar typeissues.

 

**Note 12**—**Revenue**

 

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

 

The Corvina oil is deliveredby tank vessel to the Petroperu refinery in Talara, located approximately70 miles south of the platform.  Produced oil is kept in productioninventory until the Company increases the inventory quantities to a sufficientlevel that the refinery in Talara will accept delivery.

 

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 million barrels ofcrude oil have been delivered to the Petroperu refinery located in Talara,whichever comes first. The price per barrel of oil under the agreement isdetermined using a basket of crude oils based on a 15-day average of Forties,Oman, and Suez blend crude oil prices, as quoted in the Spot Crude PricesAssessment published in Platt’s Crude Oilgram Price Report, minus $1 per barreland other customary purchase price adjustments.

 

In May 2010, theCompany, through its wholly-owned subsidiary BPZ E&P, entered into ashort-term 400,000 barrel oil supply agreement with Petroperu. Under the termsof the contract, the Company agrees to sell, and Petroperu agrees to purchasethe

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

Company’s 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 the Company is allowed to sell oil under thecontract as long as the salt content is less than 25 pounds per thousandbarrels of oil.  There is no purchaseprice adjustment associated with the oil sales if the salt content is less than10 pounds per thousand barrels.

 

In July 2010, theCompany, through its wholly-owned subsidiary BPZ E&P, entered into a secondshort-term 110,000 barrel oil supply agreement with Petroperu. Under the termsof the contract, the Company agrees to sell, and Petroperu agrees to purchasethe Company’s crude oil production originating from the Albacora oilfield inBlock Z-1. The price per barrel of oil under the agreement is determined usinga basket of crude oils based on a 15-day average of Forties, Oman, and Suezblend crude oil prices, as quoted in the Spot Crude Prices Assessment publishedin Platt’s Crude Oilgram Price Report, minus $4.30 per barrel and othercustomary purchase price adjustments. As part of the purchase price adjustments,the Company is 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 purchase priceadjustment associated with the oil sales if the salt content is between 25pounds and 60 pounds per thousand barrels. All 110,000 barrels under thissupply agreement were delivered and sold to Petroperu during the month of July2010.

 

During the three and sixmonths ended June 30, 2010, the Company produced approximately 375,673 and834,293 barrels of oil, respectively.  For the same periods in 2009, theCompany produced approximately 209,391 and 564,566 barrels of oil,respectively. For the three and six months ended June 30, 2010, theCompany sold 303,840 and 647,155 barrels of oil at an average per barrel price,net of royalties, of approximately $73.71, and $71.76, respectively. For thesame periods in 2009 the Company sold 205,836 and 536,683 barrels of oil at anaverage per barrel price, net of royalties, of approximately $53.68, and$45.23, respectively.

 

The Company’s revenues arereported net of royalties owed to the government of Peru. Royalties are assessedby 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 six months ended June 30, 2010, the revenues receivedby the Company are net of royalty costs of approximately 5% of gross revenuesor $1.2 million and $2.6 million, respectively. For the same periods in 2009,the revenues received by the Company were net of royalty costs of approximately5% of gross revenues or $0.6 million and $1.4 million, respectively.

 

**Note 13 — Income Tax**

 

Forthe three and six months ended June 30, 2010, the Company recognized an incometax expense of approximately $1.0 million and $2.2 million, respectively, on anet loss before income tax of approximately $3.2 million and $3.9 million,respectively.  For the same periods in2009, the Company recognized an income tax benefit of approximately $1.7 millionand $2.9 million, respectively, on a net loss before income tax ofapproximately $11.5 million and $19.7 million, respectively.  The difference between the effective tax raterecognized and the 22% statutory rate provided for under the Block Z-1 LicenseContract is largely 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 in the Company’s deferred taxasset balance is primarily due to the inability to deduct, for Peruvian incometax purposes, the amortization associated with its total investment, includingboth intangible drilling as well as exploration costs associated with BlockZ-1. As a result, the Company is subject to tax prepayments on a taxable incomeeven though the Company incurred a book loss. This will continue until theCompany transitions into the commercial stage of production as defined underthe 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 six months ended June30, 2010 and 2009, respectively, the Company did not have any accrued interestor penalties associated with any unrecognized tax benefits, nor was anyinterest expense recognized during those periods.

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

**Note 14 — 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, geographicareas, and major customers. The Company’s management reporting structureprovided for only one segment for the three and six months ended June 30, 2010and 2009 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 15 — Commitments and Contingencies**

 

*ExtendedWell Testing Regulation*

 

OnDecember 13, 2009 new legislation regulating extended well testing in Perubecame effective under a Supreme Decree.  The new regulation provides thatall new wells may be placed on production testing for up to six months. If the operator believes that additional time for testing is needed to 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 opinion on the technicaljustification for the EWT.  After the initial six month period or after anapproved EWT program expires, the operator will be required to have thenecessary gas and water reinjection equipment in place to continue producingthe well according to existing environmental regulations.  For wells thathave been under testing for more than six months as of the date of publicationof the Supreme Decree, the new regulation provides 30 business days to apply tothe DGH for the corresponding EWT permit. Additionally, during both the initialsix month testing period and any extended period that may be granted, theCompany must also obtain gas flaring permits for each well in order for it tobe in compliance with Peruvian environmental legislation.

 

*Transition to Commercial Production*

 

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.

 

TheCompany initially planned to have the needed gas and water re-injectionfacilities at the CX-11 platform by the approved FDCP of May 31,2010.  However, due to the delayeddelivery of certain equipment, the Company applied for a revised FDCP ofNovember 30, 2010 and received approval of the revised date from Perupetro inMay 2010.  Unless EWT periods areapproved, and upon expiration of such periods, all production will cease untilthe Company meets the requirements, including installation of water and gas re-injectionfacilities, to transition to commercial production.

 

Inthe Albacora field in Block Z-1, the Company is conducting the initialengineering study on the Albacora field to assess the equipment needs to injectthe associated gas and efficiently transition the field into commercialproduction in order to minimize potential future production interruptions dueto EWT regulations.

 

*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.

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

AtJune 30, 2010, the Company is producing oil under a testing program from theCX11-17D and A-14XD wells and has limited oil production from the CX11-22Dwell.  The first five Corvina wells wereclosed due to the expiration of the EWT period on or about May 31, 2010 and theCX11-19D well was closed in June 2010, in order for the Company to complete aminor workover to the well. The first five Corvina wells will remain closedunless the Company receives approval from the Ministry of Energy and Mines tocontinue oil production from these wells under another EWT period or the FDCP.

 

Subsequentto June 30, 2010, the workover on the CX11-19D well was completed, however theCompany was not able to place this well on production as the initial six monthtesting period had expired and the Company is awaiting approval from the Ministryof Energy and Mines to continue oil production from this well.  Also subsequent to June 30, 2010, the Companyreceived initial notice that its applications for the first five Corvina wellsand the CX11-19D well to enter an extended well testing period have been deniedby the DGH.  The Company has requestedthe DGH reconsider its denial of the Company’s applications because the Companybelieves that recent well results further emphasize the need for additionaltesting. 

 

Additionally,early in July 2010, the Company suspended production from the A-14XD well forapproximately two weeks because the initial six month testing periodexpired.  The Company received a sixmonth 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.

 

Althoughthe Company has requested the DGH reconsider the denial of the EWT and gasflaring permits for the first five Corvina wells and the CX11-19D, no assurancecan be given that DGH or the Ministry of Energy and Mines will grant approvalof these permits or any future permits requested by the Company. As such, theCompany’s current view is that it may only be able to produce its new wells forup to six months under the new well testing regulations.  Testing of these wells beyond the initial sixmonth period will require application to the Ministry of Energy and Mines,which may not grant approval.

 

Withrespect to the Corvina field, the Company is drilling an additional well, theCX11-23D, prior to the installation of the gas and water reinjectionfacilities, which are expected to be completed on or around November 30, 2010.

 

Withrespect to the Albacora field, the Company intends to request additional EWTand gas flaring permits for all wells after their initial six month testingperiod, until the appropriate gas and water reinjection facilities areinstalled and operational.

 

*EcuadorianHydrocarbon Law*

 

Subsequent to June 30, 2010,the Company became aware of a new Ecuadorian hydrocarbon law that will allowthe Ecuadorian government to nationalize oil fields if a private operator does notcomply with local laws.  The new law went into effect on July 26,2010.  Besides allowing for the nationalization of private companies thatdo not comply with local laws, the legislation aims to change currentproduction-sharing arrangements under 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 issued toIFC in a private transaction during September 2009, the Company receivedcomments from the SEC pertaining to its registration statement, Form 10-K forthe 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 the relatedearnings press release. In general, the questions or comments from the SECrelated to: (i) clarifications in several of the Company’s disclosures; (ii)the basis for the assumptions underlying its SEC oil reserves reported for 2008in light of its actual production performance in 2009; (iii) the reasons its2009 production fell short of 2008 projections; (iv) the consideration theCompany gave to the reasonable certainty of its assumptions underlying its SECoil reserves and the related accounting reported in its financial statements;and (v) how the Company is taking into consideration certain items anduncertainties for its 2009 reserves report. 

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

The Company promptlyresponded to the SEC’s requests and, where appropriate, made clarifications toits disclosures. On April 14, 2010, the SEC notified the Company that they hadno further comments at that time.

 

*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 mining activities.Hydrocarbons are included under “Companies Performing Other Activities”, thusOil and Gas Companies pay profit sharing at a rate of 5%. The 5% of income isdetermined by calculating a percentage of the Company’s Peruvian subsidiaries’annual total revenues subject to income tax less the expenses required toproduce revenue or maintain the source of revenues. The benefit granted by thelaw to employees is calculated on the basis of “income subject to taxation” perthe Peruvian tax code, and not based on income/(loss) before incomes taxes asreported under GAAP. For the three and six months ended June 30, 2010,approximately $0.7 million and $1.6 million of expense related to profitsharing is included in “General and administrative expense” in the ConsolidatedStatement of Operations as the Company’s Peruvian subsidiaries have “incomesubject to taxation” per the Peruvian tax code. For the same periods in 2009,the Company incurred profit sharing expense of $0.2 million and $0.5 million,respectively. The Company is subject to profit sharing expense each year itsPeruvian subsidiaries are considered profitable under the Peruvian tax code.

 

*BargeIncident*

 

In August 2006, theCompany incurred an operational delay resulting from a navigation incident whichcaused the BPZ-01 barge to be grounded on a sand bar in Talara Bay in northwestPeru.  The Company expects to file an insurance claim after the drydocking of the vessel, which is scheduled for the first quarter of 2011. As of June 30, 2010, the Company has not presented a final claim to itsinsurance carrier for the barge repairs.

 

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

 

*PerformanceBonds and Obligations*

 

As of June 30, 2010,the Company has restricted cash deposits of $4.5 million. In connection withthe 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 $0.8 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.

 

*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 LM6000 gas-fired turbines from GE Packaged Power, Inc. and GE International, Inc.Sucursal de Peru (collectively “GE”). The Agreement required an initial downpayment of $5.1 million and monthly progress payments of $1.1 million per unit.In January 2009, BPZ and GE entered into an amendment of the contract.Under the terms of the amendment, both GE and BPZ agreed to a suspension periodunder the Agreement from and including December 15, 2008 throughNovember 15, 2009, whereby no failure on the part of BPZ or GE to performany obligations under the Agreement would give rise to a breach of contract orthe right to terminate the contract, provided the Company make a $3.4 millionprogress payment no later than February 25, 2009, and a $3.5 millionprogress payment to GE no later than November 16, 2009. On February 24,2009, the Company paid the first progress payment of $3.4 million. The Companywas still in negotiations with GE to modify the terms of the Agreement at thetime the second progress payment was due on November 16, 2009, and GEagreed to a short extension of the deadline for the milestone payment in orderto conclude ongoing negotiations with respect to new delivery dates, pricing,payment terms and payment security for the reinstatement of the Agreement.Amended terms were agreed with GE by Letter Agreement on

 

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**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

November 20, 2009, atwhich time the Company made the $3.5 million progress payment. Under the termsof the Letter Agreement, GE and BPZ agreed to a variable monthly payment planwith a final $20.7 million payment due December 1, 2010.  Additionally, should the Company locate ajoint venture partner and obtain financing for the three LM6000 gas-firedturbines and services prior to the December 1, 2010 deadline, the Companyagrees to pay the final payment under the Letter Agreement within 7 days ofobtaining the financing and funding.

 

Should the Company not makethe payments in accordance with the terms of the Letter Agreement, this wouldresult in immediate termination of the Agreement without any additional noticeor cure period. As of June 30, 2010, the Company has made payments to GEtotaling $21.0 million. Additionally, through August 9, 2010 the Company madeadditional payments of $2.5 million and plans to meet the remaining paymentsdue throughout 2010 by using proceeds of the convertible debt offering orsubsequent project financing. Failure to make any of the remaining progresspayments in full would result in a charge-off of all of the previously madeprogress payments.

 

*Gas-to-Power Project Financing*

 

The Corvina gas-to-powerproject entails the installation of a 10-mile gas pipeline from the CX-11platform 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 identifiedand held initial discussions with 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 project. However, the Company expects toretain the responsibility for the construction of the pipeline as well asretain ownership of the pipeline. If the Company is unable to identify andreach an agreement with a potential partner, it plans to continue moving theproject forward to completion without a partner. The Company is currently inthe process of identifying and securing the additional financing necessary tomove the project forward.

 

**Note 16 — Legal Proceedings**

 

*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 operation. Based on the Company’s assessment of the available facts, including thefact that none of the Peruvian government-sanctioned investigations into theSupe incident found fault on the part of Tecnomarine or BPZ E&P, theCompany does not believe the outcome of the legal proceeding will have amaterial adverse effect on its financial condition, results of operations orcash flows. The Company intends to vigorously defend this action but cautionsthat there is inherent risk in litigation, which is difficult to quantify,especially at the early stage of litigation proceedings. In any event, theCompany believes that any monetary damages arising from the incident would be adequatelycovered by its insurance policies, after a customary deductible.

 

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** **

**BPZ Resources, Inc. andSubsidiaries**

**Notes To Consolidated FinancialStatements**

**(Unaudited)**

 

**Note 17 — Subsequent Events**

 

Thefollowing events took place subsequent to June 30, 2010:

 

TheCompany, through its wholly-owned subsidiary BPZ E&P, entered into ashort-term 110,000 barrel oil supply agreement with Petroperu. For furtherinformation see Note 12, “Revenue”.

 

The Company received noticeregarding the status of its application for an EWT permit for the CX11-19D andfirst five Corvina wells. For further information see Note 15, “Commitments andContingencies”.

 

TheCompany closed the A-14XD well for approximately two weeks during July until itreceived EWT and gas flaring permits to re-open the well.  For further information see Note 15, “Commitmentsand Contingencies”.

 

TheCompany purchased the leased production equipment onboard the floating,production, storage and offloading vessel, Namoku. For further information seeNote 9, “Long-Term Debt and Capital Lease Obligations”.

 

The Company issued certainstock-based compensation awards. See Note 10 “Stockholders’ Equity” for furtherinformation.

 

TheCompany became aware of a new Ecuadorian hydrocarbon law that will allow theEcuadorian government to nationalize oil fields if a private operator does notcomply with local laws.  For further information see Note 15, “Commitmentsand Contingencies”.

 

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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 withoffices in Lima, Peru and Quito, Ecuador. We are focused on the exploration,development and production of oil and natural gas in Peru and to a 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 in November 2001,the Block XIX contract was signed in December 2003 and Blocks XXII andXXIII contracts were signed in November 2007. Generally, according to theOrganic Hydrocarbon Law No. 26221 and the regulations thereunder (the “OrganicHydrocarbon Law” or “Hydrocarbon Law”), the seven-year term for the explorationphase can be extended in each contract by an additional three years up to amaximum of ten years. However, specific provisions of each license contract canvary the exploration phase of the contract as established by the HydrocarbonLaw. The license contracts require us to conduct specified activities in therespective blocks during each exploration period in the exploration phase. Ifthe exploration activities are successful, we may decide to enter theexploitation phase and our 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 inour Block Z-1, the 40-year term may apply to oil exploration and production aswell.

 

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 of appraising,exploring and developing our potential oil and natural gas reserves from the Aplatform in the Albacora field of Block Z-1 and began selling oil during thesecond quarter of 2010.  From the time webegan producing from the CX-11 platform in the Corvina field in November 2007and the Albacora field in December 2009, through June 30, 2010, we haveproduced approximately 2.7 million barrels 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 FDCP is November 30,2010;

 

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·                              Development ofthe Albacora field in Block Z-1 where we have commenced drilling and beguninitial production well testing. We will also need to install equipment inAlbacora as necessary to comply with Peruvian environmental regulations and areplanning on an approximately two-year period to transition to commercialproduction;

 

·                              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 been developedand related financing has yet to be obtained, preventing us from reportingvolumes 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 license properties and build our reportableasset values;

 

·                              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 other properties, preparation of the development plans for the properties,refurbishment of and designs for platforms to perform our drilling campaigns inthe Corvina and Albacora fields in Block Z-1, procuring machinery and equipmentfor an 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 andefficiently (i) quantify the potential value of our oil and gas holdingsin Peru; (ii) increase production and cash flows from our identifiedholdings; and (iii) create a revenue stream through implementation of ourgas-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 monetize our future natural gas production.

 

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. The gas-to-powerproject will generate a revenue stream by creating a market for the gasdiscovered in our Corvina field that is currently shut-in.  We plan to utilize part of our future naturalgas production as a supply source for the development of a gas-fired powergeneration facility in Peru, which we currently plan to wholly- or partially-own.This project has not yet been financed and we continue to consider the bestfinancing alternatives for the project.

 

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**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 opinion on the technicaljustification for the EWT.  After the initial six month period or after anapproved EWT program expires, the operator will be required to have thenecessary gas and water reinjection equipment in place to continue producingthe well according to existing environmental regulations.  For wells thathave been under testing for more than six months as of the date of publicationof the Supreme Decree, the new regulation provides 30 business days to apply tothe DGH for the corresponding EWT permit. Additionally, during both the initialsix month testing period and any extended period that may be granted, we mustalso obtain gas flaring permits for each well in order for us to be incompliance with Peruvian environmental legislation.

 

**Transition to CommercialProduction**

 

OnDecember 29, 2009, we received approval, from Perupetro, of our proposedfirst date of commercial production (“FDCP”), as set forth in the current fielddevelopment plan (“FDP”) for the Corvina field in Block Z-1, which wasMay 31, 2010.

 

Weinitially planned to have the needed gas and water reinjection facilities atthe CX-11 platform by the approved FDCP of May 31, 2010.  However, due to the delayed delivery ofcertain equipment, we applied for a revised FDCP of November 30, 2010 andreceived approval of the revised date from Perupetro in May 2010.  UnlessEWT periods are approved, and 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.

 

In the Albacora field in Block Z-1, we areconducting the initial engineering study on the Albacora field to assess theequipment needs to inject the associated gas and efficiently transition thefield into commercial production in order to minimize the potential futureproduction interruptions due to EWT regulations.

 

**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 extended welltesting permit for the first five producing wells in Corvina (the CX11-21XD,CX11-14D, CX11-20XD, CX11-18XD and the CX11-15D wells, collectively the “firstfive Corvina wells”) to continue gathering data to fully understand the drivemechanisms that are present in Corvina. On March 23, 2010, we received a decision from the DGH notifying us ofapproval to continue extended well testing on our first five Corvina wells,until the original FDCP date of May 31, 2010, subject to specific limits on theamount of natural gas flared from each of the first five Corvina wells.

 

AtJune 30, 2010, we are producing oil from the CX11-17D and the A-14XD wells andhave limited testing oil production from the CX11-22D well.  The first five Corvina wells were closed dueto the expiration of EWT period and the CX11-19D well was closed in order forus to complete a minor workover to the well. The first five Corvina wells willremain closed unless we receive approval from the Ministry of Energy and Minesto continue oil production from these wells or the FDCP.

 

Subsequentto June 30, 2010, the workover on the CX11-19D well was completed, however wewere not able to place this well on production because the initial six monthtesting period had expired and we are awaiting approval from the Ministry ofEnergy and Mines to continue oil production from this well.  Also subsequent to June 30, 2010, we receivedinitial notice that our applications for the first five Corvina wells and CX11-19Dwell to enter an extended well testing period have been denied by the DGH.  We have requested the DGH reconsider itsdenial of our applications because we believe that recent well results furtheremphasize the need for additional testing. 

 

Additionallyin early July 2010, we suspended production from the A-14XD well because theinitial six month testing period expired. However, in July 2010, we received a six month extended well testingpermit and a six month gas flaring permit that should allow us to continue oilproduction of this well at the same level as the well’s initial six monthproduction.

 

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Althoughwe have requested the DGH reconsider the denial of the EWT and gas flaringpermits for the first five Corvina wells and the CX11-19D, no assurance can begiven that DGH or the Ministry of Energy and Mines will grant approval of thesepermits or any future permits requested by us. Our current view is that we maybe able to produce our new wells for at least six months, under the new welltesting regulations.  Testing of thesewells 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 plan on drilling an additional well, theCX11-23D, prior to the installation of the gas and water reinjection facilitieswhich is expected to be completed on or around November 30, 2010.

 

Withrespect to the Albacora field, we intend to request additional EWT and gasflaring permits for all wells until the appropriate gas and water reinjectionfacilities are installed and operational.

 

**Oil Development**

 

 ***General***

 

We will conduct additional drilling activitiesbased in part on an ongoing assessment of economic efficiencies, likely successand logistical issues such as license requirements, scheduling, requiredmaintenance and replacement of equipment.  This assessment could result inincreased emphasis and activities on a given prospect and conversely, could resultin decreased emphasis on a given prospect for a period of time.  Inparticular, we will assess allocation of our current resources among theCorvina, Albacora, and Delfin fields and certain onshore prospects as theydevelop, as well as our gas-to-power project.

 

***Seismic Data Acquisition***

 

We are in the initialprocess of acquiring seismic data to assist us in exploring, appraising anddeveloping certain areas of interest within our blocks located in northwestPeru. The purpose of the seismic survey is to improve the subsurface imaging ofcertain areas within the blocks in order to better define the position offuture wells as well as to comply with our exploration commitments under ourlicense contracts.

 

For Block Z-1, we intend toacquire approximately 1,500 square kilometers of three dimensional (“3-D”)seismic data.  The 3-D seismic data survey will include areas of interestwithin the Corvina, Albacora, and Delfin fields as well as certain prospectsand leads located within the Mero and Piedra Redonda regions and certain deepwater leads located within Block Z-1. Additionally, the 3-D seismic survey willinclude data underneath four existing platforms in the Albacora, Corvina andPiedra Redonda fields.  The seismic data survey will fulfill our commitmentsunder the fourth exploration period of the Block Z-1 license contract ifconducted within the allowed contractual time frame.  We initially attempted to conduct thisseismic survey in late 2009, but suspended the survey as directed by theMinistry of Energy and Mines, due to issues relating to our corporate socialresponsibility program and a requirement that all stakeholders in our area ofinfluence understood and participated in the environmental permittingprocess.  We are currently working on anew seismic environmental permit and we estimate the 3-D seismic data survey tobe completed by the end of 2011.

 

 For Block XXIII, we intend to acquireapproximately 360 square kilometers of 3-D seismic data and 290 kilometers oftwo dimensional (“2-D”) seismic data which will include certain areas ofinterest within the Palo Santo region and four other prospects that are part ofthe Mancora gas play.  The seismic survey was initiated in July 2010 andwe expect the 3-D and 2-D seismic data survey to be completed by the firstquarter of 2011.

 

For Block XXII, we intend toacquire 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 by the first quarter of 2011.

 

***Corvina Field***

 

Weare producing oil from the CX-11 platform, located in the Corvina field withinthe offshore Block Z-1, under a well testing program that started onNovember 1, 2007.  The Corvina field consists of approximately 47,000acres in water depths of less than 300 feet.  We are currentlyconcentrating our drilling efforts on West Corvina, which consists of 3,500acres and have completed a total of eight oil wells, the CX11-22D, theCX11-17D, the CX11-19D, the CX11-15D, the CX11-21XD, the CX11-20XD, theCX11-18XD and the CX11-14D.  The oil is delivered by tank vessel to thePetroperu refinery in Talara, located approximately 70 miles south of theplatform.  Produced oil is kept in production inventory until such time itis delivered to the refinery.

 

In February 2010, wecompleted the CX11-17D well in the Corvina field in offshore Block Z-1 innorthwest Peru. The

 

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CX11-17D well is the seventhoil well from the CX-11 platform and has been placed into the production welltesting program. The CX11-17D well was drilled and successfully completed intoa proved undeveloped area of the Corvina field, targeting sands produced by ourother 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. In July 2010, production from CX11-19D was stopped as theinitial six month testing period expired. Testing still needs to be performedto evaluate the results of the workover.

 

In late June 2010, wecompleted the testing of the CX11-22D well in the Corvina field in offshoreBlock Z-1 in northwest Peru and placed the well into the well testing programin July 2010. The CX11-22D well was drilled in an up dip location of theCorvina field to continue appraising its oil and gas potential.  The wellhas two drill strings to allow it to simultaneously produce oil and reinjectformation water as part of our plan to transition to commercial production inCorvina. The long string of the dual completion string targets one set of oilsands while the short string will be used for water reinjection. The welltested oil but with high gas rates due to gas coming from one of the higherintervals that was opened to help define the gas-oil contact.  The wellfailed to achieve a consistent initial production rate because of the resultinghigh gas-to-oil ratios.  Well test data indicates that this is not the gaschanneling issue that occurred in previous wells.  To avoid any delays intransitioning Corvina to commercial production, we plan to work over this wellto isolate the gas sands once drilling of the CX11-23D is completed and thefield enters commercial production.  The CX11-22D is being producedintermittently to manage the amount of gas produced with the oil.

 

In July 2010, we begandrilling the CX11-23D well. This well is expected to be the last well drilledfrom the CX-11 platform. We expect this well to be completed during the thirdquarter of 2010. After the completion of the CX11-23D, we plan to begin theinstallation and commissioning of the gas and water reinjection equipment, in orderto meet the revised projected FDCP of November 30, 2010.

 

Typically, the Corvina oilwells have seen initial production declines rates of approximately 50% duringthe first year of production before stabilizing. Although each of the Corvinawells have declined differently, partly due to the fact that these wells werecompleted in different zones and some of the wells encountered mechanicalproblems, they all have initially shown typical solution gas drive behaviorwhich can lead to significant production declines during the first year beforeleveling off to sustainable rates. We do not believe these results areindicative of the Corvina field generally, but are instead the result oftechnical/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, as 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 water reinjectionequipment and get our produced oil to market. While we do not foreseedifficulties 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 productionforecast and remaining reserves to be produced.

 

Currently, all wells in theCorvina field are being tested and produced under the new well testingregulation giving companies six months to evaluate a well before applying forthe extended well testing program. We initially planned to have the needed gasand water reinjection facilities at the CX-11 platform by the initial approvedFDCP of May 31, 2010.  However, dueto the delayed delivery of certain equipment, we applied for a revised FDCP ofNovember 30, 2010 and received approval for the revised date from Perupetro.

 

AtJune 30, 2010, we are producing oil from the CX11-17D well and have limited oilproduction from the CX11-22D well.  Thefirst five Corvina wells and the CX11-19D well were closed at the end of May2010 and during June 2010, respectively, and will remain closed unless wereceive the EWT and gas flaring approval from the Ministry of Energy and Minesto allow us to continue oil production from these wells, or the First Date ofCommercial Production.

 

We are attempting to haveall gas and water reinjection equipment in place by November 30, 2010, as wellas have all other requirements complied with, at which time all wells in theCorvina field would be placed into commercial production. Any delays indelivering or commissioning reinjection equipment or delays in other permittingaspects may force us to keep our Corvina wells closed, until we are ready totransition from exploration to exploitation, unless we obtain approval forextended well testing and associated gas flaring for each well as required byPeru regulations.

 

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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, under a well testing program pursuant to thenew regulations.

 

In January 2010, wecommenced drilling the A-15D, the second Albacora well, which was to be drilledto approximately 13,000 feet vertical depth and intended to test prospectivesands below the lowest known oil sands tested or produced to date in the field.In mid-January 2010, we stopped oil production and drilling activities inorder to install the production equipment on the A platform.  In February 2010, we resumed drilling ofthe A-15D well as well as resumed testing the A-14XD.

 

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 was evidentlycaused when one of the main beams supporting the top deck of the platform bentdue to the concentration of stresses at the base of the drilling rig.  The platform was temporarily repaired andsubsequently, we began drilling the A-16D well, a follow up to the A-15D well,in April 2010.

 

TheA-16D well was originally intended to follow the same trajectory as the A-15Dwith 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 May2010, we began drilling the A-17D well. This well is expected to be completed during the third quarter of 2010.

 

In May 2010, we,through our wholly-owned subsidiary BPZ E&P, entered into a short-term400,000 barrel oil supply agreement with Petroperu. Under the terms of theagreement Petroperu agrees to purchase up to 400,000 barrels of 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 we are allowed to sell oil underthe contract as long as the salt content is less than 25 pounds per thousandbarrels of oil.  There is no purchaseprice adjustment associated with salt content if the salt content is less than10 pounds per thousand barrels.

 

In July 2010 we,through our wholly-owned subsidiary BPZ E&P, entered into a secondshort-term 110,000 barrel oil supply agreement with Petroperu. Under the termsof the agreement, Petroperu agrees to purchase the oil production originatingfrom the Albacora oilfield in Block Z-1. The price per barrel of oil under theagreement is the same as under 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. This contract allows us to sell some of our oil whilecompleting the installation of specialized oil desalting equipment at theAlbacora platform.  All 110,000 barrelsunder this supply agreement were delivered and sold to Petroperu during themonth of July 2010. In addition, the A platform was fully repaired.

 

Consistentwith our methodology for Corvina, we have requested our independent petroleumengineers, Netherland, Sewell & Associates, Inc. (“NSAI”), to evaluatethe reserves of the Albacora oil field using what we believe are reasonablyconservative estimates of known uncertainties, such as the scheduling fordrilling and installation of necessary production equipment and the timingduration to apply for and receive the necessary regulatory permits. Therefore,we conservatively simulated the closure of certain production over a period oftime reasonably expected to occur while these issues are being resolved.

 

**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 dated December 16,2006 (the “Subscription Agreement”) by and between IFC and us, IFC has theright, within 45 days of notice of the offering, to purchase shares of ourcommon stock for the same price and terms as the participants in an offering toretain its proportionate ownership in us. IFC exercised its pre-emptive rightto purchase approximately 1.6 million shares of common stock at the offeringprice of $4.66 per share to which it was entitled under 

 

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the Subscription Agreement,resulting in gross proceeds to us of approximately $7.6 million. Thetransaction 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 SEC pertainingto 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**

 

TheCorvina gas-to-power project entails the installation of a 10-mile gas pipelinefrom the CX-11 platform to shore, the construction of gas processing facilitiesand a 135 megawatt (“MW”) simple-cycle power generation facility.  Theproposed 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 opportunities for us to generate and sellsignificantly greater volumes of power into the Peruvian and possiblyEcuadorian power markets.  Accordingly, the revenues from the natural gasdelivered to the power plant will be derived from the sale of electricity.

 

Wecurrently estimate the gas-to-power project will cost approximately $150.0million, excluding 19% value-added tax which will be recovered via futurerevenue billings.  The $150.0 million includes $130.0 million for theestimated cost of the power plant and $20.0 million for the natural gaspipeline. While we have identified and held initial discussions with potentialjoint venture partners for the gas-to-power project, in an attempt to secureadditional financing and other resources for the project, we have not enteredinto any definitive agreements with a potential partner.  In the event we are able to identify andreach an agreement with a potential joint venture partner, we may only retain aminority position in the project. However, we expect to retain theresponsibility for the construction and ownership of the pipeline. If we areunable to identify and reach an agreement with a potential partner, we plan tocontinue moving the project forward to completion without a partner. We arecurrently in the process of identifying and securing the additional financingnecessary to move the project forward.

 

**SECComments**

 

In connection with aregistration statement filed on October 21, 2009 to register shares issued toIFC in a private transaction during September 2009, we received comments fromthe SEC pertaining to our registration statement, our Form 10-K for the yearended December 31, 2008, our Definitive Proxy Statement filed on April 30,2009, and our Form 10-Q for the period ended September 30, 2009 and the relatedearnings press release. In general, the questions or comments from the SECrelated to: (i) clarifications in several of our disclosures; (ii) the basisfor the assumptions underlying our SEC oil reserves reported for 2008 in lightof our actual production performance in 2009; (iii) the reasons our 2009production fell short of 2008 projections; (iv) the consideration we gave tothe reasonable certainty of our assumptions underlying our SEC oil reserves andthe related accounting reported in our financial statements; and (v) how we aretaking into consideration certain items and uncertainties for our 2009 reservesreport. We promptly responded to the SEC’s requests and, where appropriate,made clarifications 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 June 30,2010 and 2009:

* *
| ** **                                        | ** ** | **Three Months Ended**               | ** ** | ** **    | ** ** | **Six Months Ended**                 | ** ** | ** **    | ** ** |
|---------------------------------------------------|------------|------------------------------------------------|------------|---------------|------------|------------------------------------------------|------------|---------------|------------|
| ** **                                        | ** ** | **June  30,**                                  | ** ** | **Increase/** | ** ** | **June  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)                                      |       | 304                                            |       | 206           |       | 98                                             |       | 647           |       | 537 |   | 110 |   |
| ** **                                        | ** ** | ** **                                     | ** ** | ** **    | ** ** | ** **                                     | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Net  revenue:                                     |       |                                           |       |          |       |                                           |       |          |       |   |   |   |   |
| Oil                                               |       | $                                              | 22,397     |          | $          | 11,049                                         |       | $             | 11,348     |   | $ | 46,442 |   | $ | 24,274 |   | $ | 22,168 |   |
| ** **                                        | ** ** | ** **                                     | ** ** | ** **    | ** ** | ** **                                     | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Average  sales price (approximately):             | ** ** | ** **                                     | ** ** | ** **    | ** ** | ** **                                     | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Oil  (per Bbl)                                    |       | $                                              | 73.71      |          | $          | 53.68                                          |       | $             | 20.03      |   | $ | 71.76 |   | $ | 45.23 |   | $ | 26.53 |   |
| ** **                                        | ** ** | ** **                                     | ** ** | ** **    | ** ** | ** **                                     | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Operating  expenses                               | ** ** | ** **                                     | ** ** | ** **    | ** ** | ** **                                     | ** ** | ** **    | ** ** | ** ** | ** ** | ** ** | ** ** |
| Lease  operating expense                          |       | 5,578                                          |       | 7,876         |       | (2,298                                         | )          | 10,342        |       | 11,854 |   | $ | (1,512 | ) |
| General  and administrative expense               |       | 8,203                                          |       | 7,998         |       | 205                                            |       | 16,229        |       | 16,481 |   | (252 | ) |
| Geological,  geophysical and engineering expense  |       | 402                                            |       | 553           |       | (151                                           | )          | 903           |       | 899 |   | 4 |   |
| Depreciation,  depletion and amortization expense |       | 8,045                                          |       | 5,508         |       | 2,537                                          |       | 17,534        |       | 13,386 |   | 4,148 |   |
| Total  operating expenses                         |       | $                                              | 22,228     |          | $          | 21,935                                         |       | $             | 293        |   | $ | 45,008 |   | $ | 42,620 |   | $ | 2,388 |   |
|                                              |       |                                           |       |          |       |                                           |       |          |       |   |   |   |   |
| Operating  income (loss)                          |       | $                                              | 169        |          | $          | (10,886                                        | )          | $             | 11,055     |   | $ | 1,434 |   | $ | (18,346 | ) | $ | 19,780 |   |

 

*NetRevenue*

 

For both the three and sixmonths ended June 30, 2010 and 2009, all oil sales were from oil produced underthe Peruvian well testing regulations.

 

For the three months endedJune 30, 2010, our net revenue increased by $11.3 million to $22.4 million from$11.0 million for the same period in 2009. The increase in net revenue is dueto an increase of $20.03, or 37%, in the average per barrel sales pricereceived and an increase in the amount of oil sold, 98 MBbls. During the secondquarter of 2010, oil prices have remained consistent at $70 - $80 per barrelcompared to steadily increasing prices in the second quarter of 2009 which rosesteadily from $48 -$68 per barrel.

 

Forthe three months ended June 30, 2010, we had seven producing wells in theCorvina field and one producing well in the Albacora field compared to fiveproducing wells in the Corvina field during the same period in 2009. Thisresulted in an increase in total oil production of 166 MBbls to a total of 375MBbls produced during the three months ended June 30, 2010 compared to 209MBbls during the same period in 2009. Although total production increased, dueto the high salt content within the oil produced from the Albacora field, themajority of oil produced from the Albacora field, except 28 MBbls which wesold, is included in inventory, 193,186 barrels at June 30, 2010. We recentlysigned an oil sales contract for oil to allow us to sell 110 MBbls of oiloriginating from the Albacora field with salt content of up to 60 pounds perthousand barrels.  We are also in theprocess of installing and commissioning specialized desalting equipment at theAlbacora platform that should allow us to further reduce the salt content tolevels acceptable by Petroperu.

 

Althoughthe number of wells contributing to sales increased in 2010, we constrained theoil production from all our wells in Corvina, except the CX11-17D and CX11-19D,in order to comply with the natural gas flaring limits set by the DGH. Inaddition, oil production from the CX11-14D well has been suspended sinceNovember 7, 2009 due to water issues in production that caused sandproduction and lifting issues. In June 2010, we suspended oil production fromthe CX11-19D well in order to perform a workover of that well and only obtainedlimited test production from the CX11-22D well. After the workover was completed on the CX11-19D well in July 2010, thewell was closed as the initial six month testing period had expired. Insummary, the majority of oil produced and sold in the three months ended June30, 2010 came from the latest wells, the CX11-17D and CX11-19D, which were not constrainedby the gas flaring limits during the quarter. During the three months ended June 30, 2009, oil production from theCX11-20XD well was partially suspended due to workover of the well and we hadlimited oil production from the CX11-15D well as that well was completed andbrought onto production towards the end of the quarter.

 

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For the six months ended June 30,2010, our net revenue increased by $22.1 million to $46.4 million from $24.3million for the same period in 2009. The increase in net revenue is due to anincrease of $26.53, or 59%, in the average per barrel sales price received andan increase in the amount of oil sold, 110 MBbls. During the six months ended June 30,2010, oil prices have remained consistent at $70 - $80 per barrel compared tosteadily increasing prices in 2009 which rose steadily from $31 -$68 perbarrel.

 

Forthe six months ended June 30, 2010, we had seven producing wells in theCorvina field and one producing well in the Albacora field compared to fiveproducing wells in the Corvina field during the same period in 2009. Thisresulted in an increase in total oil production of 270 MBbls to a total of 834MBbls produced during the six months ended June 30, 2010 compared to 565MBbls during the same period in 2009. Although total production increased, dueto the high salt content within the oil produced from the Albacora field, themajority of oil produced from the Albacora field is included in inventory(approximately 193 MBbls at June 30, 2010). In July 2010, we signedan oil sales contract for oil to allow us to sell 110 MBbls of oil originatingfrom the Albacora field with salt content of up to 60 pounds per thousandbarrels. All 110 MBbls of oil were delivered and sold to Petroperu during July.  We are also in the process of installingspecialized desalting equipment at the Albacora platform that should allow usto further reduce the salt content to levels acceptable by Petroperu in orderto re-initiate sales under the original 400,000 barrels short-term contract.

 

Weare currently attempting to have all the required Corvina gas and water reinjectionequipment in place by November 30, 2010, as well as have all otherrequirements complied with, at which time all wells in the Corvina field wouldbe placed into commercial production. Although we have submittedreconsideration requests for EWT and gas flaring permits for the first fiveCorvina wells and the CX11-19D well and plan to request additional EWT and gasflaring permits for all wells completed in the Albacora field until theappropriate gas and water reinjection facilities are installed and operational,there can be no assurance that the Ministry of Energy and Mines will grantapproval of these permits or any future permits requested by us. Under thecurrent Peruvian well testing regulation, new wells may be tested for a periodof six months. Testing of these wells beyond the initial six month period willrequire application to the Ministry of Energy and Mines, which may not grantapproval. We may also be required to obtain corresponding gas flaring permitsfrom 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 six months ended June 30, 2010, the revenuesreceived by us are net of royalty costs of approximately 5% of gross revenuesor $1.2 million and $2.6 million, respectively. For same periods in 2009, therevenues received by us are net of royalty costs of approximately 5% of grossrevenues or $0.6 million and $1.4 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 June 30,2010, lease operating expenses decreased by $2.3 million to $5.6 million($18.35 per Bbl) from $7.9 million ($38.23 per Bbl) for the same period in2009. The decrease in the lease operating expenses is comprised of decreasedworkover expenses of $1.6 million, decreased underwater flowline expenses of$1.3 million and increased expenses transferred to oil inventory of $1.7million.  Partially offsetting thesedecreases to expense are increases in equipment rental expense of $0.2 million,increased crude oil transportation costs of $0.6 million, increased lab fees of$0.3 million, increased pumping service costs of $0.4 million and increasedfuel costs of $0.8 million.

 

For the six months ended June 30,2010, lease operating expenses decreased by $1.5 million to $10.3 million($15.98 per Bbl) from $11.9 million ($22.09 per Bbl) for the same period in2009. The decrease in the lease operating expenses is comprised of decreasedworkover expenses of $1.6 million, decreased underwater flowline expenses of$1.2 million and increased expenses transferred to oil inventory of $3.2million.  Partially offsetting thesedecreases to expense are increases in equipment rental expense of $0.2 million,increased crude oil transportation costs of $2.0 million, increased lab fees of$0.3 million, increased maintenance and barge repairs of $0.5 million,increased pumping service costs of $0.4 million and increased fuel costs of$1.1 million.

 

For both the three and sixmonths ended June 30, 2010 compared to the same periods in 2009, thedecrease in lease operating expense is due to lower workover expenses andflowline repair expenses.  The majorityof increases in other expenses, including crude oil transportation costs, labfees, pumping services, and fuel costs, are being included in oil inventorycosts as the majority of oil production from the Albacora field is being heldin inventory (193,186 barrels at June 30, 2010) until we are able todeliver and sell the oil to Petroperu. The reason for the increase in expenses, including crude oiltransportation costs, lab fees, pumping services, and fuel costs,  is that we are operating in two fields in2010 while we were operating in only one field for the same period in 2009. In February 2010,we began chartering a double-hull tanker with a capacity of approximately65,000 barrels and leasing a storage vessel with capacity of approximately160,000 barrels in order to upgrade our oil transportation and storagecapabilities.  Therefore, we 

 

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expect the per barrel amountof lease operating expense to increase until oil production and sales increaseto a sufficient level to reduce per barrel expense of the monthly charteringand leasing costs and operating costs associated with these additional vessels.

 

*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 ended June 30,2010, general and administrative expenses increased $0.2 million to $8.2million from $8.0 million for the same period in 2009.  Stock-basedcompensation expense, a subset of general and administrative expenses, decreasedby $2.3 million to $1.4 million for the three months ended June 30, 2010from $3.7 million for the same period in 2009. The decrease in stock-basedcompensation expense is due to the vesting of the majority of awards granted in2007 and 2008, which were granted at a time when the grant date fair value washigher due to the high price of our common stock. Also contributing to thedecrease in stock based compensation is approximately $0.7 million ofstock-based compensation expense related to the accelerated vesting of certainrestricted stock and stock option awards granted to a former member of theBoard of Directors that occurred during the second quarter of 2009, which didnot occur during the same period in 2010. Other general and administrative expensesincreased $2.5 million to $6.8 million from $4.3 million for the same period in2009. The $2.5 million increase is due to increased salary and salary relatedexpenses of $1.0 million, increased professional fees of $1.0 million, whichincludes legal, consulting, accounting, and contract labor fees,  increased transportation costs of $0.1million, increased rent and equipment rental charges of $0.2 million andincreased non-deductible tax expenses of $0.1 million. .

 

For the six months ended June 30,2010, general and administrative expenses decreased $0.3 million to $16.2million from $16.5 million for the same period in 2009.  Stock-basedcompensation expense, a subset of general and administrative expenses,decreased by $3.7 million to $3.3 million for the six months ended June 30,2010 from $7.0 million for the same period in 2009. The decrease in stock-basedcompensation expense is due to the decrease in fair market value of awardsgranted in 2010 as a result of the decline in the stock price of BPZ and we areno longer recognizing as much stock compensation expense as a result of awardsgranted in previous years, with high grant date fair values, as these awardshave vested. Also contributing to the decrease in stock based compensation isapproximately $0.7 million of stock-based compensation expense related to theaccelerated vesting for certain restricted stock and stock option awardsgranted to a former member of the Board of Directors and that occurred duringthe second quarter of 2009 which did not occur during the same period in 2010.Other general and administrative expenses increased $3.5 million to $12.9million from $9.5 million for the same period in 2009. The $3.5 millionincrease is due to increased salary and salary related expenses of $2.0million, increased consulting fees of $0.9 million, increased maintenance andrepair expense of $0.3 million and increased rent expense of $0.3 million.

 

For both the three and sixmonths ended June 30, 2010, the increase in salary and salary relatedexpenses results from an aggregate bonus of $1.3 million awarded to certainexecutive and other key personnel during the current year with no correspondingbonuses awarded during the same periods in 2009.  Also contributing to the increase in salaryand salary related expenses is increased profit sharing expense. The increasein professional fees is due to increased reserve engineering analysis andconsulting for vessel leasing activities. The increase in rent expense is dueto the rental of new office space for our Peru office in the current year.

 

*Geological,Geophysical and Engineering*

 

Geological, geophysical andengineering expenses include laboratory, environmental and seismic acquisitionrelated expenses. For the three months ended June 30, 2010, geological,geophysical and engineering expenses decreased $0.2 million to $0.4 millioncompared to $0.6 million for the same period in 2009. For the six months ended June 30,2010 and 2009, geological, geophysical and engineering expenses remained flatat $0.9 million.

 

*Depreciation,Depletion and Amortization*

 

For the three months ended June 30,2010, depreciation, depletion and amortization expense increased $2.5 millionto $8.0 million from $5.5 million for the same period in 2009. For the sixmonths ended June 30, 2010, depreciation, depletion and amortizationexpense increased $4.1 million to $17.5 million from $13.4 million for the sameperiod in 2009. For both the three and six months ended June 30, 2010 and2009, the majority of depletion expense comes from oil sold from the Corvinafield. The depletion of Albacora costs are included in oil inventory until suchtime as we are able to sell the oil being stored to Petroperu. For the threemonths ended June 30, 2010, the increase in depreciation, depletion andamortization expense is due to increased sales and production compared to thesame period in 2009.  For the six monthsended June 30, 2010, the increase in depreciation, depletion andamortization expense is due to increased depletion expense as a result of areduction in the reserve base in 2009 that is partially offset by a decrease inthe average costs being amortized as the newer wells being brought ontoproduction have cost less to drill and 

 

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complete. The 2009 reserveanalysis as prepared by NSAI included a 1.6 MMBbls negative revision inreserves due to the lower than expected performance of the CX11-14D, CX11-18XD,and CX11-20XD wells.

 

*OtherIncome (Expense)*

 

For the three months ended June 30,2010, income from our investment in Ecuador property, net of investmentamortization, increased by $400,000 to income of $353,000 from an expense of$47,000 in 2009.  For the six monthsended June 30, 2010, income from our investment in Ecuador property, netof investment amortization, increased by $400,000 to income of $306,000 from anexpense of $94,000 in 2009.  For bothperiods, the difference is due to receiving $400,000 in payments during thethree and six months ended June 30, 2010, with no corresponding paymentsduring the same periods in 2009. For both the three and six months ended June 30,2010 and 2009, investment income / (expense) includes amortization expense ofapproximately $47,000 and $94,000, respectively.

 

Forthe three months ended June 30, 2010, we recognized approximately $3.7million of net interest expense which includes $6.8 million of interest expensereduced by $2.9 million of capitalized interest expense. For the same period in2009, we did not recognize any interest expense as we capitalized all interestexpense of $1.2 million to construction in progress. For the six months ended June 30,2010, we recognized approximately $5.7 million of net interest expense whichincludes $10.0 million of interest expense reduced by $4.3 million ofcapitalized interest expense. For the same period in 2009, we did not recognizeany interest expense as we capitalized all interest expense of $2.2 million toconstruction in progress.  For both thethree and six months ended June 30, 2010, the increase in interest expenseis due to the $170.9 million of 2015 Convertible Notes issued in the currentyear.

 

For the three months ended June 30,2010, other expense decreased by $0.5 million to income of approximately $5,000in 2010 from an expense of $0.5 million in 2009.  For the six months endedJune 30, 2010, other expense decreased by $1.3 million to income ofapproximately $11,000 in 2010 from an expense of $1.3 million in 2009. Thereason for the decrease in expense is due to approximately $1.3 million ofexpense incurred in 2009 that was not repeated in 2010. Approximately $0.8million of the $1.3 million was incurred during the first quarter of 2009 andrelated to the settlement of a disputed contractual obligation with a formerconsultant concerning services provided to both BPZ and its predecessor at thetime BPZ became publicly traded.  Anadditional $0.4 million of the $1.3 million was recognized during the secondquarter of 2009 and relates to stock options awarded to a former member of theBoard of Directors that was recognized upon issuance of the award.

 

*IncomeTaxes*

 

Forthe three and six months ended June 30, 2010, we recognized an income taxprovision of approximately $1.0 million and $2.2 million, respectively, on anet loss before income tax of approximately $3.2 million and $3.9 million,respectively. For the same periods in 2009, we recognized an income tax benefitof approximately $1.7 million and $2.9 million, respectively, on a net lossbefore income tax of approximately $11.5 million and $19.7 million,respectively. The difference between the effective tax rate recognized and the22% statutory rate provided for under the Block Z-1 License Contract is largelydue 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 in our deferred tax asset balance is primarily dueto the inability to deduct, for Peruvian income tax purposes, the amortizationassociated with its total investment, including both intangible drilling aswell as exploration costs associated with Block Z-1.  As a result, we are subject to tax prepaymentson a taxable income even though we incurred a book loss.  This will continue until we transition intothe commercial stage of production as defined under the Block Z-1 LicenseContract.

 

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 six months ended June 30,2010 and 2009, we did not have any accrued interest or penalties associatedwith any unrecognized tax benefits, nor was any interest expense recognizedduring those periods.

 

For the three months ended June 30,2010, our net loss decreased $5.6 million to a net loss of $4.3 million or($0.04) per basic and diluted share from net loss of $9.8 million or ($0.10)per basic and diluted share for the same period in 2009. For the six monthsended June 30, 2010, our net loss decreased $10.8 million to $6.0 millionor ($0.05) per basic and diluted share from $16.9 million or ($0.18) per basicand diluted share for the same period in 2009.

 

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**Liquidity, CapitalResources and Capital Expenditures**

 

At June 30, 2010, wehad cash and cash equivalents of $93.2 million and current accounts receivablerelated to our June oil sales of $2.5 million, all of which was collectedin July 2010. We also had $31.0 million in Value-Added Tax receivable,which we will collect over time as we invoice our oil sales.

 

AtJune 30, 2010, we had trade accounts payable and accrued liabilities of$34.8 million.

 

AtJune 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$138.1 million includes the $170.9 million of principal reduced by $32.8million of the remaining unamortized discount. At June 30, 2010, thecurrent and long-term portions of our capital lease obligations, primarilyrelated to the barges used in our marine operations were $4.5 million and $5.5million, respectively.

 
| ** **                  | ** ** | **For the Six Months Ended** | ** ** |
|-----------------------------|------------|------------------------------|------------|
| ** **                  | ** ** | **June 30,**            | ** ** |
| **Cash Flows**              | ** ** | **2010**                     | ** ** | **2009** | ** ** |
| ** **                  | ** ** | **(in thousands)**           | ** ** |
| Cash provided by (used in): |       |                         |       |   |   |
| Operating activities        |       | $                            | (12,661    | ) | $ | (13,405 | ) |
| Investing activities        |       | (74,124                      | )          | (29,531 | ) |
| Financing activities        |       | 161,863                      |       | 125,329 |   |
|                             |            |                              |            |  |  |  |  |

 

*Operating Activities*

 

Cash used in operatingactivities decreased by $0.7 million to a use of cash of $12.7 million for thesix months ended June 30, 2010 from a use of cash of $13.4 million for thesame period in 2009. The change in cash flow before changes in operating assetsand liabilities increased by $13.6 million reflecting a lower net loss of$10.8 million due to higher oil production revenues and higher non-cashamortization during 2010 compared to 2009. Changes in operating assets andliabilities provided a use of cash of $12.8 million.  The increase in the use of cash is due to: (1) loweraccount receivable balances due to the timing of oil deliveries and payments ofthose deliveries, $2.2 million; (2) increase in inventory balances dueincreased pipe, casing and accessories and higher oil inventory balances, $8.0million; (3) increase in other assets to secure additional pipe, casingand accessories, $4.1 million. Offsetting these uses of cash are changes in operating assets andliabilities including: (1) increases to the value-added tax receivable asa result of increased expenses, $1.4 million; and (2) increases in thechange to net liabilities of $0.1 million.

 

*Investing Activities*

 

Netcash used in investing activities increased by $44.6 million to cash usedin investing activities of $74.1 million for the six months ended June 30,2010 from $29.5 million in 2009 and is due to increased capital expenditures of$44.9 million in 2010 as our operations included two fields in 2010, theCorvina and Albacora fields, as opposed to operating only one field during thesame period in 2009, the Corvina field. Also contributing to the change ininvesting activities are changes in restricted cash providing a use of cash of$0.3 million.

 

*2010Equipment Activity*

 

During the six months ended June 30, 2010, we incurredcapital expenditures of approximately $76.4 million associated with our developmentinitiatives for the exploration and production of oil and natural gas reservesand the complementary development of proprietary gas-fired power generationfacility in Peru.

 

Of the incurred costsmentioned above, we incurred capital expenditures related to the drilling andtesting of the CX11-15D, CX11-23D ,CX11-17D and CX11-22D in the Corvina fieldof approximately $0.5 million, $0.2 million, $7.3 million and $18.4 million,respectively. In the Albacora field, we incurred capital expenditures relatedto the drilling of the A-15D, A-16D and A-17D of approximately $8.6 million,$6.5 million and $7.3 million, respectively.

 

In 2009, we entered into alease-purchase agreement to acquire the Don Fernando barge to serve as aconstruction lay barge as well as tender assist barge for drilling andconstruction operations and may be fitted to lay subsea pipe for thegas-to-power project.  

 

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During the six months ended June 30,2010, we capitalized an additional $2.9 million in order to have the bargeready to support our operations.

 

For the further developmentof the planned gas-fired power generation facility, BPZ incurred costs ofapproximately $5.6 million as part of our agreement to purchase three LM6000gas-fired turbines.

 

For the six months ended June 30,2010, we incurred approximately $1.8 million for upgrades to our existingplatforms as well as costs incurred in the construction of new platforms. Inaddition, we incurred $2.9 million in equipment for our production facilitiesat the A platform in Albacora and the CX-11 platform in Corvina. We incurred$5.1 million for the purchase of machinery and equipment used in operations inPeru, $0.3 million for the Caleta La Cruz dock refurbishment, $3.5 million inassets in transit, $0.5 million in furniture and improvements related to thenew offices in Peru and $0.2 million related to the asset retirement obligationfor the CX11-17D and CX11-22D wells.

 

Forthe three and six months ended June 30, 2010, in accordance with the “successfulefforts” method of accounting, we capitalized approximately $0.5 million and$0.9 million of depreciation expense, respectively, mainly related to thetender assist barges serving as support equipment, and $2.9 million and $4.3million of interest expense, respectively, to construction in progress. For thesame periods in 2009, we capitalized approximately $0.4 million and $0.7 millionof depreciation expense, respectively, and $1.2 million and $2.2 million ofinterest expense, respectively, to construction in progress.

 

For the three and six monthsended June 30, 2010, we recognized $8.0 million and $17.5 million ofdepreciation, depletion and amortization expense, respectively. For the sameperiods in 2009, we recognized $5.5 million and $13.4 million of depreciation,depletion and amortization expense, respectively.

 

*FinancingActivities*

 

Cash provided by financingactivities increased by $36.5 million to $161.9 million for the six monthsended June 30, 2010 comparedto $125.3 million for the same period in 2009. The increase in cash provided byfinancing activities is due to increased borrowings of $169.9 million and lowerrepayments of borrowings of $0.3 million that is partially offset by anincrease in cash paid for debt issue costs of $6.1 million a lesser amountraised cash raised through equity issuances in 2009 of $127.6 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 June 30, 2010 and December 31, 2009long-term debt and capital lease obligations consist of the following:

 
| ** **                                                                            | ** ** | **June 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 ($32.8) million |       | 138,090                 |       | —                      |       |
| Capital Lease Obligations                                                             |       | 9,973                   |       | 11,910                      |       |
| Other                                                                                 |       | —                  |       | 1,023                       |       |
|                                                                                  |       | 163,063                 |       | 27,933                      |       |
| Less: Current Portion of Long-Term Debt and  Capital Lease Obligations                |       | 9,493                   |       | 5,352                       |       |
|                                                                                  |       | $                       | 153,570    |                        | $          | 22,581 |   |

 

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*$170.9million Convertible Notes due 2015*

 

In February and March 2010,we closed on the private offering for an aggregate $170.9 million convertiblenotes due 2015 (the “2015 Convertible Notes”). The 2015 Convertible Notesoffering was comprised of (i) the initial $140.0 million of 2015Convertible Notes sold in an initial private offering, (ii) the exercise,by the initial purchaser, of a 30-day option to purchase an additional $21.0million of 2015 Convertible Notes, and (iii) IFC’s election to participatein the offering, pursuant to a contractual right, 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 us and Wells Fargo Bank, National Association, as trustee (“theIndenture”).

 

The 2015 Convertible Notesare our general senior unsecured obligations and rank equally in right ofpayment with all of our other existing and future senior unsecuredindebtedness.  The 2015 Convertible Notes are effectively subordinate toall of our secured indebtedness to the extent of the value of the assetscollateralizing such indebtedness.  The 2015 Convertible Notes are notguaranteed by our subsidiaries.

 

We will pay interest on the2015 Convertible Notes at a rate of 6.50% per year on March 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, 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 June 30,2010, 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 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 ourcommon 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 second businessday 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 to 100%of the principal amount of the notes to be purchased plus any accrued andunpaid interest to, but excluding, the purchase date.

 

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 

 

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default arising out ofcertain bankruptcy events (as set forth in the Indenture), the principal andaccrued and unpaid interest (including additional interest or premium, if any),on the notes 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 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 separately accountfor 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 $6.4million, $11.1 million, $11.1 million, $11.1 million, $11.1 million and $176.5million, respectively.

 

Asof June 30, 2010, the net amount of $138.1 million includes the $170.9million of principal reduced by $32.8 million of the remaining unamortizeddiscount. The net amount of the equity component is $33.3 million which includesthe initial discount of $34.6 million reduced by $1.3 million of directtransaction costs. The remaining unamortized discount of $32.8 million will beamortized into interest expense, using the effective interest method, over theremaining life of the loan agreement, whose term expires in March 2015.  At June 30, 2010, using the currentconversion rate of 148.3856 shares per $1,000 principal amount of the 2015Convertible 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.  However, we are currentlylimited, by NYSE rules, to issuing up to 23,031,663 shares (19.99% of the stockoutstanding at the time of the issuance of the 2015 Convertible Notes) in satisfactionof conversion of the 2015 Convertible Notes. Should we need to issue shares inexcess of the 19.99% limit, we would need approval by the affirmative vote ofthe majority of shareholders in order to issue the shares in excess of the19.99% limit. As of June 30, 2010, there is no excess if-converted valueto the holders of the 2015 Convertible Notes as the price of our common stockat June 30, 2010, $4.15 per share, is less than the conversion price.

 

Forboth the three and six months ended June 30, 2010, the effective interestrate for the 2015 Convertible Notes is 12%; including the amortization of debtissue costs, the effective interest rate is 12.6%.

 

Theamount of interest expense related to 2015 Convertible Notes for the threemonths ended June 30, 2010 is $5.1 million, disregarding capitalizedinterest considerations, and includes $3.6 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 six monthsended June 30, 2010 is $6.5 million, disregarding capitalized interestconsiderations, and includes $4.5 million of interest expense related to thecontractual interest coupon, $1.7 million of non-cash interest expense relatedto the amortization of the discount and $0.3 million of interest expenserelated to the amortization of debt issue costs.  There were no similar expenses for the sameperiod in 2009.

 

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*$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 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 on the value of oil reserves.  Inaddition, we are subject to various financial covenants calculated as of thelast day of each quarter, including a life of field coverage ratio, life ofloan coverage ratio, debt to equity ratio and interest coverage ratio. In February 2010,we received a waiver from IFC for the life of field coverage ratio and life ofloan coverage ratio through August 2010. We also requested and received awaiver 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 for three gas-fired turbines to IFC untilDecember 2010. Accordingly, we were in compliance with all materialcovenants of the Loan Agreement as of June 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 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) declare all or part of the principal amount of the loan, togetherwith accrued interest, payable on demand; or (iv) declare any and all ofthe security documents under the facility enforceable and exercise its rightsunder such documents. In addition, if any borrower is liquidated or declaredbankrupt, all loans and interest accrued on it or any other amounts due, willbecome immediately due and payable without notice.

 

*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%.

 

Subsequent to June 30,2010, we exercised the second year purchase option and purchased the capitallease production equipment used on board our floating, production, storage andoffloading vessel, the Namoku.

 

Forthe three and six months ended June 30, 2010, we recognized approximately$3.7 million and $5.7 million of net interest expense, respectively, whichincludes $6.6 million and $10.0 million of interest expense, respectively,reduced by $2.9 million and $4.3 million of capitalized interest expense, respectively.For the same periods in 2009, we did not recognize any interest expense as wecapitalized all interest expense of $1.2 million and $2.2 million,respectively, to construction in progress.

 

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*PerformanceBonds*

 

As of June 30, 2010, we haverestricted cash deposits of $4.5 million. In connection with our properties inPeru, we have obtained four performance bonds totaling $5.3 million that arepartially collateralized by restricted cash deposits of $3.1 million to insurecertain performance obligations and commitments under the license contracts forBlocks Z-1, XIX, XXII and XXIII. Additionally, we have $0.8 million ofrestricted cash to collateralize insurance bonds for import duties related tothe Don Fernando barge and $0.6 million of restricted cash to insure certainperformance obligations and commitments at our gas-to-power project site nearTumbes. In addition, we have an unsecured performance bond of $0.1 million toguarantee our performance under an office lease agreement in 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.

 

**LiquidityOutlook**

 

  Weestimate for the remaining half of 2010 our required principal and interestpayments for our outstanding debt to be approximately $8.3 million, ourrequired principal and interest payments for our capital leaseobligations to be approximately $3.5 million, our operating leasepayments to be approximately $13.7 million and capital expenditures to beapproximately $100.4 million (which includes $63.3 million for the drilling,development and production in the Corvina field and Albacora field, both fieldsare located in Block Z-1 in northwest Peru, $2.3 million in other capitalizedcosts, $4.1 million for additional marine support operations and $30.7 million forthe three LM6000 gas-fired turbines). In addition, we expect to incurapproximately $18.0 million in seismic acquisition costs for Blocks XXII andXXIII.

 

Ourmajor sources of funding to date have been through oil sales, equity raises,convertible debt issuances and, to a lesser extent, debt financingactivities.  With our current cashbalance, current and prospective Corvina and Albacora oil development cashflow, our recent convertible debt issuance, other potential third-partyfinancing and potential financing from future equity raises, we believe we willhave sufficient capital resources to execute our current Corvina and Albacoraoil development projects as well as service our current debt obligations andplan to continue pursuing our gas-to-power project once project funding becomesavailable. However, the timing and execution of our project is dependent on avariety of factors, including the technical design of facilities, permittingapproval, timely installation ofreinjection equipment and transition to commercial production,availability of equipment, time and costs required for delivery of materialsand construction operations, performance by contractors and the success ofplanned financing, many of which factors are outside our control and cannot beassured.

 

**Off-Balance SheetArrangements**

 

As of June 30, 2010, we had notransactions, agreements or other contractual arrangements with unconsolidatedentities or financial partnerships, often referred to as special purposeentities, which generally are established for the purpose of facilitatingoff-balance sheet arrangements.

 

**Critical Accounting Estimates**

 

Inour annual report on Form 10-K for the year ended December 31, 2009, asamended, we identified our most critical accounting policies. In preparing thefinancial statements, we make assumptions, estimates and judgments that affectthe amounts reported. We periodically evaluate our estimates and judgments thatare the most critical in nature which are related to oil reserves, successfulefforts method of accounting, revenue recognition, impairment of long-livedassets, future dismantlement, restoration, and abandonment costs, as well asstock-based compensation. Our estimates are based on historical experience andon our future expectations that we believe are reasonable. Those estimates andassumptions affect the reported amounts of assets, liabilities, revenues andexpenses 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.

 

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In January 2010, wepartially adopted 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 onemployers’ disclosures about postretirement benefit plans assets. The requirementsto disclose separately purchases, sales, issuances, and settlements in theLevel 3 reconciliation are effective for fiscal years beginning afterDecember 15, 2010 (and for interim periods within such years). As such, wewill apply the disclosure requirements relative to the Level 3 reconciliationin the first quarter of 2011. There was no impact on our financial position,results of operations or cash flows as a result of the partial adoption of ASUNo. 2010-06. For further information, please see Note 11, “Fair ValueMeasurements and Disclosures”.

 

**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 increase production,or the ability to generate income or cash flows are by nature, forward-lookingstatements.  These statements are basedon certain assumptions and analyses made by the management of BPZ in light ofits experience and its perception of historical trends, current conditions andexpected future developments as well as other factors it believes areappropriate 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 ofreinjection 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 ofloss arising from adverse changes in interest rates, oil and natural gas pricesand foreign 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.

 

*InterestRate Risk.*

 

As of June 30, 2010, we hadlong-term debt and capital lease obligations of approximately $153.6 millionand current maturities of long-term debt and capital lease obligations ofapproximately $9.5 million, consisting of the current portion of our IFC loan,capital lease obligations for barges and production equipment and loans foroffice furniture.

 

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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 June 2010 levels, interest expense would increase byapproximately $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 floating production, storage and offloadingvessel (“FPSO”) and transportation barges began in August 2007 and is setto expire in May 2014. Lease payments are variable based on the workingstatus of the barges, with a purchase option of $3.0 million in May 2012,$2.0 million in May 2013, and required to be purchased by us for $1.0million in May 2014.  The imputed interest rate necessary to reducethe net minimum lease payments to present value over the lease term is34.9%.  We have two additional loans for office equipment containing aterm of 60 months and bearing fixed interest rates of 5.94% and 9.44%,respectively, with principal and interest payments due on a monthly basis.

 

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.

 

*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 sixmonths ended June 30, 2010 and 2009, exchange rate gains and losses werenegligible.

 

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**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 informationrequired to be disclosed by the Company in the reports that the Company filesor submits under the Exchange Act is recorded, processed, summarized andreported within the time periods specified in the SEC’s rules andforms.  Our disclosure controls andprocedures include controls and procedures designed to ensure that informationrequired to be disclosed in reports filed or submitted under the Exchange Actis accumulated and communicated to our management, including our principalexecutive officer and principal financial officer, as appropriate, to allowtimely decisions regarding required disclosure.

 

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

 

Duringthe quarter ended June 30, 2010, there was no change in internal control overfinancial reporting that materially affected, or is reasonably likely tomaterially affect, our internal control over financial reporting.

 

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**PART II**

 

**Item 1. Legal Proceedings**

 

See Note 16, “Legal Proceedings”, of the Notes to UnauditedConsolidated Financial Statements included in this Form 10-Q and Item 3 ofPart I of our Annual Report on Form 10-K for the year ended December 31,2009, as amended, for a discussion of legal proceedings, which are incorporatedinto this Part II, Item 1. “Legal Proceedings” 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 six monthsended June 30, 2010, there were no material changes in our risk factors aspreviously 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) |

 

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**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:  August 9, 2010 | * * | /s/  MANUEL PABLO ZÚÑIGA-PFLÜCKER |
|                  |     | Manuel  Pablo Zúñiga-Pflücker               |
| * *              | * * | *President, Chief Executive Officer and Director*          |

 

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