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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

For the transition period from           to          

Commission File Number: 001-12697

BPZ RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)

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

Registrant’s Telephone Number, Including Area Code: (281) 556-6200

N/A

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

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

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

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

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

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

As of May 12, 2011, there were 116,021,099 shares of common stock, no par value, outstanding.

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PART I

Item 1. Financial Statements

BPZ Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except share amounts)

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

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BPZ Resources, Inc. and Subsidiaries

Consolidated Statements of Operations (Unaudited)

(In thousands, except per share data)

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

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BPZ Resources, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (Unaudited)

(In thousands)

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

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BPZ Resources, Inc. and Subsidiaries

Notes To Consolidated Financial Statements

(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 in Houston, Texas with offices in Lima, Peru and Quito, Ecuador. The Company is focused on the exploration, development and production of oil and natural gas in Peru and to a lesser extent Ecuador. The Company also intends to utilize part of its planned future natural gas production as a supply source for the complementary development of a gas-fired power generation facility which is expected to be wholly- or partially-owned by the Company.

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

Additionally, through its wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, the Company owns a 10% non-operating net profits interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). The agreement covering the Company’s interest in the property extends through May 2016.

The Company is in the process of developing its oil and natural gas reserves.  The Company was producing and selling oil from the CX-11 platform in the Corvina field of Block Z-1 under a well testing program, until it placed the Corvina field into commercial production in November 2010. The Company is also in the initial stages of appraising, exploring and developing its potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1 and began producing from the A-14XD well in December 2009, and selling oil from the A-14XD well under a well testing program during the second quarter of 2010.  Additionally, the Company’s activities in Peru include analysis and evaluation of technical data on its other properties, preparation of the development plans for the properties, designs for platforms, procuring equipment for an extended drilling campaign, obtaining all necessary environmental and operating permits, bringing additional production on-line, seismic acquisition, obtaining detailed engineering and design of the power plant and gas processing facilities and securing the required capital and financing to conduct the current plan of operation.

Basis of Presentation and Principles of Consolidation

The accompanying consolidated financial statements of BPZ Resources, Inc. and its subsidiaries have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP” or “U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. The unaudited financial statements reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of the financial position and results of operations for the interim periods presented on a basis consistent with the annual audited financial statements.  All such adjustments are of a normal, recurring nature. All significant transactions between BPZ and its consolidated subsidiaries have been eliminated. Certain prior period amounts have been reclassified to conform to current year presentation. Results of operations for interim periods are not necessarily indicative of the results of operations that may be expected for the entire year. The balance sheet at December 31, 2010 has been derived from the audited financial statements at that date but does not include all of the information and footnotes required by GAAP for complete financial

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statements. These interim financial statements should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010.

Use of Estimates

The preparation of the consolidated financial statements in accordance with U.S. GAAP requires management to make certain estimates and assumptions. These estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses in the consolidated financial statements, and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

Estimates of crude oil reserves are the most significant of the Company’s estimates. All of the reserves data in this Form 10-Q are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.

Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment including impairment and asset retirement obligations, derivatives and deferred income tax assets. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment and future expectations regarding estimates and assumptions. As future events and their effects cannot be determined accurately, actual results could differ significantly from management’s estimates.

Summary of Significant Accounting Policies

The Company has provided a summary discussion of significant accounting policies, estimates and judgments in Note 1 to the Notes to Consolidated Financial Statements included in its Annual Report on Form 10-K for the year ended December 31, 2010.

Note 2 — Value-Added Tax Receivable

Value-added tax (referred to as “IGV” in Peru) is generally imposed on goods and services at a rate of 18% effective March 2011 and 19% in previous periods.

Peru currently has an IGV early recovery program for oil and gas companies during the exploration phase. Under this program, IGV paid on the acquisition of certain goods and services used directly in hydrocarbon exploration activities can be recovered prior to a commercial discovery taking place or the initiation of production and revenue billings. Because the Company has oil sales in the Corvina field in commercial production and Albacora field under a well testing program, it was determined that it is no longer eligible for the IGV early recovery program. Accordingly, the Company is recovering its IGV receivable with IGV payables associated with future oil sales under the normal IGV recovery process.

The Company’s current portion of value-added tax receivable as of March 31, 2011 and December 31, 2010 was $ 26.2 million and $28.4 million, respectively. For the three months ended March 31, 2011, the Company accrued approximately $5.4 million for IGV related to expenditures, reduced by approximately $7.5 million for IGV related to the sale of oil for the same period in 2011. In addition, at March 31, 2011 and December 31, 2010, the Company has approximately $3.0 million of value-added tax receivable as a long-term asset. See Note 4, “Prepaid and Other Current Assets and Other Non-Current Assets” for further information.

Note 3 — Inventories

Inventories consist primarily of crude oil, tubular goods, accessories and spare parts for production equipment, stated at the lower of average cost or market. The balance of inventory at March 31, 2011 and December 31, 2010 was $16.8 million and $19.0 million, respectively.

Inventory associated with tubular goods, accessories and spare parts at March 31, 2011 and December 31, 2010 was $15.6 million and $16.4 million, respectively.

The Company maintains crude oil inventories in storage barges until the inventory quantities are at a sufficient level that the refinery in Talara will accept delivery.  Oil inventory is stated at the lower of average cost or market value. Cost is determined on a weighted average basis based on production costs. The crude oil inventory at March 31, 2011 consisted of approximately 30.0 MBbls

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at an estimated cost of $1.3 million or $41.80 per barrel. The crude oil inventory at December 31, 2010 consisted of approximately 49.8 MBbls at an estimated cost of $2.6 million or $50.55 per barrel.

Note 4 — Prepaid and Other Current Assets and Other Non-Current Assets

Below is a summary of prepaid and other current assets as of March 31, 2011 and December 31, 2010:

Prepaid expenses and other are primarily related to prepayments for drilling services, equipment rental and material procurement. Deposits are primarily rent deposits in connection with the Company’s offices in Houston and Peru. Prepaid insurance consists of premiums related to the Company’s operations as well as general liability and directors and officer’s insurance policies. Insurance receivable is related to the barge incident which occurred in early August 2006. The Company incurred an operational delay of approximately three weeks, resulting from a navigation incident, which caused the BPZ-01 barge to be grounded on a sand bank in Talara Bay in northwest Peru. As of March 31, 2011, the Company has an insurance receivable of approximately $0.7 million for the estimated insurance repair claims of $0.8 million expected to be filed with the insurance carrier. A deductible of $75,000 will be applied to this insurance claim when reimbursed.  The dry docking of the vessel occurred during the first quarter of 2011. The Company expects to submit a claim to its insurance carrier and receive payment during the second or third quarter of 2011.

Below is a summary of other non-current assets as of March 31, 2011 and December 31, 2010:

Other non-current assets consist of (i) direct transaction costs incurred by the Company in connection with its debt and capital raising efforts and (ii) claims related to an incident involving a small tanker that one of the Company’s marine transportation contractors was chartering from the Peruvian Navy’s commercial branch in 2008. As of March 31, 2011, the Company is seeking recovery of these amounts from the Peruvian Navy’s commercial branch. The Company expects to recover the majority of these amounts from either the Peruvian Navy or its insurance carrier.  Due to the uncertainty in timing of resolving the claims, the Company has classified the amount as a non-current asset.

In connection with the Company’s $15.0 million International Finance Corporation (“IFC”) Reserve-Based Credit Facility, the Company incurred approximately $0.2 million of debt issue costs that were being amortized over the life of the loan agreement, originally due December 2012.  In January 2011, the Company repaid the amounts outstanding under the IFC Reserve-Based Credit Facility with the proceeds received under a new $40.0 million secured debt facility with Credit Suisse AG, Cayman Islands Branch (“Credit Suisse”). Accordingly, the Company expensed the remaining $0.1 million portion of debt issue costs associated with the IFC Reserve-Based Credit Facility and recorded additional debt issue costs of approximately $1.5 million associated with the $40.0 million secured debt facility. The debt issue costs associated with the $40.0 million secured debt facility are being amortized over the life of the facility, which has partial principal payments due every three months from July 2012 through July 2013, using the effective interest method.

In connection with the $170.9 million Convertible Notes due 2015, the Company incurred approximately $4.8 million of debt issue costs that are being amortized over the life of the indenture agreement, due March 2015.

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For the three months ended March 31, 2011 and 2010, the Company amortized into interest expense $1.9 million and $0.5 million of debt issue costs, respectively. For further information regarding the Company’s debt, see Note 9, “Long-Term Debt and Capital Lease Obligations”.

As of March 31, 2011 and December 31, 2010, the Company classified $3.0 million of its value-added tax receivable balance as a long-term asset as it believes it will take longer than one year to receive the benefit of this portion of the value-added tax receivable.

Note 5 — Property, Equipment and Construction in Progress

Below is a summary of property, equipment and construction in progress as of March 31, 2011 and December 31, 2010:

The Company follows the “successful efforts” method of accounting for its costs of acquisition, exploration and development of oil and gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved developed crude oil reserves on a field-by-field basis.

During the three months ended March 31, 2011, the Company incurred net capital expenditures of approximately $8.8 million associated with its development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of a proprietary gas-fired power generation facility for the sale of electricity in Peru.

For the three months ended March 31, 2011, the Company incurred approximately $0.3 million for the CX11-17D well, $0.3 million for a water well in Block XIX, $1.1 million related to the CX-15 platform and $0.4 million of costs incurred in the planning and construction of new platforms and site preparation costs. In addition, the Company incurred $2.7 million in equipment for its permanent production facilities in the Albacora and Corvina fields, as well as $0.7 million for improvements to its gas reinjection facilities and existing production systems. The Company added approximately $2.2 million of costs to the power plant.

For the three months ended March 31, 2011, the Company incurred approximately $0.1 million in machinery and equipment, $0.4 million for assets in transit and $0.5 million in computer hardware, software and telecommunication equipment.

For the three months ended March 31, 2011, the Company capitalized an immaterial amount of depreciation expense and $2.7 million of interest expense to construction in progress, which are included in the amounts above. For the same period in 2010, the Company capitalized approximately $0.4 million of depreciation expense and $1.4 million of interest expense, respectively, to construction in progress.

For the three months ended March 31, 2011 and 2010, the Company recognized $10.0 million and $9.5 million of depreciation, depletion and amortization expense, respectively.

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Note 6 — Asset Retirement Obligation

An obligation related to the future plugging and abandonment of the producing oil wells in the Corvina and Albacora fields, has been recorded in accordance with the provisions of ASC Topic 410, “Asset Retirement and Environmental Obligations”. ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon the Company’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using the Company’s credit-adjusted-risk-free rate. The carrying value of the ARO is adjusted to the newly calculated value, with a corresponding offsetting adjustment to the related capitalized oil and gas property assets.

Activity related to the Company’s ARO for the three months ended March 31, 2011 and the year ended December 31, 2010 is as follows:

The 2010 revisions in estimates are due to the shift in timing of cash flows associated with expected payment of the ARO liability.  As the expected timing to settle the liabilities was extended in 2010, the present value of the liabilities was decreased and, as a result, the Company reduced both the liability and capitalized asset by approximately $0.3 million in accordance with ASC Topic 410.

Note 7 — Investment in Ecuador Property

The Company has a 10% non-operating net profits interest in an oil and gas property in Ecuador (the “Santa Elena Property”) totaling $1.0 million at both March 31, 2011 and December 31, 2010. The Company accounts for this investment under the cost method and records its share of cash received or paid as other income or expense. Since the Company’s investment represents ownership of an oil and gas property, which is a depleting asset, the Company is amortizing the cost of the investment on a straight-line basis over the remaining term of the agreement which expires in May 2016.  Investment expense from the Company’s investment in Ecuador property was approximately $47,000 for the three months ended March 31, 2011 and 2010, respectively. During the three months ended March 31, 2011 and 2010, no distributions were received from the Company’s Ecuador investment.

Note 8 — Restricted Cash and Performance Bonds

As of March 31, 2011, the Company had restricted cash deposits of $7.8 million. In connection with the Company’s properties in Peru, it obtained four performance bonds totaling $5.3 million that are partially collateralized by restricted cash deposits of $3.1 million to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally, the Company has $2.0 million of restricted cash to collateralize insurance bonds for import duties related to the Don Fernando, the Company’s construction barge, and $0.6 million of restricted cash to insure certain performance obligations and commitments at the Company’s gas-to-power project site near Tumbes. In addition, the Company has an unsecured performance bond of $0.1 million to guarantee its performance under an office lease agreement in Peru.

Also included in restricted cash is a $2.0 million reserve fund as required under the $40.0 million secured debt facility entered into by the Company in January of 2011.  The $2.0 million reserve fund is required to be maintained for the first 18 month

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period and, thereafter, the Company must maintain a balance in the reserve fund equal to the aggregate amount of payments of principal and interest on the $40.0 million secured debt facility due immediately on the succeeding principal repayment date.

As of December 31, 2010, the Company had restricted cash deposits of $5.8 million. The $5.8 million of restricted cash deposits relate to the performance bonds, import duties, and performance obligations mentioned above.

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

Note 9 — Long-Term Debt and Capital Lease Obligations

At March 31, 2011 and December 31, 2010, long-term debt and capital lease obligations consist of the following:

$40.0 Million Secured Debt Facility

In January 2011, the Company, through its subsidiaries, completed a credit agreement with Credit Suisse where Credit Suisse provided $40.0 million secured debt financing (the “$40.0 million secured debt facility”) to the Company’s power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L. The Company and its subsidiary, BPZ E&P, agreed to unconditionally guarantee the $40.0 million secured debt facility on an unsecured basis.  The $40.0 million secured debt facility contains an arranger fee payable to Credit Suisse International. A portion of the arranger fee is based on a percentage of the principal amount outstanding and the remainder is based on the performance of the price of crude oil (Brent) from the closing date to the repayment dates (the “Performance Based Arranger Fee”). For further information regarding the Performance Based Arranger Fee, see Note 10, “Derivative Financial Instruments” and for information on the methodology used to value the Performance Based Arranger Fee, see Note 12, “Fair Value Measurements and Disclosures”.

The $40.0 million secured debt facility is secured, in part, by three LM6000 gas-fired packaged power units that were purchased by the Company from GE, through its power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L. The $40.0 million secured debt financing is also secured by certain other equipment and property pledged in favor of Credit Suisse and Credit Suisse International.

The $40.0 million secured debt facility requires the Company to establish and maintain a reserve fund during the term of the facility. For further information regarding the reserve fund, and its requirements, see Note 8, “Restricted Cash and Performance Bonds”.

The $40.0 million secured debt facility matures on July 27, 2013, with principal repayment due in equal quarterly installments of $8.0 million commencing on July 27, 2012.  The $40.0 million secured debt facility bears interest at three month LIBOR plus 7.0%. Interest is due and payable every three month period after the commencement of the loan.

The $40.0 million secured debt facility subjects the Company to various financial covenants calculated as of the last day of each quarter, including a maximum leverage ratio, a consolidated interest coverage ratio, a maximum capitalization ratio and minimum oil production quota per quarter. The Company was in compliance with these financial covenants at March 31, 2011.

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The $40.0 million secured debt facility provides for events of default and cure periods customary for facilities of this type, including, among other things, payment breaches under any of the finance documents; representation and warranty breaches; any default, early amortization event or similar event occurring with respect to one or more debt facilities in an aggregate outstanding principal amount of at least $3,000,000, if the effect is to accelerate the maturity thereof; failure to comply with obligations; application for the appointment of a receiver; making a general assignment for the benefit of creditors; insolvencies or filing of bankruptcy; certain monetary and non-monetary judgments, orders, decrees or awards against the Company or its subsidiaries; suspension, revocation or termination of any $40.0 million secured debt facility financing or security documents with Credit Suisse or certain key agreements; and change in control.  In addition, the $40.0 million secured debt facility provides for a mandatory repayment of the loans if the Company secures financing for its gas-to-power project.

If an event of default occurs, Credit Suisse shall, , or may, by notice to the Company, (i) immediately terminate the lending commitments; and/or (ii) declare all or part of the principal amount of the loan, together with accrued interest, immediately due and payable, without demand; provided however that, all lending commitments shall automatically terminate and all amounts due and payable on any loan will automatically become immediately due and payable without notice if the Company or any subsidiary appoints a receiver, liquidator or trustee, make a general assignment for the benefit of their creditors, become insolvent, bankrupt, liquidate, or are subject to certain monetary judgments exceeding in the aggregate, $3,000,000; and/or (iii) liquidate the security collateral and apply the proceeds thereof to pay the loans.

In January 2011, the Company received the $40.0 million in proceeds and recorded approximately $1.5 million of associated fees and commissions as debt issue costs that are being amortized to interest expense over the term of the debt using the interest method.

Proceeds from the $40.0 million secured debt facility will be utilized to meet the Company’s 2011 capital expenditure budget, to finance its exploration and development work programs, and to reduce its existing debt.

At March 31, 2011, the Company estimates the cash payments related to the $40.0 million secured debt facility, excluding the potential payments for the Performance Based Arranger Fee, but including interest payments, for the year ended December 31, 2011, 2012, and 2013 to be approximately $2.3 million, $18.7 million and $24.6 million, respectively.

$170.9 million Convertible Notes due 2015

During the first quarter of 2010, the Company closed on a private offering for an aggregate of $170.9 million of convertible notes due 2015 (the “2015 Convertible Notes”). The 2015 Convertible Notes are the Company’s general senior unsecured obligations and rank equally in right of payment with all of the Company’s other existing and future senior unsecured indebtedness.  The 2015 Convertible Notes are effectively subordinate to all of the Company’s secured indebtedness to the extent of the value of the assets collateralizing such indebtedness.  The 2015 Convertible Notes are not guaranteed by the Company’s subsidiaries.

The interest rate on the 2015 Convertible Notes is 6.50% per year with interest payments due on March 1st and September 1st of each year.  The 2015 Convertible Notes mature on March 1, 2015. The initial conversion rate of 148.3856 shares per $1,000 principal amount (equal to an initial conversion price of approximately $6.74 per share of common stock) was adjusted on February 3, 2011 in accordance with the terms of the Indenture. As a result, the conversion rate and conversion price changed to 169.0082 and $5.9169, respectively. Upon conversion, the Company must deliver, at its option, either (1) a number of shares of its common stock determined as set forth in the Indenture, (2) cash, or (3) a combination of cash and shares of its common stock.

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

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

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

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

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

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

If the Company experiences any one of the certain specified types of corporate transactions, holders may require the Company to purchase all or a portion of their 2015 Convertible Notes. Any repurchase of the notes pursuant to these provisions will be for cash at a price equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the purchase date.

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

Net proceeds from the sale of the 2015 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by the Company, were approximately $164.9 million.  The initial purchaser received commissions of approximately $5.5 million in connection with the sale and the Company incurred approximately $0.6 million of direct expenses in connection with the offering.  The Company used the net proceeds for general corporate purposes including, capital expenditures and working capital, reduction or refinancing of debt, and other corporate obligations.

The Company accounts for the 2015 Convertible Notes in accordance with FASB Staff Position (“FSP”) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which is codified under ASC Topic 470, “Debt”. Under the accounting guidance, convertible debt instruments that may be settled entirely or partially in cash upon conversion are required to separately account for the liability and equity components of the instrument in a manner that reflects the issuer’s non-convertible debt borrowing rate. The value assigned to the liability component is determined by measuring the fair value of a similar liability that does not have an equity conversion feature. The value assigned to the equity component is determined by deducting the fair value of the liability component from the initial proceeds. The excess of the principal amount of the liability component over its carrying amount (the non-cash discount) is amortized to interest cost using the effective interest method over the term of the debt agreement. In addition, transaction costs incurred that directly relate to the issuance of convertible debt instruments must be allocated to the liability and equity components in proportion to the allocation of proceeds and accounted for as debt issuance costs and equity issuance costs, respectively.

The Company estimated its non-convertible borrowing rate at the date of issuance of the 2015 Convertible Notes to be 12%. The 12% non-convertible borrowing rate represented the borrowing rate of similar companies with the same credit quality as the Company and was obtained through a quote from the initial purchaser. Using the income method and discounting the principal and interest payments of the 2015 Convertible Notes using the 12% non-convertible borrowing rate, the Company estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $136.3 million with the discount being approximately $34.6 million. The discount is being amortized as non-cash interest expense over the life of the notes using the interest method. In addition, the Company allocated approximately $4.8 million of the $6.1 million of fees and commissions as debt issue costs that are being amortized as non-cash interest expense over the life of the notes using the interest method. The remaining $1.3 million of fees and commissions were treated as transaction costs associated with the equity component. The Company estimates the cash payments including interest payments related to the 2015 Convertible Notes, assuming no conversion, for the year ended December 31, 2011, 2012, 2013, 2014 and 2015 to be approximately $11.1 million, $11.1 million, $11.1 million, $11.1 million and $176.5 million, respectively. The Company evaluated the 2015 Convertible Notes agreement for potential embedded derivatives, noting that the conversion feature and make-whole provisions did not meet the embedded derivative criteria as set forth in ASC Topic 815, “Derivatives and Hedging”. Therefore, no additional amounts have been recorded for those items.

As of March 31, 2011, the net amount of $142.2 million includes the $170.9 million of principal reduced by $28.7 million of the remaining unamortized discount. The net amount of the equity component is $33.3 million, which includes the initial discount of $34.6 million, reduced by $1.3 million of direct transaction costs. The remaining unamortized discount of $28.7 million will be

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amortized into interest expense, using the effective interest method, over the remaining life of the loan agreement, whose term expires in March 2015.  At March 31, 2011, using the conversion rate of 169.0082 shares per $1,000 principal amount of the 2015 Convertible Notes, if the $170.9 million of principal were converted into shares of common stock, the notes would convert into approximately 28.9 million shares of common stock.  As of March 31, 2011, there is no excess if-converted value to the holders of the 2015 Convertible Notes as the price of the Company’s common stock at March 31, 2011, $5.30 per share, is less than the conversion price.

For the three months ended March 31, 2011 and 2010, the annual effective interest rate on the 2015 Convertible Notes, including the amortization of debt issue costs, was approximately 12.6%.

For the three months ended March 31, 2011, the amount of interest expense related to the 2015 Convertible Notes was $4.4 million, disregarding capitalized interest considerations, and includes $2.8 million of interest expense related to the contractual interest coupon, $1.4 million of non-cash interest expense related to the amortization of the discount and $0.2 million of interest expense related to the amortization of debt issue costs.

For the three months ended March 31, 2010, the amount of interest expense related to the 2015 Convertible Notes was $2.2 million, disregarding capitalized interest considerations, and includes $1.7 million of interest expense related to the contractual interest coupon, $0.4 million of non-cash interest expense related to the amortization of the discount and $0.1 million of interest expense related to the amortization of debt issue costs.

$15.0 Million IFC Reserve-Based Credit Facility

The Company had a $15.0 million reserve-based lending facility (“IFC Facility”) agreement (the “Loan Agreement”) with IFC through its subsidiaries BPZ E&P and BPZ Marine Peru S.R.L. as borrowers. As of December 31, 2010, the reserve-based lending facility had $12.5 million outstanding with an original maturity date in December 2012; however, following the closing of the $40.0 million secured debt facility in January 2011, a portion of the proceeds was used to repay the amount outstanding to IFC.

The IFC Facility had interest at an approximate rate of LIBOR plus 2.75%, equivalent to 3.21% based on the six-month LIBOR rate of 0.46% at December 31, 2010.  The maximum amount available under this facility began at $15.0 million and was to be reduced by $2.5 million beginning on December 16, 2010 and every six months thereafter during the term of the Loan Agreement.  The amount available under the Loan Agreement was subject to a semi-annual borrowing base determination based on the value of oil reserves.  In addition, the Company was subject to various financial covenants calculated as of the last day of each quarter, including a life of field coverage ratio, life of loan coverage ratio, debt to equity ratio and interest coverage ratio. The Loan Agreement also provided for events of default, cure periods and lender remedies customary for agreements of this type. The Company was in compliance with all material covenants of the Loan Agreement as of the time of repayment.

Capital Leases

The Company is party to several capital lease agreements, as more fully described in its Form 10-K for the year ended December 31, 2010.  Generally, the Company enters into capital lease agreements in order to secure marine vessels in order to support its operations in Peru and to obtain furniture and fixtures for its offices located in Houston and Peru. The contractual term of the capital lease agreements range between two to five years and the effective interest rate of the capital lease agreements range between 17.6% and 34.9%.

Interest Expense

For the three months ended March 31, 2011, the Company recognized approximately $3.7 million of net interest expense which includes $6.4 million of interest expense reduced by $2.7 million of capitalized interest expense. For the same period in 2010, the Company recognized approximately $1.9 million of net interest expense which includes $3.3 million of interest expense reduced by $1.4 million of capitalized interest expense.

Note 10 — Derivative Financial Instruments

Objective and Strategies for Using Derivative Instruments:

In connection with the $40.0 million secured debt facility, the Company and Credit Suisse agreed that a portion of the arranger fee would be based on the performance for oil prices and be payable at each of the principal repayment dates.  The fee is calculated by multiplying and agreed upon amount by the change in oil prices from the loan origination date and the oil price at each principal repayment dates. Additionally, the fee is capped at 18% of the loan proceeds obtained by the Company. The Performance

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Based Arranger Fee is being accounted for as an embedded financing derivative under ASC Topic 815, “Derivatives and Hedging” and, accordingly, is being recorded at fair value with any mark-to-market changes in value reflected as unrealized loss on derivatives in the accompanying consolidated statements of operations.

Derivative Financial Instruments Not Designated as Hedging Instruments

Amount of (Gain) Loss on Derivative Instruments Recognized in Income

See Note 12, “Fair Value Measurements and Disclosures” for a discussion of methods and assumptions used to estimate the fair values of the Company’s derivative instruments.

Note 11 — Stockholders’ Equity

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

Potentially Dilutive Securities

In addition to the shares issued and outstanding, the Company has the following potentially dilutive securities at March 31, 2011 and 2010.  None of these potentially dilutive shares have been included in the calculation of loss per share as the effect would be anti-dilutive.

The potentially dilutive shares are as follows:

Stock Option and Restricted Stock Plans

The Company has in effect the 2007 Long-Term Incentive Compensation Plan, as amended in 2010 to increase the number of shares available (the “2007 LTIP”), and the 2007 Directors’ Compensation Incentive Plan (the “Directors’ Plan”). The 2007 LTIP and the Directors’ Plan provide for awards of options, stock appreciation rights, restricted stock, restricted stock units, performance awards, other stock-based awards and cash-based awards to any of the Company’s officers, employees, consultants, employees of certain of the Company’s affiliates, as well as non-employee directors. The number of shares authorized under the amended 2007 LTIP and Directors’ Plan is 8.0 million and 2.5 million, respectively. As of March 31, 2011 approximately 3.1 million shares remain available for future grants under the 2007 LTIP and 0.8 million shares remain available for future grants under the Directors’ Plan.

The following table summarizes stock-based compensation costs recognized under ASC Topic 718, “Stock Compensation” for the three months ended March 31, 2011 and 2010, respectively, and are generally included in “general and administrative expense” in the accompanying consolidated statements of operations:

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Restricted Stock Awards and Performance Shares

On March 1, 2011, the Company’s Board of Directors awarded 74,683 shares of restricted stock to officers and other key employees under the Company’s 2007 LTIP.  The restricted stock awards generally vest on the second anniversary of the grant date. On March 14, 2011, the Company granted certain officers 220,000 shares of restricted stock under the Company’s 2007 LTIP.  These awards fully vest on March 1, 2013.  For the three months ended March 31, 2011, the weighted average grant date fair value per share of the awards granted was $6.11.

Stock Options

On March 1, 2011, the Company’s Board of Directors awarded officers and other key employees a total of 224,049 options to purchase the Company’s common stock under the Company’s 2007 LTIP.  These options generally vest in equal annual installments over a three-year period from the grant date.

For the three months ended March 31, 2011, the Company awarded its non-employee directors a total of 275,000 options to purchase the Company’s common stock under the Directors’ Plan.  These options generally vest in equal annual installments over a two-year period from the grant date.

For the three months ended March 31, 2011, the weighted average exercise price per share of the options awards granted and the weighted average fair value per share of the options awards granted were $6.42 and $4.14, respectively.

Note 12— Fair Value Measurements and Disclosures

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

The following describes the valuation methodologies the Company uses for its fair value measurements.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Cash and Cash Equivalents

Cash and cash equivalents include all cash balances and any highly liquid investments with an original maturity of 90 days or less. The carrying amount approximates fair value because of the short maturity of these instruments.

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Restricted Cash

Restricted cash includes all cash balances which are classified as long-term as they are associated with the Company’s long-term assets. The carrying amount approximates fair value because the nature of the restricted cash balance is the same as cash.  The fair value of restricted cash is measured using Level 1 inputs within the three-level valuation hierarchy.

Derivative Financial Instruments

The Company’s derivative financial instruments consist of variable financing arranger fee payments that are dependent on the change in oil prices from the loan origination date of the Company’s $40.0 million secured debt facility and the oil price on each repayment date. The Company estimates the fair value of these payments based on published forward commodity price curves at each financial reporting date. The discount rate used to discount the associated cash flows is based on the Company’s credit-adjusted risk-free rate. For further information regarding the Company’s derivatives, see Note 10, “Derivative Financial Instruments”.

Measurement information for assets and liabilities that are measured at fair value on a recurring basis was as follows:

Non-Financial Assets and Liabilities

The Company discloses or recognizes its non-financial assets and liabilities, such as asset retirement obligations and impairments of long-lived assets, at fair value on a non-recurring basis. See Note 6, “Asset Retirement Obligation” for further information.  None of the Company’s non-financial assets and liabilities were impaired as of March 31, 2011 and December 31, 2010.

Additional Fair Value Disclosures

Debt with Variable Interest Rates

The fair value of the Company’s $40.0 million secured debt facility, at March 31, 2011, and the Company’s IFC Facility, at December 31, 2010, approximates the carrying value because the interest rates are based on floating rates identified by reference to market rates, and because the interest rates charged are at rates at which the Company could borrow under similar terms.

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

(1)                    Excludes obligations under capital lease arrangements and variable rate debt.

(2)                    The Company estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $202.9 million and $176.5 million at March 31, 2011 and December 31, 2010, respectively, based on observed market prices for the same or similar type issues.

Note 13— Oil Revenue

At March 31, 2011, the Company has developed nine wells in the Corvina field and one well in the Albacora field.  Of these wells, five were producing oil, one was being used for gas reinjection, one was being used for water reinjection and the remaining wells were shut-in at March 31, 2011.  In late-January 2011, the A-14XD well in the Albacora field was shut-in as the Company’s extended well testing and gas flaring permits had expired.  At March 31, 2010, the Company was producing oil from six wells in the Corvina field and one well in the Albacora field under a well testing program.

The Company began producing oil on a limited basis in November 2007 from the CX11-21XD and CX11-14D wells in the Corvina field under a well testing program.  During the second and fourth quarter of 2008, it added production from the CX11-18XD and CX20-20XD wells, respectively, under the well testing program.  In 2009, the Company added the CX-15D during the second quarter and the CX11-19D well in the Corvina field and the A-14XD well in the Albacora field during the fourth quarter to its well testing program. In 2010, the Company added the CX11-17D during the first quarter, the CX11-22D during the third quarter and the CX11-23D the well during the fourth quarter to its well testing program.  Additionally, on November 30, 2010, the Company transitioned the Corvina field from extended well testing into commercial production.

The oil is delivered by vessel to the refinery owned by Petroleos del Peru - PETROPERU S.A. (“Petroperu”), a private law state company engaged in the refining, transportation, distribution and trading of petroleum products to meet Peru’s domestic energy needs, in Talara, located approximately 70 miles south of the platform.  Produced oil is kept in production inventory until the Company increases the inventory quantities to a sufficient level that the refinery in Talara will accept delivery.  Although all of the Company’s oil sales are to Petroperu, it believes that the loss of Petroperu as its sole customer would not materially impact the Company’s business because it could readily find other purchasers for the Company’s oil production both in Peru and internationally.

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

In May 2010, through its wholly-owned subsidiary BPZ E&P, the Company entered into a short-term 400 MBbls oil supply agreement with Petroperu. Under the terms of the contract, the Company agreed to sell, and Petroperu agreed to purchase the Company’s crude oil production originating from the Albacora oilfield in Block Z-1. The price per barrel of oil under the agreement is determined using a basket of crude oils based on a 15-day average of Forties, Oman, and Suez blend crude oil prices, as quoted in the

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Spot Crude Prices Assessment published in Platt’s Crude Oilgram Price Report, minus $3 per barrel and other customary purchase price adjustments. As part of the price adjustments the Company is allowed to sell oil under the contract as long as the salt content is less than 25 pounds per thousand barrels of oil.  There is no purchase price adjustment associated with the oil sales if the salt content is less than 10 pounds per thousand barrels.

The Company’s revenues are reported net of royalties owed to the government of Peru. Royalties are assessed by Perupetro S.A. (“Perupetro”), a corporation owned by the Peruvian government empowered to become a party in the contracts for the exploration and/or exploitation of hydrocarbons in order to promote these activities in Peru, as stipulated in the Block Z-1 license agreement based on production. However, their calculation is based on the past five-day average basket of crude oils prices, as discussed above, before the crude oil delivery date. For the three months ended March 31, 2011 and 2010, the revenues received by the Company are net of royalty costs of approximately 5% of gross revenues or $2.0 million and $1.3 million, respectively.

Note 14 — Standby Costs

After completing the CX11-23D well in the Corvina field and the A-17D well in the Albacora field at the end of the third quarter of 2010, the Company suspended drilling operations until it completes a seismic data acquisition program planned for 2011 and fabricates and installs a new drilling platform in Block Z-1, currently scheduled for mid-2012.  As a result, for the three months ending March 31, 2011, the Company incurred $2.3 million in standby costs that includes $1.8 million of standby rig costs and $0.5 million of allocated expenses associated with drilling operations.  There were no similar expenses incurred by the Company during the first three months of 2010.

Note 15 — Income Tax

For the three months ended March 31, 2011, the Company recognized an income tax expense of approximately $0.7 million on a net loss before income tax of approximately $7.4 million.  For the same periods in 2010, the Company recognized an income tax expense of approximately $1.1 million on a net loss before income tax of approximately $0.7 million.  The difference between the effective tax rate recognized and the 22% statutory rate provided for under the Block Z-1 License Contract is due to:

·                  The Company has a valuation allowance for the full amount of the domestic deferred tax asset resulting from the income tax benefit generated from net losses 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 be realized prior to the expiration of net operating loss carryforwards in various amounts through 2027.  Consequently, approximately $9.6 million of loss before income taxes did not produce any tax benefit.

·                  Income before income taxes of approximately $2.2 million related primarily to the Block Z-1 license contract resulted in income tax expense of approximately $0.7 million.  This differed from the 22% statutory rate due to certain U.S. expenses which are not deductible in Peru.

Estimated interest and penalties related to potential underpayment on unrecognized tax benefits, if any, are classified as a component of tax expense in the consolidated statement of operations. For the three months ended March 31, 2011 and 2010, respectively, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during those periods.

Note 16 — Business Segment Information

The Company determines and discloses its segments in accordance with ASC Topic 280, “Segment Reporting” (“ASC Topic 280”), previously in accordance with SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information”,  which uses a “management” approach for determining segments. The management approach designates the internal organization that is used by management for making operating decisions and assessing parlance as the source of the Company’s reportable segments. ASC Topic 280 also requires disclosures about products or services, geographic areas, and major customers. The Company’s management reporting structure provided for only one segment for the three months ended March 31, 2011 and 2010. Accordingly, no separate segment information is presented. In addition, the Company operates only in Peru and has only one customer for its oil production, Petroperu. The majority of the Company’s long-lived assets are located in Peru. Management does not consider its investment in Ecuador as separate business segment.

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Note 17 — Commitments and Contingencies

Extended Well Testing Regulation

On December 13, 2009, new legislation regulating well testing in Peru became effective under a Supreme Decree.  The new regulation provides that all new wells may be placed on production testing for up to six months.  If the operator believes that additional time for testing is needed to properly evaluate the productive capacity of the field, and can technically justify such need, a request for the well to enter into an Extended Well Test (“EWT”) period must be submitted to the General Directorate of Hydrocarbons (“DGH”), the agency of the Ministry of Energy and Mines responsible for regulating the optimum development of oil and gas fields.  The approval process for an EWT permit requires that the DGH request Perupetro’s opinion on the technical justification for the EWT.  After the initial six-month period or after an approved EWT program expires, the operator will be required to have the necessary gas and water reinjection equipment in place to continue producing the well according to existing environmental regulations.  Additionally, during both the initial six-month testing period and any extended period that may be granted, the Company must also obtain gas flaring permits for each well in order for it to be in compliance with Peruvian environmental legislation. On November 30, 2010, in accordance with the approved first date of commercial production (“FDCP”), the Company transitioned the Corvina field into commercial production. With respect to other fields, unless EWT periods are approved, upon expiration of such periods, all production will cease until the Company meets the requirements, including installation of water and gas reinjection facilities, to transition into commercial production.

Extended Well Testing Program

Prior to transitioning the Corvina field into commercial production on November 30, 2010, the Company had been producing oil in the Corvina field subject to the new EWT regulations as described above.

The Albacora field is also subject to the same EWT regulations.  The Company had been producing oil from the Albacora field since December 2009 through late-January 2011, at which time the extended well testing permit and associated gas flaring permit expired. In January 2011, the Company received notice from Perupetro that its application for extended well testing on the A-14XD well had been denied. Accordingly, production from the A-14XD is currently shut-in.

In April 2011, the Company received authorization for interference testing, along with associated gas flaring, covering a four month period beginning June 1, 2011, from the Ministry of Energy and Mines of Peru. The permits are for the A-14XD, A-9G, and A-13E oil wells, with the latter two having been drilled by a previous operator, which are all currently shut-in at the Albacora platform.  As a result, the Company plans to workover the A-9G and A-13E wells, with an estimated start in May 2011. Each well is expected to be opened at various intervals, both on an individual basis and simultaneously, during the four-month period to test reservoir connectivity of the sands that were producing at the A-14XD well. Upon completion of the interference testing, the Company plans to open previously untested zones in each of the three wells. However, in order to produce from those new zones, the Company must request authorization to flare associated gas until the gas reinjection equipment is installed at the Albacora platform which is currently scheduled for year-end 2011.

With respect to any additional EWT and gas flaring permits the Company requests, it can give no assurance that the DGH or the Ministry of Energy and Mines will grant approval of any current or future permits requested by the Company.

Profit Sharing

The Constitution of Peru and Legislative Decree Nos. 677 and 892 gives employees working in private companies engaged in activities generating income as defined by the Income Tax Law the right to share in the company’s profits.  According to Article 3 of the United Nations International Standard Industrial Classification, BPZ E&P’s tax category is classified under the “mining companies” section, which sets the rate at 8%. However, in Peru, the Hydrocarbon Law states, and the Supreme Court ruled, that hydrocarbons are not related to mining activities. Hydrocarbons are included under “Companies Performing Other Activities”, thus Oil and Gas Companies pay profit sharing at a rate of 5%. The 5% of income is determined by calculating a percentage of the Company’s Peruvian subsidiaries’ annual total revenues subject to income tax less the expenses required to produce revenue or maintain the source of revenues. The benefit granted by the law to employees is calculated on the basis of “income subject to taxation” per the Peruvian tax code, and not based on income/(loss) before incomes taxes as reported under GAAP. For the three months ended March, 31 2011, profit sharing expense was not material to the Company as the Company’s Peruvian subsidiaries did not have a material amount of “income subject to taxation” per the Peruvian tax code. As a result of the Company declaring commercial production in the Corvina field on November 30, 2010, certain exploration and development costs were allowed to be deductible in 2011 that were not deductible prior to the declaration of commercial production. For the three months ended March 31, 2010, approximately $0.9 million of expense related to profit sharing is included in “general and administrative expense” in the

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accompanying consolidated statement of operations as the Company’s Peruvian subsidiaries had “income subject to taxation” per the Peruvian tax code.  The Company is subject to profit sharing expense in any year its Peruvian subsidiaries are profitable according to the Peruvian tax laws.

Gas-to-Power Project Financing

The gas-to-power project entails the installation of an approximately 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and the building of an approximately 135 megawatt (“MW”) simple-cycle electric generating plant.  The proposed power plant site is located adjacent to an existing substation and power transmission lines which, after the Peruvian government completes their expansion, are expected to be capable of handling up to 320 MW of power. The existing substation and transmission lines are owned and operated by third parties.

The Company currently estimates the gas-to-power project will cost approximately $153.5 million, excluding working capital and 18% value-added tax which will be recovered via future revenue billings. The $153.5 million includes $133.5 million for the estimated cost of the power plant and $20.0 million for the estimated cost of the construction of the natural gas pipeline. While the Company has held initial discussions with several potential joint venture partners for the gas-to-power project, in an attempt to secure additional financing and other resources for the project, the Company has not entered into any definitive agreements with a potential partner. In the event the Company is able to identify and reach an agreement with a potential joint venture partner, it may only retain a minority position in the project. However, the Company expects to retain the responsibility for the construction of the pipeline as well as retain ownership of the pipeline. If the Company is unable to identify and reach an agreement with a potential partner, it plans to continue moving the project forward to completion without a partner. The Company is currently in the process of identifying and securing the permits and financing necessary to move the project forward.

Note 18 — Legal Proceeding

Navy Tanker Litigation

On October 24, 2007, Tecnomarine SAC, a contractor to BPZ E&P, entered into two short-term agreements with the Peruvian Navy’s commercial branch to charter two small tankers for use in the Company’s offshore oil production operation.  On January 30, 2008, one of the tankers, the Supe, sank after catching fire. Neither of the Peruvian governmental agencies charged with investigating the incident found fault with Tecnomarine SAC or the Company’s subsidiary, BPZ E&P. A lawsuit was nonetheless filed on December 18, 2008 in the 152nd Judicial District Court of Harris County, Texas by two crewmembers and the family and estate of two deceased sailors injured in the incident, claiming negligence and gross negligence on the part of BPZ Resources, Inc. and BPZ Energy LLC, parent entities of BPZ E&P, that were not parties to the charter agreement and were not involved in the operations.  Based on the Company’s assessment of the available facts, including the fact that none of the Peruvian government-sanctioned investigations into the Supe incident found fault on the part of Tecnomarine or BPZ E&P, the Company does not believe the outcome of the legal proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. The Company intends to vigorously defend this action but cautions that there is inherent risk in litigation, which is difficult to quantify, especially at the early stage of litigation proceedings. In any event, the Company believes that any monetary damages arising from the incident would be adequately covered by its insurance policies, after a customary deductible.

From time to time the Company may become a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows.

Additionally, the Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.

Note 19 — Subsequent Events

On April 5, 2011, the Company received authorization from Perupetro to conduct interference testing in the Albacora field. For further information, see Note 17, “Commitment and Contingencies”.

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

Overview

You should read the following discussion and analysis together with our consolidated financial statements and notes thereto and the discussion contained in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” and Item 1A.  “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2010.  The following information contains forward-looking statements that involve risks, uncertainties and assumptions.  Should one or more of these risks or uncertainties materialize, our actual results may differ from those expressed or implied by the forward-looking statements.  See “Disclosure Regarding Forward-Looking Statements” below.

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

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

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

We are in the early stages of appraising, exploring and developing the potential oil and natural gas resources throughout our various properties in Peru.   In November 2007, we began producing and selling oil from the CX-11 platform in the Corvina field of Block Z-1 under a well testing program and, in November 2010, we placed the Corvina field into commercial production. In December 2009, we began producing oil from the A-14XD well, located on the A platform in the Albacora field of Block Z-1 and began selling oil from the A-14XD well under a well testing program during the second quarter of 2010.  From the time we began producing from the CX-11 platform in the Corvina field in November 2007 and the Albacora field in December 2009, through March 31, 2011, we have produced approximately 3.8 MMBbls of oil.

At December 31, 2010, we had estimated net proved oil reserves of 38.9 MMBbls, of which 29.2 MMBbls were in the Corvina field and 9.7 MMBbls were from the Albacora field. Both fields are located in Block Z-1 offshore of northwest Peru.  Of our total proved reserves, 12.2 MMBbls (31.5%) are classified as proved reserves which includes both proved developed producing and proved developed non-producing reserves, consisting of 13 wells, and 26.6 MMBbls (68.5%) are classified as proved undeveloped reserves consisting of 21 future wells. The process of estimating oil and natural gas reserves is complex and requires many assumptions that may turn out to be inaccurate.

Our current activities and related planning are focused on the following objectives:

·                  Optimizing oil production in the Corvina field in Block Z-1 that is now in commercial production;

·                  Designing and fabricating a new drilling and production platform to be installed in the Corvina field to continue development there in 2012;

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·                  Conducting a three dimensional (“ 3-D”) seismic survey in Block Z-1 during 2011 in order to resume drilling operations in the Albacora field and to better define potential leads and prospects within the block;

·                  Fabricating and installing permanent production and injection facilities on the Albacora platform as the EWT permit for the A-14XD expired in late-January 2011;

·                  Continuing acquisition, processing and interpretation of seismic data both onshore and offshore to better understand the characteristic and potential of our properties and build our reportable asset values;

·                  Commencing an on-shore drilling campaign to explore and appraise our properties and meet our applicable license requirements;

·                  Continuing development of our gas-to-power project to monetize our natural gas reserves, which we have identified in Corvina, but for which no market has yet been developed and related financing has yet to be obtained; and

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

Our activities in Peru also include analysis and evaluation of technical data on our properties, preparation of the development plans for the properties, engineering and design and construction of platforms to perform our drilling campaigns in the Corvina and Albacora fields in Block Z-1. In addition, we plan to procure equipment for an extended drilling campaign, obtain all necessary environmental and operating permits, bring additional production on-line, seismic acquisition, obtain detailed engineering and design of the planned power plant and gas processing facilities and secure the required capital and financing to conduct the current plan of operation.

Our Business Plan

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

Our focus is to re-appraise and develop properties in northwest Peru that have been explored by other companies and have reservoirs that appear to contain commercially productive quantities of oil and gas, as well as other areas that have geological formations that we believe potentially contain commercial amounts of hydrocarbons. Additionally, we are advancing our gas-to-power project to bring future natural gas production to market and monetize our natural gas holdings.

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

Two of the four blocks (Block Z-1 and Block XXIII) contain structures drilled by previous operators who encountered hydrocarbons. However, at the time the wells were drilled, the operators did not consider it economically feasible to produce those hydrocarbons.  Having tested oil in our offshore Block Z-1 in our first wells in the Corvina field in 2007, and our first well in Albacora in December 2009, we are initially focusing on development of the proved oil reserves in those two fields.

In addition, our business plan includes a gas-to-power project as part of our overall gas marketing strategy, which entails the installation of a 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and the building of an approximately 135 megawatt (“MW”) simple cycle electric generating plant. The proposed power plant site is located adjacent to an existing substation and power transmission lines which, with certain upgrades, are expected to be capable of handling up to 320 MW of power. We currently plan to wholly- or partially-own this power generation facility. The gas-to-power project is planned to generate a revenue stream by creating a market for the gas discovered in our Corvina field that is currently shut-in.  This project has not yet been fully financed and we continue to consider the best alternatives for the project.

In the near term management is focused on designing a new platform to allow continued development of the Corvina field, obtaining the appropriate permitting to allow for a 3-D seismic shoot in Block Z-1 to optimize our future activities in that location, obtaining appropriate financing for our exploration and development programs and maximizing the value of the acreage we hold for exploration.  To help achieve this last deliverable, we have hired a financial advisor to assist us in pursuing joint venture partnerships

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and/or, farm-outs for some or all of our assets and to assist in identifying and evaluating options for financing our operations in northwest Peru.

Extended Well Testing Regulation

On December 13, 2009, new legislation regulating well testing in Peru became effective under a Supreme Decree.  The new regulation provides that all new wells may be placed on production testing for up to six months.  If the operator believes that additional time for testing is needed to properly evaluate the productive capacity of the field, and can technically justify such need, a request for the well to enter into an EWT period must be submitted to the DGH, the agency of the Ministry of Energy and Mines responsible for regulating the optimum development of oil and gas fields.  The approval process for an EWT permit requires that the DGH request an opinion on the technical justification for the EWT from Perupetro, a corporation owned by the Peruvian government empowered to become a party in the contracts for the exploration and/or exploitation of hydrocarbons in order to promote these activities in Peru.  After the initial six month period or after an approved EWT program expires, the operator will be required to have the necessary gas and water reinjection equipment in place to continue producing the well according to existing environmental regulations.  Additionally, during both the initial six month testing period and any extended period that may be granted, we must also obtain gas flaring permits for each well in order for us to be in compliance with Peruvian environmental legislation. On November 30, 2010, in accordance with the approved first date of commercial production (“FDCP”), we transitioned the Corvina field into commercial production. With respect to other fields, unless EWT periods are approved, upon expiration of such periods, all production will cease until we meet the requirements, including installation of water and gas reinjection facilities, to transition into commercial production.

Extended Well Testing Program

Prior to placing the Corvina field into commercial production on November 30, 2010, we had been producing oil in Corvina field subject to the new EWT regulations as described above.

The Albacora field is also subject to the same EWT regulations. We had been producing oil from the Albacora field since December 2009 through late-January 2011, at which time the extended well testing permit and associated gas flaring permit expired. In January 2011, we received notice from Perupetro that our application for extended well testing on the A-14XD well had been denied. Accordingly, production from the A-14XD is currently shut-in.

In April 2011, we received authorization for interference testing, along with associated gas flaring, covering a four-month period beginning June 1, 2011, from the Ministry of Energy and Mines of Peru. The permits are for the A-14XD, A-9G, and A-13E oil wells, with the latter two having been drilled by a previous operator, which are all currently shut-in at the Albacora platform.  As a result, we plan to workover the A-9G and A-13E wells, with an estimated start in May 2011. Each well is expected to be opened at various intervals, both on an individual basis and simultaneously, during the four-month period to test reservoir connectivity of the sands that were producing at the A-14XD well. Upon completion of the interference testing, we plan to open previously untested zones in each of the three wells. However, in order to produce from those new zones, we must request authorization to flare associated gas until the gas reinjection equipment is installed at the Albacora platform which is currently scheduled for year-end 2011.

With respect to any additional EWT and gas flaring permits we request, we can give no assurance that the DGH or the Ministry of Energy and Mines will grant approval of any current or future permits requested by us.

Oil Development

General

We plan to conduct additional drilling activities based in part on an ongoing assessment of economic efficiencies, license contract requirements, likely success and logistical issues such as scheduling, required maintenance and replacement of equipment.  This assessment could result in increased emphasis and activities on a given prospect and conversely, could result in decreased emphasis on a given prospect for a period of time.  In particular, we will assess allocation of our current resources among the Corvina, Albacora, and other Block Z-1 prospects and certain onshore prospects as they develop, along with our gas-to-power project.

Seismic Data Acquisition

For Block Z-1, we intend to acquire approximately 1,500 square kilometers (“kms”) of 3-D seismic data.  The 3-D seismic data survey will include areas of interest within the Corvina, Albacora, and Delfin fields as well as certain leads and prospects located within the Mero and Piedra Redonda regions and certain other leads and prospects located between 500 -1000 feet of water depth

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within Block Z-1. Additionally, the 3-D seismic survey will include data underneath four existing platforms in the Albacora, Corvina and Piedra Redonda fields.  The seismic data survey will fulfill our commitments under the fourth exploration period of the Block Z-1 license contract if conducted within the allowed contractual time frame.

We initially attempted to conduct this seismic survey in late 2009, but suspended the survey as directed by the Ministry of Energy and Mines, because of issues relating to our stakeholders in the area of operations.  We have reapplied for the environmental permits required for us to acquire additional seismic data to assist us in exploring, appraising and developing certain areas of interest within our block. We expect to receive the environmental permit in the second quarter of 2011 to allow us to acquire the 3-D seismic data and estimate we could begin conducting the seismic survey during the second half of 2011.

For Block XXIII, we acquired approximately 370 square kms of 3-D seismic data and 314 kms of two dimensional (“2-D”) seismic data which included certain areas of interest within the Palo Santo region and four other prospects that are a part of the Mancora gas play. The seismic data acquisition was initiated in July 2010 and finished in January 2011. We are currently planning to have the 3-D and 2-D seismic data processed and interpreted by mid-year 2011. We have started with the 3-D processing and interpreting of the data over the northern part of the block.

For Block XXII, we have acquired approximately 260 kms of 2-D seismic data on four potential prospects. The 2-D seismic data survey began during the fourth quarter of 2010 and finished in March 2011. We expect to have the data processed by mid-year 2011.  We have also begun work on the Environmental Impact Assessment (“EIA”) for drilling wells on this block.

Corvina Field

We originally began producing oil from the CX-11 platform, located in the Corvina field within the offshore Block Z-1 in northwest Peru, under a well testing program that started on November 1, 2007.  The Corvina field was placed into commercial production on November 30, 2010.  The Corvina field consists of approximately 47,000 acres in water depths of less than 300 feet.  We are currently concentrating our drilling efforts on West Corvina, which consists of 3,500 acres and have completed a total of nine oil wells, the CX11-23D, CX11-22D, the CX11-17D, the CX11-19D, the CX11-15D, the CX11-21XD, the CX11-20XD, the CX11-18XD and the CX11-14D wells.  The oil is delivered by vessel to storage tanks at the refinery in Talara, owned by the Peruvian national oil company, Petroperu, which is located 70 miles south of the platform.  Produced oil is kept in production inventory until such time that it is delivered to the refinery.

After completion of the CX11-23D well in the fourth quarter of 2010, the Petrex-09 rig, previously used at the Corvina CX-11 platform, was refurbished and upgraded at the Petrex yard in Talara in order to enhance its capability in preparation for the drilling of an exploration well in the onshore Block XIX.  This upgrade was performed at no cost to us and reduced standby rates were being charged during the refurbishment. We were able to renegotiate the contract for the Petrex-09 rig, which was due to expire in April 2011. As part of the new agreement, Petrex has agreed to extend the contract to January 2012 and has agreed to a significant reduction in standby rates.

We are also currently working on the design and fabrication of an additional platform to allow continued development of the Corvina field. Further, we are attempting to obtain and install Lease Automatic Custody Transfer (“LACT”) units at the Corvina field in order to better measure our oil production output.  We expect to obtain and install the LACT units by mid-year 2012.

Albacora Field

The Albacora field is located in the northern part of our offshore Block Z-1 in northwest Peru.  The current area of interest within the Albacora field is a mapped structure of approximately 7,500 acres and is located in water depths of less than 200 feet. In December 2009, we completed our first oil well in the Albacora field, the A-14XD well, under a well testing program pursuant to the new regulations. The A-14XD well had an EWT and gas flaring permit valid through late-January 2011, at which time the well was shut-in.

In April 2011, we received authorization for interference testing, along with associated gas flaring, covering a four-month period beginning June 1, 2011, from the Ministry of Energy and Mines of Peru. The permits are for the A-14XD, A-9G, and A-13E oil wells, with the latter two having been drilled by a previous operator, which are all currently shut-in at the Albacora platform.  As a result, we plan to workover the A-9G and A-13E wells, with an estimated start in May 2011. Each well is expected to be opened at various intervals, both on an individual basis and simultaneously, during the four-month period to test reservoir connectivity of the sands that were producing at the A-14XD well. Upon completion of the interference testing, we plan to open previously untested zones in each of the three wells. However, in order to produce from those new zones, we must request authorization to flare associated gas until the gas reinjection equipment is installed at the Albacora platform which is currently scheduled for year-end 2011.

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In addition to conducting interference testing in the Albacora field, we plan to conduct and complete a 3-D seismic survey of the area in order to better define the position of future wells as well as to comply with our exploration commitments under our license contracts. We completed additional government requested environmental studies to obtain the permit to begin the seismic acquisition program. Current indications are that permits should be granted and seismic acquisition could begin during the second half of 2011.

Block XIX

The selected location in Block XIX has been prepared to drill our first onshore well at the Pampa la Gallina prospect. We have decided to move forward with the drilling of this well. The refurbishment of and enhancements to the Petrex-09 rig have been completed, and we plan to complete the necessary preparation in order to transport the rig to the proper location to begin drilling the well during the second quarter of 2011. The well is expected to target potential oil bearing sands within the Heath formation and we expect to drill to a targeted depth of approximately 7,900 ft. This well fulfills the requirement for the third exploration period of the Block XIX license contract and allows retention of the acreage for further evaluation.

Block XXIII

In May 2011, we received an extension, from Perupetro, for the first exploration period in Block XXIII, which was scheduled to expire in June 2011.  As a result of the extension, the first exploration period is scheduled to expire in December 2011. This extension will allow us more time to interpret the 3-D seismic data and 2-D seismic data we recently acquired.

Marine Operations

In conjunction with the suspension of our drilling operations at the A platform in the Albacora field, in November 2010, we began chartering our drilling tender barge, the BPZ-02, and construction barge, the Don Fernando, to the operator who, at that time,  also began leasing the Petrex-18 rig.  The BPZ-02 and Don Fernando charter is for approximately one year to coincide with the time we expect to resume drilling operations at the Albacora field.

Gas-to-Power Project

Our gas-to-power project entails the installation of an approximately 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and a 135 megawatt (“MW”) net simple-cycle power generation facility.  The proposed power plant site is located adjacent to an existing substation near Zorritos and a 220 kilovolt transmission line which, after the Peruvian government completes its expansion, is expected to be capable of handling up to 320 MW of power. The existing substation and transmission lines are owned and operated by third parties.

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

We currently estimate the gas-to-power project will cost approximately $153.5 million, excluding working capital and 18% value-added tax which will be recovered via future revenue billings.  The $153.5 million includes $133.5 million for the estimated cost of the power plant and $20.0 million for the natural gas pipeline. While we have held initial discussions with several potential joint venture partners for the gas-to-power project, in an attempt to secure additional financing and other resources for the project, we have not entered into any definitive agreements with a potential partner.  In the event we are able to identify and reach an agreement with a potential joint venture partner, we may only retain a minority position in the project. However, we expect to retain the responsibility for the construction and ownership of the pipeline. If we are unable to identify and reach an agreement with a potential partner, we plan to continue moving the project forward to completion without a partner. We are currently in the process of identifying and securing permits and financing necessary to move the project forward.

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Results of Operations

The following table sets forth revenues and operating expenses for the three months ended March 31, 2011 and 2010:

Net Oil Revenue

On November 30, 2010, we placed the Corvina field into commercial production. Prior to that time all oil sales were from oil produced under the Peruvian well testing regulations. Additionally, all oil sales from the Albacora field were from oil produced under the Peruvian well testing regulations as described above.

For the three months ended March 31, 2011, our net oil revenue increased by $13.7 million to $37.7 million from $24.0 million for the same period in 2010. The increase in net oil revenue is due to an increase in the amount of oil sold, 52 MBbls, and an increase of $25.52, or 36.4%, in the average per barrel sales price received.

For the three months ended March 31, 2011 we had full oil production from five producing wells in the Corvina field. During the same period in 2010, we had full oil production from six producing wells in the Corvina field and one producing well in the Albacora field. Total oil production for the three months ended March 31, 2011 was 375 MBbls compared to 459 MBbls for the same period in 2010. Total sales for the three months ended March 31, 2011 was 395 MBbls compared to 343 MBbls for the same period in 2010.

Although the number of wells contributing to production remained relatively consistent for both the three months ended March 31, 2011 and 2010, we constrained production during both periods in order to manage the gas associated with the oil production.  For the three months ended March 31, 2011, our production was managed in order to optimize oil production while operating within the limits of the gas reinjection equipment, while in 2010, the majority of oil production came from wells that we operated within the first six months of production and therefore they were not subject to the same type of gas flaring restrictions.

In addition, production from the A-14XD well was suspended in late-January 2011. During the three months ended March 31, 2010, the oil produced from the A-14XD well was being held in storage vessels as we were in the process of negotiating an oil

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sales contract. The oil produced from the A-14XD well during the three months ended March 31, 2010 contributed significantly to the total production for the period.

The revenues above are reported net of royalties owed to the government of Peru. Royalties are assessed by Perupetro as stipulated in the Block Z-1 license agreement based on production levels. However, the royalty calculation is based on the prior five-day average of a blend of crude oil prices before the crude oil delivery date, as opposed to the price we receive for oil which is based on the prior two-week average of a blend of crude oil prices before the crude oil delivery date. For the three months ended March 31, 2011, the revenues we received are net of royalty costs of approximately 5% of gross revenues or $2.0 million. For the same period in 2010, the revenues we received are net of royalty costs of approximately 5% of gross revenues or $1.3 million.

Other Revenue

After suspending our drilling operations at the A platform in the Albacora field in Block Z-1 in October 2010, another operator chartered two of our support vessels, the BPZ-02 and Don Fernando, for a one year term.  For the three months ended March 31, 2011, we recognized approximately $1.0 million of other revenue associated with the chartering of those vessels.  There were no similar revenues during the same period in 2010.

Lease Operating

Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, maintenance and repairs expenses, operator fees, processing fees, insurance and transportation expenses.  For the three months ended March 31, 2011, lease operating expenses increased by $6.0 million to $10.8 million ($27.24 per Bbl) from $4.8 million ($13.88 per Bbl) for the same period in 2010. The increase in the lease operating expenses is due to increases in supplies used in operations of $0.6 million, increased salary and related expense of $0.4 million, increased insurance costs of $0.4 million, increased contract labor and consulting services of $0.2 million, increased repair and maintenance expenses of $1.3 million, increased fuel costs of $0.6 million, increased lab fees and other costs of $0.5 million, increased workover costs of $0.3 million, and increased expenses transferred from oil inventory of $3.0 million.  Partially offsetting these increases to expense are decreases to crude oil transportation costs of $0.3 million and decreases in contract pumping services of $0.9 million.

The following details the significant items contributing to the increase of $6.0 million of lease operating expenses:

Transfers of costs from oil inventory: During the three months ended March 31, 2011, approximately $1.1 million of oil inventory costs were added to lease operating expense as we sold more oil (395 MBbls) than we produced (375 MBbls). During the same period in 2010, approximately $1.9 million of oil inventory cost were removed from our results of operations and added to oil inventory as we produced more oil (459 MBbls) than we sold (343 MBbls). Therefore, there is a net increase in lease operating expense of $3.0 million as a result of the transfers of oil inventory costs between the two periods.  The reason we produced more oil than we sold during the three month period ended March 31, 2010, was that oil produced from the A-14XD well was being held in storage vessels as we were in the process of negotiating an oil sales contract.

Albacora lease operating expenses: In late-January 2011, the production from the A-14XD well was suspended as our extended well testing permit and gas flaring permit had expired. In February and March of 2011, we incurred approximately $2.0 million of lease operating expenses to conduct repairs and field maintenance. There were no sales of Albacora oil production during the three months ended March 31, 2010, therefore all lease operating expenses were capitalized as part of oil inventory.

In addition, the oil produced from the Albacora field, including oil held in storage, contained a higher salt content than allowable under our oil sales contract.  In order to reduce the salt content to an acceptable level, we used desalting equipment and chemicals that resulted in an increase in fuel expenses of $0.6 million for the three month period ended March 31, 2011, compared to the same period in 2010. Although we were producing oil from the Albacora field during the three months ended March 31, 2010, we did not incur significant costs to reduce the salt content due to uncertainty in the final terms of the pending oil sales contract.

Repairs and maintenance: During the three months ended March 31, 2011, the BPZ-01 vessel went into dry dock for maintenance and repairs at a total cost of approximately $1.0 million. There were no similar expenses for the same period in 2010. Excluding the costs of the dry dock maintenance and repairs, there is a general increase in repairs and maintenance costs comparing the three months ended March 31, 2011 with the same period in 2010.

The following details the significant items contributing to the partial offsetting of the increase in lease operating expenses:

Contract pumping services: For the three months ended March 31, 2011, we have the necessary equipment and production facilities at both the Corvina CX-11 platform and Albacora A-platform to process the oil produced from those fields. During the same

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period in 2010, we had to rent the pumps and separators from third parties. As a result, contract pumping service costs have decreased $0.9 million for the three months ended March 31, 2011 compared to the same period in 2010.

Crude oil production costs: In connection with the suspension of oil production at the Albacora field during the three months ended March 31, 2011, we are incurring reduced rates for certain crude oil transportation and treating vessels. As a result, crude oil transportation costs have decreased $0.3 million during the three months ended March 31, 2011 compared to the same period in 2010.

General and Administrative

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

For the three months ended March 31, 2011, general and administrative expenses increased by $1.0 million to $9.0 million from $8.0 million for the same period in 2010.  Stock-based compensation expense, a subset of general and administrative expenses, decreased by $0.6 million to $1.2 million for the three months ended March 31, 2011 from $1.8 million for the same period in 2010. The decrease in stock-based compensation expense is due to the vesting of the majority of awards granted in 2007 and 2008, which were granted at times when the grant date fair value of the awards was higher due to the high price of our common stock. Other general and administrative expenses increased $1.6 million to $7.8 million from $6.2 million for the same period in 2010. The $1.6 million increase is due to increased salary and salary related costs of $2.0 million related to discretionary bonuses paid to our employees partially offset by a decrease in material and supplies of $0.4 million.

Additionally, for the three months ended March 31, 2011, included in other general and administrative expenses are approximately $1.0 million of costs related to third party marine operating costs in 2011.  There were no similar expenses for the same period in 2010.

Geological, Geophysical and Engineering

Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses. For the three months ended March 31, 2011, geological, geophysical and engineering expenses increased $5.8 million to $6.3 million compared to $0.5 million for the same period in 2010.   The reason for the increase in geological, geophysical and engineering expense is due to $5.9 million of seismic acquisition expenses related to our seismic data acquisition plan for Block XXII and Block XXIII during the first quarter of 2011. Partially offsetting the increase in seismic acquisition expenses are decreased environmental laboratory and consulting expenses of $0.1 million for the three months ended March 31, 2011 compared to the same period in 2010.

Depreciation, Depletion and Amortization

For the three months ended March 31, 2011, depreciation, depletion and amortization expense increased $0.5 million to $10.0 million from $9.5 million for the same period in 2010.

For the three months ended March 31, 2011, depreciation expense increased $1.8 million to $2.9 million compared to $1.1 million for the same period in 2010.  During the three months ended March 31, 2010, we capitalized approximately $0.4 million of depreciation expense on support equipment to construction in progress.  For the same period in 2011, as drilling had been suspended, we capitalized an immaterial amount of depreciation expense to construction in progress.  The remaining increase of $1.4 million is due to increased production equipment and general equipment added toward the end of 2010.

For the three months ended March 31, 2011, depletion expense decreased $1.3 million to $7.1 million from $8.4 million during the same period in 2010. For both the three months ended March 31, 2011 and March 31, 2010, depletion expense is mainly from sales from Corvina oil production. The reason for the decrease in depletion expense is due to the difference in the reserve base for the three months ended March 31, 2011 (approximately 7.1 MMBbls) compared to the reserve base during the same period in 2010 (approximately 4.6 MMBbls).  Therefore, the assets subject to depletion expense during the three months ended March 31, 2011 are being depleted at a lesser rate than the assets during the same period in 2010.

Standby Costs

After completing the CX11-23D well in the Corvina field and the A-17D well in the Albacora field at the end of the third quarter of 2010, we suspended drilling operations until we complete a seismic data acquisition program planned for 2011 and fabricate and install a new drilling platform in Block Z-1, currently scheduled for mid-2012.  As a result, for the three months ending March 31, 2011, we incurred $2.3 million in standby costs that includes $1.8 million of standby rig costs and $0.5 million of allocated expenses associated with drilling operations.  There were no similar expenses incurred during the first three months of 2010.

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Other Income (Expense)

Other expense (income) includes non-operating income items.   These items include interest expense and income, gains or losses on foreign currency transactions, income and amortization related to the investment in our Ecuador property as well as losses on derivative financial instruments.  For the three months ended March 31, 2011, total other expense increased $5.7 million to $7.6 million compared to $1.9 million during the same period in 2010.  The increase is due primarily to the following:

Interest expense: For the three months ended March 31, 2011, we recognized approximately $3.7 million of net interest expense which includes $6.4 million of interest expense reduced by $2.7 million of capitalized interest expense. For the same period in 2010, we recognized $1.9 million in interest expense which included $3.3 of interest expense reduced by $1.4 of capitalized interest. The increase of $1.8 million in net interest expense is due to having $170.9 million Convertible Notes outstanding for the entire three months ended March 31, 2011and a $40.0 Secured Debt facility outstanding for two months during the three months ended March 31, 2011. During the same period in 2010, we had $170.9 million Convertible Notes outstanding for two of the three months in the period.

Unrealized loss on derivatives: In connection with obtaining the $40.0 million secured debt facility, we entered into a Performance Based Arranger Fee that we are accounting for as an embedded derivative.  As a result of the fair value measurement at March 31, 2011, we recorded a $4.3 million unrealized loss on our derivative instrument.

Income Taxes

For the three months ended March 31, 2011, we recognized an income tax expense of approximately $0.7 million on a net loss before income tax of approximately $7.4 million.  For the same periods in 2010, we recognized an income tax expense of approximately $1.1 on a net loss before income tax of approximately $0.7 million.  The difference between the effective tax rate recognized and the 22% statutory rate provided for under the Block Z-1 License Contract is due to:

·                  We have a valuation allowance for the full amount of the domestic deferred tax asset resulting from the income tax benefit generated from net losses 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 be realized prior to the expiration of net operating loss carryforwards in various amounts through 2027.  Consequently, approximately $9.6 million of loss before income taxes did not produce any tax benefit.

·                  Income before income taxes of approximately $2.2 million related primarily to the Block Z-1 license contract resulted in income tax expense of approximately $0.7 million.  This differed from the 22% statutory rate due to certain U.S. expenses which are not deductible in Peru.

Estimated interest and penalties related to potential underpayment on unrecognized tax benefits, if any, are classified as a component of tax expense in the consolidated statement of operations. For the three months ended March 31, 2011 and 2010, respectively, we did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during those periods.

Net Loss

For the three months ended March 31, 2011, our net loss increased $6.3 million to a net loss of $8.1 million or ($0.07) per basic and diluted share from net loss of $1.8 million or ($0.02) per basic and diluted share for the same period in 2010.

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Liquidity, Capital Resources and Capital Expenditures

At March 31, 2011, we had cash and cash equivalents of $25.6 million and current accounts receivable related to our March oil sales of $7.2 million, all of which was collected in April 2011. We also had $26.2 million in the current portion of our value-added tax receivable, which we expect to collect over the next twelve months as we invoice our oil sales.

At March 31, 2011, we had trade accounts payable and accrued liabilities of $38.0 million.

At March 31, 2011, our outstanding long-term debt and short-term debt consisted of 2015 Convertible Notes whose net amount of $142.2 million includes the $170.9 million of principal reduced by $28.7 million of the remaining unamortized discount and a $40.0 million secured debt facility. At March 31, 2011, the current and long-term portions of our capital lease obligations, primarily related to the barges used in our marine operations were $3.3 million and $3.3 million, respectively.

Operating Activities

Cash used in operating activities decreased by $8.7 million to a use of cash of $1.2 million for the three months ended March 31, 2011 from a use of cash of $9.9 million for the same period in 2010. The change in cash flow before changes in operating assets provided a decrease in the use of cash of $1.2 million and is due to the addition of non-cash charges of $4.3 million from unrealized loss on derivatives, $2.0 million decrease in deferred taxes and $1.4 million amortization of debt issue costs that more than offset the increased net loss of $6.3 million. Changes in operating assets and liabilities provided a source of cash of $7.5 million.  The increase in the source of cash is due to a net decrease in the change of assets, $22.6 million. Offsetting these uses of cash are changes in operating assets and liabilities providing use of cash including a decrease in the change of liabilities and taxes, $15.1 million.

Investing Activities

Net cash used in investing activities decreased by $29.2 million to cash used in investing activities of $10.8 million for the three months ended March 31, 2011 from $40.0 million for the same period in 2010.  The decrease in cash used in investing activities is due to decreased capital expenditures of $31.4 million in 2011 as our drilling operations were suspended in 2011. Also contributing to the change in investing activities are changes in restricted cash providing a use of cash of $2.2 million.

2011 Equipment Activity

During the three months ended March 31, 2011, we incurred net capital expenditures of approximately $8.8 million associated with our development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of a proprietary gas-fired power generation facility for the sale of electricity in Peru.

For the three months ended March 31, 2011, we incurred approximately $0.3 million for the CX11-17D well, $0.3 million for a water well in Block XIX, $1.1 million related to the CX-15 platform and $0.4 million of costs incurred in the planning and construction of new platforms and site preparation costs. In addition, we incurred $2.7 million in equipment for permanent production facilities in the Albacora and Corvina fields as well as $0.7 million for improvements to gas reinjection facilities and existing production systems. We added approximately $2.2 million of costs to the power plant.

For the three months ended March 31, 2011, we incurred approximately $0.1 million in equipment, $0.4 million for assets in transit and $0.5 million in computer hardware, software and telecommunication equipment.

For the three months ended March 31, 2011we capitalized an immaterial amount of depreciation expense and $2.7 million of interest expense to construction in progress, which are included in the amounts above. For the same period in 2010, we capitalized approximately $0.4 million of depreciation expense and $1.4 million of interest expense, respectively, to construction in progress.

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For the three months ended March 31, 2011 and 2010, we recognized $10.0 million and $9.5 million of depreciation, depletion and amortization expense, respectively.

Financing Activities

Cash provided by financing activities decreased by $137.0 million to $25.9 million for the three months ended March 31, 2011, compared to $162.9 million for the same period in 2010. The decrease in cash provided by financing activities is due to decreased borrowings of $130.9 million and higher repayments of borrowings of $11.6 million that is partially offset by lower debt issue costs of $4.5 million and increases in proceeds from equity issuances of $0.9 million.

Shelf Registration

To finance our operations we may sell additional shares of our common stock or other securities. Our certificate of formation does not provide for preemptive rights, although we may grant similar rights by contract from time to time. We currently have $134.6 million in common stock available under an effective shelf registration statement, and another $500.0 million available under the same shelf registration statement for debt securities, common stock, preferred stock, depositary shares and securities warrants, subscription rights, units, and guarantees of debt securities or any combination thereof, which we may sell from time to time in one or more offerings pursuant to underwritten public offerings, negotiated transactions, at the market transactions, block trades or a combination of these methods. This registration statement will expire on December 20, 2013.

Long-Term Debt and Capital Lease Obligations

At March 31, 2011 and December 31, 2010, long-term debt and capital lease obligations consisted of the following: