Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: September 30, 2011

or

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

For the transition period from         to

Commission File Number: 001-12697

BPZ RESOURCES, INC.

(Exact Name of Registrant as Specified in Its Charter)

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 x 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 November 8, 2011, there were 115,910,040 shares of common stock, no par value, outstanding.

Table of Contents

TABLE OF CONTENTS

2

Table of Contents

PART I

Item 1. Financial Statements

BPZ Resources, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands)

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

3

Table of Contents

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.

4

Table of Contents

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.

5

Table of Contents

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 the 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 Peruvian 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 currently in the process of fabricating and installing a new platform in the Corvina field to further enhance its production profile.  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 began selling oil from the A-14XD well under a well testing program during the second quarter of 2010.  The Company completed conducting interference testing in the Albacora field in the third quarter of 2011.  The Company is in the process of installing the necessary gas and water injection facilities on the Albacora platform in order to transition the field into commercial production.  Additionally, the Company’s activities in Peru include analysis and evaluation of technical data on its properties, preparation of the development plans for the properties, meeting requirements under the license contracts, fabricating and installing a new platform, procuring equipment for an extended drilling campaign, obtaining all necessary environmental, technical and operating permits, bringing additional production on-line, conducting seismic surveys, obtaining preliminary 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

6

Table of Contents

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 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 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.  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.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued additional guidance regarding fair value measurement and disclosure requirements.  The most significant change will require the Company, for Level 3 fair value measurements, to disclose quantitative information about unobservable inputs used, a description of the valuation processes used, and a qualitative discussion about the sensitivity of the measurements.  The guidance is effective for interim and annual periods beginning on or after December 15, 2011.  The Company is evaluating the impact of the new guidance.

In June 2011, the FASB issued guidance impacting the presentation of comprehensive income.  The guidance eliminates the current option to report components of other comprehensive income in the statement of changes in equity.  The guidance is intended to provide a more consistent method of presenting non-owner transactions that affect an entity’s equity.  The guidance is effective for interim and annual periods beginning on or after December 15, 2011.  The Company is evaluating the impact of the new guidance.

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 is no longer eligible for the IGV early recovery program for Block Z-1.  Accordingly, the Company is recovering its IGV receivable with IGV payables associated with future oil sales under the normal IGV recovery process.

7

Table of Contents

Activity related to the Company’s value-added tax receivable for the nine months ended September 30, 2011 and the year ended December 31, 2010 is as follows:

See Note 4, “Prepaid and Other Current Assets and Other Non-Current Assets” for further information on the long-term portion of the value-added tax receivable.

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 Company maintains crude oil inventories in storage vessels 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.

Below is a summary of inventory as of September 30, 2011 and December 31, 2010:

8

Table of Contents

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

Below is a summary of prepaid and other current assets as of September 30, 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. The insurance receivable is related to an incident that occurred in the third quarter of 2011 where, while in the process of moving certain equipment from the A platform in Albacora to the CX-11 platform in Corvina using third parties, certain equipment was damaged.  The Company expects to recover the receivable amount from either the third parties or its insurance carrier.

Below is a summary of other non-current assets as of September 30, 2011 and December 31, 2010:

Other non-current assets consist of (i) direct transaction costs incurred by the Company in connection with its debt raising efforts, (ii) claims from an incident involving a small tanker and (iii) the long-term portion of the Company’s value-added tax receivable.

At September 30, 2011 and December 31, 2010 the Company had net debt issue costs of $8.4 million and $4.2 million, respectively. At the time the debt was incurred, debt issue costs consisted of $4.4 million associated with the $75 million secured debt facility, $1.5 million, associated with the $40.0 million secured debt facility, and $4.8 million associated with $170.9 million Convertible Notes due 2015. The debt issue costs are being amortized over the life of the related debt agreements using the effective interest method.

For the three and nine months ended September 30, 2011, the Company amortized into interest expense $0.8 million and $1.7 million, respectively, of debt issue costs. For the three and nine months ended September 30, 2010, the Company amortized into interest expense $0.2 million and $0.5 million, respectively, of debt issue costs.  For further information regarding the Company’s debt, see Note 9, “Debt and Capital Lease Obligations.”

The insurance claim 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 September 30, 2011, the Company is seeking recovery of these amounts from the Peruvian Navy’s commercial branch.  The Company expects to recover all 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.

As of September 30, 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.  For further information see Note 2, “Value-Added Tax Receivable”.

9

Table of Contents

Note 5 — Property, Equipment and Construction in Progress

Below is a summary of property, equipment and construction in progress as of September 30, 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. If the Company determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are charged to exploration expense.  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.

Exploratory well costs capitalized greater than one year after completion of drilling were $13.0 million as of September 30, 2011, and December 31, 2010.  The exploratory well costs relate to the CX11-16X gas well, that was drilled in 2007, which tested sufficient quantities of gas and is currently shut-in, until such time as a market is established for selling the gas.  The Company plans to use the gas from the CX11-16X well for its gas-to-power project.  See Note 17, “Commitments and Contingencies” for further information on the gas-to-power project.

During the nine months ended September 30, 2011, the Company incurred net capital additions of approximately $59.7 million associated with its development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of a gas-fired power generation facility for the sale of electricity in Peru.

For the nine months ended September 30, 2011, the Company incurred approximately $10.7 million on the Pampa la Gallina well in Block XIX, $4.3 million for the development of the A-9G well, $4.5 million for the development of the A-13E well, $3.9 million for the development of the A-12F well, and $1.2 million for the development of the A-17D water injection well.

In addition, the Company incurred $12.6 million for development and equipment for permanent production facilities.

Also, the Company added approximately $4.5 million of costs to the power plant, which primarily consists of capitalized interest, and incurred approximately $12.2 million related to costs incurred in the design and fabrication of the CX-15 platform and $1.4 million on the Caleta Cruz dock.

For the nine months ended September 30, 2011, the Company incurred approximately $1.2 million in machinery and equipment, $0.6 million for assets in transit, $1.1 million in computer hardware, software and telecommunication equipment, $0.3 million for costs for office equipment and leasehold improvements in its offices Peru and approximately $1.2 million of other capitalized costs.

For the three and nine months ended September 30, 2011, respectively, capitalized depreciation expense was an immaterial amount and $0.2 million,  and the Company capitalized $2.8 million and $7.2 million of interest expense, respectively, to construction in progress.  For the same periods in 2010, the Company capitalized approximately $0.6 million and $1.5 million, respectively, of depreciation expense and $2.5 million and $6.9 million of interest expense, respectively, to construction in progress.

10

Table of Contents

For the three and nine months ended September 30, 2011, the Company recognized $8.5 million and $27.8 million, respectively, of depreciation, depletion and amortization expense.  For the same periods in 2010, the Company recognized $6.6 million and $24.2 million, respectively, of depreciation, depletion and amortization expense.

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 nine months ended September 30, 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”).  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.

Below is a summary reflecting the Company’s income (expense) from the investment in the Ecuador property for the three and nine months ended September 30, 2011 and 2010, respectively, and the investment in the Ecuador property at September 30, 2011 and December 31, 2010, respectively.

11

Table of Contents

Note 8 — Restricted Cash and Performance Bonds

Below is a summary of restricted cash as of September 30, 2011 and December 31, 2010:

The $75.0 million secured debt facility entered into by the Company in July of 2011 required the Company to establish a $2.5 million debt service reserve account during the first 15 months the debt facility is outstanding.  After the first 15-month period, the Company is required to keep a balance in the debt service reserve account equal to the aggregate amount of principal and interest due on the next quarterly repayment date.  The Company expects to make contributions to the debt service fund of $8.1 million in 2012, $46.3 million in 2013 and $25.7 million in 2014.

The $40.0 million secured debt facility entered into by the Company in January of 2011 required the Company to establish a $2.0 million debt service reserve account during the first 18-month period and, thereafter, the Company must maintain a balance in the debt service reserve account 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.  The Company expects to make contributions to the debt service fund of $15.0 million in 2012, and $16.4 million in 2013.

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 — Debt and Capital Lease Obligations

At September 30, 2011 and December 31, 2010, debt and capital lease obligations consisted of the following:

12

Table of Contents

$75 Million Secured Debt Facility

On July 6, 2011, the Company, and its subsidiaries, entered into a credit agreement with Credit Suisse and other parties (collectively the “lenders”), where the lenders agreed to provide a $75.0 million secured debt financing (the “$75.0 million secured debt facility”) in two loan tranches to the Company’s subsidiary, BPZ E&P.  The Company and its subsidiary BPZ Energy LLC agreed to unconditionally guarantee the $75.0 million secured debt facility.  The $75.0 million secured debt facility provides for fees payable by BPZ E&P to the lenders, and to certain collateral agents pursuant to fee letters entered into by BPZ E&P with each of such parties.  The fee letters provide for (i) a participation fee and a distribution fee equal to 2.5% of the principal amount borrowed, (ii) a structuring fee of $1.3 million, (iii) an administration fee of 0.50% of the principal amount outstanding and (iv) a performance based arranger fee (the “Performance Based Arranger Fee”) whose amount is determined by the change in the price of Brent crude oil at inception of the loans and the price at each principal repayment date, subject to a 12% ceiling of the principal amount borrowed.  The full amount available under the $75.0 million secured debt facility was drawn down by the Company on July 7, 2011.

Proceeds from the $75.0 million secured debt facility will be utilized to pay certain fees and expenses under the $75.0 million secured debt facility, to fund a debt  service reserve account under the $75.0 million secured debt facility, to reimburse certain affiliates of BPZ E&P for up to $14.0 million of capital and exploratory expenditures incurred by them in connection with the development of Block Z-1, and up to $6.0 million of capital and exploratory expenditures incurred by them in connection with the development in Block XIX in northwest Peru, and to finance BPZ E&P’s capital and exploratory expenditures in connection with the development of Block Z-1.

The $75.0 million secured debt facility is secured by (i) all of BPZ E&P’s Block Z-1 property on the northwest coast of Peru, (ii) the wellhead oil production of Block Z-1, (iii) all of BPZ E&P’s rights, title and interests under the Block Z-1 License Contract with Perupetro S.A. (“Perupetro”), a private law state company engaged in the refining, transportation, distribution and trading of petroleum products to meet Peru’s domestic energy needs, (as amended and assigned), (iv) a collection account (including BPZ E&P’s deposits and investments), (v) all of BPZ E&P’s right, title and interests under current and future contracts in connection with the sale of crude oil and/or gas produced and sold at Block Z-1, together with related receivables, (vi)  BPZ E&P’s Capital Stock, (vii) a debt service reserve account, and (viii) certain other property that is subject to a lien in favor of Credit Suisse.

The $75.0 million secured debt facility matures in July 2014, with principal repayment due in quarterly installments that range from $8.7 million to $12.5 million commencing on January 2013 through July 2014.  The $75.0 million secured debt facility has an annual interest rate of the three month LIBOR rate plus 9%, unless the Tranche B loans are prepaid in full, in which case the $75.0 million secured debt facility has an annual interest rate of the three month LIBOR rate plus 7.5%.  Interest is due and payable every three month period after the commencement of the loan.

The $75.0 million secured debt facility contains covenants that will limit the Company’s ability to, among other things, incur additional debt, create certain liens, enter into transactions with affiliates, pay dividends on or repurchase stock of the Company or its subsidiaries, or sell assets or merge with another entity.  In addition, the Company must complete certain projects in the Corvina and Albacora offshore fields in Block Z-1 by certain scheduled dates.  There are also customary financial covenants under the $75.0 million secured debt facility, including a maximum consolidated leverage ratio, minimum consolidated interest coverage ratio,

13

Table of Contents

maximum capitalization ratio, minimum oil production quota per quarter, minimum debt service coverage ratio, minimum proved developed producing reserves coverage ratio, maximum indebtedness, and minimum liquidity ratio.  The Company was in compliance with these financial covenants at September 30, 2011.

The $75.0 million secured debt facility provides for events of default customary for facilities of this type, the occurrence and continuation of which could result in the acceleration of amounts due under the facility.

In addition, the $75.0 million secured debt facility provides for optional prepayments in certain circumstances, as well as mandatory prepayments of certain portions of the loans if BPZ E&P or any guarantor and any of their respective subsidiaries enters into a permitted farm-out transaction with respect to their interests in Block Z-1 that would have the effect of reducing BPZ E&P’s and such guarantors’ collective economic interest in Block Z-1 below certain ownership thresholds.

The $75.0 million secured debt facility required the Company to establish a $2.5 million debt service reserve account during the first 15 months the debt facility is outstanding.  For further information regarding the debt service reserve account, and its requirements, see Note 8, “Restricted Cash and Performance Bonds.”

With respect to the Performance Based Arranger Fee, the fee is payable at each of the principal repayment dates.  The Performance Based Arranger Fee is calculated by multiplying the principal payments at each principal payment date by the change in oil prices from the loan origination date and the oil price at each principal payment date. Additionally, the Performance Based Arranger Fee contains a maximum amount to be paid by the Company over the term of the loan. 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 Company recorded debt issue costs of approximately $4.4 million associated with the $75.0 million secured debt facility. The debt issue costs are being amortized over the life of the facility through July 2014, using the effective interest method.

The Company estimates the cash payments related to the $75.0 million secured debt facility, excluding potential payments for the Performance Based Arranger Fee but including interest payments, for the year ended December 31, 2011, 2012, 2013 and 2014 to be approximately $1.8 million, $7.4 million, $43.5 million and $39.1 million, respectively.

$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. 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 (approximately $65.0 million) 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 debt service reserve account during the term of the facility. For further information regarding the debt service reserve account, 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 minimum consolidated interest coverage ratio, a maximum consolidated capitalization ratio and minimum oil production quota per quarter.  The Company was in compliance with these financial covenants at September 30, 2011.

14

Table of Contents

The $40.0 million secured debt facility provides for events of default customary for facilities of this type, the occurrence and continuation of which could result in the acceleration of amounts due under the facility.

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.

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 effective interest method.

Proceeds from the $40.0 million secured debt facility was 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 September 30, 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 $0.7 million, $18.8 million and $24.9 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 with repayment of $170.9 million (assuming no conversion) due 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 certain 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

(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.

15

Table of Contents

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 agreement contains customary terms and covenants and events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the 2015 Convertible Notes.

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 be separated into liability and equity components, with the liability component amount determined 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 effective 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 effective 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 remaining cash payments including interest payments related to the 2015 Convertible Notes, assuming no conversion, for 2011, 2012, 2013, 2014 and 2015 to be approximately none, $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 September 30, 2011, the net amount of $145.2 million includes the $170.9 million of principal reduced by $25.7 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 $25.7 million will be amortized into interest expense, using the effective interest method, over the remaining life of the loan agreement, whose term expires in March 2015.  At September 30, 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 September 30, 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 September 30, 2011, $2.77 per share, is less than the conversion price.

For the three and nine months ended September 30, 2011, the annual effective interest rate on the 2015 Convertible Notes, including the amortization of debt issue costs, was approximately 12.6%.

For the three and nine months ended September 30, 2011, the amount of interest expense related to the 2015 Convertible Notes was $4.5 million and $13.4 million, respectively, disregarding capitalized interest considerations, and includes $2.7 million and $8.3 million, respectively, of interest expense related to the contractual interest coupon, $1.5 million and $4.4 million, respectively, of non-cash interest expense related to the amortization of the discount and $0.3 million and $0.7 million, respectively of interest expense related to the amortization of debt issue costs.

16

Table of Contents

For the three and nine months ended September 30, 2010, the amount of interest expense related to the 2015 Convertible Notes was $4.3 million and $10.9 million, respectively, disregarding capitalized interest considerations, and includes $2.8 million and $7.3 million, respectively, of interest expense related to the contractual interest coupon, $1.3 million and $3.1 million, respectively, of non-cash interest expense related to the amortization of the discount and $0.2 million and $0.5 million, respectively of interest expense related to the amortization of debt issue costs.

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 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

The following table is a summary of interest expense for the three and nine months ended September 30, 2011 and 2010:

Note 10 — Derivative Financial Instruments

Objective and Strategies for Using Derivative Instruments:

In connection with the $40.0 million secured debt facility and the $75.0 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 the principal payment amount by the change in oil prices from the loan origination date and the oil price at each principal repayment date. Additionally, the fee is capped at 18% of the $40.0 million secured debt facility and 12% of the $75.0 million secured debt facility.  The Performance 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 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

17

Table of Contents

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

Basic earnings (loss) per share of common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings (loss) per share of common stock may include the effect of the Company’s shares issuable under a convertible debt agreement, outstanding stock options or shares of restricted stock, except in periods in which there is a net loss. The following table summarizes the calculation of basic and diluted earnings (loss) per share:

(1)  Inclusion of the shares for these awards would have had an anti-diutive effect.

Stock Option and Restricted Stock Plans

The Company has in effect the 2007 Long-Term Incentive Compensation Plan, as amended (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 September 30, 2011, approximately 3.5 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 and nine months ended September 30, 2011 and 2010, respectively, and are generally included in “general and administrative expense” in the accompanying consolidated statements of operations:

18

Table of Contents