| • 10-Q • EX-10.1 • EX-10.2 • EX-10.3 • EX-10.4 • EX-10.5 • EX-31.1 • EX-31.2 • EX-32.1 • EX-32.2 • XBRL INSTANCE DOCUMENT • XBRL TAXONOMY EXTENSION SCHEMA DOCUMENT • XBRL TAXONOMY EXTENSION CALCULATION LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION DEFINITION LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION LABELS LINKBASE DOCUMENT • XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE DOCUMENT | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
UNITED STATES Washington, DC 20549
FORM 10-Q
(Mark One)
For the quarterly period ended: March 31, 2012
or
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
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 April 30, 2012, there were 116,329,586 shares of common stock, no par value, outstanding.
BPZ Resources, Inc. and Subsidiaries (In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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.
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.
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, LLC, a Texas limited liability company, formerly BPZ Energy, Inc. and its subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership. Currently, the Company, through BPZ E&P, has exclusive rights and license contracts for oil and 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 license agreement and new operating agreement covering the property extend 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 interference testing in the Albacora field in the third quarter of 2011. The Company has installed all of the equipment necessary for the reinjection of gas and water at the Albacora platform, completed tie-ins and tested the equipment, and is working on the final environmental permit to start commercial production in Albacora. In the meantime, the Company has obtained a permit that allows it to flare gas from A-14XD, A-13E and A-9G wells until the final environmental permit is obtained. 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, optimizing current production, 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. See Note 17, “Commitments and Contingencies,” for information related to the Company’s new joint venture.
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 consolidated 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 consolidated 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, 2011 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 consolidated 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, 2011.
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, 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. Current credit market conditions combined with volatile commodity prices have resulted in increased uncertainty inherent in such 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, 2011. These interim financial statements should be read in conjunction with the consolidated audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2011.
Recent Accounting Pronouncements
In May 2011, the Financial Accounting Standards Board (FASB) issued additional guidance that clarifies application of fair value measurement and disclosure requirements and is effective for annual and interim periods beginning after December 15, 2011. As of March 31, 2012, the Company adopted the provisions of this guidance, which did not impact the consolidated financial statements. The only impact was to fair value disclosures.
In December 2011, the FASB issued guidance that requires that an entity disclose information about offsetting and related arrangements to enable users of the Company’s financial statements to understand the effect of those arrangements on the Company’s financial position. The guidance is effective for annual periods beginning on or after January 1, 2013. The Company is currently evaluating the provisions of this guidance and assessing the impact, if any, it may have on the Company’s financial position and results of operations.
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. Accordingly, the Company is recovering its IGV receivable with IGV payables associated with oil sales under the normal IGV recovery process.
Activity related to the Company’s value-added tax receivable for the three months ended March 31, 2012 and the year ended December 31, 2011 is as follows:
Note 3 — Inventory
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 March 31, 2012 and December 31, 2011:
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, 2012 and December 31, 2011:
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 officers’ 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. The restricted cash is related to the current portion of the $40.0 million secured debt facility entered into by the Company in January of 2011 that requires the Company to establish a $2.0 million debt service reserve account during the first 18-month period. Also, the restricted cash is related to the current portion of the $75.0 million secured debt facility entered into by the Company in July of 2011 that requires the Company to establish a $2.5 million debt service reserve account during the first 15-month period. For further information see Note 8, “Restricted Cash and Performance Bonds.”
Below is a summary of other non-current assets as of March 31, 2012 and December 31, 2011:
Other non-current assets consist of direct transaction costs incurred by the Company in connection with its debt raising efforts.
At March 31, 2012 and December 31, 2011 the Company had net debt issue costs of $6.6 million and $7.5 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. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
For the three months ended March 31, 2012, the Company amortized into interest expense $0.9 million of debt issue costs. For the three months ended March 31, 2011, the Company amortized into interest expense $0.5 million of debt issue costs. For further information regarding the Company’s debt, see Note 9, “Debt and Capital Lease Obligations.”
Note 5 — Property, Equipment and Construction in Progress
Below is a summary of property, equipment and construction in progress as of March 31, 2012 and December 31, 2011:
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. Certain costs of exploratory wells are capitalized pending determinations that proved reserves have been found. Exploratory well costs continue to be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If the determination is dependent upon the results of planned additional wells and required capital expenditures to produce the reserves found, the drilling costs will be capitalized as long as sufficient reserves have been found to justify completion of the exploratory well and additional wells are underway or planned to complete the evaluation of the well. All costs related to unsuccessful exploratory wells are expensed when such wells are determined to be non-productive.
Exploratory well costs capitalized greater than one year after completion of drilling were $13.0 million as of March 31, 2012, and December 31, 2011. 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 three months ended March 31, 2012, the Company incurred capital expenditures of approximately $22.5 million associated with its development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of gas-fired power generation of electricity for sale in Peru. A summary of capital expenditures follows.
For the three months ended March 31, 2012, the Company incurred approximately $15.0 million related to costs incurred in the design and fabrication of the CX-15 platform and incurred $4.6 million for development of and equipment for permanent production facilities.
Also, the Company added approximately $1.5 million of costs to the power plant, which primarily consists of capitalized interest, and incurred approximately $1.4 million related to other capitalized costs.
For the three months ended March 31, 2012, capitalized depreciation expense was an immaterial amount, and the Company capitalized $3.0 million of interest expense to construction in progress. For the same period in 2011, the Company capitalized an immaterial amount of depreciation expense and $2.7 million of interest expense to construction in progress.
For the three months ended March 31, 2012, the Company recognized $11.5 million of depreciation, depletion and amortization expense. For the same period in 2011, the Company recognized $10.0 million of depreciation, depletion and amortization expense.
Note 6 — Asset Retirement Obligation
An obligation related to the future plug and abandonment of the producing oil wells in the Corvina and Albacora fields and the Pampa la Gallina well in Block XIX has been recorded in accordance with the provisions of Accounting Standard Codification (“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 asset retirement cost.
Activity related to the Company’s ARO for the three months ended March 31, 2012 and the year ended December 31, 2011 is as follows:
The 2011 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 2011, 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 months ended March 31, 2012 and 2011, respectively, and the investment in the Ecuador property at March 31, 2012 and December 31, 2011, respectively.
Note 8 — Restricted Cash and Performance Bonds
Below is a summary of restricted cash as of March 31, 2012 and December 31, 2011:
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 and, thereafter, maintain the next quarterly interest and principal payment within the debt service reserve account. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
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 $15.1 million in 2012 and, thereafter, maintain the next quarterly interest and principal payment within the debt service reserve account. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
See Note 4, “Prepaid and Other Current Assets and Other Non-Current Assets” for further information on the current portion of restricted cash.
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 March 31, 2012 and December 31, 2011, debt and capital lease obligations consisted of the following:
$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 were 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. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
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 was originally set to mature in July 2014, with principal repayment due in quarterly installments that range from $8.7 million to $12.5 million commencing in 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%. Interest is due and payable every three month period after the commencement of the loan. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
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, 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. On February 29, 2012, the Company and its subsidiaries entered into a third amendment to the $75.0 million secured debt facility dated as of July 6, 2011, with the lenders. The amendment, effective as of February 29, 2012, deferred the date by which commercial production must commence in the Albacora field from February 29, 2012 to April 16, 2012. On January 9, 2012, the Company and its subsidiaries entered into a second amendment to the $75.0 million secured debt facility dated as of July 6, 2011 with the lenders. The amendment, effective as of December 30, 2011, (i) removed the requirement to provide audited financial statements from BPZ Energy LLC, (ii) increased the maximum consolidated total debt allowed for BPZ E&P from $120 million to $122 million for the fiscal year ended December 31, 2011, (iii) deferred the date by which commercial production must commence in the Albacora field from January 1, 2012 to February 29, 2012, and (iv) extended the date by which the Company must implement a hedging strategy reasonably acceptable to the lenders from January 2, 2012 to April 1, 2012. The Company and its subsidiaries previously amended the $75.0 million secured debt facility to make conforming changes. The Company was in compliance with these financial covenants at March 31, 2012. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
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. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
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.” See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
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. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
As of March 31, 2012, the Company estimated 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, 2012, 2013 and 2014 to be approximately $5.7 million, $43.1 million and $38.8 million, respectively. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
$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 $68.0 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.” See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
The $40.0 million secured debt facility was originally set to mature 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. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
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. On January 9, 2012, the Company and its subsidiaries, Empresa Eléctrica Nueva Esperanza S.R.L. and BPZ Exploración & Producción S.R.L., entered into a third amendment to the $40.0 million secured debt facility with Credit Suisse. The amendment, effective as of December 30, 2011, increased the maximum aggregate indebtedness allowed for the BPZ E&P and BPZ Lote Z-1 S.R.L. from $120 million to $122 million. The Company and its subsidiaries previously amended the $40.0 million secured debt facility to make conforming changes. The Company was in compliance with these financial covenants at March 31, 2012. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
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. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
Proceeds from the $40.0 million secured debt facility were utilized to meet the Company’s 2011 capital expenditure budget, to finance its exploration and development work programs, and to reduce its existing debt.
As of March 31, 2012, the Company estimated 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, 2012, and 2013 to be approximately $17.9 million and $24.6 million, respectively. See Note 17, “Commitments and Contingencies,” for information related to amendments to the secured debt facilities.
$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.
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 ASC Topic 470, “Debt”, as it pertains to accounting for convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement). 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 2012, 2013, 2014 and 2015 to be approximately $5.5 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, 2012, the net amount of $148.4 million includes the $170.9 million of principal reduced by $22.5 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 $22.5 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 March 31, 2012, 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, 2012, 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, 2012, $4.03 per share, is less than the conversion price.
For the three months ended March 31, 2012, 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, 2012, the amount of interest expense related to the 2015 Convertible Notes was $4.6 million, disregarding capitalized interest considerations, and includes $2.8 million of interest expense related to the contractual interest coupon, $1.6 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, 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.
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, 2011. 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 terms of the capital lease agreements range between two to five years and the effective interest rates 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 months ended March 31, 2012 and 2011:
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 of 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 gain or 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
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 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, and 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, 2012, approximately 3.6 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, 2012 and 2011, respectively, and are generally included in “general and administrative expense” in the accompanying consolidated statements of operations:
Restricted Stock Awards and Performance Shares
For the three months ended March 31, 2012, the Company’s Board of Directors did not grant any restricted stock awards.
Stock Options
For the three months ended March 31, 2012, the Company’s Board of Directors did not grant any stock option awards.
Employee Stock Purchase Plan
The employee stock purchase plan, which was approved by the shareholders on June 24, 2011, provides eligible employees the opportunity to acquire shares of BPZ Resources, Inc. common stock at a discount through payroll deductions. Employees are allowed to purchase up to 2,500 shares in any one offering period (not longer than twenty-seven months), within IRS limitations and plan rules. The offering period means each period of time which common stock is offered to participants. Generally, the purchase price for stock acquired under the plan is the lower of 85% (subject to compensation committee adjustment) of the fair market value of the common stock on the grant date or the fair market value of the common stock on the investment date. Under this plan, 2,000,000 common shares were reserved for issuance and purchase by eligible employees. Activity under this plan began in the first quarter of 2012. At March 31, 2012, 2,000,000 shares were available for issuance. On April 3, 2012, 17,309 shares were issued to employees at a price of $2.74 per share.
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:
· Level 1 — Fair value measurements which use quoted market prices (unadjusted) in active markets for identical assets or liabilities.
· Level 2 — Fair value measurements which use inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly.
· Level 3 — Fair value measurements which use unobservable inputs.
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.
Accounts Receivable, Accounts Payables and Accrued Liabilities
Accounts Receivable, Accounts Payable and Accrued Liabilities are considered to be representative of their respective fair values due to the short-term maturity of these instruments.
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, the $75.0 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:
Additional Fair Value Disclosures
Debt with Variable Interest Rates
The fair value of the Company’s $75.0 million secured debt facility and $40.0 million secured debt facility, at March 31, 2012, 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. The floating rate debt is considered to be a Level 2 measurement on the fair value hierarchy.
The fair value information regarding the Company’s fixed rate debt is as follows at March 31, 2012 and December 31, 2011:
(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 $162.5 million and $140.5 million at March 31, 2012 and December 31, 2011, respectively, based on observed market prices for the same or similar type of debt issues. The fair value of the $170.9 million 2015 Convertible Notes is considered to be a Level 1 measurement on the fair value hierarchy.
Note 13— Oil Revenue
At March 31, 2012, the Company had developed nine wells in the Corvina field and four wells in the Albacora field. Of these wells, eight wells were producing oil, three wells were producing oil intermittently, one well was being used for gas injection and the remaining well was being used for water reinjection.
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 CX11-20XD 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 well during the first quarter, the CX11-22D well during the third quarter and the CX11-23D well during the fourth quarter to its well testing program. On November 30, 2010, the Company transitioned the Corvina field from extended well testing into commercial production. In the third quarter of 2011, the Company added the A-13E and A-9G wells in the Albacora field to production. In the fourth quarter of 2011, the Company added the A-12F in the Albacora field to production.
The oil is delivered by vessel to the refinery owned by the Peruvian national oil company, Petroleos del Peru - PETROPERU S.A. (“Petroperu”), 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 have 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 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, as stipulated in the Block Z-1 License Contract 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, as opposed to the price the Company receives 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, 2012 and 2011, the revenues received by the Company are net of royalty costs of approximately 5% of gross revenues or $2.1 million and $2.0 million, respectively.
Note 14 — Standby Costs
During 2011, the Company suspended drilling operations until it completes a seismic data acquisition program and fabricate and install a new drilling platform in Block Z-1, scheduled for the second half of 2012. The contract for the Petrex-09 rig that was used in the Corvina field which contributed to standby costs in 2011, expired in January 2012 at which time the rig was returned. However, the Petrex-18 rig that was rented to another operator in 2011 was returned to the Company in January 2012 and is currently on standby. The contract for the Petrex-18 rig expires in December 2013. As a result, for the three months ending March 31, 2012, the Company incurred $1.2 million in standby rig costs for the Petrex-18 rig. For the three months ending March 31, 2011, the Company incurred $2.3 million in standby costs that includes $1.8 million of standby costs for the Petres-09 rig. Additionally, the Company incurred $0.5 million of allocated expenses associated with drilling operations for the three months ended March 31, 2011.
Note 15 — Income Tax
The following is a summary of income (loss) before income taxes and income tax expense (benefit) for the three months ended March 31, 2012 and March 31, 2011:
The Company has recognized a gross deferred tax asset related to net operating loss carryforwards attributable to the United States, before application of the valuation allowances. The Company has a valuation allowance for the full amount of the domestic net deferred tax asset, 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 2031. Furthermore, because the Company has no operations within the U.S. taxing jurisdiction, it is likely that sufficient generation of revenue to offset the Company’s deferred tax asset is remote.
The difference from the 22% statutory rate provided for under the Block Z-1 License Contract is due to other Peruvian operations that have a different statutory tax rate, certain expenses which are not deductible in Peru and a change in the timing of when certain expenses are deductible.
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. The Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the three months ended March 31, 2012 or 2011, respectively. The Company did not have any uncertain tax positions generated from unrecognized tax benefits resulting from differences between positions taken in tax returns and amounts recognized in the financial statements as of March 31, 2012 or December 31, 2011.
Note 16 — Business Segment Information
The Company determines and discloses its segments in accordance with ASC Topic 280, “Segment Reporting” (“ASC Topic 280”), 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, 2012 and 2011, respectively. 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 a separate business segment.
Note 17 — Commitments and Contingencies
Extended Well Testing Program
The Company had been producing oil from the Albacora field since December 2009. During the first quarter of 2012, the Company continues well testing on A-14XD, A-9G and A-13E wells until July 1, 2012, or until it receives the required environmental permit for gas injection, whichever comes first. In addition, the Company’s request was granted by the General Directorate of Hydrocarbons (“DGH”) to permit testing on the A-12F to allow a determination to be made whether to use this well as either a gas injector or oil producer.
With respect to any additional Extended Well Test (“EWT”) and gas flaring permits that are requested, the Company 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 give 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, 2012 and March 31, 2011, respectively, 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 in 2010, which allowed certain exploration and development costs to be deductible in 2012 and 2011 that were not deductible in previous years. 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 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 420 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 may move the project forward to completion without a partner. The Company has obtained certain permits and is in the process of obtaining additional permits to move the project forward.
Contracts for CX-15 Platform at the Corvina Field
In the third quarter of 2011, Soluciones Energeticas S.R.L., a subsidiary of the Company, finalized contracts with a third party to fabricate, mobilize and install a platform at the Corvina field in offshore Block Z-1. The estimated total project cost of the CX-15 project, including all production and compression equipment, is now expected to be approximately $77.0 million. The Company has guaranteed payment of the platform contracts.
Block Z-1 Transaction
On April 27, 2012, the Company and Pacific Rubiales Energy Corp. (together with its subsidiaries, collectively “Pacific Rubiales”) executed a Stock Purchase Agreement (“SPA”) where the Company formed an unincorporated joint venture relationship with Pacific Rubiales to explore and develop the offshore Block Z-1 located in Peru. Pursuant to the SPA, Pacific Rubiales agreed to pay $150 million for a 49% participating interest in Block Z-1 and agreed to fund $185 million of the Company’s share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012.
In order to finalize the joint venture, Peruvian governmental approvals are needed to allow Pacific Rubiales to become a party to the Block Z-1 license contract. Until the required approvals are obtained, Pacific Rubiales has agreed to provide the Company certain loans to continue to fund the Company’s Block Z-1 capital and exploratory activities. Except in the event of a termination, the loans will not accrue interest. On April 27, 2012, the Company obtained an initial loan of $65 million and a loan of $54 million for capital and exploratory activities through April 30, 2012.
At closing, after the proper approvals are obtained, the Company expects Pacific Rubiales to exchange these loans along with an additional $85 million, plus any other amounts due to the Company or from the Company under the SPA, for the interests and assets obtained from the Company under the SPA and under the Block Z-1 license contract. If, among other things, the Peruvian government does not approve Pacific Rubiales to become a party to the License Contract, the SPA terminates. If the SPA is terminated and certain provisions regarding fault of the parties do not apply, the $65 million paid and any amounts advanced to the Company for capital and exploratory expenditures will be converted into an interest bearing loan, accruing interest after the termination date at the rate of three month LIBOR plus 9%. The Company shall be obligated to repay such amounts together with a termination value, calculated pursuant to the SPA, to Pacific Rubiales in accordance with the repayment schedule as specified in the SPA. At closing, operating revenues and expenses will also be allocated to each partner’s respective participating interest.
In addition to the SPA, the Company, through its subsidiaries, entered into a related Joint Operating Agreement (“JOA”) and various other agreements which define the parties’ respective rights and obligations with respect to their operations under the License Contract. These other agreements will be ratified by the parties at closing. The JOA governs other legal, technical, and operational rights and obligations of the parties with respect to the joint operations of Block Z-1. Under terms of the JOA, BPZ E&P will be the operator of the Block Z-1 License Contract and will retain a 51% participating interest, while Pacific Rubiales assumes a 49% participating interest. After closing Pacific Rubiales will manage the technical and operational duties in Block Z-1 under a services contract with BPZ E&P. BPZ E&P will carry out administrative, regulatory, government and community related duties. The JOA will continue for the term of the license contract and thereafter until all decommissioning obligations under the license contract have been satisfied.
Amendments to Secured Debt Facilities related to the Block Z-1 Transaction
As a result of the Block Z-1 Transaction, the Company, through its subsidiaries, entered into a fourth amendment of the $75 million secured debt facility with Credit Suisse (the “Fourth Amendment”). Pursuant to the Fourth Amendment, the Company made a $40 million voluntary principal prepayment, together with accrued and unpaid interest, of the $75 million secured debt facility. In connection with the prepayment, the Company incurred a prepayment fee of $5.8 million payable in four equal installments, the first of which was paid on the prepayment date and the remaining to be paid on the interest payment dates in July 2012, October 2012 and January 2013.
The Fourth Amendment sets a revised principal repayment schedule such that BPZ E&P shall repay the outstanding principal amount of both loan tranches in eleven consecutive quarterly installments on each respective payment date beginning in January 2013, thereby extending the maturity date to July 2015. BPZ E&P has the right at any time to prepay the loans in whole, but not in part, subject to certain conditions as set forth in the Credit Agreement. Further, the Fourth Amendment sets forth certain conditions for mandatory prepayments of the loans and states that BPZ E&P must provide notice to Credit Suisse of certain matters relating to Block Z-1, including but not limited to billing statements, operating revenues and expenses, material filings, amendments or modifications to the SPA, JOA or related agreements. BPZ E&P and the guarantors may modify, supplement or waive only certain provisions of the SPA, JOA, Carry Agreement, OSA, or related documents in certain limited cases and only to the extent that such modification, supplement or waiver does not adversely affect the interests of the lenders under the Credit Agreement. The Fourth Amendment amended certain covenants on limitations on capital and exploratory expenditures, amended financial covenant requirements, deferred the date by which commercial production must commence in the Albacora field, from April 16, 2012 to July 31, 2012, deferred the date by which construction of the CX-15 platform in the Corvina field must be completed, from August 31, 2012 to January 31, 2013, deferred the date by which crude oil production must begin at the CX-15 platform, from October 31, 2012 to March 31, 2013, and eliminated the requirement that the Company must implement a hedging strategy reasonably acceptable to the lenders. In addition, the Fourth Amendment prohibits the Company from making any asset sale other than a non Block Z-1 farm-out transaction and the permitted Block Z-1 transfer pursuant to the SPA.
Further, the Company, through its subsidiaries, entered into a fourth amendment to the $40.0 million secured debt facility with Credit Suisse (the “EENE Fourth Amendment”). The EENE Fourth Amendment sets a revised principal repayment schedule such that the Company shall repay the outstanding principal amount of each loan in eleven consecutive quarterly installments on the respective payment dates beginning in July 2012, thereby extending the maturity to January 2015. The EENE Fourth Amendment amended certain covenants on limitations on investments, capital and exploratory expenditures, amended financial covenant requirements, and amended the interest rate such that the applicable margin rate increased to 8% from 7%. The EENE Fourth Amendment also made conforming changes similar to those made to the BPZ E&P Fourth Amendment.
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 is vigorously defending 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 27, 2012, the Company and its subsidiaries entered into an unincorporated joint venture. For further information, see Note 17 “Commitments and Contingencies.”
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” included in our Annual Report on Form 10-K as updated in Part I, Item 3., of this Quarterly Report on Form 10-Q for the period ended March 31, 2012 and Item 1A.,”Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2011, as updated in Part II, Item 1A, of this Quarterly Report on Form 10-Q for the period ended March 31, 2012.
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. Also, see “Cautionary Statement Regarding Certain Information Releases” below for material related to the release of certain information.
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 subsidiary BPZ Energy, LLC, a Texas limited liability company, and our wholly-owned subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership. 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 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 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 license agreement and new operating agreement covering the property extend through May 2016.
We are in the process of developing our Peruvian oil and natural gas reserves. We were producing and selling oil from the CX-11 platform in the Corvina field of Block Z-1 under a well testing program until we placed the Corvina field into commercial production in November 2010. We are currently in the process of fabricating and installing a new platform in the Corvina field to further enhance our production profile. We are also in the initial stages of appraising, exploring and developing our potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1. We 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. We completed conducting interference testing in the Albacora field in the third quarter of 2011. We have installed all of the equipment necessary for the reinjection of gas and water at the Albacora platform, completed tie-ins and tested the equipment, and are working on the final environmental permit to allow us to commission the equipment to start commercial production in Albacora. In the meantime, we have obtained a permit that allows us to flare gas from the A-14XD, A-13E and A-9G wells until the permit is obtained. 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, 2012, we have produced approximately 5.1 MMBbls of oil.
At December 31, 2011, we had estimated net proved oil reserves of 34.7 MMBbls, of which 27.8 MMBbls were in the Corvina field and 6.9 MMBbls were from the Albacora field. Both fields are located in Block Z-1 offshore of northwest Peru. Of our total proved reserves, 6.6 MMBbls (19.0%) are classified as proved developed reserves, which includes both proved developed
producing and proved developed non-producing reserves, consisting of 12 wells, and 28.1 MMBbls (81.0%) are classified as proved undeveloped reserves. 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;
· Fabricating a new drilling and production platform (the CX-15) to be installed in September 2012 to continue development in the Corvina field;
· Conducting a three dimensional (“3-D”) seismic survey in Block Z-1 to assess the viability of further exploration and development activity within the block;
· Commissioning permanent production and injection facilities on the Albacora platform for gas and water injection;
· Continuing acquisition, processing and interpretation of seismic data both onshore and offshore to better understand the characteristic and potential of our properties;
· Planning an on-shore drilling campaign to explore and appraise our properties and meet our applicable license requirements;
· Identifying potential partners for our other operations;
· 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 secured 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, meeting requirements under the license contracts, procuring equipment for an extended drilling campaign, obtaining all necessary environmental, technical and operating permits, optimizing current production and obtaining preliminary engineering and design of the power plant and gas processing facilities.
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; (iii) create an additional revenue stream through implementation of our gas market strategy; and (iv) bring working interest partners into some or all of our Peruvian blocks to facilitate the exploration and development of these blocks.
Our focus is to reappraise and develop properties in northwest Peru that have been explored by other companies that 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.
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 June 2011, we drilled our first onshore well in Block XIX. The well tests yielded low rates of oil to surface with high water content of low-salinity. In December 2011, we determined that this well had no further utility and therefore, declared the well a dry hole. We are planning to acquire additional seismic data before considering further drilling activity in this block.
In the near term, management is focused on fabricating and installing the new platform, the CX-15, as well as obtaining related permits to allow continued development of the Corvina field, conducting a 3-D seismic survey 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 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. In June 2011, we announced the start of a process to identify and select a potential partner for our offshore Block Z-1. In April 2012, we announced the formation of an unincorporated joint venture, subject to certain closing conditions and approvals, with Pacific Rubiales Energy Corp. (together with its subsidiaries, collectively “Pacific Rubiales”) to explore and develop offshore Block Z-1 in Peru. See Block Z-1 Transaction below for additional details on the joint venture.
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 420 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 or being reinjected. This project has not yet been financed and we continue to consider the best alternatives for the project. Meanwhile, we have obtained certain permits and are in the process of obtaining additional permits to move the project forward.
Extended Well Testing Program
We had been producing oil from the Albacora field since December 2009. During the first quarter of 2012, we continue well testing on A-14XD, A-9G and A-13E wells until July 1, 2012, or until we receive the required environmental permit for gas injection, whichever comes first. In addition, our request was granted by the General Directorate of Hydrocarbons (“DGH”) to permit testing on the A-12F to allow a determination to be made whether to use this well as either a gas injector or oil producer.
With respect to any additional Extended Well Test (“EWT”) and gas flaring permits that are requested, 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
Seismic acquisition activity is 80% complete in Block Z-1. A second boat is being contracted to enable seismic acquisition of certain remaining areas given the CGGVeritas Vantage vessel was unable to navigate the restricted waters between the platforms and shore due to high fishing vessel traffic and unusual currents. In the interim, bids have been received for processing the seismic data acquired to date.
Block Z-1
Block Z-1 Transaction
On April 27, 2012, we and Pacific Rubiales executed a Stock Purchase Agreement (“SPA”) where we formed an unincorporated joint venture relationship with Pacific Rubiales to explore and develop the offshore Block Z-1 located in Peru. Pursuant to the SPA, Pacific Rubiales agreed to pay $150 million for a 49% participating interest in Block Z-1 and agreed to fund $185 million of our share of capital and exploratory expenditures in Block Z-1 from the effective date of the SPA, January 1, 2012.
In order to finalize the joint venture, Peruvian governmental approvals are needed to allow Pacific Rubiales to become a party to the Block Z-1 license contract. Until the required approvals are obtained, Pacific Rubiales has agreed to provide us certain loans to continue to fund our Block Z-1 capital and exploratory activities. Except in the event of a termination, the loans will not accrue interest. On April 27, 2012, we obtained an initial loan of $65 million and a loan of $54 million for capital and exploratory activities through April 30, 2012.
At closing, after the proper approvals are obtained, we expect Pacific Rubiales to exchange these loans along with an additional $85 million, plus any other amounts due to us or from us under the SPA, for the interests and assets obtained from us under the SPA and under the Block Z-1 license contract. If, among other things, the Peruvian government does not approve Pacific Rubiales to become a party to the License Contract, the SPA terminates. If the SPA is terminated and certain provisions regarding fault of the parties do not apply, the $65 million paid and any amounts advanced to us for capital and exploratory expenditures will be converted into an interest bearing loan, accruing interest after the termination date at the rate of three month LIBOR plus 9%. We shall be obligated to repay such amounts together with a termination value, calculated pursuant to the SPA, to Pacific Rubiales in accordance with the repayment schedule as specified in the SPA. At closing, operating revenues and expenses will also be allocated to each partner’s respective participating interest.
In addition to the SPA, we, through our subsidiaries, entered into a related Joint Operating Agreement (“JOA”) and various other agreements which define the parties’ respective rights and obligations with respect to their operations under the License Contract. These other agreements will be ratified by the parties at closing. The JOA governs other legal, technical, and operational rights and obligations of the parties with respect to the joint operations of Block Z-1. Under terms of the JOA, BPZ E&P will be the operator of the Block Z-1 License Contract and will retain a 51% participating interest, while Pacific Rubiales assumes a 49% participating interest. After closing Pacific Rubiales will manage the technical and operational duties in Block Z-1 under a services contract with BPZ E&P. BPZ E&P will carry out administrative, regulatory, government and community related duties. The JOA will continue for the term of the license contract and thereafter until all decommissioning obligations under the license contract have been satisfied.
Amendments to Secured Debt Facilities related to the Block Z-1 Transaction
As a result of the Block Z-1 Transaction, we, through our subsidiaries, entered into a fourth amendment of the $75 million secured debt facility with Credit Suisse (the “Fourth Amendment”). Pursuant to the Fourth Amendment, we made a $40 million voluntary principal prepayment, together with accrued and unpaid interest, of the $75 million secured debt facility. In connection with the prepayment, we incurred a prepayment fee of $5.8 million payable in four equal installments, the first of which was paid on the prepayment date and the remaining to be paid on the interest payment dates in July 2012, October 2012 and January 2013.
The Fourth Amendment sets a revised principal repayment schedule such that BPZ E&P shall repay the outstanding principal amount of both loan tranches in eleven consecutive quarterly installments on each respective payment date beginning in January 2013, thereby extending the maturity date to July 2015. BPZ E&P has the right at any time to prepay the loans in whole, but not in part, subject to certain conditions as set forth in the Credit Agreement. Further, the Fourth Amendment sets forth certain conditions for mandatory prepayments of the loans and states that BPZ E&P must provide notice to Credit Suisse of certain matters relating to Block Z-1, including but not limited to billing statements, operating revenues and expenses, material filings, amendments or modifications to the SPA, JOA or related agreements. BPZ E&P and the guarantors may modify, supplement or waive only certain provisions of the SPA, JOA, Carry Agreement, OSA, or related documents in certain limited cases and only to the extent that such modification, supplement or waiver does not adversely affect the interests of the lenders under the Credit Agreement. The Fourth Amendment amended certain covenants on limitations on capital and exploratory expenditures, amended financial covenant requirements, deferred the date by which commercial production must commence in the Albacora field, from April 16, 2012 to July 31, 2012, deferred the date by which construction of the CX-15 platform in the Corvina field must be completed, from August 31, 2012 to January 31, 2013, deferred the date by which crude oil production must begin at the CX-15 platform, from October 31, 2012 to March 31, 2013, and eliminated the requirement that the we must implement a hedging strategy reasonably acceptable to the lenders. In addition, the Fourth Amendment prohibits us from making any asset sale other than a non Block Z-1 farm-out transaction and the permitted Block Z-1 transfer pursuant to the SPA.
Further, we, through our subsidiaries, entered into a fourth amendment to the $40.0 million secured debt facility with Credit Suisse (the “EENE Fourth Amendment”). The EENE Fourth Amendment sets a revised principal repayment schedule such that we shall repay the outstanding principal amount of each loan in eleven consecutive quarterly installments on the respective payment dates beginning in July 2012, thereby extending the maturity to January 2015. The EENE Fourth Amendment amended certain covenants on limitations on investments, capital and exploratory expenditures, amended financial covenant requirements, and amended the interest rate such that the applicable margin rate increased to 8% from 7%. The EENE Fourth Amendment also made conforming changes similar to those made to the BPZ E&P Fourth Amendment.
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, the 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, some of which are currently being used as gas injection and/or water injection wells. Produced oil is kept in production inventory until such time that it is delivered to the refinery. The oil is delivered by vessel to storage tanks at the refinery in Talara, owned by the Peruvian national oil company, Petroleos del Peru — PETROPERU S.A. (“Petroperu”), which is located 70 miles south of the platform.
In the first quarter of 2012, the Corvina gas cap reinjection program has shown positive results. As a result, during the past four months production has been relatively stable. This gas cap reinjection program has been combined with ongoing artificial lift measures at both fields to optimize our oil production.
The CX-15 platform fabrication continues at the shipyard in China with hull tube final assembly now underway with good progress on production pressure vessels and topside decks taking shape. The anticipated sail date for the transport vessel carrying the platform to Peru is late July with installation of the platform anticipated by the end of September 2012, with rig mobilization to occur thereafter. First drilling is expected to occur in the fourth quarter of 2012. The necessary permits are still being processed and approvals are anticipated to coincide with rig mobilization.
Further, we are working on obtaining and installing a Lease Automatic Custody Transfer (“LACT”) unit at the Corvina field to meet the agreed date to comply with applicable regulations. We expect to obtain and install the LACT unit in the fourth quarter of 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. We had been producing oil from the Albacora field since December 2009.
Installation of the Albacora gas and water reinjection equipment was completed and the equipment was ready for reinjection start up early in the first quarter of 2012. We completed tie-ins and tested the equipment, and are working on the final environmental permit to allow for commissioning of equipment to start use of the permanent facilities at Albacora. In the interim, we have received permits to flare gas until July 2012.
Block XIX
We have received approval from Perupetro S.A. (“Perupetro”) to conduct a limited 3-D seismic survey as part of our minimum work commitment for the fourth exploration period to further evaluate future drilling locations. An environmental assessment is currently being prepared for the additional seismic work.
Block XXII
As a result of the 2-D seismic survey completed in 2011, three prospects and one lead have been defined. Evaluation continues and we expect to develop a detailed assessment of each prospect in order to define their technical merit and risk to determine its exploration potential.
We have notified Perupetro that the commitment for the second exploration period will be the drilling of one well. The timing of the actual drilling will depend on approval of the environment assessment, which is currently being prepared, and subsequent receipt of the necessary permits. Drilling on Block XXII is expected no earlier than 2013.
Block XXIII
We have begun the process to obtain environmental permits for the potential drilling of several prospects identified by the 2-D and 3-D seismic data acquired in 2011 on Block XXIII.
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 420 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 (“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 may move the project forward to completion without a partner. We have obtained certain permits and are in the process of obtaining additional permits to move the project forward.
Results of Operations
The following table sets forth revenues and operating expenses for the three months ended March 31, 2012 and 2011:
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, 2012, our net oil revenue decreased by $1.2 million to $36.5 million from $37.7 million for the same period in 2011. The decrease in net oil revenue is due to a decrease in the amount of oil sold of 61 MBbls, partially offset by an increase of $13.59, or 14.2%, in the average per barrel sales price received.
The price/volume analysis of our sales revenues for the quarter ended March 31, 2012 compared to the quarter ended March 31, 2011is as follows:
For the three months ended March 31, 2012, we had consistent oil production from eight producing wells and intermittent production from three wells. During the same period in 2011, we had consistent oil production from five producing wells. Total oil production for the three months ended March 31, 2012 was 353 MBbls compared to 375 MBbls for the same period in 2011. Total sales for the three months ended March 31, 2012 were 334 MBbls compared to 395 MBbls for the same period in 2011.
The decrease in oil production is due to higher decline rates than expected in oil production in the Corvina field, partially offset by higher oil production from the Albacora field.
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 both the three months ended March 31, 2012 and 2011, the revenues we received are net of royalty costs of approximately 5% of gross revenues or $2.1 million and $2.0 million, respectively.
Other Revenue
During 2011, another operator chartered two of our support vessels, the BPZ-02 and Don Fernando, for a one-year term. The operator charting the vessels returned the Don Fernando in September 2011 and the BPZ-02 in January 2012. For the three months ended March 31, 2012 and 2011, we recognized approximately $0.1 million and $1.0 million, respectively, of other revenue associated with the chartering of those vessels.
Lease Operating Expense
Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities, as well as crude oil transportation. 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, 2012, lease operating expenses increased by $0.6 million to $11.4 million ($34.02 per Bbl) from $10.8 million ($27.24 per Bbl) for the same period in 2011. The increase in the lease operating expenses is due to increased repair and maintenance expenses of $1.0 million, increased contract services of $0.6 million, increased fuel costs of $0.3 million, increased equipment rental of $0.3 million and increased other lease operating expenses of $0.1 million. Partially offsetting these increases to expense are decreases in the lease operating costs associated with oil inventory of $1.7 million.
The following details the significant items contributing to the increase of $0.6 million for the three months ended March 31, 2012 compared to March 31, 2011 of lease operating expenses:
Repairs and maintenance: For the three months ended March 31, 2012, repairs and maintenance expense increased $1.0 million compared to the same period in the prior year. The reason for the increase in maintenance and repair expense is primarily due to increased platform, and crane maintenance services and additional support vessel services used in the first quarter of 2012 compared to the same period in 2011.
Contract services: For the three months ended March 31, 2012, we had 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. However in the fourth quarter of 2011, we rented hydraulic jet pumps to stimulate and assist oil production in both the Corvina and Albacora fields and continued to use these services in the first quarter of 2012. As a result, contract service costs have increased $0.6 million for the quarter ended March 31, 2012.
Transfers of costs to/from oil inventory: During the three months ended March 31, 2012, approximately $0.5 million of oil inventory costs were removed from lease operating expense as we produced more oil (353 MBbls), than we sold (334 MBbls), resulting in an buildup of oil inventory due to the timing of oil delivered to the refinery. In the same period in 2011, approximately $1.2 million of oil inventory costs were added to our results of operations as we sold more oil (395 MBbls) than we produced (375 MBbls). Therefore, there is a net decrease in lease operating expense of $1.7 million as a result of the transfers of oil inventory costs between the two periods.
General and Administrative Expense
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, 2012, general and administrative expenses decreased by $1.9 million to $7.1 million from $9.0 million for the same period in 2011. Stock-based compensation expense, a subset of general and administrative expenses, decreased by $0.5 million to $0.7 million for the three months ended March 31, 2012 from $1.2 million for the same period in 2011. The decrease in stock-based compensation expense is due to the vesting of the majority of awards granted in 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. Therefore our stock-based compensation expense declined as a majority of these older awards vested prior to the first quarter of 2012 and are not contributing as much expense as compared to the same period in 2011. Other general and administrative expenses decreased $1.4 million to $6.4 million from $7.8 million for the same period in 2011. The $1.4 million decrease is due to lower salary and related
costs of $1.9 million resulting from a 2011 discretionary bonus, partially offset by other higher general and administrative expenses in 2012 of $0.5 million.
Geological, Geophysical and Engineering Expense
Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses. For the three months ended March 31, 2012, geological, geophysical and engineering expenses increased $18.0 million to $24.3 million compared to $6.3 million for the same period in 2011, is due to increased seismic acquisition activity associated with our seismic data acquisition plan for Block Z-1 in 2012, compared to our seismic data acquisition plan for Block XXII and Block XXIII in 2011.
Depreciation, Depletion and Amortization Expense
For the three months ended March 31, 2012, depreciation, depletion and amortization expense increased $1.5 million to $11.5 million from $10.0 million for the same period in 2011.
For the three months ended March 31, 2012, depletion expense increased $1.0 million to $8.1 million from $7.1 million during the same period in 2011, due primarily to a lower reserve base in the Corvina and Albacora fields in 2012.
For the three months ended March 31, 2012, depreciation expense increased $0.5 million to $3.4 million compared to $2.9 million for the same period in 2011, due to increased production equipment and general equipment added toward the end of 2011.
Standby Costs
During 2011, we suspended drilling operations until we complete a seismic data acquisition program and fabricate and install a new drilling platform in Block Z-1, scheduled for the second half of 2012. The contract for the Petrex-09 rig that was used in the Corvina field which contributed to standby costs in 2011, expired in January 2012 at which time the rig was returned. However, the Petrex-18 rig that was rented to another operator in 2011 was returned to us in January 2012 and is currently on standby. The contract for the Petrex-18 rig expires in December 2013. As a result, for the three months ending March 31, 2012, we incurred $1.2 million in standby rig costs for the Petrex-18 rig. For the three months ending March 31, 2011, we incurred $2.3 million in standby costs that includes $1.8 million of standby costs for the Petres-09 rig. Additionally, we incurred $0.5 million of allocated expenses associated with drilling operations for the three months ended March 31, 2011.
Other Income (Expense)
Other income (expense) 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 gains or losses on derivative financial instruments. For the three months ended March 31, 2012, total other expense increased $5.1 million to $12.7 million compared to $7.6 million during the same period in 2011. The increase is due primarily to the following:
Interest expense: For the three months ended March 31, 2012, we recognized approximately $6.2 million of net interest expense, which includes $9.2 million of interest expense reduced by $3.0 million of capitalized interest expense. For the same period in 2011, we recognized $3.7 million in net interest expense which included $6.4 million of interest expense reduced by $2.7 million of capitalized interest. The increase of $2.5 million in net interest expense for the three month period ended March 31, 2012, compared to the same period in 2011, is due to higher debt outstanding in 2012 compared to 2011.
Loss on derivatives: In connection with obtaining the $40.0 million and $75.0 million secured debt facilities in January and July 2011, respectively, we entered into Performance Based Arranger Fees that we are accounting for as embedded derivatives. As a result of the fair value measurement at March 31, 2012 and 2011, the loss associated with the embedded derivatives increased $2.1 million to $6.4 million for the three months ended March 31, 2012 from $4.3 million in 2011. The reason for the increase in the loss associated with derivatives is due to having two derivatives outstanding for the three months ended Mach 31, 2012 while one was outstanding during 2011 and the increase in oil prices during the three months ended March 31, 2012 compared to the same period in 2011.
Income Taxes
The following is a summary of income (loss) before income taxes and income tax expense (benefit) for the three months ended March 31, 2012 and March 31, 2011:
We have recognized a gross deferred tax asset related to net operating loss carryforwards attributable to the United States, before application of the valuation allowances. We have a valuation allowance for the full amount of the domestic net deferred tax asset, as we believe, 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 2031. Furthermore, because we have no operations within the U.S. taxing jurisdiction, it is likely that sufficient generation of revenue to offset our deferred tax asset is remote.
The difference from the 22% statutory rate provided for under the Block Z-1 License Contract is due to other Peruvian operations that have a different statutory tax rate, certain expenses which are not deductible in Peru and a change in the timing of when certain expenses are deductible.
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. We did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the three months ended March 31, 2012 or 2011, respectively. We did not have any uncertain tax positions generated from unrecognized tax benefits resulting from differences between positions taken in tax returns and amounts recognized in the financial statements as of March 31, 2012 or December 31, 2011.
Net Loss
For the three months ended March 31, 2012, our net loss increased $19.2 million to a net loss of $27.3 million or ($0.24) per basic and diluted share from a net loss of $8.1 million or ($0.07) per basic and diluted share for the same period in 2011.
Liquidity, Capital Resources and Capital Expenditures
At March 31, 2012, we had cash and cash equivalents of $32.9 million, a current accounts receivable balance of $8.9 million and a working capital deficit of $2.0 million.
At March 31, 2012, we had trade accounts payable and accrued liabilities of $52.0 million.
At March 31, 2012, our outstanding long-term debt and short-term debt consisted of 2015 Convertible Notes whose net amount of $148.4 million includes the $170.9 million of principal reduced by $22.5 million of the remaining unamortized discount, a $40.0 million secured debt facility and a $75.0 million secured debt facility. At March 31, 2012, the current and long-term portions of our debt were $32.7 million and $230.6 million, respectively. At March 31, 2012, the current and long-term portions of our capital lease obligations, primarily related to the vessels used in our marine operations, were $0.9 million and $2.4 million, respectively.
Operating Activities
Cash used in operating activities increased by $1.4 million to a use of cash of $2.6 million for the three months ended March 31, 2012 from a use of cash of $1.2 million for the same period in 2011. Cash flows in 2012 decreased due to lower sales volumes as well as the impact of higher costs, partially offset by higher oil prices. This resulted in a decrease of $19.9 million in cash flow before changes in operating assets during 2012 compared to 2011. Changes in cash flow as a result of changes in operating assets and liabilities provided an increase in the source of cash of $18.5 million. The increase in the source of cash is due to an increase in the change of liabilities providing a source of cash of $26.1 million. Offsetting these sources of cash are changes of a net decrease in assets providing a use of cash of $7.6 million
Investing Activities
Net cash used in investing activities increased by $11.6 million to $22.4 million for the three months ended March 31, 2012 from $10.8 million for the same period in 2011. The increase in cash used in investing activities is due to increased capital expenditures of $13.6 million in 2012, partially offset by the change of restricted cash of $2.0 million.
2012 Capital Expenditures
During the three months ended March 31, 2012, we incurred capital expenditures of approximately $22.5 million associated with our development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of gas-fired power generation of electricity for sale in Peru. A summary of capital expenditures follows.
For the three months ended March 31, 2012, we incurred approximately $15.0 million related to costs incurred in the design and fabrication of the CX-15 platform and incurred $4.6 million for development and equipment for permanent production facilities.
Also, we added approximately $1.5 million of costs to the power plant, which primarily consists of capitalized interest, and incurred approximately $1.4 million related to other capitalized costs.
For the three months ended March 31, 2012, capitalized depreciation expense was an immaterial amount and we capitalized $3.0 million of interest expense to construction in progress. For the same period in 2011, we capitalized an immaterial amount of depreciation expense and $2.7 million of interest expense to construction in progress.
Financing Activities
Cash provided by (used in) financing activities decreased by $26.1 million to a use of cash of $0.2 million for the three months ended March 31, 2012, compared to a source of cash of $25.9 million for the same period in 2011. The decrease in cash provided by financing activities is due to decreased borrowings of $40.0 million and lower proceeds from equity issuances of $0.9 million, partially offset by lower repayments of borrowings of $13.3 million and lower debt issue costs of $1.5 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.
Debt and Capital Lease Obligations
At March 31, 2012 and December 31, 2011, Debt and capital lease obligations consisted of the following:
$75 Million Secured Debt Facility
On July 6, 2011, we and our 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 our subsidiary, BPZ E&P. We and our 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 erformance 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 us on July 7, 2011.
Proceeds from the $75.0 million secured debt facility were 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. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
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, 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 was originally set to mature in July 2014, with principal repayment due in quarterly installments that range from $8.7 million to $12.5 million commencing in 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%. Interest is due and payable every three month period after the commencement of the loan. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
The $75.0 million secured debt facility contains covenants that will limit our ability to, among other things, incur additional debt, create certain liens, enter into transactions with affiliates, pay dividends on or repurchase our stock or the stock of our subsidiaries, or sell assets or merge with another entity. In addition, we 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, 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. On February 29, 2012, we and our subsidiaries entered into a third amendment to the $75.0 million secured debt facility dated as of July 6, 2011, with the lenders. The amendment, effective as of February 29, 2012 deferred the date by which commercial production must commence in the Albacora field from February 29, 2012 to April 16, 2012. On January 9, 2012, we and our subsidiaries entered into a second amendment to the $75.0 million secured debt facility dated as of July 6, 2011 with the lenders. The amendment, effective as of December 30, 2011, (i) removed the requirement to provide audited financial statements from BPZ Energy LLC, (ii) increased the maximum consolidated total debt allowed for BPZ E&P from $120 million to $122 million for the fiscal year ended December 31, 2011, (iii) deferred the date by which commercial production must commence in the Albacora field from January 1, 2012 to February 29, 2012, and (iv) extended the date by which we must implement a hedging strategy reasonably acceptable to the lenders from January 2, 2012 to April 1, 2012. We, and our subsidiaries, previously amended the $75.0 million secured debt facility to make conforming changes. We were in compliance with these debt covenants at March 31, 2012. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
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. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
The $75.0 million secured debt facility required us 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.” See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
With respect to the performance based arrangement fee, the fee is payable at each of the principal repayment dates. The performance based arrangement 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 us 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.”
We 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. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
As of March 31, 2012 we estimated 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, 2012, 2013 and 2014 to be approximately $5.7 million, $43.1 million and $38.8 million, respectively. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
$40.0 Million Secured Debt Facility
In January 2011, we, through our 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 our power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L. We and our 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 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 $68.0 million) that were purchased by us from GE through our 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 us 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.” See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
The $40.0 million secured debt facility was originally set to mature 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. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
The $40.0 million secured debt facility subjects us 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. On January 9, 2012, we and our subsidiaries, Empresa Eléctrica Nueva Esperanza S.R.L. and BPZ Exploración & Producción S.R.L., entered into a third amendment to the $40.0 million secured debt facility with Credit Suisse. The amendment, effective as of December 30, 2011, increased the maximum aggregate indebtedness allowed for the BPZ E&P and BPZ Lote Z-1 S.R.L. from $120 million to $122 million. We, and our subsidiary, previously amended the $40.0 million secured debt facility to make conforming changes. We were in compliance with these financial covenants at March 31, 2012. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
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 loan if we secure financing for our gas-to-power project.
In January 2011, we 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 loan using the effective interest method. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
Proceeds from the $40.0 million secured debt facility were utilized to meet our 2011 capital expenditure budget, to finance our exploration and development work programs, and to reduce our existing debt.
As of March 31, 2012, we estimated 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, 2012, and 2013 to be approximately $17.9 million and $24.6 million, respectively. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
$170.9 Million Convertible Notes due 2015
During the first quarter of 2010, we 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 our general senior unsecured obligations and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness. The 2015 Convertible Notes are effectively subordinate to all of our secured indebtedness to the extent of the value of the assets collateralizing such indebtedness. The 2015 Convertible Notes are not guaranteed by our 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, we must deliver, at our 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 our 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 our 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 our 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, we 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 we mail the redemption notice, the “last reported sale price” of our 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 we experience any one of the certain specified types of corporate transactions, holders may require us 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 us, were approximately $164.9 million. The initial purchaser received commissions of approximately $5.5 million in connection with the sale and we incurred approximately $0.6 million of direct expenses in connection with the offering. We used the net proceeds for general corporate purposes, including capital expenditures and working capital, reduction or refinancing of debt, and other corporate obligations.
We accounted for the 2015 Convertible Notes in accordance with Accounting Standard Codification (“ASC”) Topic 470, “Debt”, as it pertains to accounting for convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement). 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 nonconvertible 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.
We estimated our 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 us 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, we 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, we 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 loan using the effective interest method. The remaining $1.3 million of fees and commissions were treated as transaction costs associated with the equity component. We estimate the cash payments including interest payments related to the 2015 Convertible Notes, assuming no conversion, for the year ended December 31, 2012, 2013, 2014 and 2015 to be approximately $5.5 million, $11.1 million, $11.1 million and $176.5 million, respectively. We 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, 2012, the net amount of $148.4 million includes the $170.9 million of principal reduced by $22.5 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 $22.5 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 March 31, 2012, 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, 2012, there is no excess if-converted value to the holders of the 2015 Convertible Notes as the price of our common stock at March 31, 2012, $4.03 per share, is less than the conversion price.
For the three months ended March 31, 2012, 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, 2012, the amount of interest expense related to the 2015 Convertible Notes was $4.6 million, disregarding capitalized interest considerations, and includes $2.8 million of interest expense related to the contractual interest coupon, $1.6 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, 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.
Capital Leases
We are party to several capital lease agreements, as more fully described in our Form 10-K for the year ended December 31, 2011. Generally, we enter into capital lease agreements in order to secure marine vessels to support our operations in Peru and to obtain furniture and fixtures for our offices located in Houston and Peru. The contractual terms of the capital lease agreements range between two to five years and the effective interest rates of the capital lease agreements range between 17.6% and 34.9%.
Restricted Cash and Performance Bonds
Below is a summary of restricted cash as of March 31, 2012 and December 31, 2011:
The $75.0 million secured debt facility we entered into in July of 2011 required us 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, we are 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. We expect to make contributions to the debt service fund of $8.1 million in 2012 and, thereafter, maintain the next quarterly interest and principal payment within the debt service reserve account. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
The $40.0 million secured debt facility we entered into in January of 2011 required us to establish a $2.0 million debt service reserve account during the first 18-month period and, thereafter, we 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. We expect to make contributions to the debt service fund of $15.1 million in 2012 and, thereafter, maintain the next quarterly interest and principal payment within the debt service reserve account. See Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to amendments to the secured debt facilities.
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.
Revision to the 2012 Estimated Capital and Exploratory Expenditures Budget
We are revising our originally estimated 2012 capital expenditures budget from $80 million to approximately $92 million. Included in the revision are increases of $25 million for the CX-15 platform due to changes in production facility design which required additional equipment and includes the allocation of costs associated with the use of our marine equipment. In addition, due to the change in timing of the CX 15 platform installation, $13 million of associated drilling costs originally budgeted for 2012 are being deferred to the 2013 capital budget.
In addition to the changes in capital expenditures, we have revised our geological, geophysical and engineering expenses (or exploratory expenses) to $38 million from the $25 million previously reported as a result of higher costs related to vessel standby, community affairs, marine support and an additional boat required to complete the Block Z-1 3-D seismic acquisition.
Liquidity Outlook
Our major sources of funding to date have been oil sales and equity and debt financing activities. With our current cash balance, current and prospective Corvina and Albacora oil development cash flow, remaining proceeds from our recent debt facilities and potential future equity financing, the timing of which may depend on alternative sources of financing, such as other possible joint venture arrangements, our cash position and market conditions, we believe we will have sufficient capital resources to execute our planned Corvina and Albacora oil development projects and our initial onshore projects as well as service our current obligations.
In 2010, we hired a financial advisor to help us in pursuing joint venture partnerships and/or, farm-outs for some of our assets in northwest Peru. In June 2011, we announced the start of a process to identify and select a potential partner for our offshore Block Z-1. In April 2012, we announced the formation of an unincorporated joint venture, subject to certain closing conditions and approvals, with Pacific Rubiales to explore and develop offshore Block Z-1 in Peru. See Block Z-1 Transaction above for additional details on the joint venture.
Off-Balance Sheet Arrangements
As of March 31, 2012, we had no transactions, agreements or other contractual arrangements with unconsolidated entities or financial partnerships, often referred to as special purpose entities, which generally are established for the purpose of facilitating off-balance sheet arrangements. See Block Z-1 Transaction and Amendments to Secured Debt Facilities related to the Block Z-1 Transaction discussed above for information related to the joint venture and the amendments to the secured debt facilities.
Contractual Obligations
In the third quarter of 2011, Soluciones Energeticas S.R.L., our subsidiary, finalized contracts with a third party to fabricate, mobilize and install a platform at the Corvina field in offshore Block Z-1. The estimated total project cost of the CX-15 project, including all production and compression equipment, is now expected to be approximately $77.0 million. We have guaranteed payment of the platform contracts.
Critical Accounting Estimates
In our annual report on Form 10-K for the year ended December 31, 2011, we identified our most critical accounting policies. In preparing the consolidated financial statements, we make assumptions, estimates and judgments that affect the amounts reported. We periodically evaluate our estimates and judgments that are the most critical in nature which are related to oil reserves, successful efforts method of accounting, revenue recognition, impairment of long-lived assets, future dismantlement, restoration, and abandonment costs, derivative instruments, as well as stock-based compensation. Our estimates are based on historical experience and on our future expectations that we believe are reasonable. Those estimates and assumptions affect the reported amounts of assets, liabilities, revenues and expenses in the consolidated financial statements, and the disclosure of contingent assets and liabilities. Actual results are likely to differ from our current estimates and those differences may be material.
Recent Accounting Pronouncements
In May 2011, the Financial Accounting Standards Board (FASB) issued additional guidance that clarifies application of fair value measurement and disclosure requirements and is effective for annual and interim periods beginning after December 15, 2011. As of March 31, 2012, we adopted the provisions of this guidance, which did not impact the consolidated financial statements. The only impact was to fair value disclosures.
In December 2011, the FASB issued guidance that requires that an entity disclose information about offsetting and related arrangements to enable users of our financial statements to understand the effect of those arrangements on our financial position. The guidance is effective for annual periods beginning on or after January 1, 2013. We are currently evaluating the provisions of this guidance and assessing the impact, if any, it may have on our financial position and results of operations.
Disclosure Regarding Forward-Looking Statements
We caution that this document contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All
statements, other than statements of historical facts, included in or incorporated by reference into this Form 10-Q which address activities, events or developments which we expect, believe or anticipate will or may occur in the future are forward-looking statements. The words “believes,” “intends,” “expects,” “anticipates,” “projects,” “estimates,” “predicts,” “plans” and similar expressions, or the negative thereof, are also intended to identify forward-looking statements. In particular, statements, expressed or implied, concerning future operating results, the ability to replace or increase reserves, or to increase production, or the ability to generate income or cash flows are by nature, forward-looking statements. These statements are based on certain assumptions and analyses made by the management of BPZ in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate in the circumstances. However, forward-looking statements are not guarantees of performance and no assurance can be given that these expectations will be achieved.
Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, but are not limited to, any of the following in the jurisdictions in which BPZ or its subsidiaries are doing business: market conditions, uncertainties inherent in oil and gas production operations and estimating reserves, unexpected future capital expenditures, the timing and extent of changes in commodity prices for crude oil, natural gas and related products, currency exchange rates, interest rates, inflation, the availability of goods and services, drilling and other operational risks, satisfaction of well testing period requirements, successful installation of required permanent processing facilities, receipt of all required permits, successful installation of reinjection equipment and transition to commercial production, successful completion of new drilling platforms, successful installation and operation of the new turbines, availability of capital resources, success of our operational risk management activities, governmental relations, legislative or regulatory changes, political developments, acts of war and terrorism. A more detailed discussion on risks relating to the oil and natural gas industry and to our Company is included in our Annual Report on Form 10-K for the year ended December 31, 2011.
In light of these risks, uncertainties and assumptions, we caution the reader that these forward-looking statements are subject to risks and uncertainties, many of which are beyond our control, which could cause actual events or results to differ materially from those expressed or implied by the statements. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements. We undertake no obligations to update or revise our forward-looking statements, whether as a result of new information, future events or otherwise.
Cautionary Statement Regarding Certain Information Releases
We are aware that certain information concerning our operations and production is available from time to time from Perupetro and the Ministry of Energy and Mines. This information is available from the websites of Perupetro and the Ministry of Energy and Mines and may be available from other official sources of which we are unaware. This information is published by Perupetro and the Ministry of Energy and Mines outside our control and may be published in a format different from the format we use to disclose such information, in compliance with SEC and other U.S. regulatory requirements.
Additionally, our joint venture partner in Block Z-1, Pacific Rubiales Energy Corp. (“PRE”), is a Canadian public company that is not listed on a U.S. stock exchange, but is listed on the Toronto (TSX), Bolsa de Valores de Colombia (BVC) and BOVESPA stock exchanges. As such PRE may be subject to different disclosure requirements than us. Information concerning us, such as information concerning energy reserves, may be published by PRE outside of our control and may be published in a format different from the format we use to disclose such information, in compliance with SEC and other U.S. regulatory requirements.
We provide any such information in the format required, and at the times required, by the SEC and as determined to be both material and relevant by our management. We urge interested investors and third parties to consider closely the disclosure in our SEC filings, available from us at 580 Westlake Park Blvd., Suite 525, Houston, Texas 77079; Telephone: (281) 556-6200; Internet: www.bpzenergy.com. These filings can also be obtained from the SEC via the internet at www.sec.gov.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates, oil and natural gas prices and foreign currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Interest Rate Risk
As of March 31, 2012, we had long-term debt and capital lease obligations of approximately $233.0 million and current maturities of long-term debt and capital lease obligations of approximately $33.6 million.
The $75.0 million secured debt facility, which at March 31, 2012 had $75.0 million outstanding, is variable rate debt that exposes us to the risk of increased interest expense in the event of increases in short-term interest rates. If the variable interest rate were to increase by 1% from the rate at inception, interest expense would increase by approximately $0.8 million annually. The carrying value of the variable interest rate debt approximates fair value as it bears interest at current market rates.
The $40.0 million secured debt facility, which at March 31, 2012 had $40.0 million outstanding, is variable rate debt that exposes us to the risk of increased interest expense in the event of increases in short-term interest rates. If the variable interest rate were to increase by 1% from the rate at inception, interest expense would increase by approximately $0.4 million annually. The carrying value of the variable interest rate debt approximates fair value as it bears interest at current market rates.
The capital lease obligation for the Namoku and Nu’uanu vessels began in August 2007 and is set to expire in May 2014. Lease payments are variable based on the working status of the vessels, with a purchase option of $3.0 million in May 2012, $2.0 million in May 2013, and with a purchase requirement for $1.0 million in May 2014. The imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 34.9%. We do not expect a significant change in the market interest rate to impact the interest on our capital lease obligations.
In February and March 2010, we closed on the private offering for an aggregate $170.9 million of convertible notes due 2015. The 2015 Convertible Notes are general senior unsecured obligations of BPZ and subject us to risks related to changes in the fair value of the debt however, due to make-whole provisions within the Indenture, our exposure to potential gains if we were to repay or refinance such debt are minimal.
The fair value of our 6.5% 2015 Convertible Notes as compared to the carrying value at March 31, 2012 and December 31, 2011, was as follows:
(1) Excludes obligations under capital lease arrangements and variable rate debt. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||