ITEM 1. BUSINESS
Overview
BPZ Resources, Inc., a Texas corporation, is based in Houston, Texas with offices in Lima, Peru and Quito, Ecuador. We are focused on the exploration, development and production of oil and natural gas in Peru and to a lesser extent Ecuador. We also intend to utilize part of our planned future natural gas production as a supply source for the complementary development of a gas-fired power generation facility in Peru which we expect to wholly- or partially-own.
We maintain a subsidiary, BPZ Exploración & Producción S.R.L. (“BPZ E&P”), registered in Peru through our wholly-owned subsidiary BPZ Energy International Holdings, L.P., a British Virgin Islands limited partnership, and its subsidiary BPZ Energy, LLC, a Texas limited liability company. Currently, we, through BPZ E&P, have exclusive rights and license contracts for oil and gas exploration and production covering a total of approximately 2.2 million acres, in four blocks, in northwest Peru. Our license contracts cover 100% ownership of the following properties: Block Z-1 (0.6 million acres), Block XIX (0.5 million acres), Block XXII (0.9 million acres) and Block XXIII (0.2 million acres). The Block Z-1 contract was signed in November 2001, the Block XIX contract was signed in December 2003 and Blocks XXII and XXIII contracts were signed in November 2007. Generally, according to the Organic Hydrocarbon Law No. 26221 and the regulations thereunder (the “Organic Hydrocarbon Law” or “Hydrocarbon Law”), the seven-year term for the exploration phase can be extended in each contract by an additional three years up to a maximum of ten years. However, specific provisions of each license contract can vary the exploration phase of the contract as established by the Hydrocarbon Law. The license contracts require us to conduct specified activities in the respective blocks during each exploration period in the exploration phase. If the exploration activities are successful, we may decide to enter the exploitation phase and our total contract term can extend up to 30 years for oil exploration and production and up to 40 years for gas exploration and production. In the event a block contains both oil and gas, as is the case in our Block Z-1, the 40-year term may apply to oil exploration and production as well.
Additionally, through our wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, we own a 10% non-operating net profits interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). The agreement covering the property extends through May 2016.
We are in the early stages of appraising, exploring and developing the potential oil and natural gas resources throughout our various properties in Peru. In November 2007, we began producing and selling oil from the CX-11 platform in the Corvina field of Block Z-1 under a well testing program and, in November 2010, we placed the Corvina field into commercial production. In December 2009, we began producing oil from the A-14XD well, located on the A platform in the Albacora field of Block Z-1 and began selling oil from the A-14XD well under a well testing program during the second quarter of 2010. From the time we began producing from the CX-11 platform in the Corvina field in November 2007 and the Albacora field in December 2009, through December 31, 2010, we have produced approximately 3.4 MMBbls of oil.
At December 31, 2010, we had estimated net proved oil reserves of 38.9 MMBbls, of which 29.2 MMBbls were in the Corvina field and 9.7 MMBbls were from the Albacora field. Both fields are located in Block Z-1 offshore of northwest Peru. Of our total proved reserves, 12.2 MMBbls (31.5%) are classified as proved reserves consisting of proved developed
producing and proved developed non-producing reserves consisting of 13 wells, and 26.6 MMBbls (68.5%) are classified as proved undeveloped reserves consisting of 21 future wells. The process of estimating oil and natural gas reserves is complex and requires many assumptions that may turn out to be inaccurate. See Item 1A
ITEM 1A. RISK FACTORS
Risks Relating to the Oil and Natural Gas Industry, the Power Industry, and Our Business.
We have a limited operating history and have only engaged in start-up and development activities. We are in the initial stages of developing our oil and natural gas reserves. We have recently transitioned from an extended well testing program into commercial production in our Corvina field and have begun producing and selling oil under an EWT program in our Albacora field. We are also subject to all of the risks inherent in attempting to expand a relatively new business venture. Such risks include, but are not limited to, the possible inability to profitably operate our existing properties or properties to be acquired in the future, our possible inability to fully fund the development requirements of such properties and our possible inability to acquire additional properties that will have a positive effect on our operations. We can provide no assurance that we will achieve a level of profitability that will provide a return on invested capital or that will result in an increase in the market value of our securities. Accordingly, we are subject to the risk that because of these factors and other general business risks noted throughout these “Risk Factors,” we may, in particular, not be able to profitably execute our plan of operation.
In fields we have not placed into commercial production, we must comply with Peruvian legal and regulatory requirements to be able to produce and sell oil after the expiration of production testing or approved extended well testing. If we do not obtain approval to continue our well testing on wells producing for more than six months, we would be required to suspend production from such wells and we would experience an interruption in production that would negatively impact the revenues and cash flow associated with those wells. Under new legislation regulating well testing in Peru, all new wells may be placed on production testing for up to six months. If we need additional time for testing a new well, we must submit a request for the well to enter into an EWT period, together with technical justification for such need and duration, to the DGH, the agency of the Ministry of Energy and Mines responsible for regulating the optimum development of oil and gas fields. After the initial six-month period or before an approved EWT period expires, we will be required to have the necessary gas and water reinjection equipment in place to continue producing the well according to existing environmental regulations. We are subject to this legislation in our Albacora field and any new fields we develop prior to placing them in commercial production.
As of December 31, 2010, we were producing oil from the A-14XD well in the Albacora field under extended well testing and gas flaring permits. The permits for the A-14XD well expired late-January 2011, and our application for new extended well testing and gas flaring permits to continue production from this well were denied and the well remains shut-in. Since we did not receive extended well testing permits on the well in Albacora, we will experience an interruption in production that will negatively impact any revenue and cash flow associated with this well until the applicable requirements are satisfied for commercial production in Albacora, which is anticipated to be towards year end 2011. No assurance can be given that DGH or the Ministry of Energy and Mines will grant approval of any future extended well testing and gas flaring permits requested by us. Under the new well testing regulations, our current view is that we may be able to test any new wells in Albacora or any other field for at least six months. Testing of these wells beyond the initial six month period will require application to the Ministry of Energy and Mines, which may not grant approval.
Our reserve estimates depend on many assumptions that may turn out to be inaccurate. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors that may turn out to be inaccurate. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of reserves shown in the Annual Report.
In order to prepare our reserve estimates, our independent petroleum engineer must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates, and those variances may be material. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, our independent petroleum engineer may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
One should not assume that the net present value of our proved reserves prepared in accordance with the Commission’s guidelines referred to in this report is the current market value of our estimated oil reserves. We base the net present value of future net cash flows from our proved reserves on an unweighted arithmetic average of the first-day-of-the month price for each month during the 12-month calendar year and year-end costs. Actual future prices, costs, taxes and the volume of produced reserves may differ materially from those used in the net present value estimate.
Except as required by applicable law, we undertake no duty to update this information and do not intend to update this information.
As of December 31, 2010, approximately 69% of our estimated net proved reserves were undeveloped. There can be no assurance that all of these reserves will ultimately be developed or produced. We own rights to oil and gas properties that have limited or no development. There are no guarantees that our properties will be developed profitably or that the potential oil and gas resources on the property will produce as expected if they are developed.
Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. We have prepared estimates of our natural gas and oil reserves and the costs associated with these reserves in accordance with industry standards. However, the estimated costs may not be accurate, development may not occur as scheduled, or the actual results may not be as estimated. We may not have or be able to obtain the capital we need to develop these proved reserves.
We have not been profitable since we commenced operations and have historically had significant working capital deficits. To date we have had limited revenue and limited earnings from operations. Though we currently have a working capital surplus, the sources of our working capital surplus have generally been equity and debt financings rather than revenue from operations and we may incur working capital deficits in the future. We cannot provide any assurance that we will be profitable in the future or that we will be able to generate cash from operations or financings to fund working capital deficits.
We require additional financing for the exploration and development of our foreign oil and gas properties and the construction of our proposed power generation facility, pipeline and gas processing facility. Since becoming a public company on September 10, 2004, we have funded our operations with the net proceeds of (i) approximately $288 million in various private and public offerings of our common stock, (ii) $186.4 million in convertible debt financing, including $170.9 million of convertible debt financing sold in a private offering and $15.5 million in convertible debt financing from the International Finance Corporation (“IFC”) that was converted into approximately 1.5 million shares of our common stock in May 2008, and (iii) $40.0 million in a credit facility with Credit Suisse AG, Cayman Islands Branch (“Credit Suisse”). We have recently begun to generate revenues from operations. With these funds we have begun to implement our plans to develop our existing oil and gas properties, but we will need significant additional financing to fully implement our plan of operation. As we continue to execute our business plan and expand our operations, our cash commitments increase and the likelihood of our seeking additional financing, either through the equity markets, debt financing or a combination of both, will increase over the next six months. If we are unable to timely obtain adequate funds to finance our exploration and development, our ability to develop our oil and natural gas reserves may be limited or substantially delayed. Such limitations or delays could result in the potential loss of our oil and gas properties if we were unable to meet our obligations under the license agreements, which could, in turn, limit our ability to repay our debts. Inability to timely obtain funds also could cause us to delay, scale back or abandon our plans for construction of our power generation facility, pipelines and gas processing facility.
Future amounts required to fund our foreign activities may be obtained through additional equity and debt financing, joint venture arrangements, the sale of oil and gas interests, and/or future cash flows from operations. However, adequate funds may not be available when needed or may not be available on favorable terms. The exact nature and terms of such funding sources are unknown at this time, and there can be no assurance that we will obtain such funding or have adequate funding available to finance our future operations.
Any failure to meet our debt obligations or the occurrence of a continuing default under our debt facility would adversely affect our business and financial condition.
On January 27, 2011, we and our subsidiaries, Empresa Eléctrica Nueva Esperanza S.R.L. and BPZ Exploración & Producción S.R.L., entered into a Credit Agreement with Credit Suisse, as lender and administrative agent, dated January 27, 2011, wherein Credit Suisse agreed to provide a $40 million secured debt financing to our power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L., and we and our subsidiary BPZ E&P agreed to unconditionally guarantee the debt facility on an unsecured basis.
The debt facility is secured, in part, by three LM6000 gas-fired packaged power units that were purchased from GE Packaged Power Inc. and GE International Inc. Sucursal de Perú, through its power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L., in accordance with the terms and conditions of the Turbine Purchase Agreement, as subsequently amended (the “Turbine Purchase Agreement”). The debt facility is also secured by certain other equipment and property pledged in favor of Credit Suisse and Credit Suisse International.
The debt facility provides for events of default customary for agreements of this type, including, among other things:
· payment breaches under any of the finance documents;
· representation and warranty breaches;
· any default, early amortization event or similar event occurring with respect to one or more debt facilities in an aggregate outstanding principal amount of at least $3,000,000, if the effect is to accelerate the maturity thereof;
· failure to comply with obligations under the finance documents;
· application for the appointment of a receiver by the borrower or any guarantor;
· making a general assignment for the benefit of creditors by the borrower or any guarantor;
· insolvencies or filing of bankruptcy by the borrower or any guarantor;
· certain monetary and non-monetary judgments, orders, decrees or awards against the borrower, or any guarantor and any of their respective subsidiaries;
· suspension, revocation or termination of any debt facility financing or security documents with Credit Suisse or certain key agreements;
· change in control; and
· failure to perform Empresa Eléctrica Nueva Esperanza S.R.L.’s obligations under the Turbine Purchase Agreement.
If an event of default occurs, Credit Suisse shall, upon the request of the majority lenders, or may, by notice to the borrower, (i) immediately terminate the lending commitments; and/or (ii) declare all or part of the principal amount of the loans, together with accrued interest, immediately due and payable, without demand; provided that, all lending commitments shall automatically terminate and all amounts due and payable on any loan will automatically become immediately due and payable without notice if the borrower or any guarantor and any of their respective subsidiaries appoint a receiver, liquidator or trustee, make a general assignment for the benefit of their creditors, become insolvent, bankrupt, liquidate, or are subject to certain monetary judgments exceeding in the aggregate, $3,000,000; and/or (iii) liquidate the security collateral and apply the proceeds thereof to pay the loans.
The debt facility matures on July 27, 2013, with principal repayment due in equal quarterly installments of $8 million commencing on July 27, 2012. The debt facility bears interest at three month LIBOR plus 7.0%. The interest is due and payable every three month period after the commencement of the loan. The debt facility contains an arranger fee payable to Credit Suisse International. The arranger fee is based on a percentage of the principal amount and the performance of the price of crude oil (Brent) from closing date to repayment date. The performance portion of the arranger fee is subject to a specified maximum amount. In addition, the debt facility provides for a mandatory prepayment of the loans if debt to finance our gas-to-power project is incurred or issued by Empresa Eléctrica Nueva Esperanza S.R.L., or any guarantor and any of their respective subsidiaries. We may not have sufficient funds to make any required repayment under the debt facility. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings, we may be required to arrange new financing or sell a portion of our assets.
Our ability to meet our current and future debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance the debt, sell assets or sell shares of common stock on terms that we do not find attractive, if it can be done at all.
Demand for oil and natural gas is highly volatile. A substantial or extended decline in oil or natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations as well as our ability to meet our capital expenditure obligations and financial commitments to implement our business plan. Any revenues, cash flow, profitability and future rate of growth we achieve will be greatly dependent upon prevailing prices for oil and gas. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also expected to be dependent on oil and gas prices.
Historically, oil and gas prices and markets have been volatile and are likely to be volatile again in the future. For example, oil and natural gas prices increased to historical highs in 2008 and then declined significantly over the last two quarters of 2008. These prices will likely continue to be volatile in the future. Oil and natural gas are commodities and their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand for oil and gas, market uncertainty, and a variety of additional factors beyond our control. Those factors include:
· international political conditions (including wars and civil unrest, such as the recent unrest in the Middle East);
· the domestic and foreign supply of oil and gas;
· the level of consumer demand;
· weather conditions;
· domestic and foreign governmental regulations and other actions;
· actions taken by the Organization of Petroleum Exporting Countries (OPEC);
· the price and availability of alternative fuels; and
· overall economic conditions.
Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but may also reduce the amount of oil and natural gas we can produce economically, if any. A continuation of low or a further decline in oil and natural gas prices may materially affect our future business, financial condition, results of operations, liquidity and borrowing capacity, and may require a reduction in the carrying value of our oil and gas properties. While our revenues may increase if prevailing oil and gas prices increase significantly, exploration and production costs and acquisition costs for additional properties and reserves may also increase. We do not enter into hedging arrangements or use derivative financial instruments such as crude oil forward and swap contracts to hedge our risk associated with fluctuations in commodity prices.
Recent changes in the financial and credit market may impact economic growth, and combined with the recent volatility of oil and natural gas prices, may also affect our ability to obtain funding on acceptable terms or obtain funding under our proposed credit facilities. Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. Accordingly, the equity capital markets have become exceedingly distressed. These issues, along with significant asset write offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions, have made, and will likely continue to make, it difficult to obtain debt or equity capital funding.
Due to these and possibly other factors, we cannot be certain funding will be available if needed, and to the extent required, on acceptable terms. If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our exploratory and development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.
Our future operating revenue is dependent upon the performance of our properties. Our future operating revenue depends upon our ability to profitably operate our existing properties by drilling and completing wells that produce commercial quantities of oil and gas and our ability to expand our operations through the successful implementation of our plans to explore, acquire and develop additional properties. The successful development of oil and gas properties requires an assessment of potential recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities and other factors. Such assessments are necessarily inexact. No assurance can be given that we can produce sufficient revenue to operate our existing properties or acquire additional oil and gas producing properties and leases. We may not discover or successfully produce any recoverable reserves in the future, or we may not be able to make a profit from the reserves that we may discover. In addition, we regularly bring wells on or offline depending on technical performance and, if applicable, testing period requirements. In the event that we are unable to produce sufficient operating revenue to fund our future operations, we will be forced to seek additional, third-party funding, if such funding can be obtained. Such options would possibly include debt financing, sale of equity interests in the Company, joint venture arrangements, or the sale of oil and gas interests. If we are unable to secure such financing on a timely basis, we could be required to delay or scale back our operations. If such unavailability of funds continued for an extended period of time, this could result in the termination of our operations and the loss of an investor’s entire investment.
Our business involves many uncertainties and operating risks that may prevent us from realizing profits and can cause substantial losses. Our exploration and production activities may be unsuccessful for many reasons, including weather, the drilling of dry holes, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of a natural gas or oil well will not ensure we will realize a profit on our investment. A variety of factors, including geological, regulatory and market-related factors can cause a well to become uneconomical or only marginally economical. Our business involves a variety of operating risks, including:
· fires;
· explosions;
· blow-outs and surface cratering;
· uncontrollable flows of natural gas, oil and formation water;
· natural disasters, such as earthquakes, tsunamis, typhoons and other adverse weather conditions;
· pipe, cement, subsea well or pipeline failures;
· casing collapses;
· mechanical difficulties, such as lost or stuck oil field drilling and service tools;
· abnormally pressured formations; or
· environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
Experiencing any of these operating risks could lead to problems with any well bores, platforms, gathering systems and processing facilities, which could adversely affect any drilling operations we may commence. Affected drilling operations could further lead to substantial losses as a result of:
· injury or loss of life;
· severe damage to and destruction of property, natural resources and equipment;
· pollution and other environmental damage;
· clean-up responsibilities;
· regulatory requirements, investigations and penalties;
· suspension of our operations; or
· repairs to resume operations.
If any of these risks occur, we may have to curtail or suspend any drilling or production operations and we could have our sales of oil interrupted or suspended, which could have a material adverse impact on our financial condition, operations and ability to execute our business plan.
We conduct offshore exploration, exploitation and production operations off the coast of northwest Peru, all of which are also subject to a variety of operating risks peculiar to the marine environment. Such risks include collisions, allisions, groundings and damage or loss from adverse weather conditions or interference from commercial or artesian fishing activities. These conditions can cause substantial damage to facilities, tankers and barges, as well as interrupt operations. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, exploitation and acquisitions or result in loss of equipment and properties.
Disruption of services provided by our barges and tankers could temporarily impair our operations and delay delivery of our oil to be sold. We depend on our deck barges BPZ-01 and BPZ-02 to act as tender support vessels for our offshore drilling operations in our Corvina and Albacora fields in Block Z-1. In addition, we have two barges under capital lease to use in support of our offshore oil production operations. One barge is used as a floating production, storage and offloading facility and the other is currently being used as a floating storage and offloading facility. In addition, we have time chartered a double hull tank vessel to transport crude oil from our offshore production and storage facilities in the Corvina and Albacora fields to the Talara refinery approximately 70 miles south of the platform where the oil is sold at current market prices under sales contracts with the Peruvian national oil company, Petroperu. Any disruption or delay of the services to be provided by our barges or tanker because of adverse weather conditions, accidents, mechanical failures, insufficient personnel or other events could temporarily impair our operations, delay implementation of our business plan, and increase our costs.
Future oil and natural gas declines or unsuccessful exploration efforts may result in significant charges or a write-down of our asset carrying values. We follow the successful efforts method of accounting for our investments in oil and natural 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. Certain costs of exploratory wells are capitalized pending determinations that proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed.
The capitalized costs of our oil and natural gas properties, on a field basis, cannot exceed the estimated undiscounted future net cash flows of that field. If net capitalized costs exceed undiscounted future net cash flows, we must write down the costs of each such field to our estimate of its fair market value. Unproved properties are evaluated at the lower of cost or fair market value. Accordingly, a significant decline in oil or natural gas prices or unsuccessful exploration efforts could cause a future write-down of capitalized costs.
We evaluate impairment of our proved oil and gas properties whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date even if oil or natural gas prices increase.
Our management team has limited experience in the power generation business and we need additional funding to construct power generation and pipelines. Our plan of operation includes constructing power generation and pipelines in Peru, and in the future, potentially Ecuador. However, the experience of our management team has primarily been in the oil and natural gas exploration and production industry and we have limited experience in the power generation business. We have recently hired a Director of Gas-to-Power and Project Manager. However, we continue relying on consultants and outside engineering and technical firms to provide the expertise to plan and execute the power generation aspects of our strategy and we have not yet hired all necessary full-time employees to manage this line of business. If we do not have sufficient funds or if we are unable to successfully find partners to participate in our gas-to-power project, we will need to find alternative sources of funding for the construction of the power generation, which may not be available when needed or available on favorable terms.
Construction and operation of power generation and pipelines involve significant risks and delays that cannot always be covered by insurance or contractual protections. The construction of power generation and pipelines involve many risks, including:
· supply interruptions;
· work stoppages;
· labor disputes;
· social unrest;
· inability to negotiate acceptable construction, supply or other contracts;
· inability to obtain required governmental permits and approvals;
· weather interferences;
· unforeseen engineering, environmental and geological problems;
· unanticipated cost overruns;
· possible delays in the acquisition of necessary gas turbines;
· possible delays in transporting the necessary equipment to our planned facility in Northern Peru;
· possible delays in connection with power plant construction;
· possible delays or difficulties in completing financing arrangements for the gas-to-power project; and
· possible difficulties or delays with respect to any necessary Peruvian regulatory compliance.
The ongoing construction and future operation of these facilities involve all of the risks described above, in addition to risks relating to the breakdown or failure of equipment or processes and performances below expected levels of output or efficiency. We intend to maintain commercially reasonable levels of insurance where such insurance is available and cost-effective, obtain warranties from vendors and obligate contractors to meet certain performance levels. However, the coverage or proceeds of any such insurance, warranties or performance guarantees may not be adequate to cover lost revenues or increased expenses. Any of these risks could cause us to operate below expected capacity levels, which in turn could result in lost revenues, increased expenses and higher costs.
The success of our gas-to-power project depends, in part, on the existence and growth of markets for natural gas and electricity in Peru. Peru has a relatively well-developed and stable market for electricity. Peru relies on hydroelectric generating capacity for a significant portion of their power demand. Hydroelectric plants are much less expensive to operate than plants that utilize natural gas, but they are subject to variable output based on rainfall and reservoir levels. The majority of the non-hydroelectric or thermal power capacity in Peru consists of generating plants that utilize diesel or fuel oil, which are significantly more costly than natural gas at this time. Peru has natural gas reserves and production, but does not have a well-developed natural gas infrastructure, particularly in northwest Peru where we operate. Our immediate business plan relies on the continued stability of the power market in Peru. We currently do not expect to complete our power plant until 2012. Our assessment of the future power market and demand in Peru could be inaccurate. We are subject to the following risks that:
· relatively more favorable business conditions for hydroelectric plants, a material reduction in power demand or other competitive issues may adversely affect the demand and prices for the electricity that we expect to produce by the time the power plant is completed;
· our lifting costs could exceed the minimum wholesale power prices available, making the sale of our gas uneconomical;
· potential disruptions or changes to regulations of the natural gas or power markets in these countries could occur by the time our power plant is completed, or we may not receive the necessary environmental or other permits and governmental approvals to operate our power plant;
· although we plan to enter into long-term contracts to sell a significant part of our future power production, there can be no assurance that we will be successful in obtaining such contracts or that they will be on favorable terms; and
· we will also be subject to the general commercial issues related to being in the power business, including the credit-worthiness of, and collections from future customers and the ability to profitably operate our future power plants.
The geographic concentration of our properties in northwest Peru and southwest Ecuador subjects us to an increased risk of loss of revenue or curtailment of production from factors affecting that region specifically. The geographic concentration of our properties in northwest Peru and southwest Ecuador and adjacent waters means that some or all of our properties could be affected by the same event should that region, for example, experience:
· natural disasters and severe weather (such as the effects of “El Niño,” which can cause excessive rainfall and flooding in Peru and Ecuador);
· delays or decreases in production, the availability of equipment, facilities or services;
· delays or decreases in the availability of capacity to transport, gather or process production; or
· changes in the political or regulatory environment.
Because all our properties could experience the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area.
Along with the general instability that comes from international operations, we face political and geographical risk specific to working in South America. Presently, all of our oil and gas properties are located in South America, specifically Peru and Ecuador. The success and profitability of our international operations may be adversely affected by risks associated with international activities, including:
· economic, labor, and social conditions;
· local and regional political instability;
· tax laws (including host-country export, excise and income taxes and U.S. taxes on foreign operations); and
· fluctuations in the value of the U.S. dollar versus the local currencies in which oil and gas producing activities may be conducted.
This instability in laws, expenses of operations and fluctuations in exchange rates may make our assumptions about the economic viability of our oil and gas properties incorrect. If these assumptions are incorrect, we may not be able to earn sufficient revenue to cover our costs of operations.
Social and political unrest in Peru could cause heightened scrutiny over oil and gas regulatory matters. We believe there has been recent heightened scrutiny over regulatory matters concerning oil and gas exploration and production and the award of licensing contracts in Peru, in large part due to social and political unrest. For example, in August 2008, Peru’s Congress repealed two presidential decrees that made it easier for companies and individuals to buy land belonging to indigenous peoples as a result of protests from a large number of indigenous people in Peru’s Amazon jungle. Beginning in April 2009, thousands of indigenous people again protested by blocking roads and waterways in eastern Peru to try to force the repeal of additional decrees facilitating oil exploration, commercial farming and logging in parts of the Amazon jungle, resulting in a violent clash between police officers and the protestors in June 2009. The violence led to the suspension of several of the decrees and the Peruvian President’s third reshuffle of his cabinet since he came to power in 2006.
Peru’s most recent municipal and regional political elections were held in November 2010, and the next Peruvian Presidential and Congressional election will be in April 2011. The campaigning leading up to the elections will likely cause heightened political risk and attention to various topics, including the regulation of oil and gas companies operating in Peru,
and related environmental law compliance. As a result of these or similar events, a shift in policy could occur with respect to the regulation of oil and gas companies making it more difficult or expensive to operate in such an environment.
Our operations in Peru and Ecuador involve substantial costs and are subject to certain risks because the oil and gas industry in Peru and Ecuador is less developed when compared to the United States. Because the oil and gas industry in Peru and Ecuador is less developed than in the United States, our drilling and development operations, in many instances, will take longer to complete and may cost more than similar operations in the United States. The availability of technical expertise and specific equipment and supplies may be more limited or costly in Peru and Ecuador than in the United States. If we are unable to obtain or unable to obtain without undue cost drilling rigs, equipment, supplies or personnel, our exploitation and exploration operations could be delayed or adversely affected, which could have a material adverse effect on our business, financial condition or results of operations. Furthermore, once oil and natural gas production is recovered, there are fewer ways to transport it to market for sale. Marine transportation is subject to risks such as adverse weather conditions, collisions, groundings and other risks of damage or delay. Pipeline and trucking operations are subject to uncertainty and lack of availability. Oil and natural gas pipelines and truck transport travel through miles of territory and are subject to the risk of diversion, destruction or delay. We expect that such factors will continue to subject our international operations to economic and operating risks that companies with domestic operations do not experience.
We are subject to numerous foreign laws and regulations of the oil and natural gas industry that can adversely affect the cost, manner or feasibility of doing business. Our operations are subject to extensive foreign laws and regulations relating to the exploration for oil and natural gas and the development, production and transportation of oil and natural gas as well as electrical power generation. Because the oil and gas industry in the countries in which we operate is less developed than elsewhere, changes in laws and interpretations of laws are more likely than in countries with a more developed oil and gas industry. Future laws or regulations, as well as any adverse change in the interpretation of existing laws or our failure to comply with existing legal requirements may harm our results of operations and financial condition. In particular, there are indications that the current administration in Ecuador is likely to increase state intervention in the economy via new legislation and tightening control of areas such as energy, which could have a significant impact on our ability to operate in that country. We may be required to make large and unanticipated expenditures to comply with governmental regulations, such as:
· work program guarantees and other financial responsibility requirements;
· taxation;
· royalty requirements;
· customer requirements;
· employee compensation and benefit costs;
· operational reporting;
· environmental and safety requirements; and
· unitization requirements.
Under these laws and regulations, we could be liable for:
· personal injuries;
· property and natural resource damages;
· unexpected employee compensation and benefit costs;
· governmental infringements and sanctions; and
· unitization payments.
If we fail to comply with the terms of certain contracts related to our foreign operations, we could lose our rights under each of those contracts. The terms of each of our contracts with the government of Peru, including our Peruvian oil and gas license contracts, require that we perform certain activities, such as seismic acquisition, processing and interpretations and the drilling of required wells in accordance with those contracts and agreements. We are also required to conduct environmental impact assessments and establish our ability to comply with environmental regulations. Our failure to timely perform those activities as required could result in the suspension of our current production and sale of oil, the loss of our rights under a particular contract and/or the loss of the amounts we have posted as a guaranty for the performance of such activities, which would result in a significant loss to us.
We are subject to the Foreign Corrupt Practices Act (the “FCPA”), and our failure to comply with the laws and regulations thereunder could result in penalties which could harm our reputation and have a material adverse effect on our business, results of operations and financial condition. We are subject to the FCPA, which generally prohibits companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. Since all of our oil and gas properties are in Peru and Ecuador, there is a risk of potential FCPA violations. We have a FCPA policy and a compliance program designed to ensure that the Company, its employees and agents comply with the FCPA. There is no assurance that such policy or program will work effectively all of the time or protect us against liability under the FCPA for actions taken by our agents, employees and intermediaries with respect to our business or any businesses that we acquire. Any violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.
We are subject to complex environmental regulatory and permitting laws and regulations that can adversely affect the cost, manner and feasibility of our planned operations. The exploration for, and the development, production and sale of, oil and gas in South America, and the construction and operation of power generation and gas processing facilities and pipelines in South America are subject to extensive environmental, health and safety laws and regulations. Our ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. For example, we are required to obtain an environmental permit or approval from the government in Peru prior to conducting seismic operations, drilling a well or constructing a pipeline in Peruvian territory, including the waters offshore of Peru, where we intend to conduct future oil and gas operations. We are also required to comply with numerous environmental regulations in order to transition from exploration into commercial production in the Albacora field or any new fields we develop. Additionally, environmental laws and regulations promulgated in Peru impose substantial restrictions on, among other things, the use of natural resources, interference with the natural environment, and the location of facilities, the handling and storage of hazardous materials such as hydrocarbons, the use of radioactive material, the disposal of waste, and the emission of noise and other activities. The laws create additional monitoring and reporting obligations in the event of any spillage or unregulated discharge of hazardous materials such as hydrocarbons. Failure to comply with these laws and regulations also may result in the suspension or termination of our planned drilling operations and subject us to administrative, civil and criminal penalties.
Our current permits and authorizations and our ability to get future permits and authorizations may, over time, be susceptible to increased scrutiny, resulting in increased costs, or delays in receiving appropriate authorizations. In particular, we may experience delays in obtaining permits and authorizations in Peru necessary for our operations. We have currently suspended drilling in the Albacora field until our planned 3-D seismic acquisition program in Block Z-1 is carried out. In 2009, we attempted to acquire 3-D seismic in Block Z-1, but stopped our seismic acquisition program at the request of the government. We are currently completing additional government requested environmental studies to obtain the permit to begin the seismic acquisition program. Current indications are that permits should be granted and acquisition could begin in the middle of 2011. However, any material delays in receiving these permits could delay our ability to resume our drilling program in the Albacora field and could negatively affect our indicated reserves in Albacora.
Compliance with these laws and regulations may increase our costs of operations, as well as further restrict our foreign operations. Moreover, these laws and regulations could change in ways that substantially increase our costs. These laws and regulations have changed in the past and have generally imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated developments could cause us to make environmental expenditures that are significantly higher than those we currently anticipate, thereby increasing our overall costs. Any failure to comply with these laws and regulations could cause us to suspend or terminate certain operations or subject us to administrative, civil or criminal penalties. Any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and our ability to implement our plan of operation.
Compliance with, or breach of, laws relating to the discharge of materials into, and the protection of, the environment can be costly and could limit our operations. As an owner or lessee and operator of oil and gas properties in Peru and Ecuador, we are subject to various national, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, (i) impose liability on the owner or lessee under an oil and gas lease for the cost of property damage, oil spills, discharge of hazardous materials, remediation and clean-up resulting from operations; (ii) subject the owner or lessee to liability for pollution damages and other environmental or natural resource damages; and (iii) require suspension or cessation of operations in affected areas or related sales of oil and gas.
We have established practices for continued compliance with environmental laws and regulations and we believe the costs incurred by these policies and procedures so far have been necessary business costs in our industry. However, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not increase such compliance costs, or have a material adverse effect upon our capital expenditures, earnings or competitive position.
Our oil and gas operations involve substantial costs and are subject to various economic risks. Our oil and gas operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire producing properties and to drill exploratory wells. The cost and length of time necessary to produce any reserves may be such that it will not be economically viable. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. In addition, the cost and timing of drilling, completing and operating wells is often uncertain. We also face the risk that the oil and/or gas reserves may be less than anticipated, that we will not have sufficient funds to successfully drill on the property, that we will not be able to market the oil and/or gas due to a lack of a market and that fluctuations in the prices of oil and/or gas will make development of those wells uneconomical. This could result in a total loss of our investments made in our operations.
Competition for oil and natural gas properties and prospects is intense; many of our competitors have larger financial, technical and personnel resources that give them an advantage in evaluating and obtaining properties and prospects. We operate in a highly competitive environment for reviewing prospects, acquiring properties, marketing oil and natural gas and securing trained personnel and equipment. In addition, changes in Peruvian government regulation have enabled multinational and regional companies to enter the Peruvian energy market. We actively compete with other companies in our industry when acquiring new leases or oil and gas properties. Competition in our business activities has increased and will increase further, as existing and new participants expand their activities as a result of these regulatory changes. Many of our competitors possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than we have. For example, if several companies are interested in an area, Perupetro (a state company responsible for promoting and overseeing the investment of hydrocarbon exploration and exploitation activities in Peru) may choose to call for bids, either through international competitive biddings or through private bidding processes by invitation, and award the contract to the highest bidder. These additional resources can be particularly important in reviewing prospects and purchasing properties. Our competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our competitors may also be able to pay more for productive oil and natural gas properties and exploratory prospects than we are able or willing to pay. On the acquisition opportunities made available to us, we compete with other companies in our industry for properties operated by third parties through a private bidding process, direct negotiations or some combination thereof. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. If we are unable to compete successfully in these areas in the future, our future revenues and growth may be diminished or restricted. The availability of properties for acquisition depends largely on the business practices of other oil and natural gas companies, commodity prices, general economic conditions and other factors we cannot control or influence.
The loss of senior management or key technical personnel could adversely affect us. We have engaged certain members of management who have substantial expertise in the type of endeavors we presently conduct and the geographical areas in which we conduct them. We do not maintain any life insurance against the loss of any of these individuals. To the extent their services become unavailable, we will be required to retain other qualified personnel. There can be no assurance we will be able to recruit and hire qualified persons on acceptable terms. Similarly, the oil and gas exploration industry requires the use of personnel with substantial technical expertise. In the event that the services of our current technical personnel become unavailable, we will need to hire qualified personnel to take their place. No assurance can be given that we will be able to recruit and hire such persons on acceptable terms. Inability to replace lost members of management or personnel may adversely affect us.
Insurance does not cover all risks. Exploration for, and the production of, oil and natural gas can be hazardous, involving unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can result in damage to or destruction of wells or production facilities, formations, injury to persons, loss of life, or damage to property, the environment or natural resources. As a result, we presently maintain insurance coverage in amounts consistent with our business activities and to the extent required by our license contracts. Such insurance coverage includes certain physical damage to the Company’s and third parties’ property, hull and machinery, protection and indemnity, employer’s liability, comprehensive third party general liability, workers compensation and certain pollution and environmental risks. However, we are not fully insured against all risks in all aspects of our business, such as political risk, civil unrest, war, business interruption, environmental damage and reservoir loss or damage. Further, no such insurance coverage can insure for all operational or environmental risks. The occurrence of an event that is not insured or not fully insured could result in losses to us. For example, uninsured or under insured environmental damages, property damages or damages related to personal injuries could divert capital needed to implement our plan of operation. If any such uninsured losses are significant, we may have to curtail or suspend our drilling or other operations until such time as replacement capital is obtained, if ever, and this could have a material adverse impact on our financial position.
We may not be able to replace our reserves. Our future success will depend upon our ability to find, acquire and develop oil and gas reserves that are economically recoverable. Any reserves we develop will decline as they are produced unless we are able to conduct successful revitalization activities, or are able to replace the reserves by acquiring properties containing proven reserves, or both. To develop reserves and achieve production, we must implement our development and production programs, identify and produce previously overlooked or by-passed zones and shut-in wells, acquire additional properties or undertake other replacement activities. We can give no assurance that our planned development, revitalization, and acquisition activities will result in significant reserves replacement or that we will have success in discovering and producing reserves economically. We may not be able to locate geologically satisfactory property, particularly since we will be competing for such property with other oil and gas companies, most of which have much greater financial resources than we do. Moreover, even if desirable properties are available to us, we may not have sufficient funds with which to acquire or develop them.
Risks Relating to Our Securities
Investor profits, if any, may be limited for the near future. In the past, we have never paid a dividend. We do not anticipate paying any dividends in the near future. Accordingly, investors in our common stock may not derive any profits from their investment in us for the foreseeable future, other than through any price appreciation of our common stock that may occur. Further, any appreciation in the price of our common stock may be limited or nonexistent as long as we continue to have operating losses. We have not been profitable and have accumulated deficits of operations totaling $301.0 million through December 31, 2010. To date we have had limited revenue and no earnings from operations. There can be no assurances that sufficient revenue to cover total expenses can be achieved until, if at all, we fully implement our operational plan.
Additional infusions of capital may have a dilutive effect on existing shareholders. To finance our operations we may sell additional shares of our common stock. During the first quarter of 2010, we issued $170.9 million of Convertible Notes due 2015 that, if converted to common stock, could significantly increase the amount of our common shares outstanding by up to approximately 28.9 million shares currently. We currently have $134.6 million in common stock available under an effective shelf registration statement, and another $500 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. Our certificate of formation does not provide for preemptive rights. Any additional equity financing that we receive may involve substantial dilution to our then-existing shareholders. Furthermore, we may issue common stock to acquire properties, assets, or businesses. In the event that any such shares are issued, the proportionate ownership and voting power of other shareholders will be reduced. In addition, we are authorized to issue up to 25,000,000 shares of preferred stock, the rights and preferences of which may be designated by our Board of Directors. If we issue shares of preferred stock, such preferred stock may have rights and preferences that are superior to those of our common stock.
Our operations may not generate sufficient cash to enable us to service our debt, including the Convertible Notes due 2015 or the $40.0 million credit facility with Credit Suisse. Our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt, including the Convertible Notes due 2015 or the $40.0 million credit facility with Credit
Suisse. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.
If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:
· refinancing or restructuring our debt;
· selling assets;
· reducing or delaying capital investments; or
· seeking to raise additional capital.
However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.
Shares eligible for future sale by our current shareholders may impair our ability to raise capital through the sale of our stock. As of December 31, 2010, we had 115.5 million shares of common stock issued and outstanding. In addition, we currently have outstanding 34.1 million shares of potentially dilutive securities, which mainly consist of approximately 28.9 million shares that are potentially convertible under our Convertible Notes due 2015 and 5.2 million options granted under our 2005 and 2007 Long-Term Incentive Compensation Plan, as amended. We also have an additional 4.6 million shares of common stock allocated under our 2007 Long-Term Incentive Compensation Plan and our 2007 Directors’ Compensation Incentive Plan. The Convertible Notes due 2015 in the amount of $170.9 million were issued during the first quarter of 2010. The possibility that substantial amounts of shares of our common stock may be sold in the public market may cause prevailing market prices for our common stock to decrease and thus could impair our ability to raise capital through the sale of our equity securities.
Our officers, directors, entities affiliated with them and certain institutional investors may exercise significant control over us. In the aggregate, our management and directors own or control approximately 14.3% of our common stock, and several institutional investors own approximately another 28.7% of our common stock, issued as of December 31, 2010. These shareholders own in total approximately 43.0%, and, if acting together, would be able to significantly influence all matters requiring approval by our shareholders, including the election of directors and the approval of mergers or other business combination transactions.
Our corporate organizational documents and the provisions of Texas law to which we are subject may delay or prevent a change in control of us that some shareholders may favor. Our certificate of formation and bylaws contain provisions that, either alone or in combination with the provisions of Texas law described below, may have the effect of delaying or making it more difficult for another person to acquire us by means of a hostile tender offer, open market purchases, a proxy contest or otherwise. These provisions include:
· A board of directors classified into three classes of directors with each class having staggered, three-year terms. As a result of this provision, at least two annual meetings of shareholders may be required for the shareholders to change a majority of our board of directors.
· The board’s authority to issue shares of preferred stock without shareholder approval, which preferred stock could have voting, liquidation, dividend or other rights superior to those of our common stock. To the extent any such provisions are included in any preferred stock, they could have the effect of delaying, deferring or preventing a change in control.
· Our shareholders cannot act by less than unanimous written consent and must comply with the provisions of our bylaws requiring advance notification of shareholder nominations and proposals. These provisions could have the effect of delaying or impeding a proxy contest for control of us.
· Provisions of Texas law, which we did not opt out of in our certificate of formation, that restrict business combinations with “affiliated shareholders” and provide that directors serving on staggered boards of directors, such as ours, may be removed only for cause.
Any or all of these provisions could discourage tender offers or other business combination transactions that might otherwise result in our shareholders receiving a premium over the then current market price of our common stock.
The market price and trading volume of our common stock may be volatile. The market price of our common stock may be highly volatile and subject to wide fluctuations. In addition, the trading volume in our common stock may fluctuate and cause significant price variations to occur. If the market price of our common stock declines significantly, you may be unable to resell your shares at or above the price at which the shares were acquired. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. Some of the factors that could adversely affect our share price or result in fluctuations in the price or trading volume of our common stock include:
· actual or anticipated fluctuations in our results of operations;
· failure to be covered by securities analysts, or failure by us to meet securities analysts’ expectations;
· success of our operating strategies;
· decline in the stock price of companies that are our peers;
· realization of any of the risks described in this section; or
· general market and economic conditions.
Because we are a relatively new public company, these fluctuations may be more significant for us than they would be for a company whose stock has been publicly traded over an extended period of time.
In addition, the stock market has experienced in the past, and may again in the future experience extreme price and volume fluctuations. These market fluctuations may materially and adversely affect the trading price of our common stock, regardless of our actual operating performance.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
ITEM 2. PROPERTIES
Offices
Our corporate headquarters office is in Houston, Texas, where we lease approximately 20,400 square feet of office space under a lease agreement which expires in February 2016. We sublease approximately 4,900 square feet of our office space to a tenant under a sublease agreement which expires in December 2012. We also currently lease administrative offices and warehouses in Peru. The administrative office and warehouse leased areas are approximately 22,500 square feet and 101,000 square feet, respectively, and both leases expire in December 2013. Additionally, we lease an administrative office in Quito, Ecuador of 829 square feet under a month-to-month lease.
Properties in Peru
We currently have exclusive rights to four properties in northwest Peru. We have a 100% working interest in license contracts for Block Z-1, Block XIX, Block XXII and Block XXIII. The license contracts afford an initial exploration phase of seven years. As described below, each license contract provides for additional exploration periods which can extend the exploration phase of the license contract. If exploration efforts are successful, the license contracts 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 Block Z-1 contract, the 40-year term may apply to oil exploration and production as well. These four blocks cover a combined area of approximately 2.2 million acres.
The following table is a summary of our properties in northwest Peru. As of December 31, 2010 only acreage in Block Z-1 has been partially developed.
(1) Does not include the CX11-16X well which tested quantities of gas which we believe to be of commercial amounts and is currently shut-in. Until such time as sufficient funding has been secured and the necessary infrastructure is in place for our gas-to power project, we cannot include any of these reserves as part of our SEC reserves nor include the well(s) as productive.
(2) Includes all oil producing wells developed by the Company. At December 31, 2010, seven of these wells were under production and the remaining three wells were shut-in due to high gas oil ratios and mechanical issues.
Description of Block Z-1 and License Contract
Block Z-1, a coastal offshore area encompassing approximately 555,000 acres, is situated at the southern end of the Gulf of Guayaquil in northwest Peru. Geologically, the block lies within the Tumbes Basin. From the coastline, water depths increase gradually. The average water depth of the area is approximately 200 feet and approximately 10% of the area has depths ranging from 500 feet up to 1,000 feet. Located within Block Z-1 are five structures which were drilled in the 1970s and 1980s by previous operators, including Tenneco, Inc. and Belco Oil and Gas Corporation (“Belco”). These structures are known as the Albacora, Barracuda, Corvina, Delfin and Piedra Redonda fields. Wells drilled in each of these structures tested positive for oil or gas in what we believe to be economic quantities while drilling at depths ranging from 6,000 to 12,000 feet. However, at the time the wells were drilled, it was not considered economic to produce and sell natural gas from the fields. Consequently, the wells were either suspended or abandoned.
In the Corvina field, five wells were drilled, including two wells drilled by Tenneco in the mid-1970s and three wells drilled by Belco in the late 1970s and early 1980s. Two drilling and production platforms were set up by Belco during this period and are still in place in the Corvina field. The first platform is located in the East Corvina prospect field and, based on the engineering study, we have concluded that the platform is not considered suitable for our future development plans and therefore requires us to build a new platform prior to initiating any drilling activities in this section of the Corvina field. The second platform, CX-11, is located in the West Corvina development field and is currently being used in our West Corvina drilling and production activities. All five of the previously drilled wells in the Corvina field encountered indications of natural gas and apparent reservoir-quality formations.
In the Albacora field, three wells were drilled and produced oil for a very limited time. The original drilling and production platform set up by Belco during this period is still in place in the Albacora field and has been repaired and refurbished by us. The Albacora field is located in the northern part of our offshore Block Z-1. It consists of approximately 7,500 acres and, is located in water depths of less than 200 feet.
In the Piedra Redonda field, two wells were drilled by Belco in the late 1970s and early 1980s. Indications of natural gas were present in both wells. One well was completed, while the other well encountered abnormally high pressures and was abandoned for mechanical reasons prior to reaching its intended total depth. After conducting engineering feasibility studies, we have determined the existing platform located in the Piedra Redonda field is not considered suitable for our future development plans and therefore we must build a new platform prior to initiating any drilling activities in this section of the Piedra Redonda field. In connection with the building of a new platform, we do not expect to recomplete the previously drilled and completed well by Belco due to uncertainty of the condition and potentially high wellhead pressure of the well.
We originally acquired our initial interest in Block Z-1 in a joint venture with Syntroleum Peru Holdings Limited, Sucursal del Peru, under an exploration and production license contract dated November 30, 2001, with an effective date of January 29, 2002. Under the original contract, BPZ owned a 5% non-operating working interest, along with the right of first refusal, in the block. Syntroleum later transferred its interest to Nuevo Peru ltd., Sucursal del Peru. Subsequent to the merger of Nuevo Energy, Inc. and Plains Exploration and Production Company, Nuevo Energy, Inc. transferred its interest in Block Z-1 to BPZ which then assumed a 100% working interest, as well as the remaining obligations under the contract. Perupetro approved the assumption of Nuevo’s interest by BPZ and the designation of BPZ as a qualified operator under the contract in November 2004. This action was subject to official ratification and issuance of a Supreme Decree by the government of Peru, which was issued in February 2005. Accordingly, an amended contract was signed with Perupetro, naming BPZ as the owner of 100% of the participation under the license contract.
The license contract provides for an initial exploration phase of seven years, and can be extended under certain circumstances an additional six years up to thirteen years. Each period has a commitment for exploration activities and requires a financial guarantee to secure the performance of the work commitment during such period. Block Z-1 is currently in the fourth exploration period. This period was initially scheduled to expire in November 2009. However, as a result of suspension of seismic data survey by the Ministry of Energy and Mines, the fourth period is currently under suspension until our revised Environmental Impact Study is approved by the DGAAE (“Dirección General de Asuntos Ambientales y Energéticos”), a division of the Ministry of Energy and Mines, that is responsible for environmental protection matters in Peru. The fourth and final exploration period requires the drilling of an additional exploratory well or other equivalent work commitments, such as conducting a seismic data survey. A performance bond of $1.0 million was posted for cash collateral of $1.0 million related to the fourth exploration period. The performance bond will be released at the end of the exploration period if the work commitment for that period has been satisfied. In addition, we are required to make technology transfer payments related to training costs of Perupetro professional staff during the exploration phase of $50,000 per year.
On November 21, 2007, we submitted a letter to Perupetro declaring a commercial discovery in the Block Z-1 field. On May 19, 2008 we filed the field development plan (“FDP”) with Perupetro. In November 2010, after obtaining an extension of our original proposed First Date of Commercial Production (“FDCP”), we placed the Corvina field into commercial production. In the Albacora field, we plan to install the necessary gas and water reinjection facilities on the platform to allow that field to be transitioned into commercial production by the end of 2011.
Under the contract, oil exploration, development and production can continue for a total of up to 30 years from the effective date of the contract, and gas exploration, development and production can continue for up to 40 years. In the event a block contains both oil and gas, as is the case in the Block Z-1 contract, the 40-year term may apply to oil exploration and production as well. Royalties under the contract vary from 5% to 20% based on production volumes. Royalties start at 5% if and when production is less than 5,000 boepd and are capped at 20% if and when production surpasses 100,000 boepd.
After the third exploration period, we relinquished 25% of the least prospective acreage as stipulated under the terms of the Block Z-1 License Contract as we transitioned into the fourth exploration phase under the license contract. None of the mapped prospects identified by us were included within the acreage relinquished. At the end of the fourth exploration period, we may keep the remaining contract area, provided we commit to additional exploration activities every two years, for a maximum additional period of up to six years. The additional exploration commitment requires us to drill one exploratory well, or perform ten exploratory work units per each 10,000 hectares (approximately 25,000 acres), every two years for up to a maximum period of six years, in order to keep the remaining contract area.
If we decide not to continue with an additional exploration work program beyond the initial exploration work program, we will only be allowed to keep the fields discovered and the surrounding five kilometer areas for the remainder of the contract life. Currently, we plan to continue our exploration activities to retain the additional area in Block Z-1.
Description of Block XIX and License Contract
Block XIX covers approximately 473,000 acres, lying entirely onshore and adjacent to Block Z-1 in northwest Peru. Geologically, the block lies primarily within the Tumbes Basin of Oligocene-Neogene age, but also covers part of the Talara Basin to the south. Several older wells showed evidence of gas potential in the Mancora formation as well as oil shows from the Heath Formation. The sections of the Tumbes and Talara Basins in Block XIX are primarily exploratory areas and have had limited drilling and seismic activity. However, the Mancora formation is expected to continue from offshore in Block Z-1 in Piedra Redonda through Block XXIII, also under license to us, and into Block XIX, an area which spans approximately fifty miles.
In February 2003, we entered into a Technical Evaluation Agreement with Perupetro for Block XIX. In December 2003, we signed a license contract whereby we acquired a 100% interest in Block XIX. The term for the exploration period is seven years and can be extended under certain circumstances for an additional period of up to four years. If a commercial discovery is made during the exploration period, the contract will allow for the exploration and production of oil for a period of 30 years from the effective date of the contract and the exploration and production of gas for a period of 40 years. In the event a block contains both oil and gas, the 40-year term may apply to oil exploration and production as well. Royalties under the contract vary from 5% to 20% based on production volumes. Royalties start at 5% if and when production is less than 5,000 boepd and are capped at 20% if and when production surpasses 100,000 boepd.
The seven year exploration phase is divided into five periods of 18 months, 24 months, 15 months, 15 months and 12 months, respectively. We are currently in the third exploration period, which was originally scheduled to end in September of 2010. However, due to the fact the authorization for access was delayed by Perupetro, Perupetro granted us an extension such that the third exploration phase is now scheduled to end in May 2011. However, due to a delay by Petrex in delivery the drilling rig, we have requested Perupetro to further extend the third exploration period. The third exploration period requires us to drill and test one well or perform other equivalent work commitments. If we are unable to timely obtain adequate funds to finance this exploration phase or are unable to bring a drilling rig to the block and complete the required drilling program in a timely manner, our ability to develop Block XIX could be limited or substantially delayed. Such limitations or delays could result in the potential relinquishment of Block XIX. Once we complete the third exploration period, we will reestablish timelines for the remaining exploration periods. As of December 31, 2010, we had a $585,000 bond posted for $292,500 in cash collateral as required under the license contract. Both the fourth and fifth exploration periods will require a performance bond of $585,000. The performance bond amounts are not cumulative, and will be released at the end of each exploration period if the work commitment for that period has been satisfied. In addition, we are required to make technology transfer payments related to training costs of Perupetro professional staff during the exploration phase in the amount of $5,000 per year. We must declare a commercial discovery no later than the end of the last exploration period, including any extensions or deferments.
Under the terms of the Block XIX License Contract, we are required to relinquish 20% of the least prospective licensed acreage by the end of the fourth exploration period. Accordingly, we intend to retain the most prospective acreage identified. At the end of the exploration phase, we may keep the remainder of the contract area, provided we commit to purse and implement an additional work program every two years, up to a maximum of four years. The additional exploration commitment requires us to drill one exploratory well, or certain exploratory working equivalent units, every two years for up to a maximum period of four years, in order to keep the remaining contract area. If we decide not to continue this minimum work program, we will only be allowed to keep the area over the fields discovered, plus a technical security zone around such discoveries.
Description of Block XXII and License Contract
On November 21, 2007, we signed a license contract whereby we acquired a 100% interest in Block XXII. Block XXII is located onshore in northwest Peru within the Lancones Basin of Cretaceous-Upper Eocene Age and covers an area of approximately 912,000 acres. The Lancones Basin is primarily an exploratory area and has had limited drilling and seismic activity. The southern sector of this block also covers the productive Talara basin of northwest Peru, near the Talara Refinery. The exploration period of the license contract extends over a seven year period divided into five periods or four periods of 18 months and a final period of 12 months. Under certain circumstances, the exploration periods may be extended for an additional period of up to three years. We are in the first exploration period which was originally scheduled to expire in July 2009. However, since our Environmental Impact Study took several months to be approved, the first exploration period time limit was on suspension until such approval was obtained from the DGAAE. We obtained the approval in February 2010 which extended the first exploration period to March 2011. We requested a six month extension to finish the work program, and we received approval for the extension in February 2011, which will extend the first exploration period to September 2011. The first exploration period requires that we acquire process and interpret a minimum of 240 kilometers (“kms”) of two dimensional (“2-D”) seismic data (or its equivalent in 3-D seismic or any combination of 2-D and 3-D thereof) and prepare a comprehensive geological and engineering study for the area. In order to meet the minimum requirement, we intend to acquire approximately 260 kms of 2-D seismic data which began during the fourth quarter of 2010 and should be completed, including data processing, by mid-year 2011. In each subsequent period after the first 18 month period, we are required to drill an exploratory well or perform other equivalent work commitments. If a commercial discovery is made during the exploration period, the contract will allow for the exploration and production of oil for a period of 30 years from the effective date of the contract and the exploration and production of gas for a period of 40 years. In the event a block contains both oil and gas, the 40-year term may apply to oil exploration and production as well. Royalties under the contract vary from 15% to 30% based
on production volumes. Royalties start at 15% if and when production is less than 5,000 boepd and are capped at 30% if and when production surpasses 100,000 boepd.
In connection with the first exploration period, we were required to obtain a $600,000 performance bond that is secured by cash collateral in the amount of $300,000. Performance bond amounts are not cumulative, and will be released at the end of each exploration period if the work commitment for that period has been satisfied.
Under the Block XXII License Contract, we are required to relinquish at least 20% of the least prospective original agreement area at the end of the third period and at least another 30% of the original agreement area at the end of the fourth period such that at the end of the fourth period, we will have released 50% of the original agreement area. Accordingly, we intend to retain the most prospective acreage identified. The contract does not call for any additional relinquishment of acreage within the contract area and we may retain the remaining un-relinquished area for the remainder of the contract life provided we continue executing a minimum work program as defined under the license contract. If we decide not to continue this minimum work program, we will only be allowed to keep the fields discovered and the surrounding five kilometer areas for the remainder of the contract life.
Description of Block XXIII and License Contract
On November 21, 2007, we signed a license contract whereby we acquired a 100% interest in Block XXIII, which consists of approximately 230,000 acres and is located onshore in northwest Peru between Blocks Z-1 and XIX. This block is located in the Tumbes basin, although in its southern section Talara Basin sediments may be found deeper. The sections of the Tumbes and Talara Basins in Block XXIII are primarily exploratory areas and have had limited drilling and seismic activity. The exploration period of the license contract extends over a seven year period divided in to two periods of 18 months and two periods of 24 months. We are in the first exploration period which was originally scheduled to expire in July 2009. However, since our Environmental Impact Study was not approved until April 2010 by DGAAE, the first exploration period time limit was extended until June 2011. Once we complete the first exploration period we will reestablish timelines for the remaining exploration periods. The first exploration period requires that we acquire, process and interpret a minimum of 1,230 kms of 2-D seismic data (or its equivalent in 3-D seismic or any combination of 2-D and 3-D thereof) and prepare a comprehensive geological and engineering study for the area. During the second half of 2010, in order to meet the minimum requirement, we acquired approximately 370 square kms of 3-D seismic data and 314 kms of 2-D seismic data which included certain areas of interest within the Palo Santo region and four other prospects that are part of the Mancora gas play. We expect the 3-D and 2-D seismic data to be processed and interpreted by mid-year 2011. In each subsequent period after the first exploration period, we will be required to drill a certain number of wells and/or acquire a certain amount of either 2-D or 3-D seismic data. If a commercial discovery is made during the exploration period, the contract will allow for the exploration and production of oil for a period of 30 years from the effective date of the contract and the exploration and production of gas for a period of 40 years. In the event a block contains both oil and gas, the 40-year term may apply to oil exploration and production as well. Royalties under the contract vary from 15% to 30% based on production volumes. Royalties start at 15% if and when production is less than 5,000 boepd and are capped at 30% if and when production surpasses 100,000 boepd.
In connection with the first exploration period, we were required to obtain a performance bond of $3,075,000 bond that is secured by cash collateral in the amount of $1,537,500. Performance bond amounts are not cumulative, and will be released at the end of each exploration period if the work commitment for that period has been satisfied.
Under the Blocks XXIII License Contract, we are required to relinquish 20% of the least prospective original agreement area at the end of the third period and at least another 30% of the original agreement area at the end of the fourth period such that at the end of the fourth period, we will have released 50% of the original agreement area. Accordingly, we intend to retain the most prospective acreage identified. The contract does not call for any additional relinquishment of acreage within the contract area and we may retain the remaining un-relinquished area for the remainder of the contract life provided we continue executing an exploration work program as defined under the license contract. If we decide not to continue this exploration work program, we will only be allowed to keep the fields discovered and the surrounding five kilometer areas for the remainder of the contract life.
Proved Reserves
Our estimated proved oil reserve quantities were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. NSAI was chosen based on its knowledge and experience of the region in which we operate. Numerous uncertainties arise in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. These uncertainties are greater for properties which are undeveloped or have a limited production history, such as our properties in Northern Peru. Our actual reserves, future rates of production and timing of development expenditures may vary substantially from these estimates. See Item 1A. - “Risk Factors, “ Our reserve estimates depend on many
assumptions that may turn out to be inaccurate” for further information. All of our proved reserves are in the Corvina and Albacora fields. Our net quantities of proved developed and undeveloped reserves of crude oil and standardized measure of future net cash flows are reflected in the table below. See further information about the basis of presentation of these amounts in “Supplemental Oil and Gas Disclosures (Unaudited)” to our consolidated financial statements provided herein.
As of December 31, 2010, we owned a 100% working interest in the Corvina and Albacora fields, subject to Peruvian government royalties of 5% to 20% net revenue interest depending on the level of production. The effect of these royalty interest payments is reflected in the calculation of our net proved reserves. Our estimate of proved reserves have been prepared under the assumption that our license contract will allow production for the possible 40-year term for both oil and gas, as more fully discussed under “Description of Block Z-1” above.
Net Proved Crude Oil Reserves and Future Net Cash Flows
As of December 31, 2010
Based on Average First Day-of-the-Month Fiscal-Year Prices
These estimates are based upon a reserve report prepared by NSAI, independent petroleum engineers. NSAI used internally developed reserve estimates and criteria in compliance with the SEC guidelines based on data provided by us. See Item 7. - “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Critical Accounting Policies and Estimates” and “Supplemental Oil and Gas Disclosure,” in Item 8. - “Financial Statements and Supplementary Data.” NSAI’s report is attached as Exhibit 99.1 to this Form 10-K.
The reserve volumes and values were determined under the method prescribed by the SEC, which for 2010 requires the use of an average price, calculated as the twelve-month first day of the month historical average price for the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Prior to December 31, 2009, the SEC rules required the use of year-end prices.
As of December 31, 2010, we did not have any proved undeveloped reserves previously disclosed that have remained undeveloped for five years or more. As of December 31, 2010, we have three PUD locations included in our proved oil reserves that are scheduled to be drilled after five years, as we have included contingencies that account for certain possible delays in our drilling schedule due to unexpected events, such as early mechanical issues. However, once those issues are resolved, we anticipate drilling these wells.
In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our properties, and the present value of the cash flows from the properties, are made using the twelve-month first day of the month historical average oil prices for the December 31, 2010 reserves and oil sales prices in effect as of the end of the period of such estimates for prior periods, and are held constant throughout the life of the properties, except where the guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Historically, the prices for oil have been volatile and are likely to continue to be volatile in the future.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process
Our policies regarding internal controls over the recording of reserves estimates requires reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles.
Our Chief of Strategy and Technology is responsible for compliance in reserves bookings and utilizes the reserves estimates made by our third party reserve consultant, NSAI, for the preparation of our reserve report. Our Chief of Strategy and Technology is a petroleum engineer with over 20 years operating experience in international oil and gas projects. He holds an Advanced Degree in Mathematics from Ecole Centrale de Paris, France, a Master’s Degree and Ph.D. in Petroleum Engineering from Texas A&M University, as well as an MBA from the University of Colorado.
In addition, the Board of Directors has established a Technical Committee to provide review and oversight of our determination and certification of oil and gas reserves. In providing review and oversight, the Committee may review the propriety of our methodology and procedures for determining the oil and gas reserves as well as the reserves estimates resulting from such methodology and procedures. The Technical Committee may also review the qualifications, independence and performance of our independent reserve engineers.
The reserves estimates shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (“NSAI”), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein are Mr. Dan Paul Smith and Mr. John Hattner. Dan has been practicing consulting petroleum engineering at NSAI since 1980. He is a Registered Professional Engineer in the State of Texas (License No. 49093) and has over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves. He graduated from Mississippi State University in 1973 with a Bachelor of Science Degree in Petroleum Engineering. John Hattner has been practicing consulting petroleum geology at NSAI since 1991. John is a Certified Petroleum Geologist and Geophysicist in the State of Texas (License No. 559) and has over 30 years of practical experience in petroleum geosciences, with over 19 years experience in the estimation and evaluation of reserves. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary’s College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.
Reserve Technologies
The SEC’s revised rules, effective as of year-end 2009 reporting, expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. We used a combination of production and pressure performance, wireline wellbore measurements, analytical and simulation studies, offset analogies, seismic data and interpretation, geological data, interpretation, and modeling, wireline formation tests, geophysical logs and core data, and laboratory fluid studies to calculate our reserves estimates, including the additions to the 2010 reserves estimates.
Development of Proved Reserves
As of December 31, 2010, we had proved reserves of 38.9 MMBbls which represents a slight increase over the proved reserves at December 31, 2009 of 37.5 MMBbls. The proved reserves associated with proved developed producing wells increased by 1.1 MMBbls to 5.4 MMBbls in 2010 from 4.3 MMBbls in 2009. Additions to proved developed non -producing reserves were 1.2 MMBbls bringing the total of proved developed non-producing reserves at December 31, 2010 to 6.8 MMBbls compared to 5.6 MMBbls in 2009. The reserves associated with proved undeveloped areas decreased by 1.0 MMBbls to 26.6 MMBbls at December 31, 2010 from 27.6 MMBbls in 2009.
Production, Average Sales Price and Production Costs.
The following table presents our oil production, average realized sales prices per Bbl and average production costs per Bbl for the indicated periods.
(1) We inventory our oil that has not been sold. Therefore, per unit costs, after allocating operating costs to inventory, are based on sales volume.
(2) Production costs include the oil operating, workover and repair costs.
Acreage; Productive Wells
The following table shows approximately the number of developed and undeveloped acres as of December 31, 2010:
The number of productive development wells at December 31, 2010, 2009 and 2008 were 10, 7 and 4, respectively.
Drilling Activity
The number of productive oil wells drilled in 2010, 2009 and 2008 were 3, 3 and 2, respectively. We drilled one exploratory well in 2010, the A-17D, which we deemed to be a dry hole in September 2010. We also began drilling two exploratory wells in 2010, the A-15D and the A-16D, that we subsequently abandoned. We did not drill any exploratory wells or have any dry holes in 2009 or 2008. The following lists our successful development wells that were drilled during the year ended December 31, 2010:
Successful exploratory and development wells refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. For the purpose of this table, the term “completed” refers to the installation of equipment for the production of oil or natural gas.
Present Activities
Corvina Field
The Corvina field in Block Z-1 entered commercial production on November 30, 2010. During the first month of operation, the permanent production equipment, including the compression equipment, performed as expected.
The Petrex-09 rig previously used at the Corvina CX-11 platform is being refurbished and upgraded at the Petrex yard in Talara in order to enhance its capability in preparation for the drilling of an exploration well in the onshore Block XIX. This upgrade is being performed at no cost to us and reduced stand-by rates are being charged during the refurbishment. We were able to renegotiate the contract for the Petrex-09 rig, which was due to expire in April 2011. As part of the new agreement, Petrex has agreed to extend the contract to January 2012 and to a significant reduction in stand-by rates.
Additionally we are currently focused on the design and fabrication of an additional platform within Block Z-1 to allow continued development of the Corvina field. Further we are attempting to obtain and install Lease Automatic Custody Transfer (“LACT”) units at the CX-11 platform in order to better measure our oil production output. We expect to obtain and install the LACT units by mid-year 2012.
Albacora Field
The A-14XD well in Albacora averaged 988 bopd in December, exiting 2010 in line with our projections. The well was producing under extended well testing and gas flaring permits, which expired in late-January 2011. In February 2011, we received notice from Perupetro that our application for extended well testing on the A-14XD was denied. The well is shut-in and will continue to be shut-in until we install the necessary production equipment on the platform, which is currently scheduled for the end of 2011.
As a result of our suspension of drilling activities at Albacora until we conduct a 3-D seismic survey, Petrex has suspended the Petrex-18 rig contract and leased the rig to a nearby offshore operator. We have also chartered our drilling tender barge, the BPZ-02, and Don Fernando, our construction vessel, to the same operator for approximately one year, to coincide with the time we expect to resume continuous drilling at Albacora.
Block Z-1 Seismic Acquisition
Although our Block Z-1 License Contract entered into the commercial production phase on November 30, 2010, the remaining acreage outside the Corvina field has been retained under exploration. Accordingly, the programmed 3-D seismic survey within Block Z-1 will satisfy the current license contract exploration commitment. We are continuing our efforts to obtain the required environmental permit to acquire this seismic data, and expect the seismic campaign to begin mid-year 2011.
Block XIX
The selected location is being prepared in Block XIX to drill our first onshore well at the Pampa la Gallina prospect. We are seeking to farm-out this exploration activity to leverage our 100% working interest in the field, to minimize capital expenditures for Block XIX in 2011.
Block XXII
In our onshore Block XXII, located in the Lancones basin, the 2-D seismic data survey began during the fourth quarter of 2010 and should be completed, including data processing, by mid-year 2011. This 2-D survey covers certain sections of the block, where we have mapped several oil leads based on previous seismic and old well data. The mapped leads will target the same formations that are currently producing oil in adjacent blocks owned by other operators.
Block XXIII
We have acquired approximately 370 square kms of 3-D seismic data and 314 kms of 2-D seismic data which included certain areas of interest within the Palo Santo region and four other prospects that are part of the Mancora gas play. We expect the 3-D and 2-D seismic data to be processed and interpreted by mid-year 2011.
Marine Operations
In conjunction with the suspension of our drilling operations at the A platform in the Albacora field, in November 2010, we began chartering our drilling tender barge, the BPZ-02, and construction barge, the Don Fernando, to the operator who began leasing the Petrex-18 rig. The BPZ-02 and Don Fernando charter is for approximately one year to coincide to with the time we expect to resume continuous drilling at the Albacora field.
Property in Ecuador
Through our wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, we also own a 10% non-operated net profits interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). The Santa Elena Property is located west of the city of Guayaquil along the coast of Ecuador. Almost 3,000 wells have been drilled in the field since production began in the 1920s. There are approximately 1,300 active wells which produce approximately 1,300 barrels of oil per day. The majority of the wells produce intermittently by gas lift, mechanical pump or swabbing techniques. Crude oil is gathered in holding tanks and pumped via pipeline to an oil refinery in the city of Libertad, Ecuador. The agreement covering the property extends through May 2016.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Navy Tanker Litigation
On October 24, 2007, Tecnomarine SAC, a contractor to BPZ E&P, entered into two short-term agreements with the Peruvian Navy’s commercial branch to charter two small tankers for use in the Company’s offshore oil production operation. On January 30, 2008, one of the tankers, the Supe, sank after catching fire. Neither of the Peruvian governmental agencies charged with investigating the incident found fault with Tecnomarine SAC or the Company’s subsidiary, BPZ E&P. A lawsuit was nonetheless filed on December 18, 2008 in the 152nd Judicial District Court of Harris County, Texas by two crewmembers and the family and estate of two deceased sailors injured in the incident, claiming negligence and gross negligence on the part of BPZ Resources, Inc. and BPZ Energy LLC, parent entities of BPZ E&P, that were not parties to the charter agreement and were not involved in the operations. Based on the Company’s assessment of the available facts, including the fact that none of the Peruvian government-sanctioned investigations into the Supe incident found fault on the part of Tecnomarine or BPZ E&P, the Company does not believe the outcome of the legal proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. The Company intends to vigorously defend this action but cautions that there is inherent risk in litigation, which is difficult to quantify, especially at the early stage of litigation proceedings. In any event, the Company believes that any monetary damages arising from the incident would be adequately covered by its insurance policies, after a customary deductible.
ITEM 4.
ITEM 4. RESERVED
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Effective October 26, 2009, we transferred the listing of our common stock, no par value, from the NYSE Amex to the New York Stock Exchange (“NYSE”), where we continue to trade under the symbol “BPZ.”
From October 2008, following the acquisition of the American Stock Exchange by the NYSE Euronext, until our transfer to the NYSE, our Common Stock traded on the NYSE Alternext U.S. (later renamed NYSE Amex) under the ticker “BPZ”. From January 12, 2007 until the merger of the stock exchanges, our Common Stock was traded on the American Stock Exchange (“AMEX”) under the symbol “BZP”.
The following table sets forth, for the periods indicated, the high and low prices of a share of our Common Stock as reported on the NYSE, NYSE Amex, and NYSE Alternext U.S. during the applicable time periods.
Holders
As of March 14, 2011, we had approximately 141 shareholders of record, and an estimated 16,012 beneficial owners of our common stock.
We currently intend to retain all future earnings to fund the development and growth of our business. We have never paid cash or other dividends on our stock. For the foreseeable future, we intend to retain earnings, if any, to meet our working capital requirements and to finance future operations. Accordingly, we do not plan to declare or distribute cash dividends to the holders of our common stock in the foreseeable future. As of the date of this filing, we have not repurchased any of our equity securities and have not adopted a stock repurchase program.
Recent Sales of Unregistered Securities
The information on our recent sales of unregistered securities has been previously reported in the following reports filed with the SEC:
1) Form 8-K filed on February 9, 2010;
2) Form 8-K filed on February 19, 2010; and
3) Form 8-K filed on March 15, 2010.
Performance Graph
The following graph compares the cumulative total shareholder return for the Company’s Common Stock to that of (i) the Russell 2000 Stock Index, and (ii) a Company peer group of five independent oil and gas exploration companies selected by us, for the period indicated as prescribed by the SEC’s rules. The companies in our selected peer group are Toreador Resources Corp., Contango Oil & Gas, Co, Harvest Natural Resources, Inc., Far East Energy Corp, and Carrizo Oil & Co Inc. “Cumulative total return” is defined as the change in share price during the measurement period, plus cumulative dividends for the measurement period (assuming dividend reinvestment), divided by the share price at the beginning of the measurement period. The graph assumes $100 was invested on January 1, 2005 in our Common Stock, the Russell 2000 Stock Index and a Company peer group.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and the consolidated financial statements and the notes thereto included under Item 8. - “Financial Statements and Supplementary Data”.
(1) In our Form 10K for the year ended December 31, 2009, we restated our weighted average common shares outstanding presentation to show the merger earn-out shares when issued for each period presented instead of retroactively increasing the prior periods common shares outstanding. The effect of this transaction decreased the weighted average outstanding share count for the year ended December 31, 2006 and 2007 by 9.0 million shares and 7.5 million shares, respectively.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statements and related notes contained elsewhere in this report. The following discussion includes forward-looking statements that reflect our plans, estimations and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report.
Overview
We are an independent oil and gas company focused on the exploration, development and production of oil and natural gas in Peru and Ecuador. We also intend to utilize part of our planned future natural gas production as a supply source for the development of a gas-fired power generation facility in Peru, which we currently plan to wholly- or partially- own. We have the exclusive rights and license agreements for oil and gas exploration and production covering approximately 2.2 million acres in four blocks in northwest Peru and off the northwest coast of Peru in the Gulf of Guayaquil. We also 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”).
Our current activities and related planning are focused on the following objectives:
· Optimizing oil production in the Corvina field in Block Z-1 that is now in commercial production;
· Designing and fabrication of a new drilling and production platform to be installed in the Corvina field to continue development there in 2012;
· Analyzing and developing the Albacora field in Block Z-1 where we have drilled the A-14XD well and begun initial production well testing. We have suspended drilling operations at the A platform until we reach a better understanding of the reservoir by conducting a 3-D seismic survey of the area, currently planned for 2011. The EWT permit for the A-14XD expired in late-January 2011 and the well is currently shut-in. In February 2011, our application for extended well testing for the A-14XD well was denied;
· Continuing development of our gas-to-power project to monetize our natural gas reserves, which we have identified in Corvina, but for which no market has yet been developed and related financing has yet to be obtained;
· Continuing acquisition, processing and interpreting of seismic data both onshore and offshore to better understand the characteristic and potential of our properties and build our reportable asset values;
· Commencing of an on-shore drilling campaign to develop our properties and meet our applicable license requirements; and
· Securing the required capital and financing to conduct the current plan of operation.
Our activities in Peru also include analysis and evaluation of technical data on our properties, preparation of the development plans for the properties, engineering and design and construction for platforms to perform our drilling campaigns in the Corvina and Albacora fields in Block Z-1. In addition, we plan to procure machinery and equipment for an extended drilling campaign, obtain all necessary environmental and operating permits, bring additional production on-line, seismic acquisition, obtain detailed engineering and design of the planned power plant and gas processing facilities and secure the required capital and financing to conduct the current plan of operation.
Extended Well Testing Regulation
On December 13, 2009, new legislation regulating well testing in Peru became effective under a Supreme Decree. The new regulation provides that all new wells may be placed on production testing for up to six months. If the operator believes that additional time for testing is needed to properly evaluate the productive capacity of the field, and can technically justify such need, a request for the well to enter into an EWT period must be submitted to the DGH, the agency of the Ministry of Energy and Mines responsible for regulating the optimum development of oil and gas fields. The approval process for an EWT permit requires that the DGH request an opinion on the technical justification for the EWT from Perupetro, a corporation owned by the Peruvian government empowered to become a party in the contracts for the exploration and/or exploitation of hydrocarbons in order to promote these activities in Peru. After the initial six month period or after an approved EWT program expires, the operator will be required to have the necessary gas and water reinjection equipment in place to continue producing the well according to existing environmental regulations. Additionally, during both the initial six month testing period and any extended period that may be granted, we must also obtain gas flaring permits for each well in order for us to be in compliance with Peruvian environmental legislation.
Corvina Field Placed into Commercial Production
On November 10, 2009, we received approval, from Perupetro, of our proposed FDCP, as set forth in the current FDP for the Corvina field in Block Z-1, of May 31, 2010.
However, due to the delayed delivery of certain gas and water reinjection facilities at the CX-11 platform, we applied for a revised FDCP of November 30, 2010 and received approval of the revised date in May 2010 from Perupetro. The Corvina field was put into commercial production on November 30, 2010 in accordance with the approved FDCP.
With respect to other fields, unless EWT periods are approved, upon expiration of such periods, all production would cease until we meet the requirements, including installation of water and gas reinjection facilities, to transition into commercial production.
Extended Well Testing Program
Prior to placing the Corvina field into commercial production, we have been producing oil in Corvina and are still producing oil in Albacora subject to the new EWT regulations as described above.
On January 25, 2010, we applied for an extended well testing permit for the first five producing wells in Corvina (the CX11-21XD, CX11-14D, CX11-20XD, CX11-18XD and the CX11-15D wells, collectively the “first five Corvina wells”) to continue gathering data to fully understand the drive mechanisms that are present in Corvina. On March 23, 2010, we received a decision from the DGH notifying us of approval to continue extended well testing on our first five Corvina wells, until the original FDCP date of May 31, 2010, subject to specific limits on the amount of natural gas flared from each of the first five Corvina wells.
The first five Corvina wells were shut-in due to the expiration of EWT period and the CX11-19D well has been shut-in since June 2010. In July 2010, we received initial notice that our applications for the first five Corvina wells and CX11-19D well to enter an extended well testing period were denied by the DGH. We requested the DGH reconsider its denial of our applications. In September 2010, we received notice that our application for the CX11-19D well to enter an extended well testing period was again denied by the DGH. Likewise, in October 2010, we were notified that our applications for the first five Corvina wells to continue an extended well testing period had again been denied by the DGH. However, in November 2010, we completed and installed the gas and water reinjection facilities at the CX-11 platform and placed the Corvina field into commercial production.
With respect to the Albacora field, in July 2010, we suspended production from the A-14XD well for approximately two weeks because the initial six month testing period expired. However, in July 2010, we received a six month extended well testing permit and a six month gas flaring permit that allowed us to continue testing the Albacora field through late January 2011, at which time our extended permits expired. In February 2011, we received notice from Perupetro that our application for extended well testing on the A-14XD was denied.
With respect to any additional EWT and gas flaring permits we request, we can give no assurance that the DGH or the Ministry of Energy and Mines will grant approval of any current or future permits requested by us. In September 2010, we suspended the drilling operations at the A platform in the Albacora field in order to conduct a 3-D seismic survey of the area, currently planned for 2011. During the drilling downtime, we will move forward to fabricate and install permanent
production and injection facilities on the Albacora platform. This should allow for continued production testing from the field, from the A-14XD and planned new wells once drilling operations resume by avoiding gas flaring and associated permitting issues.
Oil Development
General
We will conduct additional drilling activities based in part on an ongoing assessment of economic efficiencies, license contract requirements, likely success and logistical issues such as scheduling, required maintenance and replacement of equipment. This assessment could result in increased emphasis and activities on a given prospect and conversely, could result in decreased emphasis on a given prospect for a period of time. In particular, we will assess allocation of our current resources among the Corvina, Albacora, and other Block Z-1 prospects and certain onshore prospects as they develop, along with our gas-to-power project.
Seismic Data Acquisition
For Block Z-1, we intend to acquire approximately 1,500 square kms of 3-D seismic data. The 3-D seismic data survey will include areas of interest within the Corvina, Albacora, and Delfin fields as well as certain prospects and leads located within the Mero and Piedra Redonda regions and certain deep water leads located within Block Z-1. Additionally, the 3-D seismic survey will include data underneath four existing platforms in the Albacora, Corvina and Piedra Redonda fields. The seismic data survey will fulfill our commitments under the fourth exploration period of the Block Z-1 license contract if conducted within the allowed contractual time frame. We initially attempted to conduct this seismic survey in late 2009, but suspended the survey as directed by the Ministry of Energy and Mines, because of issues relating to our stakeholders in the area of operations. We are in the process of reapplying for the environmental permits required for us to acquire additional seismic data to assist us in exploring, appraising and developing certain areas of interest within our blocks located in northwest Peru estimate the 3-D seismic data survey could begin during the mid-year 2011.
For Block XXIII, we acquired approximately 370 square kms of 3-D seismic data and 314 kms of 2-D seismic data which included certain areas of interest within the Palo Santo region and four other prospects that are a part of the Mancora gas play. The seismic data acquisition was initiated in July 2010 and finished in January 2011. We are currently planning to have the 3-D and 2-D seismic data processed and interpreted by mid-year 2011.
For Block XXII, our plan is to acquire approximately 260 kms of 2-D seismic data on four potential prospects. The 2-D seismic data survey began during the fourth quarter of 2010 and we expect to have the survey completed, including the data processing, by mid-year 2011.
Corvina Field
We are producing oil from the CX-11 platform, located in the Corvina field within the offshore Block Z-1 in northwest Peru, originally under a well testing program that started on November 1, 2007. The Corvina field was placed into commercial production on November 30, 2010. The Corvina field consists of approximately 47,000 acres in water depths of less than 300 feet. We are currently concentrating our drilling efforts on West Corvina, which consists of 3,500 acres and have completed a total of nine oil wells, the CX11-23D, CX11-22D, the CX11-17D, the CX11-19D, the CX11-15D, the CX11-21XD, the CX11-20XD, the CX11-18XD and the CX11-14D wells. The oil is delivered by vessel in storage tanks to the refinery in Talara, owned by the Peruvian national oil company, Petroperu, which is located 100 miles south of the platform. Produced oil is kept in production inventory until such time it is delivered to the refinery.
In February 2010, we completed the CX11-17D well in the Corvina field. The CX11-17D well is the seventh oil well from the CX-11 platform and has been placed into the extended well testing program. The CX11-17D well was drilled and successfully completed into a proved undeveloped area of the Corvina field, targeting sands produced by our other wells.
In late June 2010, we completed a minor workover to the CX11-19D well to isolate a zone that was producing a high rate of gas and to access the lower oil bearing sands not previously tested. Testing has been completed and we have successfully isolated the gas channeling associated with this well.
In late June 2010, we completed the testing of the CX11-22D well in the Corvina field and placed the well into the extended well testing program in July 2010. The CX11-22D well was drilled in an up dip location of the Corvina field to continue appraising its oil and gas potential. The well has two production strings to allow it to simultaneously produce oil and re-inject formation water. The long string of the dual completion targets one set of oil sands while the short string will be used
for water reinjection. The well tested oil but with high gas rates due to gas coming from one of the higher intervals that was opened to help define the gas-oil contact. The well failed to achieve a consistent initial production rate because of the resulting high gas-to-oil ratios. Well test data indicates that this is not the gas channeling issue that occurred in previous wells. We plan to evaluate a possible work over of this well to isolate the gas sands when we bring a workover rig to the platform in 2011.
In July 2010, we began drilling the CX11-23D well. This well was the last well drilled from the CX-11 platform prior to installation of the gas and water reinjection facilities. We completed the testing of the CX11-23D well in the Corvina field and placed the well into the well testing program in September 2010.
On November 30, 2010, we started operating the gas compressor at the CX-11 Corvina platform to re-inject the associated gas and thus avoid gas flaring. In addition, we obtained the necessary approval from Perupetro to place the field into commercial production.
During December 2010, we began reopening the Corvina oil wells that were shut-in due to gas flaring restrictions and evaluating which wells to produce from in order to optimize oil production while operating within the limits of the gas- reinjection equipment.
After completion of the CX11-23D well, the Petrex-09 rig previously used at the Corvina CX-11 platform is now being refurbished and upgraded at the Petrex yard in Talara in order to enhance its capability in preparation for the drilling of an exploration well in the onshore Block XIX. This upgrade is being performed at no cost to us and reduced stand-by rates are being charged during the refurbishment. We were able to renegotiate the contract for the Petrex-09 rig, which was due to expire in April 2011. As part of the new agreement, Petrex has agreed to extend the contract to January 2012 and has agreed to a significant reduction in stand-by rates.
Additionally, we are currently focused on the design and fabrication of an additional platform within Block Z-1 to allow continued development of the Corvina field. Further we are attempting to obtain and install Lease Automatic Custody Transfer (“LACT”) units at the CX-11 platform in order to better measure our oil production output. We expect to obtain and install the LACT units by mid-year 2012.
Many of the Corvina oil wells have seen initial production decline rates of approximately 50% during the first year of production before stabilizing. Although each of the Corvina wells has declined differently, partly due to the fact that these wells were completed in different zones and some of the wells encountered mechanical problems, they have all initially shown typical solution gas drive behavior which can lead to significant production declines during the first year before leveling off to sustainable rates. We believe these results are influenced by technical/mechanical problems encountered with our initial wells; however, it is possible we will see similar production declines with new Corvina wells. The representative rates of production decline remain to be determined, because the effective production mechanism in the Corvina field has yet to be fully understood, hence the need to continue testing initial wells. Further, our ability to produce indicated reserves in Corvina depends on our ability to finance our continued operations and get our produced oil to market. While we do not foresee difficulties in meeting these requirements, any failure to do so could negatively affect our indicated reserves and their value as reported under SEC rules. Therefore, in the evaluation of reserves, we attempt to account for all possible delays we can reasonably predict and their impact on the production forecast and remaining reserves to be produced.
Albacora Field
The Albacora field is located in the northern part of our offshore Block Z-1 in northwest Peru. The current area of interest within the Albacora field is a mapped structure of approximately 7,500 acres and is located in water depths of less than 200 feet. In December 2009, we completed our first oil well in the Albacora field, the A-14XD well, under a well testing program pursuant to the new regulations. The A-14XD well had an EWT and gas flaring permit valid through late-January 2011, at which time the well was shut-in.
In January 2010, we commenced drilling the A-15D well, the second Albacora well, which was to be drilled to approximately 13,000 feet vertical depth and intended to test prospective sands below the lowest known oil sands tested or produced to date in the field. In mid-January 2010, we stopped oil production and drilling activities in order to install certain production equipment on our A platform. In February 2010, we resumed drilling of the A-15D well and resumed testing the A-14XD well.
In March 2010, while drilling the A-15D and preparing to run our 9 5/8” casing to the top of the Zorritos formation, we found that the 13 3/8” casing section had been damaged, forcing us to abandon the well. The failure of the 13 3/8” casing
was apparently caused by the tilting of the drilling rig, which in turn was evidently caused when one of the main beams supporting the top deck of the platform bent due to the concentration of stresses at the base of the drilling rig. The platform was temporarily repaired and subsequently, we began drilling the A-16D well, a follow up to the A-15D well, in April 2010.
The A-16D well was originally intended to follow the same trajectory as the A-15D well with the same two targets and the same objectives. However, in May 2010, due to the lack of drilling progress as a result of obstructions present under the seabed, we abandoned the A-16D. Accordingly, in May 2010, we began drilling the A-17D well and in July 2010 permanent repairs to the A platform were completed.
Towards the end of September 2010, we completed the testing of the A-17D well and deemed the well to be a dry hole. Because the target area of the A-17D well was an exploratory section of the Albacora field, we wrote off the costs of this well as well as the costs for two previously drilled wells, the A-15D and A-16D, because those wells were intended to follow the same trajectory and reach the same location as the A-17D well but neither reached the target due to mechanical problems. Both wells were abandoned.
Consequently, we have decided to suspend the drilling operations in the Albacora field until we conduct and complete a 3-D seismic survey of the area in order to better define the position of future wells as well as to comply with our exploration commitments under our license contracts. We are completing additional government requested environmental studies to obtain the permit to begin the seismic acquisition program. Current indications are that permits should be granted and seismic acquisition could begin in 2011. During the drilling downtime, we will move forward to fabricate and install permanent production and injection facilities on the Albacora platform. This should allow for continued production testing from the field once drilling operations resume by avoiding gas flaring and associated permitting issues.
Consistent with our methodology for Corvina, we have requested our independent petroleum engineers, NSAI, to evaluate the reserves of the Albacora oil field using what we believe are reasonably conservative estimates of known uncertainties, such as the scheduling for drilling and installation of necessary production equipment and the time required to apply for and receive the necessary regulatory permits. Thus, in evaluating our reserves, we conservatively estimated these issues and their affects on potential production timetables.
Albacora Short-Term Oil Sales Contracts
In May 2010, through our wholly-owned subsidiary BPZ E&P, we entered into a short-term 400 MBbls oil supply agreement with Petroperu. Under the terms of the agreement Petroperu agrees to purchase up to 400 MBbls of crude oil production originating from the Albacora oil field 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 we are 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 salt content if the salt content is less than 10 pounds per thousand barrels. We currently have 0.2 million barrels of oil left to sell under this contract.
Because of the salt content of the oil produced from the A platform, in August 2010, we completed the installation of specialized oil desalting equipment in order to supplement the chemical oil treatment process we are utilizing to allow us to sell oil under the requirement of the original 400 MBbls oil sales contract with Petroperu. Current indications are that the equipment will allow us to reduce the salt content level on current oil production to levels acceptable under our oil sales contract with Petroperu. In addition, we entered into two separate smaller oil sales contracts with Petroperu in order to reduce the amount of Albacora oil being stored on vessels as described below.
In July 2010, through our wholly-owned subsidiary BPZ E&P, we entered into a short-term 110 MBbls oil supply agreement with Petroperu. Under the terms of the agreement, Petroperu agrees to purchase the oil production originating from the Albacora oilfield in Block Z-1. The price per barrel of oil under the agreement uses the same basket of crude oils as the 400 MBbls oil supply agreement, however, the per barrel price is minus $4.30 and other customary purchase price adjustments. We are allowed to sell oil under the contract as long as the salt content is less than 60 pounds per thousand barrels of oil. There is an incremental price adjustment associated with salt content if it is between 25 pounds and 60 pounds of salt per thousand barrels. All 110 MBbls is under this supply agreement were delivered and sold to Petroperu during the month of July 2010.
In September 2010, through our wholly-owned subsidiary BPZ E&P, we entered into a short-term 80 MBbls oil supply agreement with Petroperu. Under the terms of the agreement, Petroperu agrees to purchase the oil production originating from the Albacora oilfield in Block Z-1. The price per barrel of oil under the agreement uses the same basket of crude oils as the 400 MBbls oil supply agreement, however, the per barrel price is minus $4.30 and other customary purchase
price adjustments. We are allowed to sell oil under the contract as long as the salt content is less than 60 pounds per thousand barrels of oil. There is an incremental price adjustment associated with salt content if it is between 25 pounds and 60 pounds of salt per thousand barrels. Approximately 50 MBbls under this supply agreement were delivered and sold to Petroperu during the month of September 2010 and the remaining 30 MBbls was delivered during October 2010.
Gas-to-Power Project
Our gas-to-power project entails the installation of an approximately 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and a 135 megawatt (“MW”) net simple-cycle power generation facility. The proposed power plant site is located adjacent to an existing substation near Zorritos and a 220 kilovolt transmission line which, after the Peruvian government completes its expansion, is expected to be capable of handling up to 320 MW of power. The existing substation and transmission lines are owned and operated by third parties.
In order to support our proposed electric generation project, we commissioned an independent power market analysis for the region. The Peruvian electricity market is deregulated and power is transported through an interconnected national grid managed by the Committee for Economic Dispatching of Electricity (known as “COES”). Based on this study, we believe we will be able to sell, under contract, economic quantities of electricity from the initial 135 MW power plant. The market study also indicates that there may be future opportunities for us to generate and sell significantly greater volumes of power into the Peruvian and possibly Ecuadorian power markets. Accordingly, the revenues from the natural gas delivered to the power plant will be derived from the sale of electricity.
We currently estimate the gas-to-power project will cost approximately $153.5 million, excluding working capital and 19% value-added tax which will be recovered via future revenue billings. The $153.5 million includes $133.5 million for the estimated cost of the power plant and $20.0 million for the natural gas pipeline. While we have held initial discussions with several potential joint venture partners for the gas-to-power project, in an attempt to secure additional financing and other resources for the project, we have not entered into any definitive agreements with a potential partner. In the event we are able to identify and reach an agreement with a potential joint venture partner, we may only retain a minority position in the project. However, we expect to retain the responsibility for the construction and ownership of the pipeline. If we are unable to identify and reach an agreement with a potential partner, we plan to continue moving the project forward to completion without a partner. We are currently in the process of identifying and securing permits and financing necessary to move the project forward.
Financing Activities
$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 (“$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. The arranger fee is based on a percentage of the principal amount and the performance of the price of crude oil (Brent) from closing date to repayment date. The performance portion of the arranger fee is subject to a specified maximum amount.
The $40.0 million secured debt facility is secured, in part, by three LM6000 gas-fired packaged power units 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 required us to establish a $2.0 million reserve fund during the first 18 months the debt facility is outstanding. After the first 18 month period, we are required to keep a balance in the reserve fund equal to the aggregate amount of payments of principal and interest on the $40.0 million secured debt facility due immediately on the succeeding principal repayment date.
The $40.0 million secured debt facility matures on July 27, 2013, with principal repayment due in equal quarterly installments of $8.0 million commencing on July 27, 2012. The $40.0 million secured debt facility bears interest at three month LIBOR plus 7.0%. Interest is due and payable every three month period after the commencement of the loan.
The $40.0 million secured debt facility provides for events of default and cure periods customary for facilities of this type, including, among other things, payment breaches under any of the finance documents; representation and warranty breaches; any default, early amortization event or similar event occurring with respect to one or more debt facilities in an aggregate outstanding principal amount of at least $3,000,000, if the effect is to accelerate the maturity thereof; failure to comply with obligations; application for the appointment of a receiver; making a general assignment for the benefit of creditors; insolvencies or filing of bankruptcy; certain monetary and non-monetary judgments, orders, decrees or awards against us or our subsidiaries; suspension, revocation or termination of any $40.0 million secured debt facility financing or security documents with Credit Suisse or certain key agreements; and change in control. In addition, the $40.0 million secured debt facility provides for a mandatory prepayment of the loans if debt to finance our gas-to-power project is obtained.
If an event of default occurs, Credit Suisse shall, upon the request of the majority lenders, or may, by notice to us, (i) immediately terminate the lending commitments; and/or (ii) declare all or part of the principal amount of the loans, together with accrued interest, immediately due and payable, without demand; provided that, all lending commitments shall automatically terminate and all amounts due and payable on any loan will automatically become immediately due and payable without notice if we or any subsidiary appoint a receiver, liquidator or trustee, make a general assignment for the benefit of their creditors, become insolvent, bankrupt, liquidate, or are subject to certain monetary judgments exceeding in the aggregate, $3,000,000; and/or (iii) liquidate the security collateral and apply the proceeds thereof to pay the loans.
In January 2011, we received the $40.0 million in proceeds and recorded approximately $1.6 million of fees and commissions associated with the $40.0 million secured debt facility as debt issue costs that will be amortized over time using the interest method as interest expense. We also established a $2.0 million debt service reserve fund.
Proceeds from the $40.0 million secured debt facility will be utilized to meet our 2011 capital expenditure budget, to finance our exploration and development work programs, and to reduce our existing debt.
With respect to the performance based arrangement fee, the fee is payable at each of the principle repayment dates. The formula for calculating fees includes an amount multiplied by the change in oil prices from the date of commencement of the loan and the price at each principle repayment date. Additionally, the performance based arranger fee contains a maximum amount to be paid by us over the term of the loan. We believe the performance based arranger fee may qualify as an embedded financing derivative under ASC 815-10, “Derivatives and Hedging”. This would require us to record the fair value of the derivative liability at inception and to revalue the liability at each financial reporting date throughout the term of the loan. We are currently assessing the impact of the expected liability and expect to record the initial liability as additional interest expense for the performance based arranger fee.
We estimate the cash payments related to the $40.0 million secured debt facility, including potential payments for the performance based arranger fee and interest, for the year ended December 31, 2011, 2012 and 2013 to be approximately $2.3 million, $19.0 million and $25.1 million, respectively.
$170.9 Million Convertible Notes due 2015
In February and March 2010, we closed on the private offering for an aggregate $170.9 million convertible notes due 2015 (the “2015 Convertible Notes”). The 2015 Convertible Notes offering was comprised of (i) the initial $140.0 million of 2015 Convertible Notes sold in an initial private offering, (ii) the exercise, by the initial purchaser, of a 30-day option to purchase an additional $21.0 million of 2015 Convertible Notes, and (iii) IFC’s election to participate in the offering, pursuant to a contractual right, for an additional $9.9 million of 2015 Convertible Notes, bringing the total proceeds of the private offering to $170.9 million. The 2015 Convertible Notes were sold to an initial purchaser who then sold the notes to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. The $170.9 million of 2015 Convertible Notes were issued pursuant to an indenture dated February 8, 2010, between us and Wells Fargo Bank, National Association, as trustee (“the Indenture”).
The 2015 Convertible Notes are 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.
We will pay interest on the 2015 Convertible Notes at a rate of 6.50% per year on March 1st and September 1st of each year, beginning on September 1, 2010. The 2015 Convertible Notes mature on March 1, 2015. The initial conversion rate was 148.3856 shares per $1,000 principal amount of the 2015 Convertible Notes (equal to an initial conversion price of approximately $6.74 per share of common stock), subject to adjustment. Upon conversion, we must deliver, at our option,
either (1) a number of shares of our common stock determined as set forth in the Indenture, (2) cash, or (3) a combination of cash and shares of our common stock (but not to exceed 19.99% of our outstanding shares at the time of such delivery).
The initial conversion rate was adjusted on February 3, 2011 as the daily Volume Weighted Average Price (“Average VWAP”) of our common stock for each of the 30 trading days ending on February 3, 2011 was less than $5.6160 per share. The arithmetic average of the Average VWAP per share of Common Stock for each of the thirty (30) consecutive Trading Days ending on February 3, 2011 was $4.9307. Since the Average VWAP is less than $5.6160 per share, the conversion rate increased such that the conversion price, as increased, represents the greater of (1) 120% of the Average VWAP and (2) $5.6160. Accordingly, the conversion rate and conversion price changed to 169.0082 and $5.9169, respectively. In addition, following the occurrence of any one of certain corporate transactions that constitutes a fundamental change (as defined in the Indenture), we will increase the conversion rate, subject to certain limitations, for a holder who elects to convert the 2015 Convertible Notes in connection with such corporate transactions during the 30-day period after the effective date of such fundamental change.
Holders may convert their 2015 Convertible Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances:
(1) during any fiscal quarter (and only during such fiscal quarter) commencing after March 31, 2010, if the last reported sale price of 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 the specified 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 up 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 five 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 contains customary terms and covenants and events of default. If an event of default (as defined therein) occurs and is continuing, the Trustee by notice to us, or the holders of at least 25% in aggregate principal amount of the 2015 Convertible Notes then outstanding by notice to us and the Trustee, may declare the principal and accrued and unpaid interest (including additional interest or premium, if any) on the 2015 Convertible Notes to be due and payable. In the case of an event of default arising out of certain bankruptcy events (as set forth in the Indenture), the principal and accrued and unpaid interest (including additional interest or premium, if any) on the notes will automatically become due and payable.
Net proceeds from the sale of the 2015 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by us, was approximately $164.9 million. The initial purchaser received commissions of approximately $5.5 million in connection with the sale of the 2015 Convertible Notes 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 are accounting for the 2015 Convertible Notes in accordance with FASB Staff Position (“FSP”) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which is codified under ASC Topic 470, “Debt”. Under the accounting guidance, convertible debt instruments that may be settled entirely or partially in cash upon conversion will be required to separately account for the liability and equity components of the instrument 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 our 2015 Convertible Notes to be 12%. The 12% non-convertible borrowing rate represents the borrowing rate of similar companies with the same credit quality as ours 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 will be amortized as non-cash interest expense into income over the life of the notes using the interest method. In addition, we recorded approximately $4.8 million of the $6.1 million of fees and commissions as debt issue costs that will be amortized over time using the interest method as interest expense. The remaining $1.3 million of fees and commissions will be treated as an original issue discount against the value of the equity component. We estimate the cash payments including interest related to the 2015 Convertible Notes, assuming no conversion, for the year ended December 31, 2011, 2012, 2013, 2014 and 2015 to be approximately $11.1 million, $11.1 million, $11.1 million, $11.1 million and $176.5 million, respectively. We evaluated the 2015 Convertible Notes agreement for potential embedded derivatives, noting that the conversion feature and make-whole provisions were determined not to 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 December 31, 2010, the net amount of $140.8 million includes the $170.9 million of principal reduced by $30.1 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 $30.1 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 December 31, 2010, using the conversion rate of 148.3856 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 25,364,737 shares of common stock. At February 3, 2011, using the new 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 28,889,927 shares of common stock. In accordance with New York Stock Exchange rules, we received shareholder approval to issue shares in excess of 19.99% of shares outstanding at the time of the offering (23,031,663 shares) should we need to issue shares in order to satisfy our obligation under the 2015 Convertible Notes. As of December 31, 2010, there is no excess if-converted value to the holders of the 2015 Convertible Notes as the price of our common stock at December 31, 2010, $4.76 per share, is less than the conversion price.
For the year ended December 31, 2010, the effective interest rate for the 2015 Convertible Notes is 12%, including the amortization of debt issue costs, the effective interest rate is 12.6%.
The amount of interest expense related to the 2015 Convertible Notes for the year ended December 31, 2010 is $15.3 million, disregarding capitalized interest considerations, and includes $10.1 million of interest expense related to the contractual interest coupon, $4.5 million of non-cash interest expense related to the amortization of the discount and $0.7 million of interest expense related to the amortization of debt issue costs.
September 2009 Private Placement of Common Stock
On September 15, 2009, we closed a private placement of approximately 1.6 million shares of common stock, no par value, to the International Finance Corporation (“IFC”) pursuant to a Subscription Agreement dated September 15, 2009. This private placement was related to our registered direct offering of approximately 18.8 million shares of common stock at a price of $4.66 per share that closed on June 30, 2009. Pursuant to the Subscription Agreement dated December 16, 2006 (the “Subscription Agreement”) by and between IFC and us, IFC has the right, within 45 days of notice of an offering, to
purchase shares of our common stock for the same price and terms as the participants in the offering to retain its proportionate ownership in us. IFC exercised its pre-emptive right to purchase approximately 1.6 million shares of common stock to which it was entitled under the Subscription Agreement, at the offering price of $4.66 per share, resulting in gross proceeds to us of approximately $7.6 million. In compliance with NYSE requirements, the transaction was submitted to and approved by the shareholders of BPZ at a Special Meeting of Shareholders on August 24, 2009. No warrants or dilutive securities were issued to IFC in connection with the private placement. The shares were placed directly by us. We used the proceeds of this offering to develop our properties under our existing license contracts and other general corporate purposes consistent with our operating plans.
Under the September 15, 2009 Subscription Agreement, we committed to file a registration statement with the SEC covering the shares no later than 45 days after the closing with respect to such shares, and used our reasonable best efforts to obtain its effectiveness. On October 21, 2009, we filed a registration statement with the SEC covering the shares. Subsequently, we received comments from the SEC pertaining to our registration statement, Form 10-K for the year ended December 31, 2008, Definitive Proxy Statement filed on April 30, 2009, Form 10-Q for the period ended September 30, 2009 and the related earnings press release as described below under “SEC Comments”. We promptly responded to the SEC’s requests. In May 2010, we filed an amended registration statement with the SEC and the amended registration statement was declared effective later that month. No penalty payments were associated with the delay in obtaining the effectiveness of the registration statement.
June 2009 Registered Direct Offering of Common Stock
On June 30, 2009, we closed the sale of approximately 18.8 million shares of our common stock, no par value, in a registered direct offering under an effective shelf registration statement. The shares of common stock were priced at $4.66 per share resulting in net proceeds to us, after placement agent fees and other fees, of approximately $82.9 million. In connection with the registered direct offering, we entered into a placement agency agreement with Canaccord Adams Inc. as lead placement agent for the offering along with Pritchard Capital Partners, LLC, and Raymond James and Associates, Inc. In addition, Rodman & Renshaw, LLC, and Wunderlich Securities, Inc. assisted as agents in the transaction. We paid approximately $4.4 million as a 5% placement agency fee of the gross proceeds received by us in accordance with the terms of the placement agency agreement. We used the proceeds of this offering to develop our properties under our existing license contracts and other general corporate purposes consistent with our operating plans.
February 2009 Private Placement of Common Stock
On February 23, 2009, we closed a private placement of approximately14.3 million shares of common stock, no par value, to institutional and accredited investors pursuant to a Stock Purchase Agreement dated February 19, 2009. Additionally, in March 2009, IFC exercised its pre-emptive right to elect to participate in the private placement offering resulting in an additional 1.4 million shares of common stock which brought the total to approximately 15.7 million shares of common stock sold in the private placement offering. The common stock was priced at $3.05 per share resulting in net proceeds to us, after placement agent and financial advisory fees, of approximately $45.2 million. No warrants or dilutive securities were issued in connection with the private placement. A financial advisory fee of $0.7 million was paid to Morgan Keegan and Company, Inc. for investment services and consulting related to the offering. Additionally a private placement fee of $2.2 million was paid to Pritchard Capital Partners, LLC, for placement services related to the offering. We used the proceeds of this offering to develop our properties under our existing license contracts and other general corporate purposes consistent with our operating plans.
Under the Stock Purchase Agreement, we committed to file a registration statement with the SEC and obtain the registration statement’s effectiveness within the time-frames outlined in the Stock Purchase Agreement. On April 27, 2009, we obtained effectiveness of the registration statement related to the Stock Purchase Agreement in compliance with such time-frames.
Turbine Purchase Agreement, Amendment and Letter Agreement
On September 26, 2008, we, through our subsidiary Empresa Electrica Nueva Esperanza S.R.L., entered into a $51.7 million contract (the “Agreement”) for the purchase of three LM6000 gas-fired packaged power units from GE Packaged Power, Inc. and GE International, Inc. Sucursal de Peru (collectively “GE”). The Agreement required an initial down payment of $5.1 million and monthly progress payments of $1.1 million per unit. In January 2009, BPZ and GE entered into an amendment of the contract. Under the terms of the amendment, both GE and BPZ agreed to a suspension period under the Agreement from and including December 15, 2008 through November 15, 2009, whereby no failure on the part of BPZ or GE to perform any obligations under the Agreement would give rise to a breach of contract or the right to terminate the contract, provided we make a $3.4 million progress payment no later than February 25, 2009 and a $3.5 million progress
payment to GE no later than November 16, 2009. On February 24, 2009, we paid the first progress payment of $3.4 million. Under the terms of the Letter Agreement, GE and BPZ agreed to a variable monthly payment plan ending in December 2010 with a final $20.7 million payment due no later than five days after receiving the notice of issuance to ship. The Company received the notices to ship and made all final payments due to GE under the agreements in December 2010.
$15.0 Million IFC Reserve-Based Credit Facility
Through December 31, 2010, we had a $15.0 million reserve-based lending facility (“IFC Facility”) agreement (the “Loan Agreement”) with IFC through our subsidiaries BPZ E&P and BPZ Marine Peru S.R.L. as borrowers. The reserve-based lending facility had $12.5 million outstanding maturing in December 2012; however, following the $40.0 million secured debt facility we entered into in January 2011, we used a portion of the proceeds to repay the amount outstanding to IFC. Because we refinanced the obligation on a long-term basis, $5.0 million of the $12.5 million that was expected to be paid within a year as of December 31, 2010 is being classified as a long term-liability, in accordance with Accounting Standard Codification (“ASC”) Topic 470, “Debt”, as we refinanced the obligation on a long-term basis.
The reserve-based lending facility had interest at an approximate rate of LIBOR plus 2.75%, equivalent to 3.21% based on the six-month LIBOR rate of 0.46% at December 31, 2010. The maximum amount available under this facility begins at $15.0 million and was to be reduced by $2.5 million beginning on December 16, 2010 and every six months thereafter during the term of the Loan Agreement. The amount available under the Loan Agreement was subject to a semi-annual borrowing base determination based on the value of oil reserves. In addition, we were subject to various financial covenants calculated as of the last day of each quarter, including a life of field coverage ratio, life of loan coverage ratio, debt to equity ratio and interest coverage ratio. The IFC Facility also provided for events of default, cure periods and lender remedies customary for facilities of this type. We were in compliance with all material covenants of the Loan Agreement as of December 31, 2010.
Future Market Trends and Expectations
Our business depends primarily on the level of current and future oil and gas demand and prices which may impact our ability to raise capital to finance the development of our current and future oil and gas opportunities, to continue developing our gas-to-power project, which anchors our gas monetizing strategy, and to maintain our commitments and obligations under our current and future license contracts. The world economies are slowly recovering from a recession which began in 2008 and extended into 2009. Growth has resumed, but is modest. There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years. In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.
In response to the current environment, we have decided to focus on oil development in Block Z-1, specifically the Corvina and Albacora fields, for 2011, and monitor operating and general and administrative expenses in an effort to enhance shareholder value.
From a production perspective, our goal is to stabilize production during 2011, assuming we encounter minimal technical difficulties and successfully operate the Corvina gas and water injection facilities. In order to attain that goal we plan to commit a majority of our 2011 capital budget of approximately $50 million on further development of the Corvina field and construction and installation of the gas and water injection facilities in the Albacora field.
Expected operational cash flow from Corvina and Albacora oil sales as well as the additional proceeds from the recent debt transaction should contribute towards funding the 2011 capital expenditures budget. In addition, we will continue to evaluate our options on additional financing as needed. We anticipate future results will be based on our production levels and current and future oil prices. When forecasting our 2011 performance, we relied on assumptions about the market for oil, our customers and suppliers, past results and operational and regulatory delays. We expect the average spot price for oil in 2011 to be relatively consistent with the average price we received in 2010, though recent political activity in the Middle East has caused crude prices to exceed this amount in the short term. Our results could materially differ from what we anticipate if any of our assumptions, such as major technical or mechanical well issues, commodity pricing, production levels or our ability to raise additional capital, prove to be incorrect. In addition, our businesses’ operations, financial condition and results of operations are subject to numerous risks and uncertainties that if realized could cause our actual results to differ substantially from our forward-looking statements. These risks and uncertainties are further described in Item 1A. - “Risk Factors” of this report.
Results of Operations
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
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.
For the year ended December 31, 2010, our net oil revenue increased by $57.6 million to $110.1 million from $52.5 million for the same period in 2009. The increase in net revenue is due to an increase in the amount of oil sold, 555 MBbls and an increase of $18.04, or 33%, in the average per barrel sales price received. During 2010, oil prices again rose during the year, trading in a range of $70 - $90 per barrel compared to prices in 2009, which rose from $39 per barrel at the start of the year to $73 per barrel toward the end of the year.
For the year ended December 31, 2010, oil production was 1,527 MBbls compared to 991 MBbls for the same period in 2009. Total sales for the year ended December 31, 2010 were 1,518 MBbls compared to 963 MBbls for the same period in 2009.
For the both the year ended December 31, 2010 and 2009, we had intermittent oil production from six producing wells in the Corvina field and one producing well in the Albacora field.
Although we suspended oil production from five of our Corvina wells as required under the Peruvian well testing regulations in May 2010 and the CX11-19D well in June 2010, we have been able to produce more oil than during the same period in 2009. Our latest wells, the CX11-17D, CX11-19D, A-14XD, and CX11-23D, experienced high production rates relative to our older producing wells. In addition, since we placed the Corvina field into commercial production, we have
begun to produce from the previous shut-in wells and are working toward finding the proper production schedule in order to optimize oil production while operating within the limits of the gas reinjection equipment.
During the year ended December 31, 2009, the majority of our oil production came from five wells with two additional wells, the CX11-19D and A-14XD, beginning producing in December 2009. Due to workovers to address issues encountered with certain wells and regular maintenance, the four of the first five Corvina wells suspended production for approximately 2 months and we were, therefore, not able to optimize oil production during 2009.
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 year ended December 31, 2010 and 2009, the oil revenues received by us are net of royalty costs of approximately 5% of gross revenues or $6.3 million and $2.9 million, respectively.
Other Revenue
After suspending our drilling operations at the A platform in the Albacora field in October 2010, another operator chartered two of our support vessels, the BPZ-02 and Don Fernando, for a one year term. Therefore included in other revenue is the revenue associated with the chartering of those vessels since November 15, 2010.
Lease Operating
Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, operator fees, processing fees, insurance and transportation. For the year ended December 31, 2010, lease operating expenses increased by $4.5 million to $32.6 million ($21.47 per Bbl) from $28.1 million ($29.21 per Bbl) for the same period in 2009. During 2010 compared to 2009, nearly all lease operating expenses increased, however we have seen the largest increases in salary and labor costs of $0.6 million, supplies used in operations of $1.0 million, increased equipment rental expense of $0.5 million, increased crude oil transportation costs of $3.7 million, increased lab fees of $0.9 million, increased repair and maintenance expenses of $2.0 million, increased fuel costs of $2.4 million, increased other lease operating expenses of 1.2 million. Partially offsetting these increases to expense are decreases in workover expenses of $7.7 million.
The main reason for the increase in the lease operating expenses is due to operating two fields in 2010 compared to operating one field for most of 2009, and lease operating expense for 2010 includes the operation of a larger oil transportation vessel and new storage vessel. Also contributing to the increase in expense in 2010 are the cost of chemicals and other desalting expenses incurred to treat the salt content of our Albacora oil in order to comply with the salt levels within our oil sales agreement with Petroperu. With respect to workovers, during the year ended December 31, 2010, we performed a total of four workovers. However, only the workover on the CX11-19D well, whose total was $1.9 million, was greater than $0.1 million. For the same period in 2009, we also had four workovers, however all workovers were major workovers to address issues encountered in our wells and totaled $9.8 million. Although lease operating expense increased in 2010 compared to 2009, the per Bbl amount decreased to $21.47 per barrel in 2010 from $29.21 per barrel in 2009 as a result of increased sales in 2010.
General and Administrative
General and administrative expenses are overhead-related expenses such as, employee compensation (including stock-based compensation), legal, consulting and accounting fees, insurance, and investor relations expenses.
For the year ended December 31, 2010, general and administrative expenses decreased $0.6 million to $32.7 million from $33.3 million for the same period in 2009. Stock-based compensation expense, a subset of general and administrative expenses, decreased by $6.8 million to $5.8 million for the year ended December 31, 2010 from $12.6 million for the same period in 2009. The decrease in stock-based compensation expense is due to the decrease in fair market value of awards granted in 2010 as a result of the decline in the stock price of BPZ and we are no longer recognizing as much stock compensation expense as a result of awards granted in previous years, with high grant date fair values, as these awards have vested. Also contributing to the decrease in stock based compensation is approximately $0.7 million of stock-based compensation expense related to the accelerated vesting for certain restricted stock and stock option awards granted to a former member of the Board of Directors and that occurred during the second quarter of 2009, which did not occur during 2010. Other general and administrative expenses increased $6.1 million to $26.7 million from $20.6 million for the same
period in 2009. The $6.1 million increase is due to increased salary and salary related expenses of $0.9 million, increased professional fees of $3.2 million, increased maintenance and repair expense of $0.7 million, increased rent expense of $0.3 million and increased travel and travel related expenses of $0.9 million.
For the year ended December 31, 2010, the increase in salary and salary related expenses resulted from (1) an aggregate bonus of $1.3 million awarded to certain executives and other key personnel during the second quarter with no corresponding bonuses awarded during the same periods in 2009, (2) salary reinstatements in 2010 that were voluntarily reduced in 2009 for certain executives and other key personnel, and (3) annual salary increase awarded during the period ended September 30, 2010 and an increase in the number of employees in 2010 compared to the same period in 2009. Partially offsetting these increases in salary and salary related expenses within general and administrative expense are salary and salary related expenses that are included in standby costs of $1.2 million. In October of 2010, we suspended our drilling operations at both the Corvina field and Albacora field and therefore, the salaries and related expenses associated to drilling activities are included in standby costs.
The $3.2 million of increase in professional fees is due to $3.8 million increased reserve engineering analysis and consulting for vessel leasing activities and increased consulting for employee recruiting increased consulting for community service relationship. Partially offsetting the increase in professional fees are $0.6 million of reduced legal fees. The increase in maintenance and repair expense is due to operating more vessels and equipment in 2010 compared to 2009. The increase in rent expense is due to the rental of new office space for our Peru office in the current year. The increase in travel and travel related fees is due to the increase in travel costs in 2010 combined with more travel and more personnel travelling in 2010 compared to the same period in 2009.
Geological, Geophysical and Engineering
Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses. For the year ended December 31, 2010, geological, geophysical and engineering expenses increased $11.4 million to $19.1 million compared to $7.7 million for the same period in 2009. The $11.4 million increase is comprised of increased seismic acquisition costs of $10.5 million and increased environmental laboratory and consulting expenses of $0.9 million. The increase of $0.9 million of environmental laboratory and consulting expenses is due to additional environmental studies for Block Z-1, Block XXII and Block XXII and additional water discharge monitoring for our production systems onboard the Namoku.
For the year ended December 31, 2010, we incurred $16.8 million seismic acquisition costs as part of our plan to obtain approximately 370 square kms of 3-D seismic data and 314 kms of 2-D seismic data related to Block XXIII and 260 kms of 2-D seismic data for Block XXII. During the year ended December 31, 2009, we incurred $6.3 million as part of our plan to acquire approximately 950 square kms of 3-D seismic data for Block Z-1. However, shortly after starting the Block Z-1 seismic acquisition in 2009, we received a notice from the Peruvian Ministry of Energy and Mines to suspend our seismic acquisition program and resubmit our application to obtain a new environmental permit.
Dry Hole Costs
For the year ended December 31, 2010, we wrote off $17.9 million of exploratory dry hole costs related to the A-17D well in the Albacora field which, in September 2010, was determined to have no commercial quantities of hydrocarbons and was abandoned. In addition, we wrote off $14.9 million of suspended well costs for two previously drilled wells, the A-15D and A-16D, as those wells were intended to follow the same trajectory and reach the same location as the A-17D well but neither reached the target due to mechanical problems and both wells were junked and abandoned. There were no similar expenses for the same periods in 2009.
Depreciation, Depletion and Amortization
For the year ended December 31, 2010, depreciation, depletion and amortization expense increased $8.0 million to $33.8 million from $25.8 million for the same period in 2009.
For the year ended December 31, 2010, approximately 75% of depletion expense came from oil sold from the Corvina field and approximately 25% came from oil sold from the Albacora field. During the same period in 2009, all of the depletion expense came from oil sales originating from the Corvina field. Therefore while total depreciation, depletion and amortization expense increased in 2010 compared to 2009, the depreciation, depletion and amortization per barrel decreased because: (1) The average costs of wells in the Covina field decreased in 2010 compared to 2009 due to lower drilling costs
for newer wells, and (2) the depletion rate for the Albacora field is less than that of the Corvina field. Therefore depreciation, depletion and amortization increased by only 31% while the number of barrels sold increased 58%.
Also contributing to depletion expense in 2010 is a negative revision in the reserve base at the end of 2009 . The 2009 reserve analysis as prepared by NSAI included a 1.6 MMBbls negative revision in reserves due to the lower than expected performance of the CX11-14D, CX11-18XD, and CX11-20XD wells.
Standby Costs
After completing the CX11-23D well in the Corvina field and the A-17D well in the Albacora field at the end of the third quarter of 2010, we suspended drilling operations until we complete a seismic data acquisition program. As a result, we incurred and are reporting $7.5 million in standby costs that include $4.9 million of standby rig costs, $0.8 million of standby vessel expenses, $1.2 million of salary and salary related expenses associated with drilling operations, and $0.6 million of fuel and other expenses. There were no similar expenses incurred by us in 2009.
Other Expense
For the year ended December 31, 2010, we are reporting $12.9 million of charges as “Other expense”. These charges include $10.7 million of charges related to certain engineering, consulting, environmental and legal costs for our planned gas plant, pipeline and gas-to-power project and $2.2 million of charges related to the abandonment of two platforms. With respect to the $10.7 million of charges related to the planned gas plant, pipeline and gas-to-power project, during the third quarter of 2010, management determined that there is no future benefit of these engineering and development costs associated with our current gas plant, pipeline and gas-to-power project plans. Accordingly, we have decided to write off these costs. With respect to the $2.2 million of platform abandonment costs, we have determined that two previously built platforms, one located in the Piedra Redonda field and the CX-13 platform located in the eastern part of the Corvina field, both of which were in existence when we acquired the rights to the offshore Block Z-1 in northwest Peru, are not suitable for our future oil development plans. Accordingly, we are writing off the $1.4 million costs incurred to evaluate the feasibility of refurbishing and using these platforms. In addition, we are accruing $0.8 million of abandonment costs related to the Piedra Redonda platform as we are obligated to ensure the platform does not cause a threat to marine vessels operating in the area or marine wildlife. There were no similar expenses for the same periods in 2009.
Other Income (Expense)
For the year ended December 31, 2010, income from our investment in Ecuador property, net of investment amortization, decreased by $0.5 million to income of $0.7 million from income of $1.2 million in 2009. During 2010, we received payments of $0.9 million and during 2009 we received $1.4 million. During both the year ended December 31, 2010 and 2009, investment income / (expense) includes amortization expense of approximately $188,000 in each period.
For the year ended December 31, 2010, we recognized approximately $11.6 million of net interest expense which includes $21.2 million of interest expense reduced by $9.6 million of capitalized interest expense. For the same period in 2009, we did not recognize any interest expense as we capitalized all interest expense of $4.4 million to construction in progress. For the year ended December 31, 2010, the increase in interest expense is due to the $170.9 million of 2015 Convertible Notes issued in the current year.
For the year ended December 31, 2010, interest income increased by $0.1 million to income of $0.3 million from income of $0.2 million in 2009.
For the year ended December 31, 2010, other expense decreased by $1.3 million to income of approximately $20,000 from an expense of $1.3 million in 2009. The reason for the decrease in other expense is due to approximately $1.3 million of expense incurred in 2009 that was not repeated in 2010. Approximately $0.8 million of the $1.3 million was incurred during the first quarter of 2009 and related to the settlement of a disputed contractual obligation with a former consultant concerning services provided to both BPZ and its predecessor at the time BPZ became publicly traded. An additional $0.4 million of the $1.3 million was recognized during the second quarter of 2009 and relates to stock options awarded to a former member of the Board of Directors that was recognized upon issuance of the award.
Income Taxes
The source of net loss before income tax expense (benefit) for the year ended December 31, is as follows (in thousands):
The income tax provision (benefit) for the year ended December 31, consists of the following (in thousands)
The income tax expense (benefit) for the year ended December 31, 2010, 2009 and 2008 differs from the amount computed by applying the U.S. statutory federal income tax rate for the applicable year to consolidated net loss before income taxes as follows (in thousands):
A summary of the components of deferred tax assets, deferred tax liabilities and other taxes deferred at December 31, 2010 and 2009 are presented below (in thousands):
Net deferred tax assets in the foregoing table include the deferred consequences of the future reversal of Peruvian deferred tax assets and liabilities on the impact of the Peruvian employee profit share plan tax of $4.3 million in 2010 and $3.3 million in 2009. As of December 31, 2010 and 2009, we had a valuation allowance for the full amount of the domestic deferred tax asset resulting from the income tax benefit generated from net losses, 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 2030. Furthermore, because we have no operations within the U.S. taxing jurisdiction, it is likely that a sufficient generation of revenue to offset our deferred tax asset is remote. As a result, we have a full allowance on our deferred tax asset generated in the U.S. The tax provision is based on taxable Peruvian income that excludes certain U.S. expenses that are not deductible at the Peruvian level. As a result, we recognized a total tax provision for the year ended December 31, 2010 of approximately $11.6 million. No provision for U.S. federal and state income taxes have been made for the difference in the book and tax basis of our investment in foreign subsidiaries as such amounts are considered permanently invested. Distribution of earnings, as dividends or otherwise, from such investments could result in U.S. federal taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable in various foreign countries. Due to our significant net operating loss carryforward position we have not recognized any excess tax benefit related to our stock compensation plans. ASC Topic 718 prohibits the recognition of such benefits until the related compensation deduction reduces the current tax liability.
We have assessed the realizability of the deferred tax asset generated in Peru. We have considered whether it is more likely than not that some portion or all of the deferred tax asset will not be realized. The ultimate realization of the deferred tax asset is dependent upon the generation of future taxable income in Peru during the periods in which those temporary differences become deductible. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, along with the transition into the commercial phase under the Block Z-1 License Contract, we believe it is more likely than not that we will realize the benefits of the these deductible differences at December 31, 2010. As a result, we recognized a deferred tax asset of $28.4 million as of December 31, 2010. In addition our subsidiary, BPZ E&P, has a 2010 net operating loss of $11.0 million; however, we expect to be able to use the net operating loss against future taxable income within the four year limit to utilize such net operating losses.
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. As of the date of adoption of FIN 48, codified under ASC Topic 740, “Income Taxes’, we did not have any accrued interest or penalties associated with any unrecognized
tax benefits, nor was any interest expense recognized during the year. Additionally, the adoption had no effect on our financial position or results of operations. 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 statement as of December 31, 2010 or December 31, 2009.
For the year ended December 31, 2010, our net loss increased $24.0 million to a net loss of $59.8 million or ($0.52) per basic and diluted share from net loss of $35.8 million or ($0.35) per basic and diluted share for the same period in 2009.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Net Revenue
For both the year ended December 31, 2009 and 2008, all oil sales were from oil produced from the CX-11 platform, located in the Corvina field within Block Z-1 in northwest Peru, under a Peruvian well testing regulations.
For the year ended December 31, 2009, our net revenue decreased by $10.5 million to $52.5 million from $63.0 million for the same period in 2008. The decrease in net revenue is due to a decrease of $21.74, or 29% in the average per barrel sales price received which was partially offset by an increase in oil sales of 137 MBbls. Oil prices reached record levels during the third quarter of 2008 before sharply falling towards the end of the year. During 2009, oil prices rose steadily from the lows seen at the beginning of the year but the average price received for oil in 2009 was considerably less than the average oil price received during 2008.
During the year ended December 31, 2009, oil production from the CX11-21XD, CX11-20XD and the CX11-15D wells were at various times and intervals partially or fully suspended due to workovers and maintenance of the wells in order to perform routine maintenance activities and to attempt to resolve certain gas channeling and water production issues encountered in the operation of the wells. Additionally, oil production from the CX11-14D well was shut-in since November 7, 2009 due to water issues in production that began in May 2009 that caused sand production and lifting issues.
The CX11-15D workover caused oil production from the well to be stopped intermittently for approximately one month during 2009 while we attempted to resolve certain gas channeling issues believed to be originating from the overlying gas sands. The workover was completed in September 2009; however the workover did not achieve the desired results. Therefore we temporarily shut in the sands under consideration and completed the well solely in the bottom set of sands that was immune to this gas channeling problem. The CX11-15D well produced only from these sands, at a reduced rate.
The CX11-20XD workover caused oil production from the well to be stopped intermittently for approximately two months during 2009 as the well developed a sustained high gas-oil ratio in April 2009. Although the high gas production was partially resolved with the workover of the well, the production from this well was restrained to maintain its gas production at a manageable level.
The CX11-21XD workover caused oil production from the well to be stopped intermittently for approximately two and a half months during 2009 as the well began producing a significant amount of associated water during production. The workover was completed in October 2009; however the workover did not achieve the desired results. Therefore we reduced oil production from this well in order to manage the water produced along with the oil, in particular when running into fluid storage capacity limitations.
At December 31, 2009, we were producing from six of our seven producing wells, the A-14XD, CX11-19D, CX11-15D, CX11-20XD, CX11-18XD and CX11-21XD, compared to four producing wells, the CX11-21XD, CX11-14D, CX11-20XD and the CX11-18XD, at December 31, 2008. However, the A-14XD oil production was stopped after placing it on production toward the end of 2009 in order to complete the installation of oil production equipment and to obtain an oil sales agreement, as requested by the OSINERGMIN (the governmental entity overseeing hydrocarbon activities in Peru). Following our presentation of appropriate documentation to the OSINERGMIN, the well testing activities in the A-14XD well resumed. Accordingly, we did not realize any oil sales from the A-14XD during 2009.
During 2009, we had oil production for approximately 10 of the 12 months from four of our seven wells. The CX11-15D began its initial production in June 2009. The CX11-19D and A-14XD began their initial production in December 2009.
During 2008, oil production operations were suspended on January 30, 2008 and our oil sales did not resume until June 2008, due to an incident involving a small tanker leased by our marine transportation contractor from the Peruvian Navy. In July 2008 the CX11-18XD was placed on production. Subsequent to June 2008, we had full oil production for three of the four wells while the CX11-20XD well began its initial production toward the end of September 2008.
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 year ended December 31, 2009 and 2008, the revenues received by us are net of royalty costs of approximately 5% of gross revenues or $2.9 million and $3.3 million, respectively.
Lease Operating
Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, operator fees, processing fees, insurance and transportation. For the year ended December 31, 2009, lease operating expenses increased by $16.5 million to $28.1 million ($29.21 per Bbl) from $11.6 million ($14.11 per Bbl) for the same period in 2008. The increase in expense is due to the additional workover and maintenance expenses incurred in 2009 and additional production costs associated with increased production facilities. During the year ended December 31, 2009, we incurred $9.8 million of workover expenses related to the CX11-20XD, CX11-21XD and CX11-15D wells and $1.2 million of additional expense incurred for the replacement of underwater hoses and flow lines, respectively. The remaining increase in the per Bbl amount of lease operating expenses is comprised of increased oil transportation costs, processing fees, and insurance costs as a result of the increased production compared to the same period in 2008.
General and Administrative
General and administrative expenses are overhead-related expenses, including employee compensation, legal, consulting and accounting fees, insurance, and investor relations expenses. For the year ended December 31, 2009, general and administrative expenses decreased $8.8 million to $33.3 million from $42.1 million for the same period in 2008. Stock-based compensation expense, a subset of general and administrative expenses, decreased by $5.8 million to $12.6 million for the year ended December 31, 2009 from $18.5 million for the same period in 2008. The decrease in stock-based
compensation expense is due to the decrease in fair market value of awards granted in 2009 as a result of the decline in the stock price of BPZ. Additionally the 2009 stock-based compensation expense includes approximately $0.7 million of stock-based compensation expense related to the accelerated vesting for certain restricted stock and stock option awards granted to a former member of the Board of Directors but excludes $0.4 million of compensation expense that is included in “Other income (expense)” on the Consolidated Statements of Operations. The $0.4 million relates to 100,000 stock options awarded to a former member of the Board of Directors. The grant date fair value of the award was recognized upon issuance of the award. Other general and administrative expenses decreased $3.0 million to $20.6 million from $23.6 million for the same period in 2008. The $3.0 million decrease is due to $2.3 million decrease of salary and salary related expenses, $1.2 million of decreased consulting and contract labor expense, $0.4 million of decreased legal expenses and $0.4 million decreased travel and travel related expenses partially offset by $0.4 million of increased bank fees and $0.8 million increased rent expenses. The reduction in salary and salary related expense is due to the voluntary salary reduction initiatives and timing of executive bonuses and employee salary increases. During the first half of 2009, certain executive and other key personnel agreed to a voluntary salary reduction of 5% to 15% of their base salaries and the Chairman of the Board of Directors agreed forgo his salary for 2009. Additionally, BPZ did not pay bonuses in 2009. In July 2009, employees who participated in the voluntary salary reduction, other than the Chairman of the Board of Directors, received a salary reinstatement. During 2008, executives and other key employees received bonuses and employees received salary increases that were retroactive to the beginning of the year. The reduction in contract labor, consulting and legal fees is due to the Shell joint venture negotiations and tax reorganization expenses for which we incurred significant fees in 2008 that were not repeated in 2009. The reduced travel and travel related expenses are due to less travel incurred by our personnel in 2009 compared to 2008. The increase in bank fees is due to higher fees charged by financial institutions in 2009 compared to 2008. The higher rent expense is due to increased office space rented by both our Houston and Peru offices in 2009 compared to 2008.
Geological, Geophysical and Engineering
Geological, geophysical and engineering expenses include laboratory, environmental and seismic acquisition related expenses. For the year ended December 31, 2009, geological, geophysical and engineering expenses increased $7.0 million to $7.8 million compared to $0.8 million for the same period in 2008. During the fourth quarter of 2009, we incurred approximately $6.3 million for seismic acquisition expenses. At the end of the third quarter of 2009, we entered into a contract to acquire approximately 950 square kms of 3-D seismic data for Block Z-1 to assist us in exploring, appraising and developing certain areas of interest and to better define the position of future wells as well as to comply with our exploration commitments under our license contracts. As Block Z-1 is located offshore, the seismic activity was to be conducted by marine seismic vessels from a third party seismic contractor. Shortly after starting the seismic operations, we received a notice from the Peruvian Ministry of Energy and Mines to suspend our seismic testing and resubmit our application for a new environmental permit. As a result of the suspension we incurred approximately $4.7 million in standby fees and mobilization and support costs as well as $1.5 million in contract extension costs of which approximately $0.8 million will be credited against the future cost of the seismic acquisition by the contractor. The contract extension guarantees the original seismic acquisition pricing as long as we are able to resume our seismic acquisition within the next two years. The remaining increase of $0.7 million is due to increased laboratory and consulting costs as a result of more environmental impact studies performed on Blocks XIX, XXII and XXIII in the current year compared to the activities of the prior year.
Depreciation, Depletion and Amortization
For the year ended December 31, 2009, depreciation, depletion and amortization expense increased $9.7 million to $25.8 million from $16.1 million for the same period in 2008. The increase is due to increased production discussed above, increased average costs per well being depleted and a reduction in the reserve base from 2008 as a result of decreased oil prices at the end of 2008.
Other Income/(Expense)
For the year ended December 31, 2009, income from our investment in Ecuador property, net of investment amortization, increased $0.5 million to $1.2 million in 2009 from $0.7 million in 2008. The increase is due to receiving $1.4 million in payments during 2009 from our investment in the Santa Elena Property while receiving $0.9 million during 2008. Income/(expense) from our investment in Ecuador is net of investment amortization expense. For both the year ended December 31, 2009 and 2008, investment income / (expense) includes amortization expense of approximately $0.2 million.
For the year ended December 31, 2009, we capitalized $4.4 million of interest expense to construction in progress. For the same period in 2008, we capitalized approximately $4.2 of interest expense to construction in progress.
For the year ended December 31, 2009 and 2008, we received interest income of $0.2 million and $0.3 million, respectively. The decrease in interest income is due to the decreased cash balances in 2009 and lower interest rates.
For the year ended December 31, 2009, other expense increased by $1.4 million to an expense of $1.3 million in 2009 from income of $0.1 million in 2008. The reason for the increase in expense is due to $0.4 million of stock compensation expense related to stock options awarded to a former member of the Board of Directors that was recognized upon issuance of the award and approximately $0.8 million of expense related to the settlement of a disputed contractual obligation with a former consultant of ours concerning services provided to both BPZ and its predecessor at the time BPZ became publicly traded. We were notified of this alleged dispute towards the end of the first quarter of 2009. The settlement was paid in April 2009. Additionally, for the year ended December 31, 2009, we recognized $0.1 million of foreign currency losses and for the same period in 2008 we recognized a $0.1 million foreign currency gain.
Income Taxes
The source of income (loss) before income tax expense (benefit) for the year ended December 31, is as follows (in thousands):
The income tax provision (benefit) for the year ended December 31, consists of the following (in thousands):
The income tax expense (benefit) for the year ended December 31, 2009 and 2008 differs from the amount computed by applying the U.S. statutory federal income tax rate for the applicable year to consolidated net loss before income taxes as follows (in thousands):
A summary of the components of deferred tax assets, deferred tax liabilities and other taxes deferred at December 31, 2009 and 2008 are presented below (in thousands):
Net deferred tax assets in the foregoing table include the deferred consequences of the future reversal of Peruvian deferred tax assets and liabilities on the impact of the Peruvian employee profit share plan tax of $3.3 million in 2009 and $1.1 million in 2008. As of December 31, 2009 and 2008, we had a valuation allowance for the full amount of the domestic deferred tax asset resulting from the income tax benefit generated from net losses, 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 2028. Furthermore, because we have no operations within the U.S. taxing jurisdiction, it is likely that a sufficient generation of revenue to offset our deferred tax asset is remote. As a result, we have a full allowance on our deferred tax asset generated in the U.S. However, we are subject to Peruvian income tax on our earnings at a statutory rate, as defined in the Block Z-1 License Contract, of 22%. Because we were under a well testing program from which we will finalize a development plan for Block Z-1, we had not moved into the commercial phase of production as defined by the license contract. As such, certain deductions were disallowed by the Peruvian tax regime while we operated under the well testing program. In addition, the tax provision is based on taxable Peruvian income that excludes certain U.S. expenses that are not deductible at the Peruvian level. As a result, we recognized a total tax provision for the year ended December 31, 2009 of approximately $6.6 million.
We moved into commercial production in Block Z-1 under the license contract in 2010, at which time our full investment in our producing properties were eligible to be amortized over five years. We assessed the realizability of the deferred tax asset generated in Peru. We considered whether it is more likely than not that some portion or the entire deferred tax asset would not be realized. The ultimate realization of the deferred tax asset is dependent upon the generation of future taxable income in Peru during the periods in which those temporary differences become deductible. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, along with the transition into the commercial phase under the Block Z-1 License Contract, we believed it is more likely than not that we will realize the benefits of the these deductible differences at December 31, 2009. As a result, we recognized a deferred tax asset of $16.9 million as of December 31, 2009.
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. As of the date of adoption of FIN 48, now codified under ASC Topic 740, “Income Taxes”, we did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor were any interest expense recognized during the year. Additionally, the adoption had no effect on our financial position or results of operations. 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 statement as of December 31, 2009 or December 31, 2008.
For the year ended December 31, 2009, our net loss increased $26.2 million to a net loss of $35.8 million or ($0.35) per basic and diluted share from a net loss of $9.6 million or ($0.12) per basic and diluted share for the same period in 2008.
Liquidity, Capital Resources and Capital Expenditures
At December 31, 2010, we had cash and cash equivalents of $11.8 million and current accounts receivable related to our December oil sales of $11.2 million, all of which was collected in early January 2011. We also had $28.4 million in the current portion of our value-added tax receivable, which we will collect over time as we invoice our oil sales.
At December 31, 2010, we had trade accounts payable and accrued liabilities of $51.8 million.
At December 31, 2010, our outstanding long-term debt and short-term debt consisted of a $12.5 million IFC Facility bearing interest at LIBOR plus 2.75% due December 31, 2012 and 2015 Convertible Notes whose net amount of $140.8 million includes the $170.9 million of principal reduced by $30.1 million of the remaining unamortized discount. At December 31, 2010, the current and long-term portions of our capital lease obligations, primarily related to the barges used in our marine operations were $4.2 million and $3.4 million, respectively.
We had a working capital surplus at December 31, 2010 of $22.7 million.
Operating Activities
Cash used in operating activities decreased by $25.7 million to a use of cash of $5.1 million for the year ended December 31, 2010 from a use of cash of $30.8 million for the same period in 2009. The change in cash flows before changes in operating assets and liabilities increased by $25.4 million as a result of higher non-cash charges during 2010 compared to 2009. Changes in cash flow as a result of changes in operating assets and liabilities provided an increase in cash of $0.3 million. The increase in the use of cash is due to: (1) increase in the change in accounts receivable due to the timing of oil deliveries and payments of those deliveries, $11.5 million; (2) increase in the change of prepaid and other assets to secure additional pipe, casing and accessories, $3.0 million; (3) decrease in the change to accrued and other liabilities balances due to the timing of payments of certain Peruvian taxes, $0.8 million; and (4) decrease in the change of current taxes payables as a result of achieving commercial production, $1.7 million. Offsetting these uses of cash are changes in operating assets and liabilities providing sources of cash including: (1) increases in the change to accounts payables, $7.6 million; and (2) decrease in the change to value-added taxes and inventory as we had less expenses subject to VAT and used less inventory in 2010 compared to the same period in 2009, $9.7 million.
Cash used in operating activities increased by $79.5 million to a use of cash of $30.8 million in 2009 from a source of cash of $48.7 million in 2008. Cash flow before changes in operating assets and liabilities decreased by $29.1 million reflecting lower oil production revenues and higher lease operating costs and geological, geophysical, and engineering costs during 2009 compared to 2008, partially offset by lower general and administrative expenses. Changes in operating assets and liabilities provided a use of cash of $50.4 million. In 2009, the change in accounts payable provided a use of cash of $2.9 million and in 2008, provided a source of cash of $23.4 million, the change being a net use of cash of $26.1 million. The reason for the change in accounts payable is due to our initiatives taken in 2009 to better manage our accounts payable balance. In 2009 the change in income taxes payable provided a use of cash of $6.4 million and in 2008 provided a source of cash of $6.8 million, the change being a net use of cash of $13.2 million. The reason for the change in income taxes payable is primarily due to the income tax cash payments made in 2009. In 2009, the change in value added tax receivable provided a use of cash of $14.0 million and in 2008, provided a use of cash of $4.6 million, the change being a net use of cash of $9.4 million. The reason for the change in the balance is due to lower oil revenues in the current year and increased costs. In 2009, the change in inventory provided a use of cash of $7.6 million and in 2008, provided a use of cash of $0.6 million, the change being a net use of cash of $7.0 million. The reason for the change is due to the increased purchase of casing and accessories for use in the Company’s current and future operations. In 2009, the change in accounts receivable provided a source of cash of $2.4 million and in 2008, provided a use of cash of $2.3 million, the change being an increase of cash of $4.7 million. The reason for the change is due to the timing and amount of our account receivable balances. The balance at the end of 2009 was
lower than the balance at the end of 2008 by $2.4 million. The balance at the end of 2008 was higher than the balance at the end of 2007 by $2.3 million.
Investing Activities
Net cash used in investing activities increased by $68.1 million to cash used in investing activities of $158.1 million for the year ended December 31, 2010 from $90.0 million in 2009. The increase is due to increased capital expenditures of $68.6 million in 2010 as our operations included two fields in 2010, the Corvina and Albacora fields, as opposed to operating only one field during the same period in 2009, the Corvina field as well as the final payments for the GE Turbines made in 2010. Also contributing to the change in investing activities are changes in restricted cash providing a use of cash of $0.5 million.
Net cash used in investing activities decreased by $12.2 million to cash used in investing activities of $90.0 million in 2009 from $102.2 million in 2008, respectively, and is primarily due to decreased capital expenditures in 2009.
2010 Equipment Activity
During the year ended December 31, 2010, we incurred capital expenditures of approximately $159.9 million associated with our development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of a proprietary gas-fired power generation facility in Peru.
Of the costs mentioned above, we incurred capital expenditures related to the drilling and testing of the CX11-23D, CX11-17D, CX11-20D, CX11-18D and CX11-22D wells in the Corvina field of approximately $14.0 million, $10.5 million, $0.8 million, $0.8 million and $20.0 million, respectively. In the Albacora field, we incurred capital expenditures related to the drilling of the A-15D, A-16D, A-17D and A-18D wells of approximately $8.5 million, $6.5 million, $17.8 million, and $0.1 million, respectively. On September 30, 2010, the costs of the A-17D well were written off as dry hole costs as well as the costs for two previously drilled wells, the A-15D and A-16D, because those wells were intended to follow the same trajectory and reach the same location as the A-17D well but neither reached the target due to mechanical problems. Both wells were abandoned. Additionally, we have incurred approximately $2.2 million in site preparation and staging for drilling a new well in Block XIX.
In 2009, we entered into a lease-purchase agreement to acquire the Don Fernando barge to serve as our construction lay barge, as well as tender assist barge for drilling and construction operations, and it may be fitted to lay subsea pipe for the gas-to-power project. During the year ended December 31, 2010, we capitalized an additional $4.0 million in order to fit the barge with equipment to support our operations.
For the further development of the planned gas-fired power generation facility, we incurred costs of approximately $41.7 million during the year ended December 31, 2010 as part of our agreement to purchase three LM 6000 gas-fired packaged power units.
For the year ended December 31, 2010, we incurred approximately $5.5 million for upgrades to our existing platforms as well as costs incurred in the design of new platforms. In addition, we incurred $16.4 million in equipment costs for our production facilities at the A platform in Albacora and the CX-11 platform in Corvina. We incurred $7.3 million for the purchase of machinery and equipment used in our various operations in Peru, and $3.9 million in additions to our flowline and anchoring systems.
For the year ended December 31, 2010, we wrote off approximately $12.1 million of property and equipment associated with its gas-to-power project and certain costs for the abandonment of two pre-existing platforms.
For the year ended December 31, 2010 included in the amounts above, in accordance with the “successful efforts” method of accounting, we capitalized approximately $1.8 million of depreciation expense, mainly related to the tender assist barges serving as support equipment, and $9.6 million of interest expense, to construction in progress.
2009 Equipment Activity
During the year ended December 31, 2009, we incurred capital expenditures of approximately $96.6 million associated with our development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of proprietary gas-fired power generation facility in Peru.
Of the incurred costs mentioned above, we incurred capital expenditures related to the drilling and testing of the CX11-15D, CX11-19D, CX11-17D and CX11-20XD in the Corvina field of approximately, $23.5 million, $12.8 million, $3.0 million and $1.0 million respectively, as well as approximately $20.6 million for the A-14XD well in the Albacora field during the year ended December 31, 2009 in addition to $5.1 million in standby, installation and mobilization costs during the same period.
We also incurred costs of approximately $7.9 million during the year ended December 31, 2009 for the design and refurbishment of the Albacora Platform. We began installing permanent production and testing facilities on the Albacora platform and incurred an additional $1.9 million in cost.
In 2009, we entered into a lease-purchase agreement to acquire the Don Fernando barge resulting in additional capital assets of approximately $7.2 million. The Don Fernando will serve as our construction lay barge as well as tender assist barge for drilling and construction operations and will eventually be fitted to lay subsea pipe for the gas-to-power project.
For the development of a Company owned gas-fired power generation facility, we incurred costs of approximately $4.9 million during the year ended December 31, 2009 as part of our agreement to purchase three LM6000 gas-fired packaged power units.
We also incurred costs for the purchase of machinery and equipment used in operations in Peru of approximately $2.9 million.
For the year ended December 31, 2009, in accordance with “successful efforts” method of accounting, we capitalized approximately $1.4 million of depreciation expense, mainly related to the tender assist barges serving as support equipment, and $4.4 million of interest expense to construction in progress
Financing Activities
Cash provided by financing activities increased by $23.2 million to $156.8 million for the year ended December 31, 2010 compared to $133.6 million for the same period in 2009. The increase in cash provided by financing activities is due to increased borrowings as a result of a convertible notes offering of $164.4 million and lower repayments of borrowings of $0.4 million that is partially offset by an increase in cash paid for debt issue costs of $6.1 million and a lesser amount of cash raised through equity issuances in 2009 of $135.0 million.
Cash provided by financing activities increased by $82.4 million to $133.6 million in 2009 compared to $51.3 million in 2008. The increase in cash provided by financing activities reflects increased proceeds from sales of our common stock, and proceeds from the exercise stock options and warrants of $91.4 million. Partially offsetting these proceeds are reduced borrowings, loan fees and reduced repayments of borrowings of ($9.0) million.
Shelf Registration
To finance our operations we may sell additional shares of our common stock. Our certificate of formation does not provide for preemptive rights, although we may grant similar rights by contract from time to time. We currently have $134.6 million in common stock available under an effective shelf registration statement, and another $500.0 million available under the same shelf registration statement for debt securities, common stock, preferred stock, depositary shares and securities warrants, subscription rights, units, and guarantees of debt securities or any combination thereof, which we may sell from time to time in one or more offerings pursuant to underwritten public offerings, negotiated transactions, at the market transactions, block trades or a combination of these methods. This registration statement will expire on December 20, 2013.
Long-Term Debt and Capital Lease Obligations
At December 31, 2010 and December 31, 2009, long-term debt and capital lease obligations consist of the following:
$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 (“$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. The arranger fee is based on a percentage of the principal amount and the performance of the price of crude oil (Brent) from closing date to repayment date. The performance portion of the arranger fee is subject to a specified maximum amount.
The $40.0 million secured debt facility is secured, in part, by three LM6000 gas-fired packaged power units 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 required us to establish a $2.0 million reserve fund during the first 18 months the debt facility is outstanding. After the first 18 month period, we are required to keep a balance in the reserve fund equal to the aggregate amount of payments of principal and interest on the $40.0 million secured debt facility due immediately on the succeeding principal repayment date.
The $40.0 million secured debt facility matures on July 27, 2013, with principal repayment due in equal quarterly installments of $8.0 million commencing on July 27, 2012. The $40.0 million secured debt facility bears interest at three month LIBOR plus 7.0%. Interest is due and payable every three month period after the commencement of the loan.
The $40.0 million secured debt facility provides for events of default and cure periods customary for facilities of this type, including, among other things, payment breaches under any of the finance documents; representation and warranty breaches; any default, early amortization event or similar event occurring with respect to one or more debt facilities in an aggregate outstanding principal amount of at least $3,000,000, if the effect is to accelerate the maturity thereof; failure to comply with obligations; application for the appointment of a receiver; making a general assignment for the benefit of creditors; insolvencies or filing of bankruptcy; certain monetary and non-monetary judgments, orders, decrees or awards against us or our subsidiaries; suspension, revocation or termination of any $40.0 million secured debt facility financing or security documents with Credit Suisse or certain key agreements; and change in control. In addition, the $40.0 million secured debt facility provides for a mandatory prepayment of the loans if debt to finance our gas-to-power project is obtained.
If an event of default occurs, Credit Suisse shall, upon the request of the majority lenders, or may, by notice to us, (i) immediately terminate the lending commitments; and/or (ii) declare all or part of the principal amount of the loans, together with accrued interest, immediately due and payable, without demand; provided that, all lending commitments shall automatically terminate and all amounts due and payable on any loan will automatically become immediately due and payable without notice if we or any subsidiary appoint a receiver, liquidator or trustee, make a general assignment for the benefit of their creditors, become insolvent, bankrupt, liquidate, or are subject to certain monetary judgments exceeding in the aggregate, $3,000,000; and/or (iii) liquidate the security collateral and apply the proceeds thereof to pay the loans.
In January 2011, we received the $40.0 million in proceeds and recorded approximately $1.6 million of fees and commissions associated with the $40.0 million secured debt facility as debt issue costs that will be amortized over time using the interest method as interest expense. We also established a $2.0 million debt service reserve fund.
Proceeds from the $40.0 million secured debt facility will be utilized to meet our 2011 capital expenditure budget, to finance our exploration and development work programs, and to reduce our existing debt.
With respect to the performance based arrangement fee, the fee is payable at each of the principle repayment dates. The formula for calculating fees includes an amount multiplied by the change in oil prices from the date of commencement of the loan and the price at each principle repayment date. Additionally, the performance based arranger fee contains a maximum amount to be paid by us over the term of the loan. We believe the performance based arranger fee may qualify as an embedded financing derivative under ASC 815-10, “Derivatives and Hedging”. This would require us to record the fair value of the derivative liability at inception and to revalue the liability at each financial reporting date throughout the term of the loan. We are currently assessing the impact of the expected liability and expect to record the initial liability as additional interest expense for the performance based arranger fee.
We estimate the cash payments related to the $40.0 million secured debt facility, including potential payments for the performance based arranger fee and interest, for the year ended December 31, 2011, 2012, and 2013 to be approximately $2.3 million, $19.0 million and $25.1 million, respectively.
$170.9 Million Convertible Notes due 2015
In February and March 2010, we closed on the private offering for an aggregate $170.9 million convertible notes due 2015 (the “2015 Convertible Notes”). The 2015 Convertible Notes offering was comprised of (i) the initial $140.0 million of 2015 Convertible Notes sold in an initial private offering, (ii) the exercise, by the initial purchaser, of a 30-day option to purchase an additional $21.0 million of 2015 Convertible Notes, and (iii) IFC’s election to participate in the offering, pursuant to a contractual right, for an additional $9.9 million of 2015 Convertible Notes, bringing the total proceeds of the private offering to $170.9 million. The 2015 Convertible Notes were sold to an initial purchaser who then sold the notes to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. The $170.9 million of 2015 Convertible Notes were issued pursuant to an indenture dated February 8, 2010, between us and Wells Fargo Bank, National Association, as trustee (“the Indenture”).
The 2015 Convertible Notes are 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.
We will pay interest on the 2015 Convertible Notes at a rate of 6.50% per year on March 1st and September 1st of each year, beginning on September 1, 2010. The 2015 Convertible Notes mature on March 1, 2015. The initial conversion rate was 148.3856 shares per $1,000 principal amount of the 2015 Convertible Notes (equal to an initial conversion price of approximately $6.74 per share of common stock), subject to adjustment. Upon conversion, we must deliver, at our option, either (1) a number of shares of our common stock determined as set forth in the Indenture, (2) cash, or (3) a combination of cash and shares of our common stock (but not to exceed 19.99% of our outstanding shares at the time of such delivery).
The initial conversion rate was adjusted on February 3, 2011 as the daily Volume Weighted Average Price (“Average VWAP”) of our common stock for each of the 30 trading days ending on February 3, 2011 was less than $5.6160 per share. The arithmetic average of the Average VWAP per share of Common Stock for each of the thirty (30) consecutive Trading Days ending on February 3, 2011 was $4.9307. Since the Average VWAP is less than $5.6160 per share, the conversion rate increased such that the conversion price, as increased, represents the greater of (1) 120% of the Average VWAP and (2) $5.6160. Accordingly, the conversion rate and conversion price changed to 169.0082 and $5.9169, In addition, following the occurrence of any one of certain corporate transactions that constitutes a fundamental change (as defined in the Indenture), we will increase the conversion rate, subject to certain limitations, for a holder who elects to convert the 2015 Convertible Notes in connection with such corporate transactions during the 30-day period after the effective date of such fundamental change.
Holders may convert their 2015 Convertible Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances:
(1) during any fiscal quarter (and only during such fiscal quarter) commencing after March 31, 2010, if the last reported sale price of 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 the specified 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 five 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 contains customary terms and covenants and events of default. If an event of default (as defined therein) occurs and is continuing, the Trustee by notice to us, or the holders of at least 25% in aggregate principal amount of the 2015 Convertible Notes then outstanding by notice to us and the Trustee, may declare the principal and accrued and unpaid interest (including additional interest or premium, if any) on the 2015 Convertible Notes to be due and payable. In the case of an event of default arising out of certain bankruptcy events (as set forth in the Indenture), the principal and accrued and unpaid interest (including additional interest or premium, if any), on the notes will automatically become due and payable.
Net proceeds from the sale of the 2015 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by us, was approximately $164.9 million. The initial purchaser received commissions of approximately $5.5 million in connection with the sale of the 2015 Convertible Notes 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.
As a result of our adoption of the new accounting standard for convertible debt that may be settled in cash upon conversion, we are required to separately account for the liability and equity components in a manner that reflects our non-convertible borrowing rate when interest cost is recognized in subsequent periods. 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 expense 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 accounting standard requires retrospective restatement of all periods presented back to the date of debt issuance with a cumulative effect of the change in accounting principle on all prior periods being recognized as of the beginning of the first period.
We are accounting for the 2015 Convertible Notes in accordance with FASB Staff Position (“FSP”) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which is codified under ASC Topic 470, “Debt”. Under the accounting guidance, convertible debt instruments
that may be settled entirely or partially in cash upon conversion will be required to separately account for the liability and equity components of the instrument 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 our 2015 Convertible Notes to be 12%. The 12% non-convertible borrowing rate represents the borrowing rate of similar companies with the same credit quality as ours 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 will be amortized as non-cash interest expense into income over the life of the notes using the interest method. In addition, we recorded approximately $4.8 million of the $6.1 million of fees and commissions as debt issue costs that will be amortized over time using the interest method as interest expense. The remaining $1.3 million of fees and commissions will be treated as an original issue discount against the value of the equity component. We estimate the cash payments, including interest related to the 2015 Convertible Notes, assuming no conversion, for the year ended December 31, 2011, 2012, 2013, 2014 and 2015 to be approximately $11.1 million, $11.1 million, $11.1 million, $11.1 million and $176.5 million, respectively. We evaluated the 2015 Convertible Notes agreement for potential embedded derivatives, noting that the conversion feature and make-whole provisions were determined not to 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 December 31, 2010, the net amount of $140.8 million includes the $170.9 million of principal reduced by $30.1 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 $30.1 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 December 31, 2010, using the conversion rate of 148.3856 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 25,364,737 shares of common stock. At February 3, 2011, using the new 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 28,889,927 shares of common stock. In accordance with NYSE rules, we received shareholder approval to issue shares in excess of 19.99% of shares outstanding at the time of the offering (23,031,663 shares) should we need to issue shares in order to satisfy our obligation under the 2015 Convertible Notes. As of December 31, 2010, there is no excess if-converted value to the holders of the 2015 Convertible Notes as the price of our common stock at December 31, 2010, $4.76 per share, is less than the conversion price.
For the year ended December 31, 2010, the effective interest rate for the 2015 Convertible Notes is 12%; including the amortization of debt issue costs, the effective interest rate is 12.6%.
The amount of interest expense related to the 2015 Convertible Notes for the year ended December 31, 2010 is $15.3 million, disregarding capitalized interest considerations, and includes $10.1 million of interest expense related to the contractual interest coupon, $4.5 million of non-cash interest expense related to the amortization of the discount and $0.7 million of interest expense related to the amortization of debt issue costs.
$15.0 Million IFC Reserve-Based Credit Facility
In 2008 we secured a $15.0 million reserve-based lending facility (“IFC Facility”) agreement (the “Loan Agreement”) with IFC through our subsidiaries BPZ E&P and BPZ Marine Peru S.R.L. as borrowers. The reserve-based lending facility was to originally mature in December 2012; however, following the $40.0 million secured debt facility we entered into in January 2011, a portion of the proceeds was used to repay the amount outstanding to the IFC. Because we refinanced the obligation on a long-term basis, $5.0 million of the $12.5 million that was expected to be paid within a year as of December 31, 2010 is being classified as a long term liability, in accordance with Accounting Standard Codification (“ASC”) Topigc 470, “Debt”, as we refinanced the obligation on a long-term basis.
The reserve-based lending facility bore interest at an approximate rate of LIBOR plus 2.75%, equivalent to 3.21% based on the six month LIBOR rate of 0.46% at December 31, 2010. The maximum amount available under this facility
began at $15.0 million and was to be reduced by $2.5 million beginning on December 16, 2010 and every six months thereafter during the term of the Loan Agreement. The amount available under the Loan Agreement was subject to a semi-annual borrowing base determination based on the value of oil reserves. In addition, we were subject to various financial covenants calculated as of the last day of each quarter, including a life of field coverage ratio, life of loan coverage ratio, debt to equity ratio and interest coverage ratio. The IFC Facility also provided for events of default, cure periods and lender remedies customary for facilities of this type. We were in compliance with all material covenants of the Loan Agreement as of December 31, 2010.
Other
In July 2009, we, through our subsidiary, BPZ E&P, entered into a $5.1 million short-term loan agreement to finance the purchase of casing and accessories for use in our current and future operations. The $5.1 million short-term loan bore an annual interest rate of 5.45% and was repaid in five monthly installments of approximately $1.0 million starting September 2009. In connection with the $5.1 million short-term loan agreement, we were required to deposit $1.0 million with the lending institution as a guaranty for the loan. The $1.0 million was applied to the last installment of the loan repayments. As of December 31, 2009, the remaining principal amount was approximately $1.0 million and, along with the accrued interest due, was repaid with the $1.0 million deposit and cash in January 2010.
Note Payable
In January 2009, in exchange for receipt of $1.0 million from an individual (“Note Holder”), we signed a promissory note (the “Note”). The Note originally provided for maturity in July 2009 and bore an annual interest rate of 12.0%. However, in March 2009 we repaid the principal amount and accrued interest in full to the Note Holder.
Capital Leases
In November 2009, we entered into a capital lease agreement for a construction barge, the Don Fernando, to assist us in our offshore construction projects. The capital lease asset and corresponding liability was recorded at $7.0 million, which represents the present value of the minimum lease payments, or the aggregate fair market value of the assets. At the end of the two year lease the title to the barge transfers to us. We accounted for the lease agreement in accordance with ASC Topic 840, “Leases”, previously accounted for under Statement of Financial Accounting Standards (“SFAS”) No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement is accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 22.4%.
In June 2007, we entered into a capital lease agreement, with an option to purchase, for two barges, Namoku and the Nu’uanu, to assist in the development of the Corvina oil field. The capital lease assets were recorded at $6.2 million, which represented the present value of the minimum lease payments, or the aggregate fair market value of the assets.
In May 2009, we entered into an amendment of our lease agreement for two barges currently under charter, the Namoku and the Nu’uanu. Under the terms of the amended lease agreement, the current charter, originally set to expire in November 2009, was extended for five years commencing on May 1, 2009. During the first 18 months of the amended lease term, the daily charter rate for the use of both barges is fixed. Commencing on November 2010, the daily charter rate for the use of both vessels will be based on a tiered structure with the daily rate dependent upon the amount of the previous month’s average daily per barrel price of West Texas Intermediate Crude Oil (“WTI”), as indicated on the New York Mercantile Exchange. Any amount paid by us after November 2010 over the initial daily rate as a result of the escalated tiered structure based on the price of WTI will be considered contingent rental payments. The amount of the contingent lease payments paid in 2010 was $0.2 million. The amended lease agreement contains a $3.0 million purchase option after the third year of the lease, a $2.0 million purchase option after the fourth year of the lease and a mandatory $1.0 million purchase obligation by us after the fifth year of the lease. We accounted for the amended lease agreement in accordance with ASC Topic 840, “Leases”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement continues to be accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 34.9%.
In June 2008, we entered into a two year capital lease agreement to acquire the production equipment used on board the Namoku resulting in additional capital assets of approximately $2.4 million. Further we capitalized an additional $2.8 million of production equipment in order to have the FPSO ready to receive and treat oil received from the CX-11 platform. The FPSO lease contains two bargain purchase options; therefore, depreciation of these leased asset will be over its useful life. The lease contains a bargain purchase option of $1.0 million at the end of the first year of the lease and a $0.5 million bargain purchase option at the end of the second year of the lease. We accounted for the lease agreement in accordance with
ASC Topic 840, “Leases”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement is accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 28.3%.
In March 2008, we entered into a lease-purchase agreement to acquire the BPZ-02 barge resulting in additional capital assets of approximately $7.0 million. In February 2009, we made the final lease payment on the BPZ-02 deck barge at which point title to the barge was transferred to us.
Performance Bonds
As of December 31, 2010, we have restricted cash deposits of $5.8 million. In connection with our properties in Peru, we have obtained four performance bonds totaling $5.3 million that are partially collateralized by restricted cash deposits of $3.1 million to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally, we have $2.0 million of restricted cash to collateralize insurance bonds for import duties related to the Don Fernando, our construction barge, and $0.6 million of restricted cash to insure certain performance obligations and commitments at our gas-to-power project site near Tumbes. In addition, we have an unsecured performance bond of $0.1 million to guarantee our performance under an office lease agreement in Peru.
All of the performance and insurance bonds are issued by Peruvian banks and their terms are governed by the corresponding license contracts, customs laws, legal requirements or rental practices.
2011 Estimated Capital Expenditures Budget
We estimate our 2011 capital expenditures budget to be approximately $50 million for the continued development of our assets in northwest Peru. The majority of the capital budget is expected to be spent on offshore Block Z-1, primarily for the design and construction of an additional production platform for the Corvina oil field, as well as, for injection equipment to be installed on the platform in the Albacora oil field by year-end 2011. The new platform in Corvina, along with the injection equipment for Albacora, is budgeted at approximately $40 million for 2011. The new platform for Corvina is expected to be installed with the production and injection equipment in 2012. We have also budgeted approximately $10 million for two automatic crude oil custody transfer units, improvements to the supply dock at Caleta Cruz and other capital projects.
In addition to capital expenditures, we plan to spend and expense approximately $18 million on seismic acquisition in Block Z-1 and $4 million to complete the seismic acquisitions in Blocks XXII and XXIII. At the CX-11 platform in Corvina, we plan two or three workovers of existing wells to optimize oil production. Workovers are expected to commence in the second quarter, and are budgeted at $3 million each. We may work over two or three of the existing oil wells at the Albacora platform in the fourth quarter of 2011 and these are also budgeted at $3 million each.
Liquidity Outlook
Our major sources of funding to date have been through oil sales, equity raises, convertible debt issuances and, to a lesser extent, debt financing activities. With our current cash balance, current and prospective Corvina and Albacora oil development cash flow, our recent debt issuance, our recent debt facility and other potential third-party financing and potential financing from future equity raises, we believe we will have sufficient capital resources to execute our planned Corvina and Albacora oil development projects as well as service our current obligations.
We have hired a financial advisor to help us in pursuing joint venture partnerships and/or, farm-outs for some or all of our assets and options for financing our operations in northwest Peru. While there will be options discussed that could provide us with additional liquidity or funding, we cannot predict the outcome of this review.
Off-Balance Sheet Arrangements
As of December 31, 2010, 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.
Contractual Obligations
(1) Includes operating leases for our executive office in Houston, Texas, and our branch offices in Lima, Peru and warehouses in Peru, respectively, The operating lease amounts also exclude $0.1 million of sublease rentals from our Houston, Texas office due in the future under noncancelable subleases.
Includes the monthly lease expense for our two drilling rigs, one being currently leased to an operator in Peru and the other rig is currently being upgraded by Petrex to be used in operations once our seismic data acquisitions is completed. One lease is set to expires in January 2012 and the other lease is set to expire in December 2013.
Includes the monthly lease expense for one of our oil transportation vessels whose lease is set to expire in February 2012 and storage vessel whose lease is set to expire in February 2013.
(2) Includes capital lease for a construction barge, the Don Fernando. The capital ease is set to expire in November 2011 at which point title to the barge transfers to us.
Includes capital lease for two production and storage barges, the Namoku and the Nu’uanu, whose lease was amended in May 2009 and is currently set to expire in April 2014. Lease payments are variable based on the working status of the barges. The amended lease agreement contains a $3.0 million purchase option after the third year of the lease, a $2.0 million purchase option after the fourth year of the lease and a mandatory $1.0 million purchase obligation by us after the fifth year of the lease. Commencing on November 2010, the daily charter rate for the use of both vessels will be based on a tiered structure with the daily rate dependent upon the amount of the previous month’s average daily per barrel price of WTI, as indicated on the New York Mercantile Exchange. Any amount paid by us after November 2010 over the initial daily rate as a result of the escalated tiered structure based on the price of WTI will be considered contingent rental payments. The amount of the contingent lease payments paid in 2010 was $0.2 million.
(3) Includes the debt and interest payments related to the $15.0 million reserve-based lending facility agreement with IFC through our subsidiaries BPZ E&P and BPZ Marine Peru S.R.L as borrowers. The reserve-based lending facility bears interest at an approximate rate of LIBOR plus 2.75%, currently equivalent to 3.21% based on the six month LIBOR rate of 0.46% at December 31, 2010. The maximum amount available under this facility will begin at $15.0 million and will be reduced by $2.5 million beginning on December 16, 2010 and every six months thereafter during the term of the Loan Agreement. In January 2011, this loan was replaced with a $40.0 million secured credit facility. As we intend to refinance the $15.0 million reserve-based lending facility with a long term obligation, the $5.0 million of principle that would have been classified as a current liability is being classified as a long-term liability in accordance with generally accepted accounting principles. We estimate the cash payments related to the $40.0 million secured debt facility, including potential payments for the performance based arranger fee, for the years ended 2011, 2012, and 2013 to be approximately $2.3 million, $19.0 million and $25.1 million, respectively.
Includes the remaining principal amount along with the accrued interest due, on the $170.9 million convertible notes due 2015. The 2015 Convertible Notes at a rate of 6.50% per year on March 1 and September 1 of each year, beginning on September 1, 2010. The 2015 Convertible Notes mature on March 1, 2015. Subsequent to December 31, 2011, using an adjusted 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 28,889,927 shares of common stock.
Critical Accounting Policies
The discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP” or “U.S. GAAP”). Management uses estimates and assumptions in preparing the consolidated financial statements in accordance with GAAP. 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. We have identified the following as critical accounting policies directly related to our business and operations, and the understanding of our financial statements.
Successful Efforts Method of Accounting
We follow the successful efforts method of accounting for our investments in 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. Certain costs of exploratory wells are capitalized pending determinations that proved reserves have been found. 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 firmly 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 or at the one year anniversary of completion of the well if proved reserves have not been attributed and capital expenditures as described in the preceding sentence are not required. We assess our capitalized exploratory wells pending evaluation each quarter to determine whether costs should remain capitalized or should be charged to earnings. Other exploration costs, including geological and geophysical costs, are expensed as incurred. We will recognize gains or losses on the sale of properties, should they occur, on a field-by-field basis.
The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and application of industry experience. Wells may be completed that are assumed to be productive and actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. The evaluations of oil and gas leasehold acquisition costs requires management’s judgment to estimate the fair value of exploratory costs related to drilling activity in a given area.
The successful efforts method of accounting can have a significant impact on the operational results reported when we enter a new exploratory area in hopes of finding oil and gas reserves. Seismic costs can be substantial, which will result in
additional exploration expenses when incurred. The initial exploratory wells may be unsuccessful and the associated costs will then be expensed as dry hole costs, and any associated leasehold costs may be impaired.
Oil and Gas Accounting Reserves Determination
The successful efforts method of accounting depends on the estimated reserves we believe are recoverable from our oil and gas reserves. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geo-physical, engineering and economic data.
To estimate the economically recoverable oil and natural gas reserves and related future net cash flows, we incorporate many factors and assumptions including:
· expected reservoir characteristics based on geological, geophysical and engineering assessments;
· future production rates based on historical performance and expected future operating and investment activities;
· future oil and gas quality differentials;
· assumed effects of regulation by governmental agencies; and
· future development and operating costs.
We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially going forward as additional data from development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.
Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the US as prescribed by the Society of Petroleum Engineers. Reserve estimates are independently evaluated at least annually by our independent qualified reserves engineers, NSAI.
Our Board of Directors oversees the review of our oil and gas reserves and related disclosures by our appointed independent reserve engineers. The Board meets with management periodically to review the reserves process, results, and to confirm that the independent reserve engineers have had access to sufficient information, including the nature and satisfactory resolution of any material differences of opinion between the Company and the reserve engineers.
Reserves estimates are critical to many of our accounting estimates, including:
· Determining whether or not an exploratory well has found economically producible reserves;
· Calculating our unit-of-production depletion rates. Proved reserves estimates are used to determine rates that are applied to each unit-of-production in calculating our depletion expense; and
· Assessing, when necessary, our oil and gas assets for impairment. Estimated future cash flows are determined using proved reserves. The critical estimates used to assess impairment, including the impact of changes in reserves estimates, are discussed below.
Revenue Recognition
We recognize revenues when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.
We sell our production in the Peruvian domestic market on a contract basis. Revenue is recorded net of royalties when the purchaser takes delivery of the oil. At the end of the period, oil that has been produced but not sold is recorded as inventory at the lower of cost or market. Cost is determined on a weighted average based on production costs.
Impairment of Long-Lived Assets
We periodically evaluate the recoverability of the carrying value of our long-lived assets and identifiable intangibles by monitoring and evaluating changes in circumstances that may indicate that the carrying amount of the asset may not be recoverable. Examples of events or changes in circumstances that indicate the recoverability of the carrying amount of an asset
should be assessed include, but are not limited to, (a) a significant decrease in the market value of an asset, (b) a significant change in the extent or manner in which an asset is used or a significant physical change in an asset, (c) a significant adverse change in legal factors or in the business climate that could affect the value of an asset or an adverse action or assessment by a regulator, (d) an accumulation of costs significantly in excess of the amount originally expected to acquire or construct an asset, and/or (e) a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with an asset used for the purpose of producing revenue.
We consider historical performance and anticipated future results in our evaluation of potential impairment. Accordingly, when indicators of impairment are present, we evaluate the carrying value of these assets in relation to the operating performance of the business and future discounted and non-discounted cash flows expected to result from the use of these assets. Impairment losses are recognized when the expected future cash flows from an asset are less than its carrying value.
Future Dismantlement, Restoration, and Abandonment Costs
The accounting for future development and abandonment costs changed on January 1, 2003, with the issuance of ASC Topic 410, “Asset Retirement and Environmental Liabilities”, previously known as SFAS No. 143, “Accounting for Asset Retirement Obligation” (“ARO”), which requires the fair value of a liability for an asset retirement obligation to be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The accrual is based on estimates of these costs for each of our properties based upon the type of production structure, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these costs is difficult and requires management to make estimates and judgments that are subject to future revisions based on numerous factors, including changing technology, the political and regulatory environment and estimates as to the proper discount rate to use and timing of abandonment.
Our plan of operations includes the drilling of wells and the construction of an electric power generation plant. We will be required to plug and abandon those wells and restore the well sites and power generation site upon abandonment if they are abandoned prior to the end of the contract period. See Note-8, “Asset Retirement Obligation” to the consolidated financial statements provided herein for further detail.
Principles of Consolidation
Our consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries and branch offices. All intercompany balances and transactions have been eliminated.
Our accounting policy regarding partnership or joint venture interests in oil and gas properties is to consolidate such interests on a pro-rata basis in accordance with accepted practice in the oil and gas industry. However, we have not been able to receive timely information to allow us to proportionately consolidate the minority non-operated net profits interest owned by our consolidated subsidiary, SMC Ecuador Inc. See Note-6, “Investment in Ecuador Property” to the consolidated financial statements for further discussion regarding the investment in our Ecuador property. Accordingly, we account for this investment under the cost method. As such, we record our share of cash received or paid attributable to this investment as other income or expense and amortizes its investment into income over the remaining term of the license agreement which expires in May 2016.
Stock Based Compensation
We account for stock-based compensation at fair value in accordance with the provisions of ASC Topic 718, “Stock Compensation” (“ASC Topic 718”), previously accounted for under SFAS 123(R), “Share-Based Payment”, which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employees (i.e. Directors). Under the provisions of ASC Topic 718, stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award, and is recognized as expense in the Consolidated Statements of Operations ratably over the employee’s or non-employee’s requisite service period, which is generally the vesting period of the equity grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of our common stock on the grant date. Additionally, stock-based compensation cost is recognized based on awards that are ultimately expected to vest, therefore, the compensation cost recognized on stock-based payment transactions is reduced for estimated forfeitures based on our historical forfeiture rates. Additionally, no stock-based compensation costs were capitalized for the year ended December 31, 2010,
2009, and 2008. We provide compensation benefits to employees and non-employee directors under share-based payment arrangements, including various employee stock option plans.
ASC Topic 230, “Statement of Cash Flows”, requires the cash flows resulting from tax deductions in excess of the compensation cost recognized for equity awards (excess tax benefits) to be classified as financing cash flows. However, as we are not able to use these tax deductions (see Note-16, “Income Taxes” for further information), we have no excess tax benefits to be classified as financing cash flows.
Foreign Exchange
The U.S. Dollar is the functional currency for our operations in both Peru and Ecuador. Ecuador has adopted the U.S. Dollar as its official currency. Peru, however, still uses its local currency, Nuevo Sol, in addition to the U.S. Dollar and therefore our financial results are subject to favorable or unfavorable fluctuations in the exchange rate and inflation of that country. We have adopted ASC Topic 830, “Foreign Currency Matters”, previously SFAS No. 52, “Foreign Currency Translation,” which requires that the translation of the applicable foreign currency into U.S. dollars be performed for balance sheet monetary accounts using current exchange rates in effect at the balance sheet date, non-monetary accounts using historical exchange rates in effect at the time the transaction occurs, and for revenue and expense accounts using a weighted average exchange rate during the period reported. Accordingly, the gains or losses resulting from such translation are included in other income and expense in the consolidated Statements of Operations.
Recent Accounting Pronouncements
In January 2010, we partially adopted the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC Topic 820 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). We will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on our financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06. For further information, please see Note-11, “Fair Value Measurements and Disclosures”.
In January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures” (“ASU 2010-3”), to provide consistency with the December 2008 SEC rules regarding Oil and Gas Disclosures. ASU 2010-3 amends existing FASB standards to align the reserves calculation and disclosure requirements under U.S. GAAP with the requirements in the SEC rules. The Company adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate. See Supplemental Oil and Gas Information (Unaudited) for further information.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The 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 December 31, 2010, we had long-term debt and capital lease obligations of approximately $156.8 million and current maturities of long-term debt and capital lease obligations of approximately $4.2 million.
The $15.0 million IFC reserve-based lending facility, which at December 31, 2010 had $12.5 million outstanding maturing in December 2012, 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 December 2010 levels, interest expense would increase by approximately $0.1 million annually. The carrying value of the variable interest rate debt approximates fair value as it bears interest at current market rates. Additionally, we refinanced the $15.0 million reserve-based lending facility with a $40.0 million secured debt facility in 2011.
The capital lease obligation for the FPSO and transportation barges began in August 2007 and is set to expire in May 2014. Lease payments are variable based on the working status of the barges, with a purchase option of $3.0 million in May 2012, $2.0 million in May 2013, and for 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 November 2009, we entered into a capital lease agreement for a construction barge, the Don Fernando, to assist us in our offshore construction projects. The capital lease asset and corresponding liability was recorded at $7.0 million, which represents the present value of the minimum lease payments, or the aggregate fair market value of the assets. At the end of the two year lease the title to the barge transfers to us. We accounted for the lease agreement in accordance with ASC Topic 840, “Leases”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement is accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 22.4%.
In February and March 2010, we closed on the private offering for an aggregate $170.9 million 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 December 31, 2010 and 2009, was as follows:
(1) Excludes obligations under capital lease arrangements and variable rate debt
(2) The Company estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $176.5 million based on observed market prices for the same or similar type issues.
We do not expect a significant change in the market interest rate to impact the interest on our term debt. However, significant changes in market interest rates may significantly affect the level of financing that will be structured with respect to our project in Peru.
Commodity Price Risk
With respect to our oil and gas business, any revenues, cash flow, profitability and future rate of growth we achieve will be greatly dependent upon prevailing prices for oil and gas. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also expected to be dependent on oil and gas prices. Historically, oil and gas prices and markets have been volatile and are likely to continue to be volatile in the future. Prices for oil and gas are subject to potentially wide fluctuations in response to relatively minor changes in supply of and demand for oil and gas, market uncertainty, and a variety of additional factors that are beyond our control.
Lower oil and natural gas prices may not only decrease our revenues on a per unit basis, but may also reduce the amount of oil and natural gas we can produce economically, if any. A substantial or extended decline in oil and natural gas prices may materially affect our future business, financial condition, results of operations, liquidity and borrowing capacity, and may require a reduction in the carrying value of our oil and gas properties. While our revenues may increase if prevailing oil and gas prices increase significantly, exploration and production costs and acquisition costs for additional properties and reserves may also increase.
With respect to our planned electricity generation business, the price we can obtain from the sale of electricity through our proposed power plant may not rise at the same rate, or may not rise at all, to match a rise in the cost of production and transportation of our gas reserves which will be used to generate the electricity. Prices for electricity in Peru have been volatile in the past and may be volatile in the future. However, gas prices in Peru are regulated and therefore not volatile.
Foreign Currency Exchange Rate Risk
The U.S. Dollar is the functional currency for our operations in both Peru and Ecuador. Ecuador has adopted the U.S. Dollar as its official currency. Peru, however, uses its local currency, the Nuevo Sol, in addition to the U.S. Dollar, and therefore, our financial results are subject to favorable or unfavorable fluctuations in the exchange rate and inflation in that country. Transaction differences have been nominal to-date but are expected to increase as our activities in Peru continue to escalate. During the year ended December 31, 2010, 2009, and 2008, exchange rate gains and losses were not material.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
BPZ Resources, Inc. and Subsidiaries
Index to Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firms
80-81
Consolidated Balance Sheets as of December 31, 2010 and 2009
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008
Notes to Consolidated Financial Statements
Supplemental Oil and Gas Disclosures (Unaudited)
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
BPZ Resources, Inc. and Subsidiaries
Houston, Texas
We have audited the accompanying consolidated balance sheet of BPZ Resources, Inc. as of December 31, 2010 and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BPZ Resources, Inc. at December 31, 2010 and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), BPZ Resources, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 16, 2011 expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Houston, TX
March 16, 2011
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders
BPZ Resources, Inc. and Subsidiaries
Houston, Texas
We have audited the accompanying consolidated balance sheet of BPZ Resources, Inc. and Subsidiaries as of December 31, 2009, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BPZ Resources, Inc. and Subsidiaries at December 31, 2009, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.
/s/ Johnson Miller & Co., CPA’s PC
Midland, Texas
March 31, 2010
BPZ Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands, except share par value amounts)
The accompanying notes are an integral part of these consolidated financial statements.
BPZ Resources, Inc. and Subsidiaries
Consolidated Statements of Operations
(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 Stockholders’ Equity
Years Ended December 31, 2010, 2009 and 2008
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
BPZ Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
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 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 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 contract, 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 extends through May 2016.
The Company is in the process of developing its oil and natural gas reserves. The Company was producing and selling oil from the CX-11 platform in the Corvina field of Block Z-1 under a well testing program, until it placed the Corvina field into commercial production in November 2010. The Company is also in the initial stages of appraising, exploring and developing its potential oil and natural gas reserves from the A platform in the Albacora field of Block Z-1 and began producing from the A-14XD, in December 2009, and selling oil from the A-14XD well under a well testing program during the second quarter of 2010. From the time the Company began producing from the CX-11 platform in the Corvina field in November 2007 and the Albacora field in December 2009, through December 31, 2010, it has produced approximately 3.4 MMBbls of oil. Additionally, the Company’s activities in Peru include analysis and evaluation of technical data on its other properties, preparation of the development plans for the properties, designs for platforms, procuring machinery and equipment for an extended drilling campaign, obtaining all necessary environmental and operating permits, bringing additional production on-line, seismic acquisition, obtaining detailed engineering and design of the power plant and gas processing facilities and securing the required capital and financing to conduct the current plan of operation.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Basis of Presentation and Principles of Consolidation
The consolidated financial statements include the accounts of BPZ Resources, Inc. and its wholly-owned subsidiaries and branch offices. All intercompany balances and transactions have been eliminated.
The Company’s accounting policy regarding partnership or joint venture interests in oil and gas properties is to consolidate such interests on a pro-rata basis in accordance with accepted practice in the oil and gas industry. However, the Company has not been able to receive timely information to allow it to proportionately consolidate the minority non-operating net profits interest owned by its consolidated subsidiary, SMC Ecuador Inc. See Note- 6, “Investment in Ecuador Property” to the consolidated financial statements for further discussion regarding the Company’s investment in its Ecuador property. Accordingly, the Company accounts for this investment under the cost method. As such, the Company records its share of cash received or paid attributable to this investment as other income or expense and amortizes its investment into income over the remaining term of the license agreement which expires in May 2016.
Use of Estimates
The preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles (“GAAP” or “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-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered.
Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment including impairment and asset retirement obligation 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 these estimates.
Reclassification
Certain reclassifications have been made to the 2009 and 2008 consolidated financial statements to conform to the 2010 presentation. These reclassifications were not material to the accompanying consolidated financial statements.
Revenue Recognition
The Company recognizes revenues when they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable, and (iv) collectability is reasonably assured.
The Company sells its production in the Peruvian domestic market on a contract basis. Revenue is recorded net of royalties when the purchaser takes delivery of the oil. At the end of the period, oil that has been produced but not sold is recorded as inventory at the lower of cost or market. Cost is determined on a weighted average based on production costs. See Note - 13, “Revenue” for further information.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Reporting and Functional Currency
The U.S. Dollar is the functional currency for the Company’s operations in both Peru and Ecuador. Ecuador has adopted the U.S. Dollar as its official currency. Peru, however, uses its local currency, Nuevo Sol, in addition to the U.S. Dollar and therefore its financial results are subject to foreign currency gains and losses. The Company has adopted Accounting Standard Codification (“ASC”) Topic 830, “Foreign Currency Matters”, previously Statement of Financial Accounting Standards (“SFAS”) No. 52, “Foreign Currency Translation,” which requires that the translation of the applicable foreign currency into U.S. dollars be performed for balance sheet monetary accounts using current exchange rates in effect at the balance sheet date, non-monetary accounts using historical exchange rates in effect at the time the transaction occurs, and for revenue and expense accounts using a weighted average exchange rate during the period reported. Accordingly, the gains or losses resulting from such translation are included in other income and expense in the consolidated statements of operations. Due to the relatively low level of activity to-date and the relatively steady exchange rate in Peru, foreign exchange gains and losses for the year ended December 31, 2010, 2009, and 2008 were not material to the Company’s financial statements.
Cash and Cash Equivalents
The Company considers cash on hand, cash in banks, money market mutual funds and highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Certain of the Company’s cash balances are maintained in foreign banks which are not covered by deposit insurance. The cash balance in the Company’s U.S. bank accounts may exceed federally insured limits.
Restricted Cash
As discussed in Note-7, “Restricted Cash”, the Company has secured various performance bonds, collateralized by certificates of deposit, to guarantee its obligations and commitments in connection with its exploratory properties in Peru. All of the performance bonds have been issued by Peruvian banks and their terms are dictated by the corresponding license contract or agreement.
Allowance for Doubtful Accounts
Currently, the Company’s contract terms regarding oil sales have a relatively short settlement period. However, the Company regularly reviews all aged accounts receivables for collectability and establishes an allowance as necessary for balances greater than 90 days outstanding. Currently, all receivables are current or were outstanding less than thirty days.
It is the Company’s belief that there are no balances in accounts receivable that will not be collected and that an allowance was not necessary at December 31, 2010 and December 31, 2009, respectively.
Property, Equipment and Construction in Progress
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 firmly 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.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
The Company assesses its capitalized exploratory wells pending evaluation each quarter to determine whether costs should remain capitalized or should be charged to earnings. Other exploration costs, including geological, geophysical and engineering costs, are expensed as incurred. The Company recognizes gains or losses on the sale of properties, should they occur, on a field-by-field basis.
Projects under construction are not depreciated or amortized until placed in service. For assets the Company constructs, it capitalizes direct costs, such as labor and materials, and indirect costs, such as overhead and interest. As of December 31, 2010, property and equipment consists of office equipment, vehicles and leasehold improvements made to the Company’s offices. All such values are stated at cost and are depreciated on a straight-line basis over the estimated useful life of the assets which ranges between three and ten years, or the term of the lease. Barges and related equipment are depreciated on a straight-line basis over the estimated useful life of the asset which is between ten and fifteen years. Maintenance and repairs are expensed as incurred. Replacements, upgrades or expenditures which improve and extend the life of the assets are capitalized. When assets are sold, retired or otherwise disposed, the applicable costs and accumulated depreciation and amortization are removed from the appropriate accounts and the resulting gain or loss is recorded.
Accrued Liabilities
The accrued liabilities included in the Company’s balance sheet at December 31, 2010 and 2009 consist mainly of accrued liabilities related to costs for which goods and services have been received by it in support of the Company’s oil and gas operations, including drilling operations, seismic and lease operating costs.
Oil and Gas Accounting Reserves Determination
The successful efforts method of accounting depends on the estimated reserves the Company believes recoverable from its oil and gas reserves. The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geo-physical, engineering and economic data.
To estimate the economically recoverable oil and natural gas reserves and related future net cash flows, the Company incorporates many factors and assumptions including:
· expected reservoir characteristics based on geological, geophysical and engineering assessments;
· future production rates based on historical performance and expected future operating and investment activities;
· future oil and gas quality differentials;
· assumed effects of regulation by governmental agencies; and
· future development and operating costs.
The Company believes its assumptions are reasonable based on the information available to it at the time it prepared the estimates. However, these estimates may change substantially going forward as additional data from development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.
Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with the Security and Exchange Commission (“SEC”) requirements and generally accepted industry practices in the US as prescribed by the Society of Petroleum Engineers. Reserve estimates are independently evaluated at least annually by independent qualified reserves engineers, Netherland, Sewell & Associates, Inc (“NSAI”). The estimate of the Company’s proved reserves as of December 31, 2010 and 2009 have been prepared and presented in accordance with new SEC rules and accounting standards. These new rules were effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on 12-month un-weighted first-day-of-the-month average pricing. The previous rules required that reserve estimates be calculated using last-day-of-the-year pricing.
The Company’s Board of Directors oversees the review of its oil and gas reserves and related disclosures by the Company’s appointed independent reserve engineers. The Board meets with management periodically to review the reserves
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
process, results, and to confirm that the independent reserve engineers have had access to sufficient information, including the nature and satisfactory resolution of any material differences of opinion between the Company and the reserve engineers.
Reserves estimates are critical to many of the Company’s accounting estimates, including:
· Determining whether or not an exploratory well has found economically producible reserves;
· Calculating the Company’s unit-of-production depletion rates. Proved reserves estimates are used to determine rates that are applied to each unit-of-production in calculating its depletion expense; and
· Assessing, when necessary, the Company’s oil and gas assets for impairment. Estimated future cash flows are determined using proved reserves. The critical estimates used to assess impairment, including the impact of changes in reserves estimates, are discussed below.
Impairment of Long-Lived Assets
The Company periodically evaluates the recoverability of the carrying value of its long-lived assets by monitoring and evaluating changes in circumstances that may indicate that the carrying amount of the asset may not be recoverable. Examples of events or changes in circumstances that indicate that the recoverability of the carrying amount of an asset should be assessed include but are not limited to the following: a significant decrease in the market value of an asset, a significant change in the extent or manner in which an asset is used or a significant physical change in an asset, a significant adverse change in legal factors or in the business climate that could affect the value of an asset or an adverse action or assessment by a regulator, an accumulation of costs significantly in excess of the amount originally expected to acquire or construct an asset, and/or a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with an asset used for the purpose of producing revenue.
The Company considers historical performance and anticipated future results in its evaluation of potential impairment. Accordingly, when indicators of impairment are present, the Company evaluates the carrying value of these assets in relation to the operating performance of the business and future discounted and non-discounted cash flows expected to result from the use of these assets. Impairment losses are recognized when the expected future cash flows from an asset are less than its carrying value. For the year ended December 31, 2010, 2009 and 2008, there were no impairment losses recognized by the Company.
Stock Based Compensation
The Company accounts for stock-based compensation at fair value in accordance with the provisions of ASC Topic 718, “Stock Compensation” (“ASC Topic 718”), previously accounted for under SFAS 123(R), “Share-Based Payment”, which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employees (i.e. Directors). Under the provisions of ASC Topic 718, stock-based compensation cost is measured at the date of grant, based on the calculated fair value of the award, and is recognized as expense in the Consolidated Statements of Operations ratably over the employee’s or non-employee’s requisite service period, which is generally the vesting period of the equity grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards and units are valued using the market price of the Company’s common stock on the grant date. Additionally, stock-based compensation cost is recognized based on awards that are ultimately expected to vest, therefore, the compensation cost recognized on stock-based payment transactions is reduced for estimated forfeitures based on the Company’s historical forfeiture rates. Additionally, no stock-based compensation costs were capitalized for the year ended December 31, 2010, 2009 and 2008. The Company provides compensation benefits to employees and non-employee directors under stock-based payment arrangements, including various employee stock option plans. See Note-10, “Stockholders’ Equity” for further discussion of the Company’s stock-based compensation plans.
ASC Topic 230, “Statement of Cash Flows”, requires the cash flows resulting from tax deductions in excess of the compensation cost recognized for equity awards (excess tax benefits) to be classified as financing cash flows. However, as the Company is not able to use these tax deductions (see Note-16, “Income Taxes” for further information), it has no excess tax benefits to be classified as financing cash flows.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Capitalized Interest
Certain interest costs have been capitalized as part of the cost of oil and gas properties under development, including wells in progress and related facilities. Total interest costs capitalized during the year ended December 31, 2010, 2009 and 2008 were $9.6 million, $4.4 million and $4.2 million, respectively.
Fair Value of Financial Instruments
The Company’s financial instruments consist of cash, trade receivables, trade payables and debt. The book values of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short-term maturity of those instruments. For further information regarding the fair value of the Company’s fixed rate debt see Note -11, “Fair Value Measurements and Disclosures”. For the Company’s variable rate debt at December 31, 2010 and 2009, the carrying value of the debt approximates fair value as 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 can currently borrow under similar terms.
Income Taxes
The Company accounts for income taxes in accordance with SFAS 109, “Accounting for Income Taxes, which was codified into ASC Topic 740, “Income Taxes”. Under ASC Topic 740, deferred tax assets and liabilities are determined based on differences between the financial reporting and tax basis of assets and liabilities, and are measured using the enacted tax rates and laws that will be in effect when the differences are expected to reverse. Valuation allowances are established when necessary to reduce deferred tax assets to the amount expected to be realized.
Environmental
The Company is subject to environmental laws and regulations of various U.S. and international jurisdictions. These laws and regulations, which are subject to change, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites.
Environmental costs that relate to current operations are expensed or capitalized as appropriate. Costs are expensed when they relate to an existing condition caused by past operations and will not contribute to current or future revenue generation. Liabilities related to environmental assessments and/or remedial efforts are accrued when property or services are provided and when such costs can be reasonably estimated. The Company’s cost for these studies and assistance related to the Company’s properties for the year ended December 31, 2010, 2009 and 2008 were approximately $2.4 million, $1.2 million and $0.5 million, respectively.
Loss per Common Share
In accordance with provisions of ASC Topic 260, “Earnings per Share”, previously known as SFAS No. 128, “Earnings per Share”, basic earnings per share is computed on the basis of the weighted-average number of common shares outstanding during the periods. Diluted earnings per share is computed based upon the weighted-average number of common shares outstanding plus the assumed issuance of common shares for all potentially dilutive securities. Diluted earnings per share equals basic earnings per share for the periods presented because the effects of potentially dilutive securities are antidilutive.
Recent Accounting Pronouncements
In January 2010, the FASB issued Accounting Standards Update 2010-03, “Oil and Gas Reserve Estimation and Disclosures” (“ASU 2010-3”), to provide consistency with the December 2008 SEC rules regarding Oil and Gas Disclosures. ASU 2010-3 amends existing FASB standards to align the reserves calculation and disclosure requirements under U.S. GAAP with the requirements in the SEC rules. The Company adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate. See Supplemental Oil and Gas Information (Unaudited) for further information.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
In January 2010, the Company partially adopted the provisions of FASB ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” which amends ASC Topic 820 to require new disclosures concerning (1) transfers into and out of Levels 1 and 2 of the fair value measurement hierarchy, and (2) activity in Level 3 measurements. In addition, ASU No. 2010-06 clarifies certain existing disclosure requirements regarding the level of disaggregation and inputs and valuation techniques and makes conforming amendments to the guidance on employers’ disclosures about postretirement benefit plans assets. The requirements to disclose separately purchases, sales, issuances, and settlements in the Level 3 reconciliation are effective for fiscal years beginning after December 15, 2010 (and for interim periods within such years). The Company will apply the disclosure requirements relative to the Level 3 reconciliation in the first quarter of 2011. There was no impact on the Company’s financial position, results of operations or cash flows as a result of the partial adoption of ASU No. 2010-06. For further information, please see Note-11, “Fair Value Measurements and Disclosures”.
Note 2 - Value Added Tax Receivable
Value-added tax (referred to as “IGV” in Peru) is generally imposed on goods and services at a rate of 19%.
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 future oil sales under the normal IGV recovery process.
The Company’s current portion of value-added tax receivable as of December 31, 2010 and December 31, 2009 was $28.4 million and $26.2 million, respectively. For the year ended December 31, 2010, the Company accrued approximately $37.5 million for IGV related to expenditures reduced by approximately $32.4 million for IGV related to the sale of oil for the same period. In addition, the Company has approximately $3.0 million of value-added tax receivable as a long-term asset. See Note-4, “Prepaid and Other Current Assets and Other Non-Current Assets” for further information.
Note 3 - 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 balance of inventory at December 31, 2010 and December 31, 2009 was $19.0 million and $12.5 million, respectively.
Inventory associated with tubular goods, accessories and spare parts at December 31, 2010 and December 31, 2009 was $16.4 million and $10.5 million, respectively.
The Company maintains crude oil inventories in storage barges until the inventory quantities are at a sufficient level that the refinery in Talara will accept delivery. These inventories are also stated at the lower of average cost or market value. Cost is determined on a weighted average basis based on production costs. The crude oil inventory at December 31, 2010 consisted of approximately 49,836 barrels at an estimated cost of $2.6 million or $50.55 per barrel. The crude oil inventory at December 31, 2009 consisted of approximately 40,108 barrels at an estimated cost of $2.0 million or $50.55 per barrel.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Note 4 - Prepaid and Other Current Assets and Other Non-Current Assets
Below is a summary of other current assets as of December 31, 2010 and 2009:
Prepaid expenses and other are primarily related to prepayments for drilling services, equipment rental and material procurement. Deposits are primarily rent deposits in connection with the Company’s offices in Houston and Peru. Prepaid insurance consists of premiums related to the Company’s operations as well as general liability and directors and officer’s insurance policies. Insurance receivable is related to the barge incident which occurred in early August 2006. The Company incurred an operational delay of approximately three weeks, resulting from a navigation incident, which caused the BPZ-01 barge to be grounded on a sand bank in Talara Bay in northwest Peru during the second mobilization trip to the Corvina platform. As of December 31, 2010, the Company has an insurance receivable of approximately $0.7 million for the estimated insurance repair claims of $0.8 million expected to be filed with the insurance carrier. A deductible of $75,000 will be applied to this insurance claim when reimbursed. The dry docking of the vessel occurred during the first quarter of 2011. The Company expects to submit a claim to its insurance carrier and receive payment during the second quarter of 2011.
Below is a summary of other non-current assets as of December 31, 2010 and December 31, 2009:
Other non-current assets consist of (i) direct transaction costs incurred by the Company in connection with its debt capital raising efforts and (ii) claims related to an incident involving a small tanker that one of its marine transportation contractors was chartering from the Peruvian Navy’s commercial branch in 2008. As of December 31, 2010, the Company is currently seeking recovery of these amounts from the Peruvian Navy’s commercial branch. The Company expects to recover the majority of these amounts from either the Peruvian Navy or its insurance carrier. Due to the uncertainty in timing of resolving the claims, the Company has classified the amount as a non-current asset.
In connection with the $15.0 million International Finance Corporation (“IFC”) Reserve-Based Credit Facility, the Company incurred approximately $0.2 million of debt issue costs that are being amortized over the life of the loan agreement, due December 2012. In connection with the $170.9 million Convertible Notes due 2015, the Company incurred approximately $4.8 million of debt issue costs that are being amortized over the life of the indenture agreement, due March 2015. For the year ended December 31, 2010, the Company amortized into interest expense $0.8 million of debt issue costs. For the same periods in 2009 and 2008, the amortization of debt issue costs were not material. For further information regarding the Company’s debt, see Note-9, “Long-Term Debt and Capital Lease Obligations”.
During the year ended December 31, 2010, the Company reclassified $3.0 million of its value-added tax receivable balance to a long-term asset as it believes it will be longer than one year to receive the benefit of this portion of the value-added tax receivable.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
In January 2011, the Company repaid the amounts outstanding under the IFC Reserve-Based Credit Facility with the proceeds received under a new financing arrangement. Accordingly, the Company expensed the remaining $0.1 million portion of debt issue costs associated with the IFC Reserve-Based Credit Facility and recorded additional debt issue costs of approximately $1.6 million associated with the new financing arrangement. For further information regarding the Company’s debt, see Note-9, “Long-Term 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 December 31, 2010 and 2009:
During the year ended December 31, 2010 and 2009, the Company incurred capital expenditures of approximately $159.9 million and $96.6 million, respectively, associated with its development initiatives for the exploration and production of oil and natural gas reserves and the complementary development of proprietary gas-fired power generation of electricity for sale in Peru.
Of the costs mentioned above, during the year ended December 31, 2010, the Company incurred capital expenditures related to the drilling and testing of the CX11-23D, CX11-17D, CX11-20D, CX11-18D and CX11-22D wells in the Corvina field of approximately $14.0 million, $10.5 million, $0.8 million, $0.8 million and $20.0 million, respectively. In the Albacora field, the Company incurred capital expenditures related to the drilling of the A-15D, A-16D, A-17D and A-18D wells of approximately $8.5 million, $6.5 million, $17.8 million, and $0.1 million, respectively. On September 30, 2010, the costs of the A-17D well were written off as dry hole costs as well as the costs for two previously drilled wells, the A-15D and A-16D, as those wells were intended to follow the same trajectory and reach the same location as the A-17D well but neither reached the target due to mechanical problems and both wells were abandoned. Additionally, the Company incurred approximately $2.2 million in site preparation and staging costs for drilling of a new well in Block XIX.
For the year ended December 31, 2009, the Company incurred capital expenditures related to the drilling and testing of the CX11-15D, CX11-19D, CX11-17D and CX11-20XD wells in the Corvina field of approximately $23.5 million, $12.8 million, $3.0 million and $1.0 million, respectively. In the Albacora field, the Company incurred capital expenditures for the A-14XD well of approximately $20.6 in addition to $5.1 million in standby, installation and mobilization costs.
Approximately $92.9 million and $86.6 million were transferred from construction in progress to producing properties for the year ended December 31, 2010 and 2009, respectively.
For the year ended December 31, 2010, the Company incurred approximately $5.5 million for upgrades to its existing platforms as well as costs incurred in the design of new platforms. In addition, the Company incurred $16.4 million in equipment for its production facilities at the A platform in Albacora and the CX-11 platform in Corvina. The Company also incurred $7.3 million for the purchase of machinery and equipment used in operations in Peru and $3.9 million in additions to flowline and anchoring systems.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
During the year ended December 31, 2009, the Company incurred costs of approximately $7.9 million for the design and refurbishment of the Albacora A platform. In addition, the Company began installing permanent production and testing facilities on the Albacora platform and incurred an additional $1.9 million in cost for that project. In 2009, the Company also incurred costs for the purchase of machinery and equipment used in operations in Peru of approximately $2.9 million.
In 2009, the Company entered into a lease-purchase agreement to acquire the Don Fernando barge resulting in additional capital assets of approximately $7.2 million. During the year ended December 31, 2010, the Company capitalized an additional $4.0 million in order to fit the barge with equipment to support its operations.
During the year ended December 31, 2010, the Company incurred $41.7 million of costs as part of its agreement to purchase three LM6000 gas-fired packaged power units for the development of a Company owned gas-fired power generation facility. During the same period in 2009, the Company incurred $4.9 million of costs towards the purchase of the turbines.
For the year ended December 31, 2010, the Company wrote off approximately $12.1 million of property and equipment associated with its gas-to-power project and certain costs for the abandonment of two platforms. For further information regarding these write offs, see Note-14, “Other expense”.
For the year ended December 31, 2010 included in the amounts above, in accordance with the “successful efforts” method of accounting, the Company capitalized approximately $1.8 million of depreciation expense, mainly related to the tender assist barges serving as support equipment, and $9.6 million of interest expense, to construction in progress. For the same periods in 2009, the Company capitalized approximately $1.4 million of depreciation expense, mainly related to the tender assist barges serving as support equipment, and $4.4 million of interest expense to construction in progress.
Note 6 - Investment in Ecuador Property
The Company has a 10% net investment interest in an oil and gas property in Ecuador (the “Santa Elena Property”) totaling $1.0 million and $1.2 million as of December 31, 2010 and December 31, 2009, respectively. 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 license agreement which expires in May 2016. Investment income from the Company’s investment in Ecuador property was $0.7 million, $1.2 million and $0.7 million for each of the years ended December 31, 2010, 2009 and 2008, respectively. For the year ended December 31, 2010, 2009, and 2008, the Company received $0.9 million, $1.4 million and $0.9 million of cash, respectively, from its investment in Ecuador property and recorded amortization expense of $0.2 million in each of the three years.
Note 7 - Restricted Cash
As of December 31, 2010, the Company had restricted cash deposits of $5.8 million. In connection with the Company’s properties in Peru, it obtained four performance bonds totaling $5.3 million that are partially collateralized by restricted cash deposits of $3.1 million to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally, the Company has $2.0 million of restricted cash to collateralize insurance bonds for import duties related to the Don Fernando, the Company’s construction barge, and $0.6 million of restricted cash to insure certain performance obligations and commitments at the Company’s gas-to-power project site near Tumbes. In addition, the Company has an unsecured performance bond of $0.1 million to guarantee its performance under an office lease agreement in Peru.
At December 31, 2009, the Company had restricted cash deposits of $5.7 million. In connection with the Company’s properties in Peru, it obtained four performance bonds totaling $5.3 million that are partially collateralized by restricted cash deposits of $3.1 million to insure certain performance obligations and commitments under the license contracts for Blocks Z-1, XIX, XXII and XXIII. Additionally, the Company had $1.6 million of restricted cash to collateralize insurance bonds for import duties related to the BPZ-01 barge and crane on board the BPZ-01. The Company also had $1.0 million of restricted cash held in trust accounts in order to secure financing to support our operations. In January 2010, the $1.0 million of restricted cash held in a trust account was released in order to make the final payment on the Company’s short-term loan
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
agreement. Furthermore the Company had an unsecured performance bond of $0.1 million to guarantee its performance under its new office lease agreement in Peru.
All of the performance and insurance bonds are issued by Peruvian banks and their terms are governed by the corresponding license contracts, customs laws, legal requirements or rental practices.
Note 8 -Asset Retirement Obligation
An obligation was recorded for the future plug and abandonment of the producing oil wells in the Corvina and Albacora fields, in accordance with the provisions of ASC Topic 410, “Asset Retirement and Environmental Obligations”. ASC 410-20 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred and becomes determinable. Under this method, when liabilities for dismantlement and abandonment costs, excluding salvage values, are initially recorded, the carrying amount of the related oil and natural gas properties is increased. The fair value of the ARO asset and liability is measured using expected future cash outflows discounted at the Company’s credit-adjusted risk-free interest rate. Accretion of the liability is recognized each period using the interest method of allocation, and the capitalized cost is depleted using the units of production method. Should either the estimated life or the estimated abandonment costs of a property change materially upon the Company’s periodic review, a new calculation is performed using the same methodology of taking the abandonment cost and inflating it forward to its abandonment date and then discounting it back to the present using the Company’s credit-adjusted-risk-free rate. The carrying value of the asset retirement obligation 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 December 31, 2010 and December 31, 2009 is as follows:
The 2010 and 2009 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 both in 2010 and 2009, 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 and $0.2 million, respectively, in accordance with ASC Topic 410.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Note 9 - Long-Term Debt and Capital Lease Obligations
At December 31, 2010 and 2009, long-term debt and capital lease obligations consist of the following:
The following is a summary of scheduled long-term debt and other debt maturities by year (in thousands):
The following is a summary of scheduled minimum lease payments under capital lease obligations by year (in thousands):
$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 (“$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. The arranger fee is based on a percentage of the
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
principal amount and the performance of the price of crude oil (Brent) from closing date to repayment date. The performance portion of the arranger fee is subject to a specified maximum amount.
The $40.0 million secured debt facility is secured, in part, by three LM6000 gas-fired packaged power units that were purchased by The Company from GE, through its power generation subsidiary, Empresa Eléctrica Nueva Esperanza S.R.L. The $40.0 million secured debt financing is also secured by certain other equipment and property pledged in favor of Credit Suisse and Credit Suisse International.
The $40.0 million secured debt facility required the Company to establish a $2.0 million reserve fund during the first 18 months the debt facility is outstanding. After the first 18 month period, The Company is required to keep a balance in the reserve fund equal to the aggregate amount of payments of principal and interest on the $40.0 million secured debt facility due immediately on the succeeding principal repayment date.
The $40.0 million secured debt facility matures on July 27, 2013, with principal repayment due in equal quarterly installments of $8.0 million commencing on July 27, 2012. The $40.0 million secured debt facility bears interest at three month LIBOR plus 7.0%. Interest is due and payable every three month period after the commencement of the loan.
The $40.0 million secured debt facility provides for events of default and cure periods customary for facilities of this type, including, among other things, payment breaches under any of the finance documents; representation and warranty breaches; any default, early amortization event or similar event occurring with respect to one or more debt facilities in an aggregate outstanding principal amount of at least $3,000,000, if the effect is to accelerate the maturity thereof; failure to comply with obligations; application for the appointment of a receiver; making a general assignment for the benefit of creditors; insolvencies or filing of bankruptcy; certain monetary and non-monetary judgments, orders, decrees or awards against the Company or its subsidiaries; suspension, revocation or termination of any $40.0 million secured debt facility financing or security documents with Credit Suisse or certain key agreements; and change in control. In addition, the $40.0 million secured debt facility provides for a mandatory prepayment of the loans if debt to finance the Company’s gas-to-power project is obtained.
If an event of default occurs, Credit Suisse shall, upon the request of the majority lenders, or may, by notice to the Company, (i) immediately terminate the lending commitments; and/or (ii) declare all or part of the principal amount of the loans, together with accrued interest, immediately due and payable, without demand; provided that, all lending commitments shall automatically terminate and all amounts due and payable on any loan will automatically become immediately due and payable without notice if the Company or any subsidiary appoints a receiver, liquidator or trustee, make a general assignment for the benefit of their creditors, become insolvent, bankrupt, liquidate, or are subject to certain monetary judgments exceeding in the aggregate, $3,000,000; and/or (iii) liquidate the security collateral and apply the proceeds thereof to pay the loans.
In January 2011, the Company received the $40.0 million in proceeds and recorded approximately $1.6 million of fees and commissions associated with the $40.0 million secured debt facility as debt issue costs that will be amortized over time using the interest method as interest expense. The Company also established a $2.0 million debt service reserve fund.
Proceeds from the $40.0 million secured debt facility will be utilized to meet the Company’s 2011 capital expenditure budget, to finance its exploration and development work programs, and to reduce its existing debt.
With respect to the performance based arrangement fee, the fee is payable at each of the principle repayment dates. The formula for calculating fees includes an amount multiplied by the change in oil prices from the date of commencement of the loan and the price at each principle repayment date. Additionally, the performance based arranger fee contains a maximum amount to be paid by the Company over the term of the loan. The Company believes the performance based arranger fee may qualify as an embedded financing derivative under ASC Topic 815, “Derivatives and Hedging”. This would require the Company to record the fair value of the derivative liability at inception and to revalue the liability at each financial reporting date throughout the term of the loan. The Company is currently assessing the impact of the expected liability and expects to record the initial liability as additional interest expense for the performance based arranger fee.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
The Company estimates the cash payments related to the $40.0 million secured debt facility, including potential payments for the performance based arranger fee and interest, for the year ended December 31, 2011, 2012, and 2013 to be approximately $2.3 million, $19.0 million and $25.1 million, respectively.
$170.9 Million Convertible Notes due 2015
In February and March 2010, the Company closed on a private offering of an aggregate of $170.9 million convertible notes due 2015 (the “2015 Convertible Notes”). The 2015 Convertible Notes offering was comprised of (i) the initial $140.0 million of 2015 Convertible Notes sold in an initial private offering, (ii) the exercise by the initial purchaser of a 30- day option to purchase an additional $21.0 million of 2015 Convertible Notes, and (iii) IFC’s election, pursuant to a contractual right, to participate in the offering for an additional $9.9 million of 2015 Convertible Notes, bringing the total proceeds of the private offering to $170.9 million. The 2015 Convertible Notes were sold to an initial purchaser who then sold the notes to qualified institutional buyers pursuant to Rule 144A of the Securities Act of 1933. The $170.9 million of 2015 Convertible Notes were issued pursuant to an indenture dated February 8, 2010, between the Company and Wells Fargo Bank, National Association, as trustee (“the Indenture”).
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 subordinated 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 Company will pay interest on the 2015 Convertible Notes at a rate of 6.50% per year on March 1 and September 1 of each year, beginning on September 1, 2010. The 2015 Convertible Notes mature on March 1, 2015. The initial conversion rate was 148.3856 shares per $1,000 principal amount of the 2015 Convertible Notes (equal to an initial conversion price of approximately $6.74 per share of common stock), subject to adjustment. 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 (but not to exceed 19.99% of the Company’s outstanding shares at the time of such delivery), (2) cash, or (3) a combination of cash and shares of its common stock.
The initial conversion rate was adjusted on February 3, 2011 as the daily Volume Weighted Average Price (“Average VWAP”) of the Company’s common stock for each of the 30 trading days ending on February 3, 2011 was less than $5.6160 per share. The arithmetic average of the Average VWAP per share of Common Stock for each of the thirty (30) consecutive Trading Days ending on February 3, 2011 was $4.9307. Since the Average VWAP is less than $5.6160 per share, the conversion rate increased such that the conversion price, as increased, represents the greater of (1) 120% of the Average VWAP and (2) $5.6160. Accordingly, the conversion rate and conversion price changed to 169.0082 and $5.9169, respectively. In addition, following the occurrence of any one of certain corporate transactions that constitutes a fundamental change (as defined in the Indenture), the Company will increase the conversion rate, subject to certain limitations, for a holder who elects to convert the 2015 Convertible Notes in connection with such corporate transactions during the 30-day period after the effective date of such fundamental change.
Holders may convert their 2015 Convertible Notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances:
(1) during any fiscal quarter (and only during such fiscal quarter) commencing after March 31, 2010, if the last reported sale price of the Company’s common stock is greater than or equal to 130% of the conversion price of the 2015 Convertible Notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter;
(2) prior to January 1, 2015, during the five business-day period after any ten consecutive trading-day period in which the trading price of $1,000 principal amount of the 2015 Convertible Notes for each trading day in the measurement period was less than 97% of the product of the last reported sale price of the Company’s common stock and the conversion rate on such trading day;
(3) if the 2015 Convertible Notes have been called for redemption; or
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
(4) upon the occurrence of one of specified corporate transactions.
Holders may also convert the 2015 Convertible Notes at their option at any time beginning on February 1, 2015, and ending at the close of business on the second business day immediately preceding the maturity date.
On or after February 3, 2013, the Company may redeem for cash all or a portion of the 2015 Convertible Notes at a redemption price of 100% of the principal amount of the notes to be redeemed plus any accrued and unpaid interest to, but not including, the redemption date, plus a “make-whole” payment if: (1) for at least 20 trading days in any consecutive 30 trading days ending within 5 trading days immediately before the date the Company mails the redemption notice, the “last reported sale price” of its common stock exceeded 175% of the conversion price in effect on that trading day, and (2) there is no continuing default with respect to the notes that has not been cured or waived on or before the redemption date.
If the Company experiences any one of the certain specified types of corporate transactions, holders may require the Company to purchase all or a portion of their 2015 Convertible Notes. Any repurchase of the notes pursuant to these provisions will be for cash at a price equal to 100% of the principal amount of the notes to be purchased plus any accrued and unpaid interest to, but excluding, the purchase date.
The Indenture contains customary terms and covenants and events of default. If an event of default (as defined therein) occurs and is continuing, the Trustee by notice to the Company, or the holders of at least 25% in aggregate principal amount of the 2015 Convertible Notes then outstanding by notice to the Company and the Trustee, may declare the principal of and accrued and unpaid interest (including additional interest or premium, if any) on the 2015 Convertible Notes to be due and payable. In the case of an event of default arising out of certain bankruptcy events (as set forth in the Indenture), the principal of and accrued and unpaid interest (including additional interest or premium, if any) on the notes will automatically become due and payable.
Net proceeds from the sale of the 2015 Convertible Notes, after deducting the discounts and commissions and any offering expenses payable by the Company, were approximately $164.9 million. The initial purchaser received commissions of approximately $5.5 million in connection with the sale of the 2015 Convertible Notes 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 is accounting for the 2015 Convertible Notes in accordance with FASB Staff Position (“FSP”) No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)” which is codified under ASC Topic 470, “Debt”. Under the accounting guidance, convertible debt instruments that may be settled entirely or partially in cash upon conversion will be required to separately account for the liability and equity components of the instrument 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.
The Company estimated its non-convertible borrowing rate at the date of issuance of its 2015 Convertible Notes to be 12%. The 12% non-convertible borrowing rate represents 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 will be amortized as non-cash interest expense into income over the life of the notes using the interest method. In addition, the Company recorded approximately $4.8 million of the $6.1 million of fees and commissions as debt issue costs that will be amortized over time using the interest method as interest expense. The remaining $1.3 million of fees and commissions is treated as an original issue discount against the value of the equity component. The Company estimates the cash payments including interest payments related to the 2015 Convertible
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Notes, assuming no conversion, for the year ended December 31, 2011, 2012, 2013, 2014 and 2015 to be approximately $11.1 million, $11.1 million, $11.1 million, $11.1 million and $176.5 million, respectively. The Company evaluated the 2015 Convertible Notes agreement for potential embedded derivatives, noting that the conversion feature and make-whole provisions were determined not to 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 December 31, 2010, the net amount of $140.8 million includes the $170.9 million of principal reduced by $30.1 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 $30.1 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 December 31, 2010, using the conversion rate of 148.3856 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 25,364,737 shares of common stock. At February 3, 2011, using the new 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 28,889,927 shares of common stock. In accordance with NYSE rules, the Company received shareholder approval to issue shares in excess of 19.99% of shares outstanding at the time of the offering (23,031,663 shares) should it need to issue shares in order to satisfy its obligation under the 2015 Convertible Notes. As of December 31, 2010, 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 December 31, 2010, $4.76 per share, is less than the conversion price.
For the year ended December 31, 2010, the effective interest rate for the 2015 Convertible Notes is 12%; including the amortization of debt issue costs, the effective interest rate is 12.6%.
The amount of interest expense related to the 2015 Convertible Notes for the year ended December 31, 2010 is $15.3 million, disregarding capitalized interest considerations, and includes $10.1 million of interest expense related to the contractual interest coupon, $4.5 million of non-cash interest expense related to the amortization of the discount and $0.7 million of interest expense related to the amortization of debt issue costs.
$15.0 Million IFC Reserve-Based Credit Facility
The Company had a $15.0 million reserve-based lending facility (“IFC Facility”) agreement (the “Loan Agreement”) with IFC through its subsidiaries BPZ E&P and BPZ Marine Peru S.R.L. as borrowers. The reserve-based lending facility had $12.5 million outstanding maturing in December 2012; however, following the $40.0 million secured debt facility entered into by the Company in January 2011, a portion of the proceeds was used to repay the amount outstanding to IFC. Because the Company refinanced the obligation on a long-term basis, $5.0 million of the $12.5 million that was originally expected to be paid within a year as of December 31, 2010 is being classified as a long-term liability, in accordance with Accounting Standard Codification (“ASC”) Topic 470, “Debt”, as the Company refinanced the obligation on a long-term basis.
The reserve-based lending facility had interest at an approximate rate of LIBOR plus 2.75%, equivalent to 3.21% based on the six-month LIBOR rate of 0.46% at December 31, 2010. The maximum amount available under this facility began at $15.0 million and was to be reduced by $2.5 million beginning on December 16, 2010 and every six months thereafter during the term of the Loan Agreement. The amount available under the Loan Agreement was subject to a semi-annual borrowing base determination based on the value of oil reserves. In addition, the Company was subject to various financial covenants calculated as of the last day of each quarter, including a life of field coverage ratio, life of loan coverage ratio, debt to equity ratio and interest coverage ratio. The Loan Agreement also provided for events of default, cure periods and lender remedies customary for agreements of this type. The Company was in compliance with all material covenants of the Loan Agreement as of December 31, 2010.
Other
In July 2009, the Company, through its subsidiary, BPZ E&P, entered into a $5.1 million short-term loan agreement to finance the purchase of casing and accessories for use in its current and future operations. The $5.1 million short-term loan bore an annual interest rate of 5.45% and was repaid in five monthly installments of approximately $1.0 million starting
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
September 2009. In connection with the $5.1 million short-term loan agreement, the Company was required to deposit $1.0 million with the lending institution as a guaranty for the loan. The $1.0 million was applied to the last installment of the loan repayments. As of December 31, 2009, the remaining principal amount was approximately $1.0 million and, along with the accrued interest due, was repaid with the $1.0 million deposit and cash in January 2010.
Note Payable
In January 2009, in exchange for receipt of $1.0 million from an individual (“Note Holder”), the Company signed a promissory note (the “Note”). The Note originally provided for maturity in July 2009 and bore an annual interest rate of 12.0%. However, in March 2009 the Company repaid the principal amount and accrued interest in full to the Note Holder.
Capital Leases
In November 2009, the Company entered into a capital lease agreement for a construction barge, the Don Fernando, to assist it in its offshore construction projects. The capital lease asset and corresponding liability was recorded at $7.0 million, which represents the present value of the minimum lease payments, or the aggregate fair market value of the assets. At the end of the two year lease the title to the barge transfers to the Company. The Company accounted for the lease agreement in accordance with ASC Topic 840, “Leases”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement is accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 22.4%.
In June 2007, the Company entered into a capital lease agreement, with an option to purchase two barges, the Namoku and the Nu’uanu,, to assist in the development of the Corvina oil. The capital lease assets were recorded at $6.2 million, which represented the present value of the minimum lease payments, or the aggregate fair market value of the assets.
In May 2009, the Company entered into an amendment of its lease agreement for two barges currently under charter, the Namoku and the Nu’uanu. Under the terms of the amended lease agreement, the current charter, originally set to expire in November 2009, was extended for five years commencing on May 1, 2009. During the first 18 months of the amended lease term, the daily charter rate for the use of both barges is fixed. Commencing in November 2010, the daily charter rate for the use of both vessels is based on a tiered structure with the daily rate dependent upon the amount of the previous month’s average daily per barrel price of West Texas Intermediate Crude Oil (“WTI”), as indicated on the New York Mercantile Exchange. Any amount paid by the Company after November 2010 over the initial daily rate as a result of the escalated tiered structure based on the price of WTI is considered contingent rental payments. The amount of the contingent lease payments paid in 2010 was $0.2 million. The amended lease agreement contains a $3.0 million purchase option after the third year of the lease, a $2.0 million purchase option after the fourth year of the lease and a mandatory $1.0 million purchase obligation by the Company after the fifth year of the lease. The Company accounted for the amended lease agreement in accordance with ASC Topic 840, “Leases”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement continues to be accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 34.9%.
In June 2008, the Company entered into a two year capital lease agreement to acquire the production equipment used on board the Namoku resulting in additional capital assets of approximately $2.4 million. Further, the Company capitalized an additional $2.8 million of production equipment in order to have the floating production, storage and offloading (“FPSO”) ready to receive and treat oil received from the CX-11 platform. The FPSO lease contains two bargain purchase options; therefore, depreciation of the leased asset was over its useful life. The lease contains a bargain purchase option of $1.0 million at the end of the first year of the lease and a $0.5 million bargain purchase option at the end of the second year of the lease. The Company accounted for the lease agreement in accordance with ASC Topic 840, “Leases”, previously accounted for under SFAS No. 13, “Accounting for Leases (As Amended)”. Under the guidance, the lease agreement is accounted for as a capital lease and the imputed interest rate necessary to reduce the net minimum lease payments to present value over the lease term is 28.3%. In July 2010, the Company exercised the second year purchase option and purchased the capital lease production equipment used on board the Company’s FPSO, the Namoku.
In March 2008, the Company entered into a lease-purchase agreement to acquire the BPZ-02 barge resulting in additional capital assets of approximately $7.0 million. In February 2009, the Company made the final lease payment on the BPZ-02 deck barge at which point title to the barge was transferred to it.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
In 2007, the Company entered into two capital loans for the purchase of office furniture. Both loans have a term of 60 months, bearing interest at 5.94% and 9.44%, respectively, with principal and interest payments due on a monthly basis. During the fourth quarter of 2010, the Company made the final payments on the lease agreements and title of the office furniture was transferred to it.
Note 10 - 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.
September 2009 Private Placement of Common Stock
On September 15, 2009, the Company closed a private placement of approximately 1.6 million shares of common stock, no par value, to IFC pursuant to a Subscription Agreement dated September 15, 2009. This private placement was related to the Company’s registered direct offering of approximately 18.8 million shares of common stock at a price of $4.66 per share that closed on June 30, 2009. Pursuant to the Subscription Agreement dated December 16, 2006 (the “Subscription Agreement”) by and between IFC and the Company, IFC has the right, within 45 days of notice of an offering, to purchase shares of the Company’s common stock for the same price and terms as the participants in the offering to retain its proportionate ownership in the Company. IFC exercised its pre-emptive right to purchase approximately 1.6 million shares of common stock to which it was entitled under the Subscription Agreement at the offering price of $4.66 per share, resulting in gross proceeds to the Company of approximately $7.6 million. In compliance with NYSE requirements, the transaction was submitted to and approved by the shareholders of the Company at a Special Meeting of Shareholders on August 24, 2009. No warrants or dilutive securities were issued to IFC in connection with the private placement. The shares were placed directly by the Company. The Company used the proceeds of this offering to develop its properties under its existing license contracts and other general corporate purposes consistent with the Company’s operating plans.
Under the September 15, 2009 Subscription Agreement, the Company committed to file a registration statement with the Securities and Exchange Commission (“SEC”) covering the shares no later than 45 days after the closing with respect to such shares. On October 21, 2009, the Company filed a registration statement with the SEC covering the shares. In May 2010, the Company filed an amended registration statement with the SEC and the amended registration statement was declared effective during the month. There were no penalty payments associated with the delay in obtaining effectiveness of the registration statement.
June 2009 Registered Direct Offering of Common Stock
On June 30, 2009, the Company closed its sale of approximately 18.8 million shares of its common stock, no par value, in a registered direct offering under an effective shelf registration statement. The shares of common stock were priced at $4.66 per share resulting in net proceeds to the Company, after placement agent fees and other fees, of approximately $82.9 million. In connection with the registered direct offering, the Company entered into a placement agency agreement with Canaccord Adams Inc. as lead placement agent for the offering along with Pritchard Capital Partners, LLC, and Raymond James and Associates, Inc. In addition, Rodman & Renshaw, LLC, and Wunderlich Securities, Inc. assisted as agents in the transaction. The Company paid approximately $4.4 million as a 5% placement agency fee of the gross proceeds received by the Company in accordance with the terms of the placement agency agreement. The Company used the proceeds of this offering to develop its properties under its existing license contracts and other general corporate purposes consistent with the Company’s operating plans.
February 2009 Private Placement of Common Stock
On February 23, 2009, the Company closed a private placement of approximately 14.3 million shares of common stock, no par value, to institutional and accredited investors pursuant to a Stock Purchase Agreement dated February 19, 2009. Additionally, in March 2009, IFC exercised its pre-emptive right to elect to participate in the private placement offering resulting in an additional 1.4 million shares of common stock which brought the total to approximately 15.7 million shares of common stock sold in the private placement offering. The common stock was priced at $3.05 per share resulting in net proceeds to the Company, after placement agent and financial advisory fees, of approximately $45.2 million. No warrants
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
or dilutive securities were issued in connection with the private placement. A financial advisory fee of $0.7 million was paid to Morgan Keegan and Company, Inc. for investment services and consulting related to the offering. Additionally, a private placement fee of $2.2 million was paid to Pritchard Capital Partners, LLC for placement services related to the offering. The Company used the proceeds of this offering to develop its properties under its existing license contracts and other general corporate purposes consistent with the Company’s operating plans.
Under the Stock Purchase Agreement, the Company committed to file a registration statement with the SEC and obtain the registration statement’s effectiveness within the time-frames outlined in the Stock Purchase Agreement. On April 27, 2009, the Company obtained effectiveness of the registration statement related to the Stock Purchase Agreement in compliance with such time-frames.
Potentially Dilutive Securities
In addition to the shares issued and outstanding, the Company had the following potentially dilutive securities at December 31, 2010, 2009 and 2008. None of these potentially dilutive shares have been included in the calculation of earnings per share as the effect would be antidilutive.
(a)
In February 2011, the initial conversion rate was adjusted and if the $170.9 million of principal related to the 2015 Convertible Notes were converted into shares of common stock, the notes would convert into 28,889,927 shares of common stock
The following table summarizes stock-based compensation costs recognized under ASC Topic 718, “Stock Compensation”, previously recognized under SFAS 123(R), for the year ended December 31, 2010, 2009, and 2008, respectively, and is generally included in “General and administrative expense” on the Consolidated Statements of Operations :
(a)
For the year ended December 31, 2008, additional compensation expense of $0.7 million was recognized for the year related to accelerated vesting for certain stock option awards.
(b)
For the year ended December 31, 2009, additional stock-based compensation of approximately $0.7 million was recognized related to the accelerated vesting for certain restricted stock and stock option awards granted to a former member of the Board of Directors.
(c)
For the year ended December 31, 2009 approximately $0.4 million of stock-based compensation is included in “Other income (expense)” on the Consolidated Statements of Operations. The amount relates to 100,000 stock options awarded to a former member of the Board of Directors to purchase the Company’s common stock. The grant date fair value of the award was recognized upon issuance of the award.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
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 Directors’ Plan provides 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 the 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 December 31, 2010, approximately 3.5 million shares remain available for future grants under the 2007 LTIP and 1.1 million shares remain available for future grants under the Directors’ Plan.
Restricted Stock Awards and Performance Shares
At December 31, 2010, there were approximately 448,790 shares of restricted stock awards outstanding to officers, directors and employees all of which generally vest with the passage of time on the second or third anniversary of the date of grant. Restricted stock is subject to certain restrictions on ownership and transferability when granted. The fair value of restricted stock awards is based on the market price of the Common Stock on the date of grant. Compensation cost for such awards is recognized ratably over the vesting or service period, net of forfeitures; however, compensation cost related to performance shares will not be recorded or will be reversed if the Company does not believe it is probable that such performance criteria will be met or if the service provider (employee or otherwise) fails to meet such criteria.
A summary of the Company’s restricted stock award activity for the year ended December 31, 2010 and related information is presented below:
The weighted average grant-date fair value of restricted stock awards granted for the year ended December 31, 2009 was $5.33. There were no restricted stock awards granted in 2008. The fair value of restricted stock awards that vested during the year ended December 31, 2010, 2009 and 2008 was $4.9 million, $1.6 million, and $6.7 million, respectively. As of December 31, 2010, there was $1.2 million of total unrecognized compensation cost related to non-vested restricted stock awards, which is expected to be recognized over a weighted-average period of 1.3 years.
Stock Options
Incentive and non-qualified stock options issued to directors, officers, employees and consultants are typically granted at the fair market value on the date of grant. The Company’s stock options generally vest in equal annual installments over a two to three year period and expire ten years from the date of grant.
The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options, which have no vesting restrictions and are fully transferable and negotiable in a free trading market. This model does not consider the employment, transfer or vesting restrictions that are inherent in the Company’s stock options.
Use of an option valuation model includes highly subjective assumptions based on long-term predictions, including the expected stock price volatility and expected option term of each stock option grant.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
The following table presents the weighted-average assumptions used in the option pricing model for options granted during the year ended December 31,:
(a)
The expected life was derived based on a weighting between (a) the Company’s historical exercise and forfeiture activity and (b) the average midpoint between vesting and the contractual term and (c) from the analysis of other companies of a similar size and operational life cycle.
(b)
The volatility is based on the historical volatility of our stock for a period approximating the expected life.
(c)
The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted.
(d)
The dividend yield is based on the fact the Company does not anticipate paying any dividends.
A summary of the Company’s stock option activity for the year ended December 31, 2010 and related information is presented below:
As of December 31, 2010, there was $2.5 million of unrecognized compensation cost related to non-vested stock options that is expected to be recognized over a weighted average period of 1.1 years. The total intrinsic value of stock options (defined as the amount by which the market price of the Common Stock on the date of exercise exceeds the exercise price of the stock option) exercised during the year ended December 31, 2009, and 2008 was $0.7 million and $16.0 million, respectively. There were no stock options exercised during the year ended December 31, 2010. Cash received from stock option exercises for the year ended December 31, 2009 and 2008 was $0.6 million and $2.4 million, respectively.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
The following table summarizes information about stock options outstanding as of December 31, 2010:
Note 11- 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
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 heirarchy.
Non-Financial Assets and Liabilities
The Company discloses or recognizes its non-financial assets and liabilities, such as asset retirement obligations and impairments of long-lived assets, at fair value on a non-recurring basis. See Note-8, “Asset Retirement Obligation” for further information. As none of the Company’s non-financial assets and liabilities were impaired as of December 31, 2010 and December 31, 2009, and no other fair value measurements were required to be recognized on a non-recurring basis, additional disclosures were not provided. However, the Company did write off certain assets related to its gas-to-power project and certain platforms during the year ended December 31, 2010. For further information on these write offs, see Note 14, “Other Expense”.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Additional Fair Value Disclosures
$15.0 Million IFC Reserve-Based Credit Facility
The fair value of the Company’s IFC Facility at December 31, 2010 and December 31, 2009 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 can currently borrow under similar terms.
$170.9 Million Convertible Notes due 2015
The fair value information regarding the Company’s fixed rate debt is as follows:
(1) Excludes obligations under capital lease arrangements and variable rate debt
(2) The Company estimated the fair value of the $170.9 million 2015 Convertible Notes to be approximately $176.5 million based on observed market prices for the same or similar type issues.
Note 12 - Affiliate and Related Party Transactions
For the year ended December 31, 2010, 2009 and 2008, the Company had not entered into any transactions with affiliates or related parties.
Note 13 - Revenue
At December 31, 2010, the Company has developed nine wells in the Corvina field and one well in the Albacora field. Of these wells, seven were producing oil at December 31, 2010 with the remaining wells being shut-in. Additionally, in late-January 2011, the A-14XD well in the Albacora field was shut-in as the Company’s extended well testing and gas flaring permits had expired. At December 31, 2009, the Company was producing oil from five wells in the Corvina field and one well in the Albacora field under a well testing program.
The Company began producing oil on a limited basis in November 2007 from the CX11-21XD and CX11-14D wells in the Corvina field under a well testing program. During the second and fourth quarter of 2008, it added production from the CX11-18XD and CX20-20XD wells, respectively, under the well testing program. In 2009, the Company added the CX-15D during the second quarter and the CX11-19D well in the Corvina field and the A-14XD well in the Albacora field during the fourth quarter to its well testing program. In 2010, the Company added the CX11-17D during the first quarter, the CX11-22D during the third quarter and the CX11-23D the well during the fourth quarter to its well testing program. Additionally on November 30, 2010, the Company transitioned the Corvina field from extended well testing into commercial production.
The oil is delivered by barge to the refinery owned by Petroleos del Peru - PETROPERU S.A. (“Petroperu”), a private law state company engaged in the refining, transportation, distribution and trading of petroleum products to meet Peru’s domestic energy needs, in Talara, located approximately 70 miles south of the platform. Produced oil is kept in production inventory until the Company increases the inventory quantities to a sufficient level that the refinery in Talara will accept delivery. Although all of the Company’s oil sales are to Petroperu, it believes that the loss of Petroperu as its sole
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
customer would not materially impact the Company’s business, because it could readily find other purchasers for the Company’s oil production both in Peru and internationally.
In January 2009, the Company, through its wholly-owned subsidiary BPZ E&P, entered into a long-term oil supply agreement with Petroperu. Under the terms of the contract, the Company agrees to sell, and Petroperu agrees to purchase the Company’s crude oil production originating from the Corvina oilfield in Block Z-1. The contract term is for approximately seven years or until 17 million barrels of crude oil has been delivered to the Petroperu refinery located in Talara, whichever comes first. The price per barrel of oil under the agreement is determined using a basket of crude oils based on a 15-day average of Forties, Oman, and Suez blend crude oil prices, as quoted in the Spot Crude Prices Assessment published in Platt’s Crude Oilgram Price Report, minus $1 per barrel and other customary purchase price adjustments. The Company has approximately 14.9 MMBbls remaining under the contract.
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 agrees to sell, and Petroperu agrees 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 has approximately 203 MBbls remaining under the contract.
In July 2010, through its wholly-owned subsidiary BPZ E&P, the Company entered into a second short-term 110 MBbls 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 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 $4.30 per barrel and other customary purchase price adjustments. As part of the purchase price adjustments, the Company is allowed to sell oil under the contract as long as the salt content is less than 60 pounds per thousand barrels of oil. There is an incremental purchase price adjustment associated with the oil sales if the salt content is between 25 pounds and 60 pounds per thousand barrels. All 110 MBbls under this supply agreement were delivered and sold to Petroperu during the month of July 2010.
In September 2010, through its wholly-owned subsidiary BPZ E&P, the Company entered into a third short-term 80 MBbls 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 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 $4.30 per barrel and other customary purchase price adjustments. As part of the purchase price adjustments, the Company is allowed to sell oil under the contract as long as the salt content is less than 60 pounds per thousand barrels of oil. There is an incremental purchase price adjustment associated with the oil sales if the salt content is between 25 pounds and 60 pounds per thousand barrels. Approximately 50 MBbls under this supply agreement were delivered and sold to Petroperu during the month of September 2010 and the remaining 30 MBbls was delivered during October 2010.
During the year ended December 31, 2010, 2009 and 2008, the Company produced approximately 1,527 MBbls, 991 MBbls and 827 MBbls of oil, respectively. For the year ended December 31, 2010, 2009 and 2008, the Company sold 1,517 MBbls, 963 MBbls and 826 MBbls barrels of oil at an average per barrel price, net of royalties, of approximately $72.53, $54.49 and $76.23, respectively.
The Company’s revenues are reported net of royalties owed to the government of Peru. Royalties are assessed by Perupetro S.A. (“Perupetro”), a corporation owned by the Peruvian government empowered to become a party in the contracts for the exploration and/or exploitation of hydrocarbons in order to promote these activities in Peru, as stipulated in the Block Z-1 license agreement based on production. However, their calculation is based on the past five-day average basket of crude oils prices, as discussed above, before the crude oil delivery date. For the year ended December 31, 2010, 2009 and
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
2008, the revenues received by the Company are net of royalty costs of approximately 5% of gross revenues or $6.3 million, $2.9 million and $3.3 million, respectively.
Note 14- Other Expense
For the year ended December 31, 2010, the Company is reporting $12.9 million of charges in the Consolidated Statements of Operations as “Other expense”. These charges include $10.7 million of charges related to certain engineering, consulting, environmental and legal costs for the Company’s planned gas plant, pipeline and gas-to-power project and $2.2 million of charges related to the abandonment of two platforms. With respect to the $10.7 million of charges related to the planned gas plant, pipeline and gas-to-power project, during the third quarter of 2010, management determined that there is no future benefit of these engineering and development costs associated with the Company’s current gas plant, pipeline and gas-to-power project plans. Accordingly, the Company wrote off these costs. With respect to the $2.2 million of platform abandonment costs, the Company has determined that two previously built platforms, one located in the Piedra Redonda field and the CX-13 platform located in the eastern part of the Corvina field, both of which were in existence when the Company acquired the rights to the offshore Block Z-1 in northwest Peru, are not suitable for the Company’s future oil development plans. Accordingly, the Company wrote off the $1.4 million of costs incurred to evaluate the feasibility of refurbishing and using these platforms. In addition, the Company is accruing $0.8 million of abandonment costs related to the platform in the Piedra Redonda field as it is obligated to ensure the platform does not cause a threat to marine vessels operating in the area or marine wildlife. There were no similar expenses incurred by the Company in 2009 or 2008.
Note 15- Standby Costs
After completing the CX11-23D well in the Corvina field and the A-17D well in the Albacora field at the end of the third quarter of 2010, the Company suspended drilling operations until it completes a seismic data acquisition program. During the drilling downtime, the Company plans to move forward to fabricate and install permanent production and injection facilities on the Albacora platform. This should allow for continued production testing from the field once drilling operations resume by avoiding gas flaring and associated permitting issues. Once drilling operations resume, the Company expects standby costs to be capitalized as part of drilling costs for the new wells drilled.
As a result, the Company incurred and is reporting $7.5 million in standby costs that include $4.9 million of standby rig costs, $0.8 million of standby vessel expenses, $1.2 million of salary and salary related expenses associated with drilling operations, and $0.6 million of fuel and other expenses. There were no similar expenses incurred by the Company in 2009 or 2008.
Note 16 - Income Taxes
The source of net loss before income tax expense (benefit) for the year ended December 31, is as follows (in thousands):
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
The income tax provision (benefit) for the year ended December 31, consists of the following (in thousands)
The income tax expense (benefit) for the year ended December 31, 2010, 2009 and 2008 differs from the amount computed by applying the U.S. statutory federal income tax rate for the applicable year to consolidated net loss before income taxes as follows (in thousands):
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
A summary of the components of deferred tax assets, deferred tax liabilities and other taxes deferred at December 31, 2010 and 2009 are presented below (in thousands):
Net deferred tax assets in the foregoing table include the deferred consequences of the future reversal of Peruvian deferred tax assets and liabilities on the impact of the Peruvian employee profit share plan tax of $4.3 million in 2010 and $3.3 million in 2009. As of December 31, 2010 and 2009, the Company had a valuation allowance for the full amount of the domestic deferred tax asset resulting from the income tax benefit generated from net losses, 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 2030. Furthermore, because the Company has no operations within the U.S. taxing jurisdiction, it is likely that a sufficient generation of revenue to offset the Company’s deferred tax asset is remote. As a result, the Company has a full allowance on its deferred tax asset generated in the U.S. However, the Company is subject to Peruvian income tax on its earnings at a statutory rate, as defined in the Block Z-1 License Contract, of 22%. The tax provision is based on taxable Peruvian income that excludes certain U.S. expenses that are not deductible at the Peruvian level. As a result, the Company recognized a total tax provision for the year ended December 31, 2010 of approximately $11.6 million. No provision for U.S. federal and state income taxes have been made for the difference in the book and tax basis of the Company’s investment in foreign subsidiaries as such amounts are considered permanently invested. Distribution of earnings, as dividends or otherwise, from such investments could result in U.S. federal taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable in various foreign countries. Due to the Company’s significant net operating loss carryforward position the Company has not recognized any excess tax benefit related to its stock compensation plans. ASC Topic 718 prohibits the recognition of such benefits until the related compensation deduction reduces the current tax liability.
The Company assessed the realizability of the deferred tax asset generated in Peru. It considered whether it is more likely than not that some portion or all of the deferred tax asset will not be realized. The ultimate realization of the deferred tax asset is dependent upon the generation of future taxable income in Peru during the periods in which those temporary differences become deductible. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, along with the transition into the commercial phase under the Block Z-1 License Contract, the Company believes it is more likely than not that it will realize the benefits of the these deductible differences at December 31, 2010. As a result, the Company recognized a deferred tax asset of $28.4 million as of December 31, 2010. In addition the Company’s subsidiary, BPZ E&P, has a 2010 net operating loss of $11.0 million; however, the Company expects to be able to use the net operating loss against future taxable income within the four year limit to utilize such net operating losses.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
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. As of the date of adoption of FIN 48, codified under ASC Topic 740, “Income Taxes’, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the year. Additionally, the adoption had no effect on the Company’s financial position or results of operations. 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 statement as of December 31, 2010 or December 31, 2009.
Note 17 - Business Segment Information
The Company determines and discloses its segments in accordance with ASC Topic 280, “Segment Reporting” (“ASC Topic 280”) , previously in accordance with SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information”, which uses a “management” approach for determining segments. The management approach designates the internal organization that is used by management for making operating decisions and assessing parlance as the source of the Company’s reportable segments. ASC Topic 280 also requires disclosures about products or services, geographic areas, and major customers. The Company’s management reporting structure provided for only one segment for the year ended December 31, 2010, 2009 and 2008. Accordingly, no separate segment information is presented. In addition, the Company operates only in Peru and has only one customer for its oil production, Petroperu. The majority of the Company’s long-lived assets are located in Peru. Management does not consider its investment in Ecuador as separate business segment.
Note 18 - Commitments and Contingencies
Extended Well Testing Regulation
On December 13, 2009, new legislation regulating well testing in Peru became effective under a Supreme Decree. The new regulation provides that all new wells may be placed on production testing for up to six months. If the operator believes that additional time for testing is needed to properly evaluate the productive capacity of the field, and can technically justify such need, a request for the well to enter into an Extended Well Test (“EWT”) period must be submitted to the General Directorate of Hydrocarbons (“DGH”), the agency of the Ministry of Energy and Mines responsible for regulating the optimum development of oil and gas fields. The approval process for a EWT permit requires that the DGH request Perupetro’s opinion on the technical justification for the EWT. After the initial six-month period or after an approved EWT program expires, the operator will be required to have the necessary gas and water reinjection equipment in place to continue producing the well according to existing environmental regulations. Additionally, during both the initial six-month testing period and any extended period that may be granted, the Company must also obtain gas flaring permits for each well in order for it to be in compliance with Peruvian environmental legislation.
Corvina Field Transition into Commercial Production
On November 10, 2009, the Company received approval, from Perupetro, of its proposed First Date of Commercial Production (“FDCP”), as set forth in the current Field Development Plan (“FDP”) for the Corvina field in Block Z-1, which was May 31, 2010.
However, due to the delayed delivery of certain equipment gas and water reinjection facilities at the CX-11 platform, the Company applied for a revised FDCP of November 30, 2010 and received approval of the revised date in May 2010 from Perupetro. The Corvina field transitioned into commercial production on November 30, 2010 in accordance with the approved FDCP. With respect to other fields, unless EWT periods are approved, upon expiration of such periods, all production will cease until the Company meets the requirements, including installation of water and gas reinjection facilities, to transition into commercial production.
Extended Well Testing Program
Prior to transition into commercial production, the Company had been producing oil in the Corvina and Albacora fields subject to the new EWT regulations as described below.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
On January 25, 2010, the Company applied for an extended well testing permit for the first five producing wells in Corvina (the CX11-21XD, CX11-14D, CX11-20XD, CX11-18XD and the CX11-15D wells, collectively the “first five Corvina wells”) to continue gathering data to fully understand the drive mechanisms that are present in Corvina. On March 23, 2010, the Company received a decision from the DGH notifying it of approval to continue extended well testing on our first five Corvina wells, until the original FDCP date of May 31, 2010, subject to specific limits on the amount of natural gas flared from each of the first five Corvina wells.
The first five Corvina wells were shut-in due to the expiration of EWT period and the CX11-19D well has been shut-in since June 2010. In July 2010, the Company received initial notice that its applications for the first five Corvina wells and CX11-19D well to enter an extended well testing period were denied by the DGH. The Company requested the DGH to reconsider its denial of its applications. In September 2010, the Company received notice that its application for the CX11-19D well to enter an extended well testing period was again denied by the DGH. Likewise, in October 2010, the Company was notified that its applications for the first five Corvina wells to continue an extended well testing period was again denied by the DGH. However, in November 2010, the Company completed and installed the gas and water reinjection facilities at the CX-11 platform and transitioned the Corvina field to commercial production.
With respect to the Albacora field, in July 2010, the Company suspended production from the A-14XD well for approximately two weeks because the initial six-month testing period expired. However, in July 2010, the Company received a six-month extended well testing permit and a six-month gas flaring permit that allowed us to continue testing the Albacora field through late-January 2011, at which time the second permits expired. In January 2011, the Company received notice from Perupetro that its application for extended well testing on the A-14XD well was denied.
With respect to any additional EWT and gas flaring permits the Company requests, it can give no assurance that the DGH or the Ministry of Energy and Mines will grant approval of any current or future permits requested by the Company. In September 2010, the Company suspended the drilling operations at the A platform in the Albacora field in order to conduct a 3-D seismic survey of the area, currently planned for 2011. During the drilling downtime, the Company plans to move forward to fabricate and install permanent production and injection facilities on the Albacora platform. This should allow for continued production testing from the field once drilling operations resume by avoiding gas flaring and associated permitting issues.
Ecuadorian Hydrocarbon Law
In July, 2010, the Company was notified of changes to the Ecuadorian hydrocarbon law that included provisions that will allow the Ecuadorian government to nationalize oil fields if a private operator does not agree to contractual changes mandated by the new hydrocarbon laws. The consortium, of which the Company is a participant, has successfully negotiated a service contract during the fourth quarter of 2010; as such, the Company does not believe there is a significant risk of nationalization of its interest in the Santa Elena field. The Company is still reviewing the impact of this new law, if any, as it pertains to its 10% net investment interest in an oil and gas property in Ecuador. However, the Company does not believe any such impact on its Ecuadorian investment will have a material impact on the Company’s overall financial position. For further information see Note-6, “Investment in Ecuador Property”.
Profit Sharing
The Constitution of Peru and Legislative Decree Nos. 677 and 892 gives employees working in private companies engaged in activities generating income as defined by the Income Tax Law the right to share in the company’s profits. According to Article 3 of the United Nations International Standard Industrial Classification, BPZ E&P’s tax category is classified under the “mining companies” section, which sets the rate at 8%. However, in Peru, the Hydrocarbon Law states, and the Supreme Court ruled, that hydrocarbons are not related to mining activities. Hydrocarbons are included under “Companies Performing Other Activities”, thus Oil and Gas Companies pay profit sharing at a rate of 5%. The 5% of income is determined by calculating a percentage of the Company’s Peruvian subsidiaries’ annual total revenues subject to income tax less the expenses required to produce revenue or maintain the source of revenues. The benefit granted by the law to employees is calculated on the basis of “income subject to taxation” per the Peruvian tax code, and not based on income/(loss) before incomes taxes as reported under GAAP. For the year ended December 31, 2010, 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 declaring commercial production in the Corvina field, which allowed
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
certain exploration and development costs to be deductible in 2010 that were not deductible in previous years. For the year ended December 31, 2009 and 2008, approximately $1.3 million and $1.9 million of expense related to profit sharing is included in “General and administrative expense” in the Consolidated Statement of Operations as the Company’s Peruvian subsidiaries had “income subject to taxation” per the Peruvian tax code. The Company is subject to profit sharing expense any year its Peruvian subsidiaries are profitable according to the Peruvian tax laws.
Gas-to-Power Project Financing
The gas-to-power project entails the installation of an approximately 10-mile gas pipeline from the CX-11 platform to shore, the construction of gas processing facilities and the building of an approximately 135 megawatt (“MW”) simple-cycle electric generating plant. The proposed power plant site is located adjacent to an existing substation and power transmission lines which, after the Peruvian government completes their expansion, are expected to be capable of handling up to 320 MW of power. The existing substation and transmission lines are owned and operated by third parties.
The Company currently estimates the gas-to-power project will cost approximately $153.5 million, excluding working capital and 19% value-added tax which will be recovered via future revenue billings. The $153.5 million includes $133.5 million for the estimated cost of the power plant and $20.0 million for the estimated cost of the construction of the natural gas pipeline. While the Company has held initial discussions with several potential joint venture partners for the gas-to-power project, in an attempt to secure additional financing and other resources for the project, the Company has not entered into any definitive agreements with a potential partner. In the event the Company is able to identify and reach an agreement with a potential joint venture partner, it may only retain a minority position in the project. However, the Company expects to retain the responsibility for the construction of the pipeline as well as retain ownership of the pipeline. If the Company is unable to identify and reach an agreement with a potential partner, it plans to continue moving the project forward to completion without a partner. The Company is currently in the process of identifying and securing the permits and financing necessary to move the project forward.
Note 19 - Legal Proceedings
Navy Tanker Litigation
On October 24, 2007, Tecnomarine SAC, a contractor to BPZ E&P, entered into two short-term agreements with the Peruvian Navy’s commercial branch to charter two small tankers for use in the Company’s offshore oil production operation. On January 30, 2008, one of the tankers, the Supe, sank after catching fire. Neither of the Peruvian governmental agencies charged with investigating the incident found fault with Tecnomarine SAC or the Company’s subsidiary, BPZ E&P. A lawsuit was nonetheless filed on December 18, 2008 in the 152nd Judicial District Court of Harris County, Texas by two crewmembers and the family and estate of two deceased sailors injured in the incident, claiming negligence and gross negligence on the part of BPZ Resources, Inc. and BPZ Energy LLC., parent entities of BPZ E&P, that were not parties to the charter agreement and were not involved in the operations. Based on the Company’s assessment of the available facts, including the fact that none of the Peruvian government-sanctioned investigations into the Supe incident found fault on the part of Tecnomarine or BPZ E&P, the Company does not believe the outcome of the legal proceeding will have a material adverse effect on its financial condition, results of operations or cash flows. The Company intends to vigorously defend this action but cautions that there is inherent risk in litigation, which is difficult to quantify, especially at the early stage of litigation proceedings. In any event, the Company believes that any monetary damages arising from the incident would be adequately covered by its insurance policies, after a customary deductible.
From time to time the Company may become a party to various legal proceedings arising in the ordinary course of business. While the outcome of lawsuits cannot be predicted with certainty, the Company is not currently a party to any proceeding that it believes could have a potential material adverse effect on its financial condition, results of operations or cash flows.
Additionally, the Company is subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes environmental protection requirements that result in increased costs to the oil and natural gas industry in general, the business and prospects of the Company could be adversely affected.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Note 20 - Operating Leases
The Company is committed under various operating leases, which primarily relate to office space, warehouse rental, drilling rig equipment, and marine support vessels. Total rent expense incurred for the year ended December 31, 2010, 2009 and 2008 was approximately $1.6 million, $1.4 million and $0.5 million, respectively.
Minimum non-cancelable lease and purchase commitments are as follows (in thousands):
For the Year Ending December 31,
Includes operating leases for the Company’s executive office in Houston, Texas, and its branch offices in Lima, Peru and warehouses in Peru, respectively, The operating lease amounts also exclude $0.1 million of sublease rentals from the Company’s Houston, Texas office due in the future under noncancelable subleases.
Includes the monthly lease expense for the Company’s two drilling rigs, one being currently leased to an operator in Peru and the other rig is currently being upgraded by Petrex to be used in operations once the Company’s seismic data acquisitions is completed. One lease is set to expire in January 2012 and the other lease is set to expire in December 2013.
Includes the monthly lease expense for one of the Company’s oil transportation vessels whose lease is set to expire in February 2012 and storage vessel whose lease is set to expire in February 2013.
Note 21 - Subsequent Events
The Company and its subsidiaries completed a credit agreement with Credit Suisse on January 27, 2011 where Credit Suisse provided $40.0 million of secured financing and utilized a portion of the proceeds to retire the existing debt with IFC. For further information, see Note 9 “Long-Term Debt and Capital Lease Obligations”.
The initial conversion rate on the $170.9 Million Convertible Notes due 2015 was adjusted on February 3, 2011. The conversion rate and conversion price changed to 169.0082 and $5.9169, respectively. For further information, see Note 9 “Long-Term Debt and Capital Lease Obligations”.
On January 24, 2011, production from the A14-XD well was shut-in under the EWT program. On February 10, 2011, the Company received notice that its application for EWT testing for the A-14XD well was denied. For further information, see Note-18, “Commitment and Contingencies”.
BPZ RESOURCES, INC AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Note 22 - Quarterly Results of Operations (Unaudited)
BPZ RESOURCES, INC AND SUBSIDIARIES
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES
YEARS ENDED DECEMBER 31, 2010, 2009 and 2008
Supplemental Oil and Gas Disclosures (Unaudited)
Oil and Natural Gas Producing Activities
The following disclosures for the Company are made in accordance with ASC Topic 932, “Extractive Activities -Oil and Gas” and SEC rules for oil and gas reporting disclosures. Users of this information should be aware that the process of estimating quantities of proved, proved developed and proved undeveloped crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures. Accordingly, reserve estimates are often different from the quantities of crude oil and natural gas ultimately recovered.
SEC and FASB Updates on Oil and Gas reporting
On December 31, 2008 the SEC adopted the final rules regarding amendments to current oil and gas reporting requirements. The amendments are designed to modernize and update the oil and gas disclosure requirements to align them with current practices and changes in technology. Additionally, in January 2010, the FASB issued Accounting Standard Update 2010-3, “Oil and Gas Reserve Estimation and Disclosures”, to align its reporting guidance with the new SEC rules. The Company adopted these rules effective December 31, 2009 and the changes, including those related to pricing, are included in the Company’s reserve estimates.
The most significant changes to the Company’s reserve estimates as a result of the new rules are as follows:
· Requiring companies to report oil and gas reserves using an un-weighted average price based upon the prior 12-month period rather than year-end prices;
· Requiring companies to report the independence and qualifications of a preparer or auditor, based on current Society of Petroleum Engineers criteria;
· Requiring the filing of reports for companies that rely on a third party to prepare reserves estimates or conduct a reserves audit; and
· Limiting proved undeveloped reserves locations to those that are scheduled to be drilled within the next five years.
Reserves
Proved reserves represent estimated quantities of crude oil and natural gas that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made.
Proved developed reserves are proved reserves expected to be recovered, through wells and equipment in place and under operating methods being utilized at the time the estimates were made.
Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Our relevant management controls over proved reserve attribution, estimation and evaluation include:
· controls over and processes for the collection and processing of all pertinent operating data and documents needed by our independent reservoir engineers to estimate our proved reserves;
· engagement of well qualified and independent reservoir engineers for review of our operating data and documents and preparation of reserve reports annually in accordance with all SEC reserve estimation guidelines;
· review by our senior reservoir engineer and his staff of the independent reservoir engineers’ reserves reports for completion and accuracy; and
· oversight and review by our Technical Committee, made up of independent members of the Board of Directors, who review the propriety of our methodology and procedures for determining the oil and gas reserves as well as the reserves estimates resulting from such methodology and procedures. The Technical Committee may also review the qualifications, independence and performance of our independent reserve engineers.
After December 31, 2008, an un-weighted average of the first-day-of-the month price based upon the prior 12-month period is used for future sales of natural gas, crude oil and natural gas liquids. Future operating costs, production taxes and capital costs will be based on current costs as of each year-end, with no escalation. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. Reserve data represent estimates only and should not be construed as being exact. Moreover, the standardized measure should not be construed as the current market value of the proved oil and natural gas reserves or the costs that would be incurred to obtain equivalent reserves. A market value determination would include many additional factors including (a) anticipated future changes in natural gas and crude oil prices, production and development costs, (b) an allowance for return on investment, (c) the value of additional reserves, not considered proved at present, which may be recovered as a result of further exploration and development activities, and (d) other business risk.
Proved Undeveloped Reserves (“PUD” or “PUDs”)
As of December 31, 2010, we had a total quantity of 21 PUDs contributing 26.6 MMbbls to our 2010 proved oil reserves. Of the total 21 PUDs, 17 PUDs are associated to the Corvina field and 4 PUDs are associated to the Albacora field. During the year ended December 31, 2010, three PUDs, contributing to the 2009 proved oil reserves, were converted into proved developed reserves in the Corvina field, the CX11-17D, the CX11-22D and the CX11-23D wells. Costs incurred to advance the development of these PUDs in 2010 were approximately $44.5 million. As of December 31, 2010, we did not have any PUDs previously disclosed that have remained undeveloped for five years or more. As of December 31, 2010, we have three PUD locations included in our proved oil reserves that are scheduled to be drilled after five years, as we have included contingencies that account for certain possible delays in our drilling schedule due to unexpected events, such as early mechanical issues as an example. However, once those issues are resolved, we anticipate drilling these wells.
Capitalized Costs Relating to Oil and Gas Producing Activities
The following table sets forth the capitalized costs relating to the Company’s natural gas and crude oil producing activities at December 31, 2010 and 2009:
(1) BPZ Energy purchased the Investment in Ecuador Property in 2004.
Pursuant to ASC Topic 410, “Asset Retirement and Environmental Obligations”, previously accounted for in accordance with SFAS No 143 “Accounting for Asset Retirement Obligations”, net capitalized cost includes asset retirement cost of $0.9 million and $0.8 million as of December 31, 2010 and December 31, 2009, respectively.
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities
The following table sets forth costs incurred related to the Company’s oil and natural gas activities for the year ended December 31, 2010 and 2009 (in thousands):
(1) BPZ Energy purchased the Investment in Ecuador Property in 2004.
Results of Operations for Oil and Natural Gas Producing Activities
The results of operations for oil and natural gas producing activities, excluding interest charges and general and administrative expenses; sales are based on market prices.
(1) Investment in Ecuador Property
Net Proved Reserve Summary
The following table sets forth the Company’s net proved developed and undeveloped reserves at December 31, 2010, 2009 and 2008, and the changes in the net proved reserves for each of the three years in the period then ended. All of the Company’s proved reserves are located in Peru. The Company’s net profit interest in the Santa Elena property is located in Ecuador and is based on a service contract.
(1) Includes crude oil, condensate and natural gas liquids.
(2) Natural gas volumes have been converted to equivalent natural gas liquids and crude oil volumes using a conversion factor of six thousand cubic feet of natural gas to one barrel of natural gas liquids and crude oil.
(3) Based on an independent reservoir engineer’s report provided by the operator of the Santa Elena property.
(4) The Company does not currently have the financial capacity or commitments for a development program of this magnitude for its gas reserves. Accordingly, the Company has not disclosed amounts of proved gas reserves in its SEC filings. At such time as the Company obtains sufficient financial commitments to proceed with the full development of the gas-to-power project and all other conditions necessary to record proved reserves are met, the Company expects to record SEC proved gas reserves as permitted under SEC rules and disclose such reserves in future SEC filings.
(5) The Company did not have the financial capacity or commitments for a development program of this magnitude. Accordingly, the Company did not disclose amounts of proved reserves in its SEC filings for the year ended December 31, 2006.
(6) The 2007 balance represents the initial oil reserves as a result of completing the two initial wells drilled and completed by the Company toward the end of 2007. The 2008 additions to the extensions and, discoveries and additions of 7.8 MMBbls were due to additional wells drilled in 2008. The 2009 additions to the extensions and discoveries and additions of 22.8 MMBbls were due to additional wells drilled in the Corvina field (12. 8 MMBbls) and the discoveries of the Albacora field (10.1 MMBbls). The 2010 additions to the extensions and, discoveries and additions of 2.6 MMBbls were due to additional wells drilled in the Corvina field.
(7) The 2008 negative revisions were due to price. The 2007 reserve analysis as prepared by NSAI used $85.49 per barrel price while the 2008 reserve analysis as prepared by NSAI used a $37.80 per barrel price, resulting in a negative revision of 1.7 MMBbls in 2008. The 2009 reserve analysis as prepared by NSAI included negative revisions due to performance. The negative revision was due to the lower than expected performance of the CX11-14D, CX11-18XD, and CX11-20XD wells and corresponding revisions of other wells resulting in a negative revision of 1.6 MMBbls. The 2010 reserve analysis as prepared by NSAI included positive revisions due to price of approximately 347 MBbls that was partially offset by negative revisions of approximately 28 MBbls due to performance. The 2010 reserve analysis as prepared by NSAI used a $76.92 per barrel price while the 2009 reserve analysis as prepared by NSAI used a $57.30 per barrel price.
(8) The 2008 oil production was from the Corvina field. The 2009 oil production of 991 MBbls includes 984MBbls from the Corvina field and 7 MBbls from the Albacora field. The 2010 oil production of 1,527 MBbls includes 1,123MBbls from the
Corvina field and 404 MBbls from the Albacora field.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves
The following information has been developed utilizing procedures prescribed U.S. GAAP and based on natural gas and crude oil reserve and production volumes estimated by the independent petroleum reservoir engineers. This information may be useful for certain comparison purposes but should not be solely relied upon in evaluating the Company or its performance. Further, information contained in the following table should not be considered as representative of realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company’s oil and natural gas assets.
The future cash flows presented below are based on sales prices, cost rates and statutory income tax rates in existence as of the date of the projections. It is expected that material revisions to some estimates of natural gas and crude oil reserves may occur in the future, development and production of the reserves may occur in periods other than those assumed, and actual prices realized and costs incurred may vary significantly from those used. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and natural gas producing activities.
Management does not rely upon the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.
The following table sets forth the standardized measure of discounted future net cash flows from projected production of the Company’s crude oil reserves for the year ended December 31, 2010, 2009 and 2008 (in thousands):
(1)
Investment in Ecuador Property
(2)
Based on an independent reservoir engineer’s report provided by the operator of the Santa Elena property.
(3)
The per barrel price used in determining future cash inflows for the year ended December 31, 2010, 2009 and 2008 were $76.92, $57.30 and $37.80, respectively.
The following table sets forth the principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil reserves for the year ended December 31, 2010, 2009 and 2008:
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
(a) Evaluation of Disclosure Controls and Procedures
We performed an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer have concluded that as of December 31, 2010 our disclosure controls and procedures, as defined in Rule 13a-15(e), are effective to ensure that information we are required to disclose in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.
(b) Changes in Internal Control Over Financial Reporting
There was no change in the Company’s internal control over financial reporting during the quarter ended December 31, 2010 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
(c) Management’s Annual Report on Internal Control over Financial Reporting
Management of the Company, including our principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal controls over financial reporting, as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls are designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of the consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition.
Management conducted an evaluation of the effectiveness of our internal controls over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this evaluation. We did not identify any material weaknesses in our internal controls as a result of this evaluation. Based on this evaluation, management has concluded that our internal controls over financial reporting were effective as of December 31, 2010.
BDO USA, LLP, the independent registered public accounting firm who also audited our consolidated financial statements, has issued an attestation report on our internal control over financial reporting as of December 31, 2010, which is set forth below under “Attestation Report”.
(d) Attestation Report
Report of Independent Registered Public Accounting Firm
on Internal Control over Financial Reporting
To the Board of Directors and Stockholders
BPZ Resources, Inc. and Subsidiaries
Houston, Texas
We have audited BPZ Resources, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). BPZ Resources, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Annual Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, BPZ Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of BPZ Resources, Inc. as of December 31, 2010, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended, and our report dated March 16, 2011 expressed an unqualified opinion thereon.
/s/ BDO USA, LLP
Houston, TX
March 16, 2011
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Annual Report on Form 10-K.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Annual Report on Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Annual Report on Form 10-K.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Annual Report on Form 10-K.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this item is incorporated by reference from our definitive proxy statement to be filed with the SEC within 120 days after the end of our fiscal year covered by this Annual Report on Form 10-K.
PART IV
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry that are used in this report.
Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent determined using the ratio of approximately six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Bopd. Barrels of oil per day.
Boepd. Barrels of oil equivalent per day.
Deterministic estimate. Refers to a method of estimation whereby a single value for each parameter in the reserves calculation is used in the reserves estimation procedure.
Developed reserves. Oil and natural gas reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development project. A project by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Drill Stem Test. A test of the flow rates of a formation thru the drill pipe to determine the fluid and gas content, pressure and estimated production rates of the reservoir.
Dry hole or well. A well that proves to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.
Exploitation. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Exploratory well. A well drilled to find and a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of approximately six Mcf of natural gas to one Bbl of crude oil or other hydrocarbon.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
Oil. Crude oil, condensate and natural gas liquids.
Probabilistic estimate. Refers to a method of estimation whereby the full range of values that could reasonably occur for each unknown parameter in the reserves estimation procedure is used to generate a full range of possible outcomes and their associated probabilities of occurrence.
Productive well. A well that is found to be capable of producing hydrocarbons.
Proved properties. Properties with proved reserves.
Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. As used in this definition, “existing economic conditions” include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The SEC provides a complete definition of proved reserves in Rule 4-10(a)(22) of Regulation S-X.
Reasonable certainty. When deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities of hydrocarbons will be recovered. When probabilistic methods are used, reasonable certainty means at least a 90% probability that the quantities of hydrocarbons actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience, engineering, and economic data are made to estimated ultimate recovery with time, reasonably certain estimated ultimate recovery is much more likely to increase or remain constant than to decrease.
Recompletion. The completion for production of an existing well bore in another formation from that which the well has been previously completed.
Reliable technology. A grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
Reserves. Estimated remaining quantities of oil, natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or
a revenue interest in the production, installed means of delivering the oil, natural gas or related substances to market, and all permits and financing required to implement the project.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Undeveloped reserves. Oil and natural gas reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Unproved properties. Properties with no proved reserves.
Workover. A remedial operation on a completed well to restore, maintain or improve the well’s production.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 16, 2011.
Pursuant to the requirements of the Securities Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
/s/ MANUEL PABLO ZÚÑIGA-PFLÜCKER
/s/ EDWARD G. CAMINOS
Manuel Pablo Zúñiga-Pflücker
Edward G. Caminos
President, Chief Executive Officer and Director
Chief Financial Officer
March 16, 2011
(Principal Financial Officer and Principal Accounting Officer)
March 16, 2011
/s/ JAMES B. TAYLOR
/s/ JOHN J. LENDRUM, III
James B. Taylor
John J. Lendrum, III
Director and Chairman of the Board
Director
March 16, 2011
March 16, 2011
/s/ GORDON GRAY
/s/ DENNIS G. STRAUCH
Gordon Gray
Dennis G. Strauch
Director
Director
March 16, 2011
March 16, 2011
/s/ STEPHEN C. BEASLEY
Stephen C. Beasley
Director
March 16, 2011
INDEX OF EXHIBITS
2.1
Plan of Conversion for BPZ Energy, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on August 24, 2007).
3.1
Certificate of Formation of BPZ Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on August 24, 2007).
3.2
Bylaws of BPZ Resources, Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Form 8-K filed on August 17, 2007).
3.3
First Amendment to the Bylaws of BPZ Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on March 7, 2011).
4.2
Indenture for 6.5% Convertible Senior Notes due 2015 by and among BPZ Resources Inc. and Wells Fargo Bank National Association, as trustee, dated February 8, 2010 (incorporated by reference to exhibit 4.1 to the Company’s Form 8-K filed on February 9, 2010)
4.3
Form of 6.5% Convertible Senior Note due 2015 (included in Exhibit 4.2)
10.1*
BPZ Energy, Inc. 2005 Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form S-8 filed on July 5, 2005 (SEC File No. 333- 126388)).
10.2*
BPZ Energy, Inc. 2007 Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on August 24, 2007).
10.3*
BPZ Energy, Inc. 2007 Directors Compensation Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on August 24, 2007).
10.4
Merger Agreement between Navidec, Inc. and BPZ Energy, Inc. dated July 8, 2004 (incorporated by reference to Exhibit 10.1 from the Company’s Form 8-K filed on July 13, 2004).
10.5
Closing Agreement between Navidec, Inc. and BPZ, Inc. dated September 8, 2004(incorporated by reference to Exhibit 10.1 from the Company’s Form 8-K filed on September 14, 2004).
10.6
License Contract from the Government of Peru for Block Z-1 dated November 30, 2001 (incorporated by reference to Exhibit 10.5 to the Company’s Form SB-2 filed on February 14, 2005 (SEC File No. 333-122816)).
10.7
Amendment to License Contract from the Government of Peru for Block Z-1 dated February 3, 2005 (incorporated by reference to Exhibit 10.5 of the Company’s Annual Report on Form 10-KSB for the year ended December 31, 2004 filed on April 15, 2005).
10.8
License Contract from the Government of Peru for Block XIX dated December 12, 2003 (incorporated by reference to Exhibit 10.6 to the Company’s Form SB-2 filed on February 14, 2005 (SEC File No. 333-122816)).
10.9
License Contract from the Government of Peru for Block XXII dated November 21, 2007 (incorporated by reference to Exhibit 10.9 to the Company’s Form 10-K filed on March 14, 2008)
10.10
License Contract from the Government of Peru for Block XXIII dated November 21, 2007 (incorporated by reference to Exhibit 10.10 to the Company’s Form 10-K filed on March 14, 2008).
10.11
Contract No. 001-2009-Mextipetroperu - Supply of 17,000,000 Barrels of Crude Oil for Talara Refinery dated January 8, 2009, by and among BPZ Exploración & Producción S.R.L., and Petroleos del Perú-PETROPERU S.A.(incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on January 14, 2009).
10.12
Contract for Sale of Equipment and Services dated September 26, 2008 (incorporated by reference to Exhibit 10.11 to BPZ Resources, Inc.’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 filed on November 10, 2008).
10.13
Amendment dated January 23, 2009 to Contract for Sale of Equipment and Services dated September 26, 2008 by and among GE Packaged Power, Inc. GE International, Inc. Sucursal De Peru and Empresa Eléctrica Nueva Esperanza, SRL (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on January 29, 2009).
10.14
C Loan Agreement between BPZ Resources, Inc. (formerly BPZ Energy, Inc.) and International Finance Corporation, dated November 17, 2007 (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on November 26, 2007).
10.15
Loan Agreement between BPZ Exploracion & Produccion S.R.L and BPZ Marine Peru S.R.L and International Finance Corporation dated as of August 15, 2008 (incorporated by reference to exhibit 10.15 to the Company’s Form 10-K filed on March 2, 2009).
10.16
Common Terms Agreement between BPZ Exploracion & Produccion S.R.L and BPZ Marine Peru S.R.L., as borrowers, and International Finance Corporation, as lender, and the Additional Secured Facility Lenders dated as of August 15, 2008 (incorporated by reference to exhibit 10.16 to the Company’s Form 10-K filed on March 2, 2009).
10.17
Stock Purchase Agreement by and among BPZ Resources, Inc. and Investors (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on February 24, 2009).
10.18
Placement Agency Agreement and form of the Subscription Agreement by and among BPZ Resources, Inc. and Investors with Placement Agents dated as of June 25, 2009 (incorporated by reference to exhibit 1.1 to the Company’s Form 8-K filed on June 29, 2009)
10.19
Subscription Agreement by and among BPZ Resources Inc. and International Finance Corporation , as Investor, to purchase 1,630,776 shares of common stock dated September 15, 2009 (incorporated by reference to exhibit 10.1 to the Company’s Form 8-K filed on September 16, 2009)
10.20
Letter Agreement by and between the Consortium of GE Packaged Power, Inc. and GE International Inc. Sucursal de Peru (collectively, “Seller”) and Empresa Electrica Nueva Esperanza S.R.L. (“Buyer”) dated as of November 20, 2009 (incorporated by reference to exhibit 10.3 to the Company’s Form 8-K filed on November 27, 2009)
10.21
US $40,000,000 Credit Agreement by and among Empresa Electrica Nueva Esperanza S.R.L., as Borrower, and BPZ Resources, Inc., and BPZ Exploración & Producción S.R.L., as Guarantors and Credit Suisse AG, Cayman Islands Branch, as Administrative Agent, and Credit Suisse International, as Arranger, dated as of January 27, 2011 (filed herewith).
10.22*
Amendment to the BPZ Energy, Inc. (n/k/a BPZ Resources, Inc.) 2007 Long-Term Incentive Compensation Plan (filed herewith).
14.1
Code of Ethics for Executive Officers (incorporated by reference to Exhibit 14.1 to Form 10-KSB/A filed on September 26, 2006).
21.1
Subsidiaries of the Registrant, filed herewith.
23.1
Consent of Independent Registered Public Accounting Firm, filed herewith.
23.2
Consent of Independent Petroleum Engineers and Geologists, filed herewith.
23.3
Consent of Independent Registered Public Accounting Firm, filed herewith.
31.1
Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
31.2
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, filed herewith.
32.1
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
32.2
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, filed herewith.
99.1
Report of Netherland, Sewell & Associates, Inc., filed herewith.
* - Management Contract or Compensatory Plan or Arrangement.