ITEM 1. BUSINESS
Overview
BPZ Energy, Inc., (the “Company” or “BPZ”) a Colorado corporation, formerly named Navidec, Inc., was incorporated in 1993 and is based in Houston, Texas. We are an exploratory stage company focused on the exploration and production of oil and natural gas and we intend to utilize part of our future natural gas production for the complementary development of gas-fired power generation.
On September 10, 2004, BPZ Energy, Inc., a Texas, (BPZ-Texas”) corporation consummated a reverse merger with Navidec, Inc., a Colorado corporation (“Navidec”), whereby BPZ-Texas became a wholly owned subsidiary of Navidec (the “Merger”). See “Business-Navidec Merger Transaction” and Note 2 to the Company’s Consolidated Financial Statements, both included in this filing, for detailed discussion regarding the Merger.
We maintain a registered branch office in Peru. Currently, we have exclusive rights and license agreements for oil and gas exploration and production covering a total of approximately 2.4 million acres in northwest Peru. Our license contracts cover 100% ownership of both Block Z-1 (739,205 acres) and Block XIX (472,860 acres). The Block Z-1 contract was signed in November 2001, and the Block XIX contract was signed in December 2003. Our license contracts provide for an initial exploration period of seven to thirteen years and seven to ten years, respectively, and require that we conduct specified activities on the properties during this period. If the exploration activities are successful, 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. We have presented all necessary documentation requested by Perupetro in order to become the qualified operator under a license contract for Block XXII (948,000 acres, referred to as Area VI in previous filings) which we previously held under a Technical Evaluation Agreement. Subsequently, in March 2006, we were notified by Perupetro that we qualified as an operator for Block XXII. In July 2006 Perupetro officially informed us that our proposal for the 248,000 acre Block XXIII, located onshore in northwest Peru between our Blocks Z-1 and XIX, was the winning bid in their recent license tender process. We have presented all necessary documentation to become the qualified operator of this new block under an exploration and production license contract
Through our wholly owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, we also own a 10% non-operated working interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). The license agreement covering the property extends through May 2016.
We are in the exploratory stage of our oil and natural gas business and to date our activities in Peru have been primarily limited to analysis and evaluation of technical data on the properties and preparation of the development plans for the properties, including detailed engineering and design of the power plant and gas processing facilities, refurbishment of one of our offshore platforms, procuring machinery and equipment for an extended drilling campaign, obtaining all necessary environmental and operating permits and securing the required capital and financing to complete the current plan of operation. We commenced drilling of our initial well, the CX11-21XD, in the Corvina Gas Field at the CX-11 platform in September 2006, and a total depth of 10,457 feet (9,234 feet true vertical depth) was reached in November 2006. In March 2007, after a total of four Drill Stem Tests were conducted on separate potential pay zones covering 413 feet from the Lower and Upper Zorritos formations, the well tested at a rate of 40 million cubic feet per day (MMcfpd) of natural gas and 3,150 barrels per day of crude oil (bopd). We next plan to workover the shut-in CX11-16X well, followed by the drilling of our second new well in the Corvina field, to test for additional gas reserves and further appraise the oil discovery. However, we caution readers that test data is not necessarily indicative of actual results. We have not drilled any other wells or recognized any revenues from operations, and we do not anticipate generating significant revenues from our properties prior to early 2008.
Navidec Merger Transaction
On September 10, 2004, BPZ Energy, Inc., a Texas corporation, consummated a reverse merger with Navidec, Inc., a Colorado corporation (“Navidec”), whereby BPZ-Texas became a wholly owned subsidiary of Navidec (the “Merger”). In the Merger, the stockholder group of BPZ-Texas obtained majority ownership and management control of the combined company. Accordingly, for accounting purposes, BPZ-Texas was treated as the acquiring entity. See Note 2 to the Consolidated Financial Statements, included in this filing, for detailed discussion regarding the Merger. All financial statements herein represent the historical financial statements of the accounting acquirer, BPZ - Texas. Upon completion of the Merger, the officers and directors of Navidec resigned, except for the former CEO of Navidec, John R. McKowen, who remained a director. Mr. McKowen, together with the management and the four directors of BPZ-Texas, became the executive officers and directors of the surviving entity. Mr. McKowen did not stand for re-election to the board of directors at the annual meeting of shareholders held on July 1, 2005. On February 4, 2005, Navidec changed its name to BPZ Energy, Inc. Although the Company’s name has been changed, the pre-merger company may be referred to as Navidec in this filing, as the context may require, to avoid confusion.
The Merger required the transfer of all of the pre-merger business operations, assets and liabilities of Navidec to its wholly owned subsidiary, Navidec Financial Services, Inc. (“NFS”), followed by the transfer of ownership of NFS to the pre-merger shareholders of record as of September 9, 2004, the day prior to the consummation of the Merger. Accordingly, the pre-merger shareholders of BPZ-Texas were not entitled to receive shares of NFS. All legal requirements for the transfer of ownership of NFS have been completed. On July 13, 2006, NFS filed a Registration Statement on Form 10SB with the SEC and an amendment thereto on October 27, 2006. It is our understanding that the Registration Statement has become effective under applicable SEC rules. NFS’ results are excluded from our financial statements for all periods presented.
As a result of the Merger, the shareholders of BPZ-Texas received the majority of the voting interests and control of the Board of Directors and management of the combined entity. The Merger Agreement provided for the immediate issuance by Navidec of 9,000,000 shares of its common stock to the shareholders of BPZ-Texas and the future issuance of an additional 18,000,000 shares on an earn-out basis if the Company achieves certain reserve and production goals. The first 9,000,000 earn-out shares were contingent on achieving certain reserve targets, which were achieved in December 2004. The remaining 9,000,000 earn-out shares are issuable once the Company is entitled to receive as its proportionate share from gross production from any oil and gas wells owned or operated by the Company not less than 2,000 barrels of oil per day or its equivalent (approximately 12 million cubic feet of gas per day) prior to December 28, 2007.
Plan of Operation
Corvina Gas-to-Power
Our plan of operation is initially focused on the development and exploitation of the oil and natural gas resource opportunities in the offshore Block Z-1 in northwest Peru, in which we own a 100% working interest. Our initial project, referred to as the Corvina Gas-to-Power project, with an estimated capital budget of $132.3 million, entails the refurbishment of the Corvina CX-11 platform, rehabilitation of an existing well and the drilling of two new wells, installation of a 10-mile gas pipeline from the platform to shore, construction of gas processing facilities and a 160 MW simple-cycle electric generating plant, and the construction of a 40-mile gas pipeline to supply gas to third party generators in Arenillas, Ecuador. In order to achieve our objectives, we must obtain significant financing from external sources. To date we have raised approximately $60 million through several private placements of our common stock. In addition, on December 20, 2006, the International Finance Corporation’s (“IFC”) Board of Executive Directors approved a $120 million financial package related to this project. See “Capital Expenditures and Liquidity and Capital Resources” below for further discussion.
Our first priority is drilling the initial gas wells in the Corvina Gas Field to develop reserves and establish deliverability at expected levels. In December 2005, we signed a drilling contract with Petrex S.A., a subsidiary of Saipem SpA of Italy. Under this contract, Petrex S.A. provided us with a platform rig capable of drilling to 16,000 feet and upgraded the rig to meet our specifications. We paid $5.5 million to upgrade and mobilize the rig. In exchange, we received a competitive fixed day rate and exclusive rights to use the rig, at our option, during the two-year period commencing with delivery of the rig in September 2006. In addition, after the guaranteed two-year period, we have the option to extend the contract for an additional year at market rates.
In April 2006, we acquired and equipped a deck barge that was used to transport the drilling rig to the Corvina CX-11 platform and then act as a tender for offshore drilling operations at Corvina, and eventually at our other properties. The deck barge, officially named BPZ-01, is equipped with a 200 ton crane for loading and off-loading. BPZ-01 and related equipment, including a smaller 35 ton crane, two winches and related spare parts, were acquired for approximately $6.0 million. BPZ-01 is an important element in the Company’s strategy to control drilling costs by allowing the use of existing platforms and avoiding the use of high-priced drill ships or barges.
The Corvina Gas Field has two existing platforms, the CX-11, which we recently refurbished and the CX-13 which we plan to refurbish in the future. The CX-11platform was evaluated as fit for operations by the independent risk management consulting firm of ABSG Consulting, Inc.
Our initial plans include the drilling of two new wells from the Corvina CX-11 platform which also has a shut-in gas well which we intend to recomplete and utilize for gas production. We have secured all tubular goods required to meet our expected needs for these first three gas wells. We have obtained the required environmental and drilling permits in order to commence drilling operations. We commenced drilling of our initial well, the CX11-21XD, in the Corvina Gas Field at the CX-11 platform in September 2006 and a total depth of 10,457 feet (9,234 feet true vertical depth) was reached in November 2006. In March 2007, after a total of four Drill Stem Tests (DST) were conducted on separate potential pay zones covering 413 feet from the Lower and Upper Zorritos formations, the well tested at a rate of 40 million cubic feet per day (MMcfpd) of natural gas and 3,150 barrels per day of crude oil (bopd). However, we caution the reader that test results are not necessarily indicative of actual production. The gas is essentially pure methane with no impurities, making it ideal for the Company’s proposed 160 MW power plant project which will require 40 MMcfpd of feedstock. The drilling of this first well at Corvina fulfills our contractual exploration commitment under the current second exploration period of the Block Z-1 License Contract. We next plan to workover the shut-in CX11-16X well, followed by the drilling of our second new well in the Corvina field, to test for additional gas reserves and further appraise the oil discovery.
Our initial plan of operation envisions the installation of a Company-owned 160 megawatt (“MW”) simple-cycle, gas-fired, electric generation plant at Nueva Esperanza, near the town of Caleta Cruz, in northwest Peru. In August 2005, we awarded the turnkey contract for the engineering, procurement and construction (EPC) of the power plant project to BTEC Turbines LP of Houston (“BTEC”). The contract was awarded following a comprehensive six-month bidding process that included field visits by all of the bidders. The engineering portion of the contract is ongoing and nearing completion. Final terms of the procurement and construction portions of contract are currently being negotiated. BTEC is expected to supply two General Electric Frame 7EA simple-cycle gas-fired turbines. BTEC will also act as the main contractor for the design, transportation, construction, startup and commissioning of the power plant. Our plan is to own 100% of the power plant. Accordingly, our revenues from the natural gas delivered to the power plant will be derived from the sale of electricity.
To transport the natural gas from the Corvina Gas Field to our planned power plant we intend to construct a 10-mile offshore pipeline. The power plant site is located adjacent to an existing substation and power transmission lines which, with certain upgrades, are expected to be capable of handling up to 360 MW of power. 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 economic quantities of electricity from the initial 160 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 Ecuadorian power markets.
During the planning stage for the drilling of the first Corvina well in Block Z-1, we incurred a substantial delay in the procurement of a drilling rig. Also, during the final stages of completing the Corvina well, we encountered a mechanical problem. This problem resulted from a gas kick following the cementing of the 7” liner in the Zorritos formation and caused cement and several joints of drill pipe to block part of the 9 5/8” intermediate casing. All obstructions were successfully cleared. Primarily because of these two events, projected power sales to the Peruvian market are now anticipated to commence in early 2008. This timeline is subject to many factors, including completion of required financing arrangements, which may be beyond our control. Based on the revised timeline, we will focus our capital expenditures on critical drilling activities. Procurement activities for the other phases of the project will be coordinated with expected additional funding from the IFC project-based debt financing, as described above, or additional equity financing.
In addition to the local power market targeted in our initial project in Peru, we intend to simultaneously develop a gas sales strategy for nearby Ecuador to capitalize on what we believe to be significant upside gas potential of the Corvina and Piedra Redonda Gas Fields located in Block Z-1, as well as the potentially significant natural gas resources in the adjacent onshore Block XIX. These properties are within 30 miles of the Ecuadorian border and we plan to develop them for export sales of either raw gas or power generation via connection to the transmission system of Ecuador. Our plan for eventual Ecuadorian gas sales includes the construction of a 40-mile pipeline from Caleta Cruz, the terminal point of our offshore pipeline from the Corvina Gas Field, to Arenillas, Ecuador. We intend to sell gas for the generation of electricity by third party power producers in the local market in Ecuador. We are planning to complete this pipeline for first sales of gas to Ecuador in late 2008, though this schedule is subject to many factors outside our control, including all necessary financing and no assurance can be given that we can meet this schedule.
In addition to the initial Corvina Gas-to-Power development project described above, we have exploration and
development rights to other fields within Block Z-1 and Blocks XIX, XXII and XXIII. We plan to seek additional financing for these projects from industry or capital market sources, and we are not currently planning to make significant capital expenditures for seismic acquisition, excluding Block XIX as described below, or other exploration and development activities beyond our initial Corvina Gas-to-Power project as described above, until we have secured such additional financing. Below is a brief summary of some of our possible future exploration and development projects:
Block Z-1
In light of the recent oil discovery on the CX11-21XD well in the Corvina field, as discussed above, we plan on targeting the same zones on the workover of the shut-in well as well as on the second new well. If the test results also indicate the presence of commercially viable oil, we may consider implementing a fast-track oil development program simultaneous with or possibly prior to the full implementation of the Corvina gas-to-power project and development of the Albacora Oil Field.
Future plans for Block Z-1 include: further development of the Corvina and Piedra Redonda Gas Fields for future industrial markets, such as petrochemicals, and for additional gas sales into Guayaquil, Ecuador, known as the industrial center of Ecuador; the development of the Albacora Oil Field for which we have completed the baseline field work towards the securing of the environmental permits required for repair of an existing platform, the workover of three shut-in wells, and the related drilling program. We have completed our internal evaluation of the Albacora oilfield’s estimated reserves based on the definitions and standards adopted in 1997 by the Society of Petroleum Engineers & World Petroleum Congresses (SPE/WPC), and we are seeking an independent certification of such reserves, though no assurance can be given that any such reserves can be proven, or will be certified as proven, or that we can demonstrate our technical or financial ability to recover any such reserves. We also have begun planning for eventual exploration and development work in the deeper water sections of Block Z-1
Block XIX
In connection with our onshore Block XIX license contract, we are obligated to shoot at least 100 kilometers of 2-D seismic surveys during the first half of 2007, unless an extension is requested and granted. Depending on the results of this work, we may elect to drill an exploratory well. We have secured the environmental permits and other authorizations to perform seismic testing in this block.
Blocks XXII and XXIII
We have initiated negotiations to obtain a license contract for exploration and development activities for Block XXII, which until December 31, 2005, we held under a Technical Evaluation Agreement. Block XXII is a large onshore block in northwest Peru which encompasses the Lancones Basin. In March 2006, we were notified by Perupetro that we qualified as an operator of Block XXII.
In July 2006, Perupetro officially informed us that our proposal for the 248,000 acre Block XXIII, located onshore in northwest Peru between our Blocks Z-1 and XIX, was the winning bid in their tender process. We have presented all necessary documentation to become the qualified operator of this new block under an exploration and production license contract.
See Item 2. - “Properties” and “Liquidity and Capital Resources” included in Item 7 of this Form 10-K for further information.
Available Information
The Company files annual, quarterly and current reports, proxy statements and other documents with the Securities and Exchange Commission (“SEC”) under the Securities Act of 1934. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at Headquarters Office, 100 F Street, NE, Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file electronically with the SEC. The public can obtain any documents that we file electronically with the SEC at http://www.sec.gov. In addition, the Company maintains a website (http://www.bpzenergy.com), on which we make available, free of charge, all of the Company’s above mentioned filings with the SEC, including Forms 3, 4 and 5 filed with respect to our equity securities under Section 16(a) of the Securities Act of 1934. These filings will be available as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
Our Competition
There is intense competition in the oil and gas industry with respect to the acquisition of producing properties, undeveloped acreage, and rights to explore for these properties. Many major and independent oil and gas companies actively pursue and bid for the mineral rights of desirable properties, and many companies have been actively engaged in acquiring oil and gas properties in Peru and Ecuador.
We believe that our early efforts and knowledge of our targeted areas have given us a competitive advantage in Peru, and to a lesser extent, in Ecuador. Although there are unleased tracts within our target area, we believe that these properties may be less attractive to other companies because it will be difficult for them to obtain a significant amount of contiguous mineral acres. This results in part from our significant holdings in the vicinity of these unleased tracts. However, increased demand for license rights in surrounding areas may impact our ability to expand and grow in the future, particularly because many of our competitors have substantially greater financial and other resources, better name recognition and longer operating histories. As a result, we may not be able to acquire additional oil and gas properties in desirable locations.
There is also intense competition in the oil and gas industry for access to drilling and other contract services and experienced technical and operating personnel needed to drill and complete wells. We recently experienced difficulty obtaining a drilling rig for our planned drilling operations, but now have a drilling rig under contract. Competition for drilling and contract services in our target area is increasing and may affect our plan of operation. We periodically adjust our operating plans and timelines to adapt to this changing environment. Increasing future demand for drillers and contractors may limit our ability to execute in a timely manner and may negatively impact our ability to grow.
Regulation Impacting Our Business
General
Various aspects of our oil and natural gas operations are currently or will be subject to various foreign laws and governmental regulations. These regulations may be changed from time to time in response to economic or political conditions. Although we believe that our operations are and will be in substantial compliance with existing legislation and requirements of governmental bodies, our ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. Our principals have many collective decades of experience in dealing directly with the Peruvian government on energy projects and in some cases have been directly involved in the drafting and promulgation of petroleum legislation. Therefore we believe we are in a unique position to understand and comply with local rules and regulations. However, our current permits and authorizations and our ability to obtain future permits and authorizations may, over time, be susceptible to increased scrutiny and greater complexity which could result in increased costs or delays in receiving appropriate authorizations.
Peru
Peruvian hydrocarbon legislation. Peru’s hydrocarbon legislation, which includes the Organic Hydrocarbon Law No. 26221 and the regulations thereunder (the “Organic Hydrocarbon Law”), governs our operations in Peru. This legislation covers the entire range of petroleum operations, defines the roles of Peruvian government agencies which regulate and interact with the oil and gas industry, requires that investments in the petroleum sector be undertaken solely by private investors (either national or foreign), and provides for the promotion of the development of hydrocarbon activities based on free competition and free access to all economic activities. This law provides that pipeline transportation and natural gas distribution must be handled via contracts. All other petroleum activities are to be freely operated and are subject only to local and international safety and environment standards.
Under this legal system, Peru is the owner of the hydrocarbons located below the surface in its national territory. However, Peru has given the ownership right to extracted hydrocarbons to Perupetro, a state company that is responsible for promoting and overseeing the investment of hydrocarbon exploration and exploitation activities in Peru. Perupetro is empowered to enter into contracts for either the exploration and exploitation or the exploitation of petroleum and gas on behalf of Peru, which are described further below. The Peruvian government also plays an active role in petroleum operations through the involvement of the Ministry of Energy and Mines, the specialized government department in charge of devising energy, mining and environmental protection policies, enacting the rules applicable to all these sectors and supervising compliance with such policies and rules. Within the Ministry of Energy and Mines, the Supervising Office for Investments in Energy (“OSINERG”) is the agency charged with economic and technical supervision. We are subject to the laws and regulations of all of these entities and agencies.
Perupetro generally enters into either license contracts or service contracts for hydrocarbon exploration and
exploitation. Peru’s laws also allow for other contract models, but the investor must propose contract terms that are compatible with Peru’s interests. A company must be qualified by Perupetro to enter into hydrocarbon exploration and exploitation contracts in Peru. In order to qualify, the company must meet the standards under the Regulations Governing the Qualifications of Oil Companies. These qualifications generally require the company to have the technical, legal, economic and financial capacity to comply with all obligations it will assume under the contract based on the characteristics of the area requested, the possible investments and the environmental protection rules governing the performance of its operations. When a contractor is a foreign investor, it is expected to incorporate a subsidiary company or registered branch in accordance with Peru’s municipal laws and appoint representatives who will interact with Perupetro.
Our Peruvian branch, BPZ Energy, Inc., Sucursal Peru, has been qualified by Perupetro with respect to our current contracts. However, Perupetro reviews the qualification for each specific contract to be signed by a company. Additionally, the qualification for foreign companies is granted in favor of the home office or corporation, which is jointly and severally liable at all times for the technical, legal, economic and financial capacity of its Peruvian branch.
When operating under a license contract, the licensee is the owner of the hydrocarbons extracted from the contract area during the performance of operations, and pays royalties which are collected by Perupetro. The licensee can market the hydrocarbons in any manner whatsoever, subject to a limitation in the case of natural emergencies where the law stipulates such manner.
Licensees are obligated to submit quarterly reports to the Petroleum Bureau (Direccion General de Hidrocarburos). Licensees must also submit a monthly economic report to the Central Bank of Peru. These reports are generally combined and delivered together with other operating reports required to be submitted to Perupetro.
Previously, all license contracts were granted by the Ministry of Energy and Mines. The change to Perupetro as the license contract grantor subjects all license contracts to a new legal framework. Although there is precedent for these new licensing procedures, there may still be some uncertainly as to exactly how the licensing procedures will function in the future.
Under exploitation service contracts, the ownership of all of the extracted petroleum is vested in Perupetro and the company will receive compensation agreed to by the parties. However, Perupetro is granted the power to remunerate the investor either in cash or in kind, depending on the level of investment and the volume of production. We have no service contracts, nor do we foresee operating under this form of contract.
The duration of the license contracts is based on the nature of the hydrocarbons discovered. The contract duration for crude oil is thirty years, while the contract duration for natural gas and condensates is forty years. The periods commence on an agreed date and are determined based on location of the contract area, season of the year in which exploration commences, and other similar factors. Contracts typically include an exploration phase and an exploitation phase, unless the contract is solely an exploitation contract. Within the contract term, seven years is allotted to exploration, with the possibility of three extensions of one year each. There is also a potential deferment period for a maximum of ten years if certain factors recognized by law delay the economic viability of a discovery, such as lack of transportation facilities or lack of a market. The exploration phase is generally divided into several periods, with a maximum of seven periods, and each period includes a minimum work program. The fulfillment of work programs must be supported by an irrevocable bank guaranty, usually in the amount of thirty to forty percent of the estimated value of the minimum work program.
Perupetro also grants technical evaluation agreements. These agreements give the contractor the right to conduct technical evaluations of the areas under such agreements and to enter into license contracts if the evaluations indicate the potential for profitable operations. The technical evaluation agreement is generally for a period of twenty-four months, depending upon the volume and nature of the work to be carried out.
We currently have two license contracts and are in the process of finalizing negotiations on the terms and conditions of two additional license contracts. As of December 31, 2006, we believe we were in compliance with all of the material requirements of each of such contracts. We have executed certain letters of guaranty to guarantee our performance under the license contracts and technical evaluation agreements, including a $350,000 bond posted in August 2005, to secure our obligation under the license contract for Block XIX. The bond was partially secured by the deposit of restricted cash with the financial institution which issued the bond. Should we fail to fulfill our obligations under the license contract without technical justification or other good cause, Perupetro could seek recourse to the bond or terminate the license.
Peruvian fiscal regime. Peru’s fiscal regime determines the levels of the government’s entitlement from petroleum activities. This regime is subject to change, which could negatively impact our business.
License contracts are subject to royalty payments, which are usually a fixed percentage of the actual production sold. The taxing regulations stipulate a minimum royalty payment of five percent increasing incrementally to a maximum of twenty percent based on production.
The Organic Hydrocarbon Law and the Regulations Governing the Tax Stability Guaranty and Other Tax Rules of the Organic Hydrocarbon Law provide that the tax regime in force on the date of signing a contract will remain unchanged during the term of the contract. Therefore, any change to the tax regime, which results in either an increase or decrease in the tax burden, will not affect the operator.
During the exploration phase, operators are exempt from import duties and other forms of taxation applicable to goods intended for exploration activities. Exemptions are withdrawn at the production phase, but exceptions are made in certain instances, and the operator may be entitled to import goods tax-free for an additional two-year period.
Taxable income is determined by deducting allowable operating and administrative expenses, including royalty payments. Income tax is levied on the income of the operator based upon the legal corporate tax rate in effect at the date the contract was signed. Operators engaged in the exploration and production of crude oil, natural gas and condensates must determine their taxable income separately for each license contract under which it operates. Where a contractor carries out these activities under different individual license contracts, it may offset its earnings before income tax under one license contract with losses under another license contract, as long as the contract with the loss is in the production phase, for purposes of determining the corporate income tax.
Peruvian labor and safety legislation. Our operations in Peru will also be subject to the Unified Labor Law, which governs the labor force in the petroleum sector. In addition, the Organic Hydrocarbon Law and related Safety Regulations for the Petroleum Industry also regulate the safety and health of workers involved in the development of hydrocarbon activities. All entities engaged in the performance of activities related to the petroleum industry must provide the General Hydrocarbons Bureau on a semi-annual basis with the list of their personnel, indicating their nationality, specialty and position. These entities must also permanently train their workers on the application of safety measures in the operations, and control of disasters and emergencies. Each entity must keep detailed records of all accidents that occur in its operations and report all accidents to the General Hydrocarbons Bureau. The regulations also contain provisions on accident prevention and personnel health and safety, which in turn include rules on living conditions, sanitary facilities, water quality at workplaces, medical assistance and first-aid services. Provisions specifically related to the exploration phase, which is our current phase of operations, are also contained in the regulations and include safety measures in camps, medical assistance, food conditions, and handling of explosives. Additional safety regulations may also apply as we expand and develop our operations.
Peruvian electric power legislation. Our business plan envisions the generation of electricity and the sale of such electric power in Peru. The basic laws in Peru governing electric power, which will apply to our future operations, are the Law of Electric Power Concessions and the Regulations for the Environmental Protection of Electric Power Activities, the corresponding regulations for each, as well as additional related laws and regulations, including all legislation regarding Electric Power Tariffs and all regulations and technical norms created by the National Commission of Electric Power Tariffs.
Peruvian environmental regulation. Our operations are subject to numerous and frequently changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Peru has enacted specific environmental regulations applicable to the petroleum industry. The Code on the Environment and the Natural Resources establishes a framework within which all specific laws and regulations applicable to each sector of the economy are to be developed. These laws and regulations are designed to ensure the continual balance of environmental and petroleum interests. The regulations stipulate certain environmental standards expected from contractors. They also specify appropriate sanctions to be enforced by the Ministry of Mines and Energy if a contractor fails to maintain such standards. The Ministry of Mines and Energy is charged with the responsibility of issuing the applicable standards. OSINERG is responsible for ensuring compliance with applicable environmental rules covering hydrocarbon activities.
The Organic Hydrocarbon Law also addresses the environmental regulatory regime in Peru. The law originally prohibited any mining or extractive operations within certain areas designated for protection. It was, however, subsequently modified to enable investors to prospect for hydrocarbons within protected areas, provided there is compliance with several obligations. We must comply with these obligations as we conduct our business on an ongoing basis. The Environmental Regulations for Hydrocarbon Activities provide that companies participating in the implementation of projects, performance of work and operation of facilities related to hydrocarbon activities, are responsible for the emission, discharge and disposal of wastes into the environment. Companies must annually file a report corresponding to the previous year describing the company’s compliance with the environmental legislation in force.
Companies involved in hydrocarbon activities must also prepare and file an Environmental Impact Study (“EIS”) with the General Hydrocarbons Bureau, which is part of the Ministry of Energy and Mines, in order for the relevant activities to comply with the maximum permissible emission limits set forth by the Ministry of Energy and Mines. An EIS must be prepared for each project to be carried out. All of these proposals must be approved by the General Environmental Bureau, which is also part of the Ministry of Energy and Mines.
In addition, any party responsible for hydrocarbon activities must file an “Oil Spill and Emergency Contingency Plan” with the General Hydrocarbons Bureau. The plan must be updated at least once a year and must contain information regarding the measures to be taken in the event of spills, explosions, fires, accidents, evacuation, etc. It must also contain information on the procedures, personnel and equipment required to be used and procedures to be followed to establish uninterrupted communication between the personnel, the government representatives, the General Hydrocarbons Bureau and other State entities.
Peru has recently enacted amendments to its environmental law, imposing substantial restrictions on the use of natural resources, interference with the natural environment, location of facilities, handling and storage of hydrocarbons, use of radioactive material, disposal of waste, emission of noise and other activities. Additionally, the laws require monitoring and reporting obligations in the event of any spillage or unregulated discharge of hydrocarbons.
Any failure to comply with environmental protection rules, the import of contaminated products, or failure to keep a monitoring register or send reports to the General Hydrocarbons Bureau in a timely fashion, could subject the company to fines. In addition, the General Hydrocarbons Bureau may consider imposing a prohibition or restriction of the relevant activity, an obligation to compensate the aggrieved parties and/or an obligation to immediately restore the area. The company responsible for any default can also be subject to a suspension of operations for a term of one, two or three months, or indefinitely. Furthermore, any contract signed with the Peruvian government, the implementation of which jeopardizes or endangers the protection or conservation of protected natural areas, can be terminated.
We are subject to all Peruvian environmental regulations applicable to the petroleum industry now in existence and those existing in the future. The enactment and enforcement of environmental laws and regulations in Peru is relatively new. We are therefore uncertain how Peruvian authorities will enforce and supervise environmental compliance and standards. Further, we cannot predict any future regulation or the cost associated with future compliance.
Although we believe that our operations are in substantial compliance with existing environmental requirements, our ability to conduct continued operations is subject to satisfying applicable regulations. Our current permits and authorizations and ability to obtain future permits and authorizations may be susceptible, on a going forward basis, to increased scrutiny, greater complexity resulting in increased costs, or delays in receiving appropriate authorizations. In particular, we may experience in the future delays in obtaining permits and authorizations in Peru necessary for our operations. We are required to obtain an environmental permit or approval from the government in Peru prior to conducting any seismic operations, drilling a well or constructing a pipeline in Peruvian territory, including the waters in offshore Peru where we intend to conduct oil and gas operations.
Compliance with Existing Legislation in Peru
Although we believe that our operations are and will be in substantial compliance with existing legislation and requirements of Peruvian governmental bodies, our ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. As noted above, our principals have many collective decades of experience in dealing directly with the Peruvian government on energy projects and in some past cases have been directly involved in the drafting and promulgation of petroleum legislation. Therefore, we believe we are in a good position to understand and comply with local rules and regulations.
Ecuador
SMC Ecuador, Inc. has had its 10% non-operating interest in the Santa Elena oil fields since 1997. As a non-operator, we are not directly subject to the laws and regulations of Ecuador covering the oil and gas industry and the environment. However, if we begin operating activities in Ecuador, we will be directly subject to such laws and regulations.
Environmental Compliance and Risks
As an owner or lessee and operator of oil and gas properties throughout South America, we are subject to various national, state and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the contractor under an oil and gas license agreement for the cost of pollution clean-up resulting from operations, subject the contractor to liability for pollution damages, and require
suspension or cessation of operations in affected areas.
Except for certain pollution coverage related to our barge, we do not presently maintain environmental insurance coverage, because, in management’s judgment, such coverage is not cost-effective at this time in view of our limited activities. However, we may acquire such insurance coverage in the future based on our assessment of the risks of our operations and the costs of such coverage. No such coverage can insure us fully against all environmental risks. We are not aware of any environmental claims existing which would have a material impact upon our financial position or results of operations.
We have made and will continue our efforts to comply with these requirements, which we believe are necessary to successful long-term operations in the oil and gas industry. We have established guidelines for continuing compliance with environmental laws and regulations. In order to carry out our plan of operation, we are required to conduct environmental impact studies and obtain environmental approvals for operations. We have engaged outside consultants to perform these studies and assist us in obtaining necessary approvals. Our estimated cost for these studies and assistance related to the Corvina gas-to-power project, Block XIX and Albacora are approximately $522,000, of which $488,000 has been incurred as of December 31, 2006.
We do not believe that compliance with federal, state or local provisions regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, will have a material adverse effect upon the capital expenditures, earnings or competitive position of the Company or its subsidiaries. However, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not have such an impact.
Operational Hazards and Insurance
Our operations will be subject to the usual hazards incident to the drilling and production of oil and gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution, releases of toxic gas and other environmental hazards and risks. These hazards can cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations.
As is common in the oil and natural gas industry, we do not insure fully against all risks associated with our business either because such insurance is not available or because premium costs are considered prohibitive. We currently have general liability insurance coverage which we believe is adequate for our current stage of operations based on management’s assessment. Such insurance may not cover every potential risk associated with the drilling, production and processing of oil and gas. In particular, coverage is not obtainable for all types of environmental hazards. Additionally, the occurrence of a significant adverse event, the risks of which are not fully covered by our insurance policy, could have a material adverse effect on our financial condition and results of operations. Moreover, no assurance can be given that we will be able to maintain adequate insurance or increase current coverage amounts at rates we consider reasonable.
Research and Development
We seek to use advanced technologies in the evaluation of our oil and gas properties and new opportunities. We generally do not develop such technologies internally, but our technical team works with outside vendors to test and utilize these technologies to the fullest practical extent, particularly in the application of geophysical and exploration software. In certain cases, our collaboration has aided the development of these technologies. We do not believe we have incurred any quantifiable incremental costs in connection with research and development activities.
Executive Officers
The following table sets forth the names of our chairman and executive officers along with their positions and ages, as of December 31, 2006. The chairman has served since his appointment in September 2004.
(1) Appointed to their respective positions on October 30, 2006.
Dr. Zúñiga y Rivero, Chairman of the Board, is the father of the Company’s President, CEO and Director, Mr. Zúñiga-Pflücker. No other family relationships exist between any directors or executive officers of the Company. Set forth below are brief descriptions of the recent employment and business experience of the officers and directors of the Company.
Dr. Fernando Zúñiga y Rivero, Chairman of the Board. Dr. Zúñiga y Rivero became Chairman of the Board of BPZ upon consummation of the Merger with Navidec, Inc. in September 2004. Immediately prior to the Merger and since 1996, he served as Chairman of BPZ & Associates Inc., (the former parent company of BPZ-Texas), which has been inactive subsequent to the Merger. Dr. Zúñiga y Rivero was also Energy Division project officer of The World Bank, where he planned and implemented exploration promotion projects in 58 countries, primarily in East and West Africa, Eastern Europe, Southeast Asia and Latin America from 1979 to 1996. Dr. Zúñiga y Rivero has fifty years of experience in the international energy industry starting as an exploration geologist, biostratigrapher, and exploration head of an Exxon affiliate in Peru; and continuing as exploration production manager, integrated operations manager, general manager, and ultimately serving as Chairman and CEO of Petroleos del Peru, the national oil company of Peru. Dr. Zúñiga y Rivero holds a B.S., a M.S. and a Ph.D. in Geology from the University of San Augustin, Peru, and he conducted postgraduate studies at the University of California, Los Angeles. In April 2005, Dr. Zúñiga y Rivero became a director of Transmeridian Exploration, Inc., a public oil and gas company with operations in Kazakhstan.
Manuel Pablo Zúñiga-Pflücker, President, Chief Executive Officer and Director. Mr. Zúñiga-Pflücker became President and Director of BPZ upon consummation of the Merger with Navidec, Inc. in September 2004 and in May 2005 assumed the additional title of Chief Executive Officer. Immediately prior to the Merger and since its formation in 2001, Mr. Zúñiga-Pflücker served as President of BPZ-Texas. Mr. Zúñiga-Pflücker also served as President of BPZ & Associates, Inc., the former parent company of BPZ-Texas, from 1989 until its Merger with Navidec, Inc. in September 2004, at which time BPZ & Associates, Inc. became inactive. Mr. Zúñiga-Pflücker began his career with Occidental Petroleum Corporation. Mr. Zúñiga-Pflücker has spent the past 20 years in the international oil and gas business, and he has been involved in projects throughout Latin America and other areas of the world ranging from exploitation of marginal oil and gas fields to frontier exploration projects. He has also focused on the creative development of natural gas fields utilizing power generation and gas to liquids technology. He holds a B.S. in mechanical engineering from the University of Maryland as well as an M.S. in petroleum engineering from Texas A&M University.
Frederic Briens, Chief Operating Officer. Mr. Briens joined BPZ as Vice President of Engineering in December 2004 and was named Chief Operating Officer in May 2005. From 2002 through 2004, Mr. Briens served as Geosciences and Business Development Manager for Perenco in Venezuela. From 1999 to 2002, Mr. Briens was the Chief Reservoir Engineer for Lundin Petroleum in Switzerland. Mr. Briens is a petroleum engineer with over 20 years of operating experience in international oil and gas projects spanning the globe. He has also served in senior technical and operating positions with Conoco, Schlumberger and Chevron. Mr. Briens holds an M.S. and a Ph.D. in petroleum engineering from Texas A&M University, an MBA from Colorado State University and an engineering degree from Ecole Centrale de Paris. Mr. Briens was a co-founder of BPZ & Associates, Inc., a predecessor to the Company, in 1989.
Edward G. Caminos, Vice President-Finance and Chief Accounting Officer. Mr. Caminos was appointed as Vice President-Finance and Chief Accounting Officer of the Company, effective October 30, 2006. Mr. Caminos served as interim Chief Financial Officer since June 15, 2006 and as Corporate Controller of the Company since January 2005. Prior to joining the Company, Mr. Caminos served as Director Financial Reporting for the Americas Division at Duke Energy from June 2004 to January 2005. From February 2001 to May 2004, Mr. Caminos served as Financial Reporting Manager and, prior to its sale, as interim Controller for the Europe Division, at Reliant Energy.
Edward Gilliard, Vice President-Finance and Treasurer. Mr. Gilliard was appointed as Vice President-Finance and Treasurer of the Company, effective October 30, 2006. Mr. Gilliard started his career in 1977 with Amoco Production Company as an operations and reservoir engineer. He worked in energy lending and project financing with Continental Illinois National Bank, Banque Indosuez, and Reliant Energy International, formerly Houston Industries Energy, where he worked on project financing for power projects in South America, as well as other regions. In 1997, he joined Burlington Resources and worked in areas such as international finance, strategic planning, business development, and governmental affairs. In the latter capacity, Mr. Gilliard was a lead editor on the National Petroleum Council’s 1999 and 2003 landmark studies on natural gas. He holds a Bachelor’s Degree in Chemical Engineering from Texas A&M University and an MBA from the University of Houston.
Employees
As of December 31, 2006, we employed 18 full-time employees (of which 3 are executive officers) in our Houston office and 14 full-time employees (of which 1 is an executive officer) in our Lima, Peru office. We had one full-time employee in the Quito, Ecuador office. BPZ believes that its relationship with its employees is satisfactory. None of our employees are
represented by a union.
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 activities. Although BPZ-Texas was formed in 2001, we are in the exploratory stage because we have not had significant business operations since formation and have generated no revenues from the production of oil or gas from our properties. 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. 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 are initially 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. Accordingly, we are subject to the risk that because of these factors and other general business risks noted throughout these “Risk Factors,” we may not be able to profitably execute our power generation strategy.
We own rights to oil and gas properties that have not yet been developed. 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.
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. With the net proceeds from: (i) a $6 million private offering completed on September 30, 2004, (ii) a $34.4 million private offering completed on July 19, 2005, (iii) a $5.0 million private offering on March 10, 2006, (iv) a $12.3 million private offering on June 20, 2006, and (v) $19.5 million private placement to the International Finance Corporation (“IFC”) on December 20, 2006, we have begun to implement our plans to develop our existing oil and gas properties as discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Plan of Operation.” On December 20, 2006, the International Finance Corporation’s (“IFC”) Board of Executive Directors approved a $120 million financial package. IFC is the private sector arm of the World Bank Group based in Washington, D.C. As part of the financing, we completed a private placement of 6,500,000 shares of common stock, no par value, to the IFC pursuant to a Subscription Agreement dated December 18, 2006. The common stock was priced at $3.00 per share resulting in proceeds to us of approximately $19.5 million. The offering was placed directly by us and there were no placement fees. The remaining $100.5 million portion of IFC financing consists of $30.5 million of debt facilities for IFC’s own account and $70 million of debt facilities for the account of third-party financial institutions. Syndication of the third-party debt component is expected to take place during the second quarter of 2007. The remaining debt portion of the financing is subject to identification of the lending syndicate members and subsequent negotiation and approval of the necessary loan documentation. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” for further discussion. If we are unable to timely obtain adequate funds to finance our exploration and development, our ability to develop our oil and 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. 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.
We anticipate that future amounts required to fund our foreign activities will be obtained through debt financing, sale of additional equity interests, joint venture arrangements, the sale of oil and gas interests, and/or future cash flows from operations. 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.
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 and acquire 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. There can be no assurance that once in operation 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, or we may not be able to make a profit from the reserves that we may discover.
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, both geological and market-related, 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 hurricanes 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;
· environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
If we experience any of these problems, any well bores, platforms, gathering systems and processing facilities could be affected, which could adversely affect any drilling operations we may commence. We could also incur substantial losses as a result of:
· environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
· 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 investigation and penalties;
· suspension of our operations; and
· repairs to resume operations.
If any of these risks occur, and our resulting losses are significant, we may have to curtail or suspend any drilling or production operations we may eventually commence.
We plan to 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 capsizing, collisions and damage or loss from adverse weather conditions or interference from commercial fishing activities. These conditions can cause substantial damage to facilities and interrupt production. 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 deck barge could temporarily impair our operations. We depend on our deck barge BPZ-01 to transport equipment to our offshore platforms and to act as a tender for our offshore drilling operations in Block Z-1. BPZ-01 is an important element in our strategy to control drilling costs by allowing the use of existing platforms and avoiding the use of high-priced drill ships or barges. Any disruption of the services provided by our deck barge 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 drilling costs. In addition, our insurance may not be adequate to cover any resulting losses.
Construction and operation of power generation and gas processing facilities and pipelines involve significant risks that cannot always be covered by insurance or contractual protections. The construction of power generation and gas processing facilities 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, and
· unanticipated cost overruns.
The ongoing operation of these facilities involves 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 expense and higher maintenance costs.
Our success depends on the existence and growth of markets for natural gas and electricity in Peru and Ecuador. Peru has a relatively well-developed and stable market for electricity, while the power market in Ecuador is not as well-developed or stable. Both countries rely on hydro-electric generating capacity for a significant portion of their power demand. Hydro 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-hydro, or thermal, power capacity in both countries consists of generating plants that utilize diesel or fuel oil, which are significantly more costly than natural gas at this time. Both countries have natural gas reserves and production, but neither has a well-developed natural gas infrastructure. Our immediate business plan relies on the continued stability of the power market in Peru (and Ecuador for the purpose of gas sales to third-party power producers in Ecuador), and our longer-term plans depend on the further development of the electricity market in Ecuador. We are subject to the risks that relatively more favorable business conditions for hydro plants or other competitive issues may adversely affect the demand and prices for the electricity that we expect to produce. We are also subject to the risks associated with potential disruptions or changes to regulations of the natural gas or power markets in these countries. We plan to enter into long-term contracts to sell a significant part of our future power production. A market for long-term purchases of power and natural gas exists, but there can
be no assurance that we will be successful in obtaining such contracts on favorable terms. 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:
· 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 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.
Instability of International Operations. 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, 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.
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 than in the United States. The oil and gas industries in Peru and Ecuador are not as developed as the oil and gas industry in the United States. As a result, 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, specific equipment and supplies may be more limited in Peru and Ecuador than in the United States. Further, once oil and natural gas production is recovered, there are fewer ways to transport it to market for sale. 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.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute our exploration and exploitation plans on a timely basis and within our budget. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our exploitation and exploration operations, which could have a material adverse effect on our business, financial condition or results of operations. If the unavailability or high cost of rigs, equipment, supplies or personnel were particularly severe in Peru and Ecuador, we could be materially and adversely affected because our operations and properties are concentrated in those areas.
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 and the development, production and transportation of oil and natural gas as well as electrical power generation. Future laws or regulations, 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. We may be required to make large and unanticipated capital expenditures to comply with governmental regulations, such as:
· work program guarantees and other financial responsibility requirements;
· taxation;
· royalty requirements;
· customer requirements;
· operational reporting; and
· safety requirements.
Under these laws and regulations, we could be liable for:
· personal injuries; and
· property and natural resource damages; and
· governmental infringements and sanctions.
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 license contracts and technical evaluation agreements, require that we perform certain activities, such as seismic interpretations and the drilling of required wells in accordance with those contracts and agreements. Our failure to timely perform those activities as required could result in the loss of our rights under a particular contract or the loss of the amounts we have posted as a guaranty for the performance of such activities, which would likely result in a significant loss to us.
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 are subject to extensive environmental 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 in offshore Peru, where we intend to conduct future oil and gas operations. Additionally, recent environmental laws and regulations promulgated in Peru impose substantial restrictions on the use of natural resources, interference with the natural environment, location of facilities, handling and storage of hydrocarbons, use of radioactive material, disposal of waste, emission of noise and other activities. The laws create additional monitoring and reporting obligations in the event of any spillage or unregulated discharge of 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 and Ecuador necessary for our operations. 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. Failure to comply with new regulations could cause us to suspend or terminate certain operations or subject us to administrative, civil and 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 discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, 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, subject the owner or lessee to liability for pollution damages and other environmental damages, and require suspension or cessation of operations in affected areas.
We have established practices for continued compliance with environmental laws and regulations. We believe the costs incurred by these policies and procedures are necessary business costs in the oil and gas industry. 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. 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 leases uneconomical. This could result in a total loss of our investment. In addition, the cost and timing of drilling, completing and operating wells is often uncertain.
Competition for oil and natural gas properties and prospects is intense; some 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. 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. We actively compete with other companies in our industry when acquiring new leases or oil and gas properties. For example, if several companies are interested in an area, Perupetro 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 divesting 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. 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 upon 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.
Insurance does not cover all risks. Exploration for, and 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 or the environment. 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 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 and reservoir loss or damage. 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 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 operations until such time as replacement capital is obtained, if ever, and this could have a material impact on our financial position.
A substantial or extended decline in oil and 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. 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. Oil and natural gas are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. 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 beyond our control. Those factors include:
· international political conditions (including wars and civil unrest);
· 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 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.
We may not be able to develop a proven reserve base. 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, except to the extent that we conduct successful revitalization activities, or are able to acquire 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. Our current strategy is to develop a reserve base, production and cash flow through the development of oil and gas fields to which we have development rights and selective acquisitions of other desirable oil and gas properties where we can utilize new and existing technology. We can give no assurance that our planned development, revitalization, and acquisition activities will result in significant reserves or that we will have success in discovering and producing reserves at economical exploration and development costs. 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 them.
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 during our exploratory stage of operations totaling $37,799,937 through December 31, 2006. To date we have not had any revenue or earnings from operations, and we will continue, in all likelihood, to sustain operating expenses without corresponding revenues until we are able, if ever, to successfully implement our plan of operation.
Additional infusions of capital may have a dilutive effect on existing shareholders. To finance our operations we plan to sell additional shares of our stock. Any additional equity financing that we receive may involve substantial dilution to our then-existing shareholders. Furthermore, we may issue 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.
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, 2006, we had 54,143,717 shares of common stock issued and outstanding. In December, 2006, we filed a Registration Statement on Form S-1 for the resale of 6,500,000 shares of common stock issued to the IFC. This registration statement has not been declared effective by the SEC as of the date of this filing. In addition, we have outstanding 14,006,152 shares of other potentially dilutive securities, which includes 9,450,000 common shares, which may be issued to the former shareholders of BPZ-Texas and two executive officers on an earn-out basis once we are entitled to receive as our proportionate share from gross production from any oil and gas wells owned or operated by us, not less than 2,000 barrels of oil per day or its equivalent (approximately 12 million cubic feet of gas per day) prior to December 28, 2007. We also have an additional 1,156,000 common shares available under our Long-Term Incentive Compensation Plan. 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.
We are controlled by our officers, directors and entities affiliated with them. In the aggregate, our management and directors own or control approximately 13.4% of our common stock issued as of December 31, 2006. These shareholders, if acting together, will 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.
The transfer of NFS could result in liability to us because the shares transferred were not registered with the SEC. On September 9, 2004, the day prior to the effective date of the Merger, Navidec assigned all of its pre-merger business operations, assets and liabilities to NFS, and all issued and outstanding shares of NFS were subsequently transferred to the Navidec pre-merger shareholders of record as of September 9, 2004 for no cash consideration. Pursuant to the terms of the Merger Agreement, the transfer and any necessary qualifications or registrations of the NFS shares under applicable securities laws was agreed to be handled by NFS, and we believed, based on information provided by NFS and its advisors, that NFS had undertaken the necessary actions to comply with applicable registration requirements. On July 13, 2006, NFS filed a Registration Statement on Form 10SB with the SEC and an amendment thereto on October 27, 2006. It is our understanding that this Registration Statement has become effective under applicable SEC rules. However, because a registration of the NFS shares was not effective at the time of the transfer of the NFS shares, it might be determined that the distribution of the NFS shares was made without full compliance with applicable registration or qualification requirements under applicable securities laws. As a result, although we took no actions in connection with the transfer, we might incur liability, as a successor to Navidec, by merger, with respect to any damages resulting from such failure to register. If, despite the fact that we did not control the transfer of the NFS shares, regulatory authorities determine that we did not comply with applicable registration requirements with respect to the transfer, fines or other sanctions might be imposed on us.
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 7,770 square feet of office space under a five-year lease which expires on September 30, 2010. We also maintain administrative offices in Lima, Peru of 3,700 square feet and Quito, Ecuador of 829 square feet, both under month-to-month leases.
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 and Block XIX. The license contracts afford an initial exploration period of seven to thirteen years and, if exploration efforts are successful, provide a total contract term of up to 40 years for gas exploration and production and up to 30 years for oil exploration and production. We also are currently in negotiations to obtain license contracts for Blocks XXII and XXIII. These four blocks cover a combined area of approximately 2.4 million acres.
The following table is a summary of our properties in northwest Peru. All acreage is considered undeveloped.
(a) License Contract
(b) Negotiating license contract
Description of Block Z-1 and License Contract
Block Z-1, a coastal offshore area encompassing 739,205 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 only 10% of the area has depths greater than 500 feet. Located within Block Z-1 are five structures which were drilled in the 1970’s and 1980’s by previous operators, including Tenneco, Inc. and Belco Oil and Gas Corporation. These structures are known as the Albacora, Barracuda, Corvina, Delfin and Piedra Redonda fields. Wells drilled in each of these structures encountered hydrocarbons, principally natural gas, 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.
We originally acquired our initial interest in Block Z-1 in a joint venture with Syntroleum Corporation, 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 in the block. Syntroleum later transferred its interest to Nuevo Energy, Inc. 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, which is divided into four periods, and can be extended under certain circumstances up to an additional six 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 second exploration period. During the second exploration period, we must drill at least one exploratory well or acquire 300 square kilometers of seismic data. We posted a $1.3 million performance bond in January 2005 in connection with the second exploration period which was originally scheduled to last for 24 months and end in July 2006. However, permission was granted to extend the second exploration period to May 2007 to compensate for the delay by the Ministry of Energy and Mines in approving our Environmental Impact Study. In December, 2006 the $1.3 million performance bond and related cash posted as collateral was released. The third exploration period is scheduled to begin in May 2007 and expire in November 2008. It will require the drilling of an additional exploratory well or other equivalent work commitments and will require a performance bond of $1.0 million. The fourth and final exploration period is scheduled to begin in November 2008 and expire in November 2009. It will also require the drilling of an additional exploratory well or other equivalent work commitments and will require a performance bond of $1.0 million. The performance bond amounts are not cumulative, and are 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 of $50,000 per year.
The exploitation, or development period of the contract will commence as soon as we declare a commercial discovery and receive approval for a field development plan. We must declare a commercial discovery no later than the end of the last exploration period, including any extensions or deferments. 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. Royalties under the contract vary from 5% to 20% based on production volumes.
Description of Block XIX and License Contract
Block XIX covers approximately 472,860 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.
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 three 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. Royalties under the contract vary from 5% to 20% based on production volumes.
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 second exploration period, which is scheduled to end in August 2007, unless an extension of up to six months to complete the work commitment is requested. During the second exploration period, we are required to acquire and interpret 100 kilometers of new 2-D seismic data and to conduct certain integrated geological, geophysical, geochemical and reservoir engineering evaluation studies. In connection with the second exploration period, we posted a $350,000 performance bond in August 2005. The third exploration period is scheduled to begin in August 2007 and will require a performance bond of $585,000. The fourth exploration period is scheduled to begin in November 2008 and will require a performance bond of $585,000. The fifth and final exploration period is scheduled to begin in February 2009 and 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. The exploitation, or development, period of the contract will commence as soon as the Company declares a commercial discovery and receives approval for a field development plan. We must declare a commercial discovery no later than the end of the last exploration period, including any extensions or deferments.
Description of 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 948,000 acres. The Lancones Basin is primarily an exploratory area and has had limited drilling and seismic activity. In December 2005, the Company notified Perupetro that it had decided to exercise its exclusive option to convert its Technical Evaluation Agreement on Block XXII (formerly known as Area VI), into a license contract. In March 2006, the Company was notified by Perupetro that it qualified as an operator for Block XXII. The negotiations on the license contract are still underway and the Company does not have sufficient information to determine the timing nor estimate the value of the various obligations and commitments in connection with this property.
Description of Block XXIII
In July 2006, Perupetro informed the Company that its proposal for Block XXIII, which consists of approximately 248,000 acres and is located onshore in northwest Peru between the Company’s Blocks Z-1 and XIX, was the winning bid in their recent tender process. The Company has presented all necessary documentation to become the qualified operator of this new block under an exploration and production license contract. The Company’s proposal covers only the exploration period and commits the Company to drill a certain number of wells, acquire certain amount of either 2-D or 3-D seismic data and prepare an integrated geological, geochemical and reservoir engineering evaluation of the hydrocarbon prospects in the block. In connection with this block, after the license contract has been signed, the Company will have to post a performance bond to guarantee its various obligations and commitments. However, as the negotiations on the license contract are still underway, the Company does not have sufficient information to determine the timing, nor to estimate the value of the performance bond to be posted in connection with this property.
Oil and Gas Resources
During 2004, we retained Gaffney Cline & Associates, Inc. (“GCA”), an internationally recognized firm of independent reserve engineers, to evaluate the oil and gas resource potential of the Corvina and Piedra Redonda Fields in the Block Z-1 license contract area. GCA focused its evaluation on the wells that were drilled by previous operators of Block Z-1 and the seismic and other geological and geophysical data available on the block.
In the Corvina Field, five wells were drilled, including two wells drilled by Tenneco, Inc. in the mid-1970’s and three wells drilled by Belco Oil and Gas Corporation (“Belco”) in the late 1970’s and early 1980’s. Two drilling and production platforms were set up by Belco during this period and are still in place in the Corvina Field. The platforms need to be repaired and refurbished, but they are structurally sound, and we believe they are suitable for our future operations. All seven wells in the
Corvina Field encountered indications of natural gas and apparent reservoir-quality formations, although only one of the wells, the CX11-16X, was completed and tested. At the time these wells were drilled, there was no commercial market for natural gas in the region. The CX11-16X produced natural gas at rates as high as 16.6 million cubic feet of gas per day (“MMcf/d”) during two separate tests over a period of approximately 20 days each. The well was temporarily abandoned. We believe this well can be reestablished as a producing well.
In the Piedra Redonda Field, two wells were drilled by Belco in the late 1970’s and early 1980’s. 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. A previously constructed drilling and production platform is still in place in the Piedra Redonda Field. The completed well in the Piedra Redonda Field, the C18X, produced natural gas at rates as high as 8.3 MMcf/d over a period of approximately 20 days during an extended test in 1979 and was also temporarily abandoned. We believe this well can be reestablished as a producing well.
GCA reviewed all available technical data available with respect to the Corvina and Piedra Redonda Fields, including a large volume of 2-D seismic data, well logs, drilling and completion reports, well test information, and other geological and geophysical data and analysis. The Company intends to develop these resources as discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The development of these resources will require a significant financial investment which is presently estimated to be in excess of $132.3 million. We do not currently have the financial capacity or commitments for a development program of this magnitude. Accordingly, the Company has not disclosed amounts of proved reserves in its SEC filings. At such time as we obtain sufficient financial commitments to proceed with the full development of Block Z-1 and all other conditions necessary to record proved reserves are met, we expect to record SEC proved reserves as permitted under SEC rules and disclose such reserves in future SEC filings.
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 working 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. The license contract provides for royalty payments equal to 23% of production. There have been almost 3,000 wells drilled in the field since production began in the 1920’s. Currently, there are approximately 1,250 active wells which produce approximately 2,000 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 license agreement covering the property extends through May 2016.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
SEC Inquiry of Navidec
Navidec was advised in February 2004 that the SEC was conducting an informal inquiry to determine whether Navidec had violated federal securities laws.. Based on information available to us, we believe the SEC’s investigation relates, at least in part, to the restatement of Navidec’s reported earnings for the first and second quarters of 2003. This restatement was reported in Navidec’s Form 10-Q for the third quarter of 2003 filed on December 11, 2003.
In December 2004, we received notice that the SEC had issued an Order Directing a Private Investigation and Designating Officers to Take Testimony and would be conducting a formal investigation. We have cooperated fully with the SEC in this matter. Pursuant to the Merger agreement, we have been indemnified by NFS for the costs of the SEC investigation, and NFS has borne the costs incurred to date. We are not aware of the future actions, if any, which the SEC intends to pursue in this matter, but no assurance can be given that the investigation has been and will be resolved without negative consequences to the Company.
Transfer of Ownership in NFS
On July 8, 2004, Navidec and BPZ-Texas entered into a Merger Agreement which was consummated on September 10, 2004. The Merger Agreement provided that all of the pre-merger business operations, assets and liabilities of Navidec would be transferred to a wholly-owned subsidiary, Navidec Financial Services, Inc. (“NFS”), followed by the transfer of NFS to the pre-merger shareholders of record as of September 9, 2004, the day prior to the consummation of the Merger. See “Business and Properties-Navidec Merger Transaction,” “Risk Factors-Risk Relating to the Offering-The transfer of NFS could result in liability to us because the shares transferred were not registered with the SEC,” and Note 2 to the Consolidated Financial Statements, included in this filing, for detailed discussion regarding the Merger.
The Merger Agreement provided that the transfer of all of the pre-merger business operations, assets and liabilities of NFS was effective as of September 9, 2004. Accordingly, the Company originally believed that it had no continuing ownership of NFS and, therefore, did not account for the post-merger operations of NFS in the presentation of its financial statements. After receipt of comments from the SEC in connection with its review of the Company’s registration statement on Form SB-2 originally filed on July 27, 2005 and further review of this issue, the Company concluded it was the record, but not beneficial, owner of NFS shares, and that any ownership interest was at most temporary.
In part because of difficulty obtaining necessary information from NFS to clarify the ownership issue, the Company commenced an action against NFS (the “Action”) on or about February 13, 2006, in District Court, Arapahoe County, Colorado (the “Court”), seeking dissolution of NFS, the appointment of a receiver, and access to NFS corporate records. The Company commenced the Action uncertain whether or when the required spin-off of NFS shares pursuant to the terms and conditions of the Merger had occurred under Colorado corporate law. The Company asserted in the Action that it believed it was a record shareholder of NFS as of the date of the request and had standing for the relief sought. NFS denied that the Company had standing to act as a shareholder and asserted that the Company had not been a shareholder of NFS since September 9, 2004. The Action was settled amongst the parties on May 19, 2006. In connection with the settlement, a Finding of Fact and Conclusions of Law (the “Order”) was issued by the Court stating that the Company was not a shareholder of NFS at any time after September 9, 2004.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECUTITY HOLDERS
There were no matters submitted to a vote of stockholders during the fourth quarter of the fiscal year covered by this Form 10-K.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information
Our Common Stock began trading on the American Stock Exchange (“AMEX”) under the symbol “BZP”, on January 12, 2007. Prior to trading on the AMEX, our Common Stock traded on the OTC Bulletin Board under the symbol “NVDC” beginning on Wednesday, August 20, 2003. In connection with the Merger, we changed our name to BPZ Energy, Inc. and began trading under the symbol “BPZI” on February 7, 2005, also on the OTC Bulletin Board. On December 27, 2005, as a result of a delay in filing our quarterly report on Form 10-Q for the quarterly period ended September 30, 2005, the Company became ineligible for trading on the OTC Bulletin Board and began trading on the Pink Sheets under the symbol “BPZI.”
The following table sets forth, for the periods indicated, the high and low prices of a share of our Common Stock as reported on OTC Bulletin Board and the Pink Sheets for the applicable time periods. The quotations provided for the over the counter market reflect interdealer prices without retail mark-up, mark-down or commissions, and may not represent actual transactions.
Holders
As of February 27, 2007, we had approximately 338 shareholders of record, plus an estimated 3,978 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 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.
Equity Compensation Plan
The BPZ Energy, Inc. 2005 Long-Term Incentive Compensation Plan (the “LTIP” or “Plan”) permits our Board of Directors to award eligible employees, directors and consultants with incentive-based and non-incentive-based compensation.
Recent Sales of Unregistered Securities
On July 1, 2005 the Company issued 9,000,000 shares of common stock to the former shareholders of BPZ-Texas in connection with earn-out provisions in the Merger Agreement. This transaction is more fully described in “Business and Properties-Navidec Merger Transaction” included herein.
On July 1, 2005, the Company issued 250,000 shares of common stock to acquire a 4% net working interest in the Santa Elena Property in Ecuador from an individual who had received the interest in connection with financing provided to the Company for the original acquisition of the property in June 2004.
On July 19, 2005, the Company completed a private placement of 11,466,000 shares of common stock, no par value, pursuant to a Stock Purchase Agreement dated July 19, 2005. The common stock was priced at $3.00 per share, which resulted in gross proceeds to the Company of approximately $34.4 million. Net proceeds from the private placement were approximately $31.9 million. For its services as placement agent in connection with the transaction, Morgan Keegan & Company, Inc. received 7% of the gross proceeds from the offering and warrants to purchase 100,000 shares of the Company’s common stock at an exercise price of $3.00 per share. Such warrants expire on July 19, 2010.
On September 30, 2005, the Company issued 15,000 shares of common stock to an individual for financial management and consulting services performed.
On December 31, 2005, the Company issued 10,000 shares of common stock to an individual for legal consulting services performed.
On March 10, 2006, the Company completed a private placement of 1,670,000 shares of common stock, no par value, to four institutional and accredited investors pursuant to a Stock Purchase Agreement. The common stock was priced at $3.00 per share resulting in proceeds to the Company of $5,010,000.
On May 21, 2006, the Company issued 10,000 shares, pursuant to a service agreement, to a consultant for legal and business advisory services rendered in Peru.
On June 30, 2006, the Company completed a private placement of common stock for proceeds of $12,325,500. The proceeds were received in July 2006. The Company sold 4,482,000 shares to eight institutional and accredited investors at a price of $2.75 per share. There were no warrants or dilutive securities issued to the investors in connection with the offering. The offering was placed directly by the Company, and there were no placement fees. However, the Company issued warrants to purchase 150,000 shares of the Company’s common stock to Morgan Keegan & Company, Inc. in consideration for their financial advisory services related to this private placement.
In connection with the July 19, 2005 private placement, as discussed above, the Company was obligated to prepare and file with the SEC a registration statement and to use its best efforts to cause the registration statement to be declared effective by the SEC no later than ninety days from July 19, 2005. The registration statement was not declared effective by the required dates, and the Company became liable to the investors for liquidated damages in an amount equal to 1.0% of the purchase price of the shares, approximately $343,980, for each thirty day period until the registration statement was declared effective by the SEC. Certain of the private placement investors, totaling 79% of the aggregate investment, have agreed to accept common stock in lieu of cash for a maximum period of 90 days. Accordingly, 867,609 shares of common stock have been issued, as of October 30, 2006, to those certain investors for liquidated damages for the period of December 16, 2005 through October 13, 2006. On November 8, 2006, the SEC declared effective the Registration Statement on Form S-1 covering the common shares issued in connection with the July 19, 2005, March 10, 2006, and June 30, 2006, private placements. As a result, the Company is no longer subject to the liquidated damages described above.
In connection with the March 10, 2006 private placement, as discussed above, the Company was obligated to prepare and file with the SEC a registration statement within sixty days, and to use its best efforts to cause the registration statement to be declared effective by the SEC no later than ninety days, from March 8, 2006. The registration statement was not filed or declared effective by the required dates and the Company became liable to the investors for liquidated damages in an amount equal to 1.0% of the purchase price of the shares, approximately $50,100, for each thirty day period until the registration statement was declared effective by the SEC. These liquidated damages are payable, at the sole discretion of the Company, by cash or by the issuance of Company common stock. Accordingly, 90,334 shares of common stock were issued, as of October 30, 2006, to those investors for liquidated damages for the period of June 7, 2006 through November 3, 2006. On November 8, 2006, the SEC declared effective the Registration Statement on Form S-1 covering the common shares issued in connection with the July 19, 2005, March 10, 2006, and June 30, 2006, private placements. As a result, the Company is no longer subject to the liquidated damages described above.
On December 20, 2006, the Company completed a private placement of 6,500,000 shares of common stock, no par value, to an accredited investor pursuant to a Subscription Agreement dated December 18, 2006. The common stock was priced at $3.00 per share resulting in proceeds to us of approximately $19.5 million. No warrants or dilutive securities were issued in connection with the offering. The offering was placed directly by the Company and there were no related placement fees.
The shares of common stock issued during the period were exempted from registration in reliance upon Section 4(2) of the Securities Act of 1933, as amended, and Regulation D promulgated thereunder. Shares in the private placement were only offered to select accredited investors (as such term is defined in Rule 501(a) of Regulation D under the Securities Act).
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS
SEE RISK FACTORS IN ITEM 1 “BUSINESS” OF THIS ANNUAL REPORT FORM 10-K. The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statement and related notes contained elsewhere in this report.
Overview
We are in the exploratory stage of our oil and natural gas business and to date our activities in Peru have been primarily limited to analysis and evaluation of technical data on the properties and preparation of the development plans for the properties, including detailed engineering and design of the power plant and gas processing facilities, refurbishment of one of our offshore platforms, procuring machinery and equipment for a drilling campaign, obtaining all necessary environmental and operating permits and securing the required capital and financing to complete the current plan of operation. We
commenced drilling of our initial well, the CX11-21XD, in the Corvina Gas Field at the CX-11 platform in September 2006, and a total depth of 10,457 feet (9,234 feet true vertical depth) was reached in November 2006. In March 2007, after a total of four Drill Stem Tests were conducted on separate potential pay zones covering 413 feet from the Lower and Upper Zorritos formations, the well tested at a rate of 40 million cubic feet per day (MMcfpd) of natural gas and 3,150 barrels per day of crude oil (bopd). We next plan to workover the shut-in CX11-16X well, followed by the drilling of our second new well in the Corvina field, to test for additional gas reserves and further appraise other oil discovery. However, we caution the reader that test results are not necessarily indicative of actual production. We have not drilled any other wells or recognized any revenues from operations, and we do not anticipate generating significant revenues from our properties prior to early 2008.
Results of Operations
Year Ended December 31, 2006 Compared to Year Ended December 31, 2005
Our operating and administrative expenses to date have consisted principally of general and administrative costs as well as geological, geophysical and engineering costs. General and administrative costs have increased significantly from $4,422,747 during the year ended December 31, 2005 to $8,306,356 during the year ended December 31, 2006 as a result of our increased activity levels, additional personnel and costs associated with being a public company. We incurred $2,048,742 of geological, geophysical and engineering costs for the year ended December 31,2006 compared to $998,131 for the same period ended, 2005. This was primarily related to the commencement of our Block Z-1 gas-to-power project.
Stock-based compensation expense for the twelve months ended December 31, 2006 was approximately $3,225,508, compared to $1,382,479 during the same period in 2005. Stock based compensation expense is primarily related to our 2005 and 2006 restricted stock and option grants and accrued stock-based compensation under our 2005 Long-Term Incentive Compensation Plan.
We received net cash distributions from our Ecuador property of $1,291,547 during the twelve months ended December 31, 2006, compared to net cash distributions of $605,278 during the same period ending 2005. Since our investment consists of an interest in a producing oil and gas property, we are amortizing the investment on a straight-line basis over the remaining term of the license agreement covering the property. Accordingly, we recorded $187,584 of amortization expense during the twelve months ended December 31, 2006, compared to $136,552 during the twelve months ended December 31, 2005.
We incurred interest expense of $15,815 during the twelve months ending December 31, 2006, primarily related to other debt related to acquiring furniture and fixtures as compared with interest expense of $11,149 and amortization of deferred financing costs of $67,561 year ended December 31, 2005, principally from notes payable incurred to finance the acquisition of SMC in September 2004.
For the year ended December 31, 2006, we recorded a foreign currency transaction gain of $56,000. The primary reason for the translation difference related to the early recovery of Value Added Tax in Peru (“IGV”), which, by Peruvian law must be transacted and accounted for in the local currency. Due to the relatively low level of activity in 2005 and the relatively steady exchange rate in Peru, translation differences were immaterial during the twelve months ended December 31, 2005.
For the twelve months ended December 31, 2006, we recorded registration delay expense totaling $3,552,513, of which approximately $1,221,734 was paid in cash and $2,330,779 was settled by the issuance of 865,238 shares of common stock. In connection with the private placement of 11,466,000 common shares in July 2005, we were obligated to prepare and file with the SEC a Registration Statement on Form S-1 and to use our best efforts to cause the Registration Statement to be declared effective by the SEC no later than ninety days from closing. The Registration Statement had not been declared effective by the required date and we were liable to the investors for liquidated damages in an amount equal to 1.0% of the
purchase price of the shares, approximately $343,000, for each thirty day period until the Registration Statement was declared effective by the SEC. In addition, in connection with the private placement of 4,482,000 common shares in March 2006, the Company was obligated to prepare and file with the SEC a Registration Statement on Form S-1 within ninety days, and to use its best efforts to cause the Registration Statement to be declared effective by the SEC no later than ninety days, from March 8, 2006. The Registration Statement was not filed or declared effective by the required dates and we were liable to the investors for liquidated damages in an amount equal to 1.0% of the purchase price of the shares, approximately $50,100, for each thirty day period until the Registration Statement was declared effective by the SEC. On November 8, 2006, the SEC declared effective the Registration Statement on Form S-1 covering the common shares issued in connection with the July 19, 2005, March 10, 2006, and June 30, 2006, private placements. As a result, the Company is no longer subject to the liquidated damages described above.
As a result of the increased cash balance from the various private placements of our common stock during 2005 and 2006, we received interest income of $787,455 during the twelve months ended December 31, 2006, as compared to $509,808 during the same period ended December 31, 2005.
We realized a net loss of $15,487,459 or $(0.35) per share for the year ended December 31, 2006, compared to a net loss of $6,406,989, or $(0.20) per share, for the same period in 2005.
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Our operating and administrative expenses to date have consisted principally of general and administrative costs and geological, geophysical and engineering costs. General and administrative costs have increased significantly from $1,856,111 during 2004 to $4,422,747 during 2005 as a result of our increased activity levels, additional personnel and costs associated with being a public company. We incurred $998,131 of geological, geophysical and engineering costs in 2005 primarily related to our Block Z-1 gas-to-power project, compared to $360,965 in 2004.
Also, during 2005, we incurred $1,382,479, in stock-based compensation as a result of amortizing the deferred compensation expense related to (i) a grant of 150,000 shares of restricted common stock to our independent directors; (ii) a grant of 970,000 shares of restricted common stock to three of our officers; and (iii) 500,000 stock options issued to the former CEO of Navidec. During 2004, we recorded stock-based compensation expense of $7,059,081 primarily as a result of shares issued for services to employees and consultants of BPZ-Texas prior to the Merger.
We received net cash distributions of $605,278 during 2005 from our Ecuador property, compared to net cash distributions of $190,621 during 2004, which included only six months from the acquisition of the property in June 2004. Our net interest in the property also increased from 6% to 10% in June 2005. Since our investment consists of an interest in a producing oil and gas property, we are amortizing the investment on a straight-line basis over the remaining term of the license agreement covering the property. Accordingly, we recorded $136,552 of amortization expense during 2005, compared to $42,760 during the six months we owned the property during 2004.
We incurred interest expense of $11,149 and amortization of deferred financing costs of $67,561 in 2005, principally from notes payable incurred to finance the acquisition of SMC in June 2004. In the prior year we incurred interest expense of $66,959 related to the notes payable incurred to finance the acquisition of SMC in June 2004 and other borrowings, as well as amortization of deferred financing costs of $360,439 primarily from notes payable incurred to finance the acquisition of SMC in June 2004.
As a result of our increased cash balance from the private placement of common stock, we received interest income of $509,808 during the year ended December 31, 2005. However, as a result of a delay in obtaining an effective Registration Statement we were liable to the investors for liquidated damages in an amount equal to 1.0% of the purchase price of the
shares for each thirty day period until the Registration Statement is declared effective by the SEC. Accordingly, the Company recorded $515,967 of registration delay expense during the year ended December 31, 2005.
We realized a net loss of $6,406,989, or $(0.20) per share, for the year ended December 31, 2005, compared to a net loss of $15,013,177, or $(0.99) per share for the same period in 2004.
Capital Expenditures
Our initial project in the offshore Block Z-1 in northwest Peru, totaling approximately $132.3 million including import duties and contingencies, entails the refurbishment of the Corvina CX-11 platform, rehabilitation of an existing well and the drilling of two new wells, installation of a 10-mile gas pipeline from the platform to shore, construction of gas processing facilities and a 160 MW simple-cycle electric generating plant, and the construction of a 40-mile gas pipeline to supply gas to third party generators in Arenillas, Ecuador. We have obtained cost estimates for most of the major equipment components and the related shipping, construction, installation and associated services. However, the costs of these procurement and construction activities can be difficult to accurately predict and are subject to changes and contingencies. Our budget has increased as a result of higher actual drilling costs in Block Z-1, primarily as a result of a mechanical problem caused by an unexpected gas kick and resulting pipe obstruction, as well as higher projected drilling costs and the selection of larger capacity turbines. These cost increases were partially offset by the removal of one well from our initial drilling program. This estimate of capital expenditures does not include value added tax (referred to as “IGV” in Peru). IGV is generally imposed on goods and services at a rate of 19%. Certain expenditures are exempt from IGV or eligible for immediate refund. IGV paid on capital expenditures is generally recoverable from our future revenue billings within Peru and is not considered part of the capitalized costs of the equipment to which it relates. We may also be able to defer payment of certain of these expenditures or obtain separate financing for the IGV.
Project Capital Budget
Liquidity and Capital Resources
We currently have no source of revenue or cash flow from operations, and our primary source of cash flow has been cash proceeds from private placements of our common stock. As of December 31, 2006, our cash balance was approximately $25.3 million.
In connection with the Merger, we received net proceeds of approximately $5.5 million from a private placement of our common stock. In July 2005, we completed a private placement of 11,466,000 shares of common stock for net proceeds of approximately $31.9 million. Morgan Keegan & Company, Inc. served as placement agent for the offering. We also received $3.4 million from the exercise of warrants during the third and fourth quarters of 2005. In March 2006 and June 2006, we completed private placements of 1,670,000 shares and 4,482,000 shares of common stock, respectively, for net proceeds of approximately $5.0 million and $12.3 million, respectively.
On December 20, 2006, the International Finance Corporation’s (“IFC”) Board of Executive Directors approved a $120 million financial package. IFC is the private sector arm of the World Bank Group based in Washington, D.C. As part of the financing, we completed a private placement of 6,500,000 shares of common stock, no par value, to the International Finance Corporation (“IFC”) pursuant to a Subscription Agreement dated December 18, 2006. The common stock was priced at $3.00 per share resulting in proceeds to us of approximately $19.5 million. The offering was placed directly by us and there were no placement fees. The remaining $100.5 million portion of IFC financing consists of $30.5 million of debt facilities for IFC’s own account and $70 million of debt facilities for the account of third-party financial institutions. Syndication of the third-party debt component by IFC is expected to take place late in the second quarter of 2007 with disbursements expected shortly thereafter. The remaining debt portion of the financing is subject to identification of the lending syndicate members and subsequent negotiation and approval of the necessary loan documentation.
During the twelve months ended December 31, 2006, we incurred capital expenditures of approximately $34.8 million
primarily related to drilling and completion of our first well in the Corvina Gas Field for approximately $20.0 million. We also incurred capital costs associated with the purchase of a deck barge and related equipment for approximately $6.5 million, the modernization and refurbishment of a platform tender assist drilling rig of approximately $4.5 million, power plant, gas processing facility, and pipeline designs of approximately $3.4 million and $0.4 million related to other miscellaneous property and equipment. In comparison, during the year ended December 31, 2005, we incurred capital expenditures of approximately $4.4 million, primarily related to refurbishment of the Corvina CX-11 platform and power plant design costs.
In early August 2006, we 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 CX-11 platform. No injuries were sustained by any of our staff, nor to any of the tug boat operator’s crew members. The BPZ-01 is a U.S. flagged vessel and as such was inspected after the incident by the U.S. Coast Guard, to its satisfaction. The barge resumed normal operations immediately thereafter. Based upon information currently available, the Company estimates that total expenditures related to this incident will be approximately $1.1 million. As of December 31, 2006, approximately $382,000 has been incurred for barge recovery and temporary repairs to the vessel. In addition, the Company expects to incur approximately $330,000 in permanent repairs to the barge and approximately $432,000 of consequential damages, primarily stand-by charges. As of the date of this filing, we have not presented a final claim to our insurance carrier for the barge repairs and we are negotiating a settlement agreement with a third party for recovery of any damages not covered through our insurance. We believe the majority of the costs associated with this incident will be reimbursed through insurance or through a third party. No assurances can be given, however, that any such recoveries will be sufficient to cover all costs associated with this incident or to the timing of any such recoveries. This incident is not expected to have a material impact on our operations or business plan.
As of December 31, 2006, in connection with our Peru properties, we have deposited approximately $1.2 million as restricted cash to collateralize two performance bonds which guarantee our various obligations and commitments under one of our license contracts and another agreement. The performance bonds were issued by Peruvian banks and their terms are governed by the corresponding license contract or agreement. We will be required to deposit approximately $1.0 million as restricted cash to collateralize a new performance bond in connection with the beginning of the third exploration period under our Block Z-1 license contract, which begins in June 2007. In addition, although we are still negotiating the terms of our commitments under our license contracts for Blocks XXII and XXIII, we anticipate having to deposit funds as restricted cash to collateralize performance bonds to guarantee our obligations totaling approximately $1 million in late 2007.
In connection with our Block XIX license contract, we are obligated to shoot at least 100 kilometers of 2-D seismic during the first half of 2007, unless an extension is requested and granted. Depending on the results of this work, we may elect to drill an exploratory well. We estimate the cost to acquire this seismic data to be approximately $3 million.
With our current cash balance, proceeds from the expected IFC debt facilities and potentially from future equity raises, we believe we will have sufficient capital resources to execute our initial gas-to-power project as we currently envision it. However, the timing and execution of our project is dependent on a variety of factors, including technical design of facilities, permitting, availability of equipment, time and costs required for delivery and construction, performance by contractors and the success of planned financing, many of which factors are outside our control and cannot be assured.
Off-Balance Sheet Arrangements
As of December 31, 2006, 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) Capital lease for office furniture in our executive office in Houston, Texas.
(2) Operating leases for our executive office in Houston, Texas, our branch office in Quito, Ecuador, and our branch office and corporate apartments in Lima, Peru.
(3) Primarily consists of purchase obligations for various equipment and services related to the Company’s drilling operations as well as powerplant and pipeline projects in Peru.
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”). 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.
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 matter 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 Statement of Financial Accounting Standards (“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 may be required to plug and abandon those wells and restore the well site and power generation site upon completion of their production. However, due to the fact that we have not yet begun operations, we do not have sufficient information to determine the timing, nor calculate the present value, of the obligation. Therefore, no such provision is reflected in the accompanying consolidated financial statements.
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. However, due to the fact that we have not yet begun operations, we do not have sufficient information to determine the timing, nor calculate the present value, of the obligation. Therefore, no such provision is reflected in the accompanying consolidated financial statements.
Accounting Changes and Error Corrections
In June 2005, the Financial Accounting Standards Board issued SFAS No. 154, Accounting Changes and Error Corrections, which replaced Accounting Principles Board Opinion No. 20, Accounting Changes (“APB 20”), and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS 154 requires retrospective application to prior period financial statements of a voluntary change in accounting principle unless it is impracticable. In contrast, APB 20 previously required that most voluntary changes in accounting principle be recognized by including the cumulative effect of changing to the new accounting principle in net income in the period of change. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Earlier application is permitted for accounting changes and correction of errors made in fiscal years beginning after June 1, 2005. SFAS 154 does not change the transition provisions of any existing accounting pronouncements, including those that are in a transition phase as of its effective date. We have elected to adopt the provisions of SFAS 154 on January 1, 2006. We do not expect adoption to have a material effect on our results of operations or financial position.
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 working interest owned by our consolidated subsidiary, SMC Ecuador Inc. See Note 7 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.
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 Soles, 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 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
FASB Staff Position (FSP) FAS 19-1 amends FASB statement no. 19 to provide revised guidance concerning the criteria for continued capitalization of exploratory costs when wells have found reserves that cannot yet be classified as proved.
FAS 19-1 provides circumstances that would permit the continued capitalization of exploratory well costs beyond one year, other than when additional exploration wells are necessary to justify major capital expenditures and those wells are under way or firmly planned for the near future. Generally, the statement allows exploratory well costs to continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project.
Accounting for Uncertainty in Income Taxes.
In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of SFAS No. 109” (“FIN 48”). This interpretation provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding derecognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this Interpretation is not expected to have a material impact on our consolidated financial position, results of operations, or cash flows.
Guidance for Quantifying Financial Statement Misstatement.
In September 2006, the Securities and Exchange Commission (“SEC”) issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), which establishes an approach requiring the quantification of financial statement errors based on the effect of the error on each of the company’s financial statements and the related financial statement disclosures. This model is commonly referred to as a “dual approach” because it requires quantification of errors under both the “iron curtain” and “roll-over” methods. The roll-over method focuses primarily on the impact of a misstatement on the income statement, including the reversing effect of prior year misstatements; however, its use can lead to the accumulation of misstatements in the balance sheet. The iron curtain method focuses primarily on the effect of correcting the period end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The Company currently uses the iron curtain method for quantifying financial statement misstatements. The Company will initially apply the provisions of SAB 108 in connection with the preparation of the Company’s annual financial statements for the year ending December 31, 2006. The use of the dual approach is not expected to have a material impact on our consolidated financial position, results of operations, or cash flows.
FASB Staff Position (FSP) No. EITF 00-19-2, “Accounting for Registration Payment Arrangements and Financial Instruments Subject to Such Arrangements”
In December 2006, the FASB issued FASB Staff Position FSP EITF 00-19-2, Accounting for Registration Payment Arrangements . This FASB Staff Position, or FSP, specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies . This FSP also requires certain disclosures regarding registration payment arrangements and liabilities recorded for such purposes. This FSP is immediately effective for registration payment arrangements entered into or modified after December 21, 2006. The guidance of this FSP is effective for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years for registration payment arrangements entered into prior to December 21, 2006. This FSP requires adoption by reporting a change in accounting principle through a cumulative-effect adjustment to the opening balance of our partners’ capital accounts as of the first interim period of the year in which this FSP is initially applied. We do not expect our adoption of this FSP to materially affect our financial position, results of operations or cash flows.
Fair Value Measurements.
In September 2006, the FASB issued SFAS No. 157,”Fair Value Measurements”, which addresses how companies should measure fair value when companies are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles (“GAAP”). As a result of SFAS No. 157, there is now a common definition of fair value to be used throughout GAAP. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. Although the disclosure requirements may be expanded where certain assets or liabilities are fair valued such as those related to stock compensation expense and hedging activities, we do not expect the adoption of SFAS No. 157 to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates, oil and natural gas prices and foreign currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Interest Rate Risk
As of December 31, 2006, the Company had long-term debt of $55,815, consisting of two secured loans for the purchase of office furniture. Both loans have a term of 60 months and bear interest at fixed rates of 5.94% and 9.44%, with principal and interest payments due on a monthly basis. Significant changes in market interest rates may significantly affect the level of financing that the IFC will structure 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. Oil and natural gas are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. 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 we 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 for the sale of power may not rise at the same rate, or may not rise at all, to match a rise in the Company’s cost to produce and transport gas reserves to our initial 160MW power plant in Caleta Cruz. Prices for both electricity and natural gas have been very volatile in the past year and have increase significantly over the past two years. The profitability of this business depends in large part on the difference between the price of power and the price of fuel used to generate power, or “spark spread.”
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, still uses its local currency, Nuevo Soles, 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. Translation differences have been nominal to-date but are expected to increase as our activities in Peru continue to escalate.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
BPZ Energy, Inc. and Subsidiaries
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2006 and 2005
Consolidated Statements of Operations for the Years Ended December 31, 2006, 2005 and 2004 and for the Period from August 20, 2001 (Inception) to December 31, 2006
Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2006, 2005 and 2004
Consolidated Statements of Cash Flows for the Years Ended December 31, 2006, 2005 and 2004 and for the Period from August 20, 2001 (Inception) to December 31, 2006
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors
BPZ Energy, Inc. and Subsidiaries
(An Exploration Stage Company)
We have audited the accompanying consolidated balance sheets of BPZ Energy, Inc. and Subsidiaries (An Exploration Stage Company) as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2006, and for the period from August 20, 2001 (Inception) through December 31, 2006. 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. An audit also includes 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 Energy, Inc. and Subsidiaries at December 31, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006 and for the period from August 20, 2001 (Inception) through December 31, 2006 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), the effectiveness of BPZ Energy, Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2006, 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 14, 2007, expressed an unqualified opinion thereon.
/s/ Johnson Miller & Co., CPA’s PC
Midland, Texas
March 14, 2007
BPZ Energy, Inc. and Subsidiaries
(An Exploratory Stage Company)
Consolidated Balance Sheets
The accompanying notes are an integral part of these consolidated financial statements.
BPZ Energy, Inc. and Subsidiaries
(An Exploratory Stage Company)
Consolidated Statements of Operations
The accompanying notes are an integral part of these consolidated financial statements.
BPZ Energy, Inc. and Subsidiaries
(An Exploratory Stage Company)
Consolidated Statements of Stockholders’ Equity (Deficit)
Years Ended December 31, 2006, 2005 and 2004
The accompanying notes are an integral part of these consolidated financial statements.
BPZ Energy, Inc. and Subsidiaries
(An Exploratory Stage Company)
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these consolidated financial statements.
BPZ Energy, Inc and Subsidiaries
(An Exploratory Stage Company)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2006
Note 1 - Basis of Presentation and Significant Accounting Policies
Organization
BPZ Energy, Inc., a Colorado corporation (“BPZ” or the “Company”) was incorporated in 1993 and is based in Houston, Texas. BPZ is an exploratory stage company with properties in northwest Peru and southwest Ecuador and is focused on the exploration and production of oil and natural gas and the complementary development of gas-fired power generation.
The Company maintains a registered branch office in Peru. Currently, BPZ has exclusive rights and license agreements for oil and gas exploration and production covering a total of approximately 2.4 million acres in northwest Peru. The Company’s license contracts cover 100% ownership of both Block Z-1 (739,205 acres), which was signed in November 2001 and Block XIX (472,860 acres), which was signed in December 2003. The license contracts provide for an initial exploration period of seven to thirteen years and seven to ten years, respectively and require that we conduct specified activities on the properties during this period. If the exploration activities are successful, the total contract term may be extended up to 30 years for oil exploration and production and up to 40 years for gas exploration and production. BPZ has presented all necessary documentation requested by Perupetro in order to become the qualified operator under a license contract for Block XXII (948,000 acres) which BPZ previously held under a Technical Evaluation Agreement and was referred to as Area VI in the Company’s previous filings. Subsequently, in March 2006, the Company was notified by Perupetro that it qualified as an operator of Block XXII. The negotiations on the license contract are still underway and the Company does have sufficient information to determine the timing nor estimate the value of the various obligations and commitments in connection with this property. In July 2006 Perupetro officially informed the Company that its proposal for the 248,000 acre Block XXIII, located onshore in northwest Peru between the Company’s Blocks Z-1 and XIX, was the winning bid in Perupetro’s recent tender process. The Company has presented all necessary documentation to become the qualified operator of this new block under an exploration and production license contract.
BPZ through its wholly owned subsidiary, SMC Ecuador Inc. (a Delaware corporation), and its registered branch in Ecuador, also owns a 10% non-operating working interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”). The license agreement covering the property extends through May 2016.
BPZ is currently in the exploratory stage and to date its activities in Peru have been limited to analysis and evaluation of technical data on the properties and preparation of the development plans for the properties, including detailed engineering and design of the power plant and gas processing facilities, refurbishment of one of its offshore platforms, procuring machinery and equipment for a drilling campaign, obtaining all necessary environmental and operating permits, and securing the required capital and financing to complete the current plan of operation. . The Company commenced drilling of our initial well, the CX11-21XD, in the Corvina Gas Field at the CX-11 platform in September 2006, and a total depth of 10,457 feet (9,234 feet true vertical depth) was reached in November 2006. In March 2007, after a total of four Drill Stem Tests were conducted on separate potential pay zones covering 413 feet from the Lower and Upper Zorritos formations, the well tested at a rate of 40 million cubic feet per day (MMcfpd) of natural gas and 3,150 barrels per day of crude oil (bopd). The Company plans to workover the shut-in CX11-16X well, followed by the drilling of their second new well in the Corvina field, to test for additional gas reserves and further appraise the oil discovery. However, we caution the reader that test results are not necessarily indicative of actual production. No other well has been drilled and the Company has not recognized any revenues from operations, nor does it anticipate to recognize any revenues from operations generating significant revenues from the Company’s properties prior to early 2008.
Basis of Presentation and Principles of Consolidation
The 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.
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-operated working interest owned by its consolidated subsidiary, SMC Ecuador Inc. See Note 7 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.
The consolidated balance sheet at December 31, 2005 is derived from the December 31, 2005 audited consolidated financial statements, as restated on the Company’s Annual Report on Form 10-KSB/A for the year ended December 31, 2005 filed on October 16, 2006.
Certain reclassifications of prior year balances have been made to conform such amounts to corresponding 2006 classifications. These reclassifications have no impact on the Company’s net loss.
Reporting and Functional Currency
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, Nuevo Soles, in addition to the U.S. Dollar and therefore our financial results are subject to foreign currency gains and losses. We have adopted 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, translation differences were immaterial during the twelve months ended December 31, 2005 and we had a translation gain of approximately $56,000 for the same period ended December 31, 2006. The primary reason for the translation difference related to the early recovery of Value Added Tax in Peru (“IGV”), which by Peruvian law must be transacted and accounted for in the local currency.
Use of Estimates
The preparation of the consolidated financial statements in accordance with U.S. generally accepted accounting principles 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.
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 8 to the Consolidated Financial Statements, the Company has secured various performance bonds, collateralized primarily 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.
Property, Equipment and Construction in Progress
The Company follows the “successful efforts” method of accounting of 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. 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.
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 we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and interest. As of December 31, 2006, property and equipment consists of office equipment, vehicles and leasehold improvements made to the Company’s offices. All values are stated at cost and are depreciated on a straight-line basis over the estimated useful life of the assets or the term of the lease. 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.
Impairment of Long-Lived Assets
The Company periodically evaluates the recoverability of the carrying value of its long-lived assets, goodwill 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 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.
Stock Based Compensation
On January 1, 2006, the Company adopted SFAS No. 123 - Revised 2004, Share-Based Payment, which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employees. SFAS 123(R) is a revision of SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”), and supersedes APB No. 25, Accounting for Stock Issued to Employees. Under the provisions of SFAS 123(R), 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 over the employee’s or non-employee’s service period, which is generally the vesting period of the equity grant.
Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with SFAS 123. As allowed under SFAS 123, the Company accounted for its stock-based compensation to employees using the intrinsic value method of accounting which bases compensation expense on the difference between the quoted market price of the award at the measurement date less the amount, if any, the employee is required to pay for the stock. As of December 31, 2005, stock-based awards to employees consisted of only restricted shares valued using the market price of the Company’s traded common stock on the date of grant. The fair value method used to value restricted shares would have yielded the same fair value and compensation expense as the intrinsic value method used; thus, no pro forma results of operations are required to be presented.
Income Taxes
The Company accounts for income taxes using the liability method. Under this method, 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.
Loss per Common Share
In accordance with provisions of 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
Continued Capitalization of Exploratory Costs
FASB Staff Position (FSP) FAS 19-1 amends SFAS statement No. 19 to provide revised guidance concerning the criteria for continued capitalization of exploratory costs when wells have found reserves that cannot yet be classified as proved. FAS 19-1 provides circumstances that would permit the continued capitalization of exploratory well costs beyond one year, other than when additional exploration wells are necessary to justify major capital expenditures and those wells are under way or firmly planned for the near future. Generally, the statement allows exploratory well costs to continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project.
Accounting for Uncertainty in Income Taxes.
In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109” (“FIN 48”). This interpretation provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes.” FIN 48 prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding derecognition, classification and disclosure of these uncertain tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this Interpretation is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.
Guidance for Quantifying Financial Statement Misstatement.
In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”), which establishes an approach requiring the quantification of financial statement errors based on the effect of the error on each of the company’s financial statements and the related financial statement disclosures. This model is commonly referred to as a “dual approach” because it requires quantification of errors under both the “iron curtain” and “roll-over” methods. The roll-over method focuses primarily on the impact of a misstatement on the income statement, including the reversing effect of prior year misstatements; however, its use can lead to the accumulation of misstatements in the balance
sheet. The iron curtain method focuses primarily on the effect of correcting the period end balance sheet with less emphasis on the reversing effects of prior year errors on the income statement. The Company currently uses the iron curtain method for quantifying financial statement misstatements. The Company will initially apply the provisions of SAB 108 in connection with the preparation of the Company’s annual financial statements for the year ending December 31, 2006. The use of the dual approach is not expected to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.
FASB Staff Position (FSP) No. EITF 00-19-2, “Accounting for Registration Payment Arrangements and Financial Instruments Subject to Such Arrangements”
In December 2006, the FASB issued FASB Staff Position FSP EITF 00-19-2, Accounting for Registration Payment Arrangements . This FASB Staff Position, or FSP, specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate agreement or included as a provision of a financial instrument or other agreement, should be separately recognized and measured in accordance with FASB Statement No. 5, Accounting for Contingencies . This FSP also requires certain disclosures regarding registration payment arrangements and liabilities recorded for such purposes. This FSP is immediately effective for registration payment arrangements entered into or modified after December 21, 2006. The guidance of this FSP is effective for fiscal years beginning after December 15, 2006, and interim periods within those fiscal years for registration payment arrangements entered into prior to December 21, 2006. This FSP requires adoption by reporting a change in accounting principle through a cumulative-effect adjustment to the opening balance of our partners’ capital accounts as of the first interim period of the year in which this FSP is initially applied. The adoption of this FSP is not expected to materially affect the Company’s financial position, results of operations or cash flows.
Fair Value Measurements.
In September 2006, the FASB issued SFAS No. 157,”Fair Value Measurements”, which addresses how companies should measure fair value when companies are required to use a fair value measure for recognition or disclosure purposes under generally accepted accounting principles (“GAAP”). As a result of SFAS 157, there is now a common definition of fair value to be used throughout GAAP. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years. Although the disclosure requirements may be expanded where certain assets or liabilities are fair valued such as those related to stock compensation expense and hedging activities, the Company does not expect the adoption of SFAS 157 to have a material impact on the Company’s consolidated financial position, results of operations, or cash flows.
Note 2 -Navidec Merger
On July 8, 2004, Navidec and BPZ-Texas entered into a Merger Agreement (the “Merger Agreement”) which was consummated on September 10, 2004. The Merger was structured from a legal standpoint as the acquisition of BPZ-Texas by Navidec. However, the stockholder group of BPZ-Texas obtained majority ownership and management control of the combined company so, in substance, the transaction was a recapitalization of BPZ-Texas rather than a business combination. This accounting treatment is identical to that resulting from a reverse merger of BPZ-Texas with Navidec under SFAS 141, except that no goodwill or other intangible asset has been recorded. All financial statements presented herein represent the historical financial statements of the accounting acquirer, BPZ-Texas. BPZ-Texas entered into the Merger primarily to obtain access to the public markets to finance its planned activities in South America.
Immediately prior to the recapitalization of BPZ-Texas, Navidec transferred all its assets and liabilities to a subsidiary, Navidec Financial Services (“NFS”), which was not acquired by BPZ-Texas and was part of a planned spin-off to Navidec shareholders of record at the time of the Merger. The recapitalization of BPZ-Texas was accomplished by Navidec, which had 3,198,368 shares outstanding, issuing 9,000,000 shares of its common stock in a one-for-one exchange for all of the outstanding common shares of BPZ-Texas. As additional incentive for the shareholders of Navidec to enter into the Merger, NFS received an additional 662,149 shares of common stock of Navidec. In its recapitalization, the Company assumed options to purchase 1,332,076 shares of Navidec common stock, which had previously been issued to employees, directors and consultants of Navidec and were outstanding on the date of the Merger. Under the terms of the Merger Agreement, the proceeds received from the exercise of these stock options are payable to NFS. The Company also assumed outstanding Class
A ($2.00 per share) and Class B ($4.00 per share) warrants to purchase 1,129,000 shares (564,500 shares per class) of Navidec common stock.
The Company also issued options to purchase 1,500,000 shares of common stock at an exercise price of $2.00 per share to NFS. Such options were due to expire on July 31, 2006. However, on May 19, 2006, the Company entered into a Settlement Agreement and Mutual Release (the “Settlement Agreement”) by and among the Company, NFS and John McKowen, the Chief Executive Officer of NFS and former Chief Executive Officer and Director of the Company (collectively, the “Parties”). Among other things, the agreement extended the expiration date for NFS’s options. The Company agreed to extend the expiration date in the remaining stock options from July 31, 2006, to one year following the effective date of the registration with the SEC of the shares NFS received in the Merger with Navidec. The registration of these shares became effective on December 15, 2006 and, as a result, the expiration date for the remaining options was extended to December 15, 2007. Subsequent to the Merger, NFS conveyed 540,000 of such options to third parties. During 2005, 275,000 options had been exercised, resulting in net proceeds to the Company of $550,000. As of December 31, 2006 1,225,000 of such options remained outstanding, of which 810,000 were held by NFS.
Additionally, the Company granted options to purchase 1,000,000 shares of common stock at an exercise price of $1.30 per share to the former CEO of Navidec in connection with his service as a director and financial consultant to the Company. On the date of the Merger, 500,000 of such stock options became fully vested. Vesting of the remaining 500,000 stock options is contingent upon the receipt of additional investment proceeds totaling $6 million, including proceeds from the exercise of outstanding warrants. Under the Settlement Agreement, among other things, the Company agreed to extend the date for vesting in the remaining 500,000 stock options from September 10, 2006, to one year following the effective date of the registration with the SEC of the shares NFS received in the Merger with Navidec. The registration of these shares became effective on December 15, 2006 and as a result the expiration of the date for vesting was extended to December 15, 2007. The Company further agreed that as of the date hereof, Mr. McKowen has raised $5,935,000 towards the required $6,000,000, mentioned above, as a condition for fully vesting of the additional 500,000 options. These stock options, when vested, will expire 10 years from the date of grant. They were recorded at a fair value of $1.20 per share using the Black-Scholes model. The unvested options are being amortized over the original 24-month vesting period at the rate of $25,000 per month unless the Company concludes such options are no longer probable of vesting.
All shares underlying such options and warrants are issuable as common stock of the Company. See Note 10 - Stockholders’ Equity of the Notes to Consolidated Financial Statements for details about the stock options and warrants assumed or granted in connection with the Merger.
After the transfer of the assets and liabilities of Navidec to NFS, Navidec had no assets, liabilities or stockholders’ equity. The 662,149 shares of common stock the Company issued to NFS in connection with the acquisition were valued at the average closing price of Navidec’s common stock quoted on the OTCBB market during a five-day trading period beginning two trading days prior to the announcement of the Merger Agreement on July 8, 2004. Navidec was publicly traded and had a market for its equity, while BPZ-Texas was privately owned. The stock options assumed to purchase 1,332,076 shares of Navidec common stock and the warrants assumed and issued to purchase 1,129,000 shares and 2,500,000 shares of Navidec common stock, respectively, were valued using the Black-Scholes model. Inputs into the Black-Scholes valuation model for the valuation of the warrants and stock options included the exercise price and remaining term for the stock options and warrants, and a volatility factor based on historical stock prices of Navidec.
The following table summarizes the foregoing compensation and Merger-related transactions as they were recorded in the year ended December 31, 2004:
(1) Fair values per share were rounded to two decimal places for presentation purposes.
(2) Amounts recorded represent the immediate vesting/expense of 500,000 options ($600,000) and the amortization of the second group of 500,000 options ($75,000) for the three months ended December 31, 2004.
(3) Items represent total merger costs of $5,470,455 on the Company’s Statement of Operations for the year ended December 31, 2004.
(4) Items included in stock-based compensation on the Company’s Statement of Operations for the year ended December 31, 2004.
Transfer of NFS
The Merger Agreement also provided that all of the pre-merger business operations, assets and liabilities of Navidec would be transferred to its then wholly-owned subsidiary, NFS, followed by the transfer of ownership of NFS to the Navidec pre-merger shareholders of record as of September 9, 2004, the day prior to the consummation of the Merger. Accordingly, the pre-merger shareholders of BPZ-Texas are not entitled to receive shares of NFS. All legal requirements for the transfer of ownership of NFS have been completed. The Company believes, based on information provided by NFS and its advisors, that NFS has undertaken the necessary actions to comply with applicable registration requirements. On July 13, 2006, NFS filed a Registration Statement on Form 10SB with the SEC and an amendment thereto on October 27, 2006. It is the Company’s understanding that this Registration Statement has become effective under applicable SEC rules.
In June 2006, a Findings of Fact and Conclusions of Law issued by the District Court, Arapahoe County, Colorado stated that the Company was not a shareholder of NFS at any time after September 9, 2004. Based on these findings, the Company concluded that it should not account for the post-Merger operations of NFS in its consolidated financial statements.
Note 3 - 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 early recovery system for exploration companies. Under this regime, IGV paid on the acquisition of goods and services used directly in hydrocarbon exploration activities can be recovered without having to wait until a commercial discovery takes place or production begins. The Company has applied for early recovery of IGV paid since it does not anticipate first sales of power to the Peruvian power market until early 2008. During the year ended December 31, 2006 the Company received a refund of approximately $2.3 million under the IGV early recovery program. The Company’s value added tax receivable balance as of December 31, 2006 was $3,159,698. The Company’s value added tax receivable balance at December 31, 2005 was $362,555.
Note 4 - Inventories
Inventories consist primarily of tubular goods, accessories and spare parts for production equipment, stated at the lower of average cost or market. The balance in inventory at December 31, 2006 was $1,945,781.
Note 5 - Prepaid and Other Current Assets
Below is a summary of other current assets as of December 31, 2006 and 2005:
Prepaid expenses are primarily related to crane, barge and barge equipment rentals which will be credited against the monthly charter or daily rates once operations commence. Deposits are primarily to secure delivery of the drilling rig and rent deposits in connection with the Company’s offices in Houston and Peru. Prepaid insurance consists of premiums related to the Company’s operations as well as general liability and directors and officers insurance policies.
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, 2006, a claim of approximately $712,000 for repairs is expected to be filed with the insurance carrier. A deductible of $100,000 will be applied to this insurance claim when reimbursed. See Note 13 “Commitments and Contingencies”, included herein, for further discussion.
Note 6 - Property, Equipment and Construction in Progress
Below is a summary of property, equipment and construction in progress as of December 31, 2006 and 2005:
As of December 31, 2006, the Company incurred costs associated with its development initiatives for the exploration and production of natural gas reserves and the complementary development of proprietary gas-fired power generation for sale in Peru. The costs relate to the initial engineering design work for the power plant, gas processing facility and pipelines, modernization and refurbishment costs of the platform tender assist drilling rig, and acquisition and refurbishment of one of the Company’s offshore platforms located in Block Z-1, as well as the purchase of a deck barge and related equipment. The Company also incurred costs for office equipment and leasehold improvements for its offices in Houston, Peru and Ecuador as well as for vehicles used in its Peruvian operations. In accordance with “successful efforts” method of accounting, the Company capitalized $195,755 of depreciation expense related to support equipment to construction in progress during the year ended December 31, 2006.
Note 7 - Investment in Ecuador Property and Note Payable
The Company has a 10% net investment interest in an oil and gas property in Ecuador (the “Santa Elena Property”) totaling $1,757,604 and $1,945,188 as of December 31, 2006 and 2005, 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. Accordingly, the Company recorded amortization expense of $187,584 and $136,552 for the years ended December 31, 2006 and 2005, respectively.
In connection with the acquisition of the Santa Elena property, the Company had a note payable balance of $208,986 as of December 31, 2004. The note agreement required monthly installment payments of $31,366, including imputed interest at 15%, through July 1, 2005 and has been paid in full as of December 31, 2005.
As part of the note agreement, the holder of the note payable received beneficial ownership of a 4% net working interest in the Santa Elena Property. In June 2005, the Company issued 250,000 shares of the Company’s common stock, valued at $1,112,500, to acquire the holder’s 4% net working interest in the property.
Note 8 - Restricted Cash
In connection with its properties in Peru, the Company has obtained two performance bonds totaling $1,350,000 to guarantee certain obligations and commitments. As of December 31, 2006, BPZ had restricted cash deposits of $1,150,000, which collateralizes the performance bonds. In addition to the cash collateral posted by BPZ, an individual shareholder of the Company provided a guarantee in the amount of $200,000 to the financial institution that issued one of the bonds to secure the Company’s performance. The performance bonds were issued by Peruvian banks and their terms are governed by the corresponding license contract or agreement.
As of December 31, 2005, the Company had posted performance bonds totaling $1,690,000 to secure the performance of its obligations and commitments related to its properties in Peru. Of such amount, $1,455,953 was collateralized by a
restricted cash deposit. The remaining $240,000 performance bonds have been guaranteed by two individual shareholders of the Company.
All of the performance bonds were issued by Peruvian banks and their terms are governed by the corresponding license contract or technical evaluation agreement.
Note 9 - Long-Term Debt
On December 31, 2006, the Company had long-term debt of $55,815 compared to $70,908 in long-term debt as of December 31, 2005. Long-term debt for both 2005 and 2006 consisted of two secured loans for the purchase of office furniture. Both loans have a term of 60 months, bearing interest at 5.94% and 9.44%, with principal and interest payments due on a monthly basis.
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.
Private Placements of Common Stock
On July 19, 2005, the Company completed a private placement of 11,466,000 shares of common stock, no par value, pursuant to a Stock Purchase Agreement. The common stock was priced at $3.00 per share, resulting in net proceeds to the Company of $31,917,213. In connection with the private placement, the Company was obligated to prepare and file with the SEC a Registration Statement on Form S-1 and to use its best efforts to cause the Registration Statement to be declared effective by the SEC no later than ninety days from July 19, 2005. The Registration Statement was not declared effective by the required date and the Company became liable to the investors for liquidated damages in an amount equal to 1.0% of the purchase price of the shares, approximately $343,980, for each thirty day period until the Registration Statement is declared effective by the SEC. Certain of the private placement investors, totaling 76% of the aggregate investment, have agreed to accept common stock in lieu of cash. Accordingly, 774,904 and 92,705 shares of common stock were issued during the year ended December 31, 2006 and 2005, respectively to those certain investors for liquidated damages.
On March 10, 2006 the Company completed a private placement of 1,670,000 shares of common stock, no par value, to four institutional and accredited investors pursuant to a Stock Purchase Agreement. The common stock was priced at $3.00 per share resulting in proceeds to the Company of $5,010,000. In connection with the private placement, the Company was obligated to prepare and file with the SEC a Registration Statement on Form S-1 within sixty days, and to use its best efforts to cause the Registration Statement to be declared effective by the SEC no later than ninety days, from March 8, 2006. The Registration Statement was not filed or declared effective by the required dates and the Company became liable to the investors for liquidated damages in an amount equal to 1.0% of the purchase price of the shares, approximately $50,100, for each thirty day period until the Registration Statement was declared effective by the SEC. These liquidated damages are payable, at the sole discretion of the Company, by cash or by the issuance of Company common stock. Accordingly, 90,334 shares of common stock were issued during the twelve months ended December 31, 2006, to those investors for liquidated damages.
On June 30, 2006, the Company completed a private placement of common stock for proceeds of $12,325,500 which were received in July 2006. The Company sold 4,482,000 shares to eight institutional and accredited investors at a price of $2.75 per share. There were no warrants or dilutive securities issued to the investors in connection with the offering. The offering was placed directly by the Company and there were no placement fees. The Company did, however, issue warrants to purchase 150,000 shares of the Company’s common stock to Morgan Keegan & Company, Inc. in consideration for their financial advisory services relating to the private placement. In connection with the private placement, the Company was obligated to prepare and file with the SEC a Registration Statement on Form S-1 and to use its best efforts to cause the Registration Statement to be declared effective by the SEC no later than 150 days after June 30, 2006.
On November 8, 2006, the SEC declared effective the Registration Statement on Form S-1 covering the common shares issued in connection with the July 19, 2005, March 10, 2006, and June 30, 2006, private placements. As a result, the Company is no longer subject to the liquidated damages described above.
On December 20, 2006, the Company completed a private placement of 6,500,000 shares of common stock, no par value, to an accredited investor pursuant to a Subscription Agreement dated December 18, 2006. The common stock was priced at $3.00 per share resulting in proceeds to us of approximately $19.5 million. No warrants or dilutive securities were
issued in connection with the offering. The offering was placed directly by the Company and there were no related placement fees.
Stock Subscription Receivable
In 2004, the Company issued 236,528 shares to an individual investor for $119,175 of cash proceeds and a subscription receivable of $230,825. The investor has pledged assets to a Peruvian bank which secure one of the Company’s performance bonds. The subscription receivable is due at such time as the Company obtains its own performance bond to replace the one posted by the investor or until the performance bond is no longer required.
Potentially Dilutive Securities
In addition to the shares issued and outstanding, the Company has the following potentially dilutive securities. None of these potentially dilutive shares have been included in the calculation of earnings per share as the effect would be anti-dilutive.
On January 1, 2006, the Company adopted SFAS No. 123 - Revised 2004, Share-Based Payment (“SFAS 123(R)”), which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employees. SFAS 123(R) is a revision of SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB No. 25, Accounting for Stock Issued to Employees. Under the provisions of SFAS 123(R), 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 over the employee’s or non-employee’s service period, which is generally the vesting period of the equity grant.
Prior to January 1, 2006, the Company accounted for stock-based compensation in accordance with SFAS 123. As allowed under SFAS 123, the Company accounted for its stock-based compensation to employees using the intrinsic value method of accounting which bases compensation expense on the difference between the quoted market price of the award at the measurement date less the amount, if any, the employee is required to pay for the stock. As of December 31, 2005, stock-based awards to employees consisted of only restricted shares valued using the market price of the Company’s traded common stock on the date of grant. The fair value method used to value restricted shares would have yielded the same fair value and compensation expense as the intrinsic value method used; thus, no pro forma results of operations are required to be presented.
In addition, stock-based awards to non-employees as of December 31, 2005 consisted of options and restricted shares issued in exchange for various legal and investment banking services. Equity instruments issued to non-employees for services were accounted for at fair value at the date of grant. The fair value for awards issued to non-employees was measured using a Black-Scholes valuation model. Expenses determined for employees and non-employees were recognized in the Company’s financial statements over the applicable service period.
The Company adopted SFAS 123(R) using the modified prospective application method and, accordingly, no prior periods have been restated as a result of the adoption of this pronouncement. Under this method, compensation cost recognized during the year ended December 31, 2006 included: (a) compensation cost for all stock-based payments granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original
provisions of SFAS 123; and (b) compensation cost for all stock-based payments granted on or after January 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123(R). SFAS 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods to reflect actual forfeitures. The Company’s forfeiture estimates were not changed as a result of adopting SFAS 123(R).
The following table summarizes stock-based compensation costs recognized under SFAS 123(R) for the year ended December 31, 2006 and under SFAS 123 for year ended December 31, 2005 and 2004:
Restricted Stock Awards and Performance Shares
The Company determines the fair value of restricted stock awards and performance shares based on the market price of the Company’s common stock on the date of grant. Compensation cost for such awards is recognized on a straight-line basis 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 and related information is presented below:
As of December 31, 2006, there was $2.4 million of total unrecognized compensation cost related to nonvested restricted stock awards, which is expected to be recognized over a weighted-average period of 1.3 years.
No performance shares were outstanding as of December 31, 2006.
Stock Options
Incentive and non-qualified stock options issued to directors, officers, employees and consultants are issued at an exercise price equal to the fair market value of the stock at the date of grant. The majority of the Company’s stock options vest pro-rata over two years from the grant date and generally expire ten years from the date of grant. Compensation cost related to stock options is recognized on a straight-line basis over the vesting or service period and is net of forfeitures.
The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes option pricing model. The following table presents the weighted-average assumptions used in the option pricing model for options granted during year ended December 31, 2006. During the year ended December 31, 2005, no options were granted by the Company. The expected life of the options represents the period of time the options are expected to be outstanding. For the year ended December 31, 2006, the expected term of options granted 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. In the future, as information regarding post-vesting termination becomes more accessible, the Company may change the method of deriving the expected term. This change could impact the fair value of options granted in the future. The Company expects to refine the method of deriving the expected term no later than January 1, 2008. For the year ended December 31, 2006, our expected volatility is based on the historical volatility of our stock for a period approximating the expected life. The risk-free interest rate is based on the observed U.S. Treasury yield curve in effect at the time the options were granted. The dividend yield is based on our history of dividend payouts.
A summary of our stock option activity and related information is presented below:
No options were exercised during the year ended December 31, 2006. As of December 31, 2006, there was $6.2 million of total unrecognized compensation cost related to nonvested stock options which is expected to be recognized over a weighted-average period of 1.5 years.
Pursuant to a Settlement Agreement and Mutual Release entered into on May 19, 2006 between the Company, Mr. McKowen and NFS, the vesting period related to the 500,000 nonvested options outstanding as of December 31, 2005, which remained unvested and outstanding as of December 31, 2006, was extended from September 10, 2006 to one year following the effective date of the registration with the SEC of the shares NFS received in the Merger with Navidec. The registration of these shares became effective on December 15, 2006 and, as a result, the expiration date for the remaining options was extended to December 16, 2007. The extension of the vesting period did not result in a revaluation of these options, as the number of options that the Company expects to vest did not change as a result of the modification.
The following table summarizes information about stock options outstanding as of December 31, 2006:
(1) 378,652 outstanding options have been excluded from this total as they relate to options assumed in the Company’s Merger with Navidec. These options have no impact on earnings.
The aggregate intrinsic value of stock options outstanding at December 31, 2006 was $6.5 million, of which $4.1 million relates to awards vested and exercisable and $2.4 million relates to awards expected to vest. The intrinsic value for stock options outstanding is calculated as the amount by which the quoted price of our common stock as of December 29, 2006 exceeds the exercise price of the option.
Warrants
As of December 31, 2006, the Company had 250,000 warrants outstanding. For their role as placement agent, in connection with the private placement of 11,466,000 shares of common stock in July 2005, Morgan Keegan & Company, Inc. received fully vested warrants to purchase 100,000 shares of the Company’s common stock at an exercise price of $3.00 per share. Such warrants expire on July 19, 2010. These warrants were valued at $325,000 using the Black-Scholes model, which amount was treated as additional non-cash stock offering costs.
Additionally, for their financial advisory services, in connection with the private placement of 4,482,000 shares of common stock in June 2006, Morgan Keegan & Company, Inc., received fully vested warrants to purchase 150,000 shares of the Company’s common stock at an exercise price of $3.00 per share. Such warrants expire on June 30, 2011. These warrants were valued at $248,645 using the Black-Scholes model, which amount was treated as additional non-cash stock offering costs.
All warrants issued were valued using the Black-Scholes model, which amount was treated as additional non-cash stock offering costs. The following table presents the weighted-average assumptions used in the option pricing model for options granted during the year ended December 31, 2006 and 2005. The same methodologies applied to determine the assumptions used to value the options noted above were also used in valuing the warrants issued to Morgan Keegan & Company. No warrants were issued during the year ended December 31, 2004.
Contingent Incentive Earn-Out Shares
During 2005, the Company’s Board of Directors awarded a total of 485,000 shares of incentive stock awards to three of the Company’s officers. The incentive stock awards vest and the earn-out shares are issuable once the Company is entitled to receive as its proportionate share from gross production from any oil and gas wells owned or operated by the Company not less than 2,000 barrels of oil per day or its equivalent (approximately 12 million cubic feet of gas per day) prior to December 28, 2007, the same target applicable to the Merger earn-out shares (see below). However, one of the Company’s officers resigned from the Company and its subsidiaries effective June 15, 2006, and as a result 225,000 of the unvested contingent incentive stock awards, representing $990,000 of future possible compensation expense, were forfeited. Subsequently, 190,000 shares of those 225,000 shares awarded to the former officer were reassigned to his replacement who was originally awarded 35,000. As of December 31, 2006, total outstanding awards related to the incentive stock awards was 450,000 shares with a combined future expense of $1,980,000. Of this amount, $819,310 and $409,655 correspond to the year ended December 31, 2006 and the same period ended December 31, 2005, respectively. Since the Company has not yet obtained a firm financing commitment for its gas-to-power project, the Company does not consider the achievement of this target to be probable for accounting purposes and is not currently accruing the associated stock-based compensation expense.
Merger Earn-Out Shares
Under the terms of the Merger Agreement, the Company committed to issue 18,000,000 shares to the former shareholders of BPZ-Texas on a contingent earn-out basis if the Company achieves certain reserve and production goals. The first earn-out target relating to reserves was achieved in December 2004 and 9,000,000 of the earn-out shares were issued. The remaining 9,000,000 earn-out shares are issuable once the Company is entitled to receive as its proportionate share from gross production from any oil and gas wells owned or operated by the Company not less than 2,000 barrels of oil per day or its equivalent (approximately 12 million cubic feet of gas per day) prior to December 28, 2007.
For accounting purposes, the earn-out arrangement is treated as a stock dividend because the earn-out is payable to the shareholders of the accounting acquirer, BPZ-Texas. Accordingly, except for a retroactive increase in the number of common shares outstanding for all periods presented, no accounting entry is required upon the issuance of the earn-out shares.
Long-Term Incentive Compensation Plan
The BPZ Energy, Inc. 2005 Long-Term Incentive Compensation Plan (the “LTIP”) permits the Board of Directors to award eligible employees, directors and consultants with incentive-based and non-incentive-based compensation. The maximum number of shares of stock of the Company that may be subject to incentives under the LTIP, including without limitation incentive options, is 4,000,000 shares, and such shares shall be reserved at all times until issued under the LTIP. Of such amount, no more than 1,600,000 shares in the aggregate shall be eligible for the issuance of performance shares, stock grants, restricted stock grants and other stock-based incentives. The LTIP will be administered and managed within the discretion of Compensation Committee of the Company or, in the absence of such committee, by the Board of Directors. Incentives under the LTIP may be granted to eligible employees, directors or consultants in any one or a combination of incentive options, non-statutory stock options, stock appreciation rights, restricted stock grants, stock grants and performance shares.
Note 11 - Affiliate and Related Party Transactions
As of December 31, 2006 and December 31, 2005, the Company had no outstanding balances with affiliates or related parties.
Note 12 - Income Taxes
There was no income tax expense or benefit for the years ended December 31, 2006, 2005 and 2004 as shown in the following table:
The tax effects of the temporary differences that gives rise to the significant portion of the deferred tax assets and liabilities are presented below:
The Company recorded a valuation allowance for the full amount of the deferred tax asset resulting from the income tax benefit above, 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.
Note 13 - Commitments and Contingencies
Barge Incident
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. No injuries were sustained by any of the Company’s staff, nor to any of the tug boat operator’s crew members. The BPZ-01 is a U.S. flagged vessel and as such was inspected after the incident by the U.S. Coast Guard, to its satisfaction. The barge resumed normal operations immediately thereafter. Based upon information currently available, the Company estimates that total expenditures related to this incident will be approximately $1.1 million. As of December 31, 2006, approximately $382,000 has been incurred for barge recovery and temporary repairs to the vessel. In addition, the Company expects to incur approximately $330,000 in permanent repairs to the barge and approximately $432,000 of consequential damages, primarily stand-by charges. As of the date of this filing, the Company has not presented a final claim to its insurance carrier for the barge repairs and is negotiating a settlement agreement with a third party for recovery of any damages not covered through its insurance. The Company believes the majority of the costs associated with this incident will be reimbursed through insurance or through a third party. No assurances can be given, however, that any such recoveries will be sufficient to cover all costs associated with this incident or to the timing of any such recoveries. This incident is not expected to have a material impact on the Company’s operations or business plan.
Transfer of NFS
On September 9, 2004, the day prior to the effective date of the Merger, Navidec assigned all of its pre-merger business operations, assets and liabilities to NFS and all issued and outstanding shares of NFS were subsequently transferred to the Navidec pre-merger shareholders of record as of September 9, 2004, for no cash consideration.
The transfer of NFS shares was effected by NFS to the pre-merger Navidec shareholders of record as of September 9, 2004. Consistent with the terms of the Merger Agreement, the Company had no control in the actions resulting in the transfer of the NFS shares and the Company believed, based on information provided by NFS and its advisors that NFS had undertaken the necessary actions to comply with applicable registration requirements. However, because a registration of the NFS shares was not effective at the time of the transfer of the NFS shares, and has still not become effective, it might be determined that the transfer of the NFS shares was made without full compliance with registration or qualification requirements under applicable securities laws. As a result, although the Company took no actions in connection with the transfer, because the Company is a successor by merger to Navidec, Inc., if regulatory authorities determine that the Company did not comply with applicable registration requirements in connection with the transfers, fines or other sanctions could be imposed on the Company with respect to the transaction.
While federal and state regulators might conclude that the Company was subject to responsibility for registration of the shares, the Company regards the possibility of liability arising from the distribution of the NFS shares as remote for the following reasons:
The Company took no action with respect to the transfer of NFS shares which, pursuant to the terms of the Merger Agreement, was agreed to be handled by NFS, including any necessary qualifications or registrations under applicable securities laws. Further, the Company believed, based on information provided by NFS and its advisors, that NFS had undertaken to comply with all applicable registration requirements. Additionally, the transfer, which was tantamount to a stock dividend to the pre-merger shareholders of Navidec, Inc., did not involve cash consideration, making a finding of any damage to shareholders unlikely. Finally, it is the Company’s understanding that NFS is taking action to register the NFS shares and is communicating with the SEC to address this issue to the SEC’s satisfaction.
Although the Company regards the possibility of liability resulting from the transfer of NFS as remote, the Company does recognize the risk of such liability, and therefore cautions current and prospective Company shareholders of such risk.
Peru Properties
As of December 31, 2006, in connection with our Peru properties, we have deposited approximately $1.2 million as restricted cash to collateralize two performance bonds which guarantee our various obligations and commitments under one of our license contracts and another agreement. The performance bonds were issued by Peruvian banks and their terms are governed by the corresponding license contract or agreement. We will be required to deposit approximately $1.0 million as restricted cash to collateralize a new performance bond in connection with the beginning of the third exploration period under our Block Z-1 license contract, which begins in June 2007. In addition, although we are still negotiating the terms of our commitments under our license contracts for Blocks XXII and XXIII, we anticipate having to deposit funds as restricted cash to collateralize performance bonds to guarantee our obligations totaling approximately $1 million in late 2007.
In connection with our Block XIX license contract, we are obligated to shoot at least 100 kilometers of 2-D seismic during the first half of 2007, unless an extension is requested and granted. Depending on the results of this work, we may elect to drill an exploratory well. We estimate the cost to acquire this seismic data to be approximately $3 million.
The Company acquired four offshore platforms in connection with its Block Z-1 property. The Company recently completed the refurbishment of one of the offshore platforms and intends to maintain all of such platforms for use throughout the life of the Block Z-1 contract. These platforms revert back to the Government of Peru at the end of the contract, provided they are in good working condition, with no further obligation to the company to dismantle or remove them. The Company and its legal advisors have reviewed Peruvian law and existing regulations from the Peruvian Ministry of Energy and Mines in conjunction with the requirements of SFAS 143 “Accounting for Asset Retirement Obligations” (“ARO”) as it applies to tangible long lived assets and their future retirement and dismantlement. The Company has concluded there is no legal obligation to dismantle the platforms, as defined in SFAS 143, and therefore recognition of an ARO is not required. Accordingly, no such provision is reflected in the accompanying consolidated financial statements. If, however, current laws or regulations were changed or the platforms were no longer in good working order, the Company could be obligated to dismantle and remove them. The current estimated cost to dismantle an offshore platform is estimated to be approximately $2 million, depending upon the condition of the platform and the depth of the water.
In December 2005, the Company signed a drilling contract with Petrex S.A., a subsidiary of Saipem SpA of Italy. Under the contract, Petrex S.A. will provide a platform rig capable of drilling to 16,000 feet and upgrade the rig to meet the
Company’s specifications. The Company intends to utilize the rig for the initial development of the Corvina gas field and may also utilize it for the expected development of the Albacora oil field, and potential appraisal wells in the Piedra Redonda gas field. The Company has agreed to pay a $5.5 million fee to mobilize and upgrade the rig. In exchange, the Company will receive a competitive fixed day rate and exclusive rights to use the rig, at its option, during the two-year period commencing in September, 2006.
In December 2005, the Company notified Perupetro that it had decided to exercise its exclusive option to convert its technical evaluation agreement on Area VI, into a license contract. The new area renamed as Block XXII, consists of approximately 948,000 acres and will encompass a significant portion of the Lancones basin. In connection with this block, after the license contract has been signed, the Company will be required to post a performance bond to guarantee certain obligations and commitments. However, negotiations on the terms of the license contract are still underway and the Company has not been officially awarded the license contract. Accordingly, the Company does not have sufficient information to determine the timing, nor estimate the value of the performance bond to be posted in connection with this property.
In July 2006, Perupetro informed the Company that its proposal for Block XXIII, which consists of approximately 248,000 acres and is located onshore in northwest Peru between the Company’s Blocks Z-1 and XIX, was the winning bid in the tender process. The Company has presented all necessary documentation to become the qualified operator of this new block under an exploration and production license contract. The Company’s proposal covers only the exploration period and commits the Company to drill a certain number of wells, acquire certain amount of either 2-D or 3-D seismic data and prepare an integrated geological, geochemical and reservoir engineering evaluation of the hydrocarbon prospects in the block. In connection with this block, after the license contract has been signed, the Company will be required to post a performance bond to guarantee certain obligations and commitments. However, negotiation on the terms of the license contract are still underway, and the Company has not been officially awarded the license contract. The Company therefore does not have sufficient information to determine the timing, nor estimate the value of the performance bond to be posted in connection with this property.
Financing Activities
On December 20, 2006, the International Finance Corporation’s (“IFC”) Board of Executive Directors approved a $120 million financial package. IFC is the private sector arm of the World Bank Group based in Washington, D.C. As part of the financing, we completed a private placement of 6,500,000 shares of common stock, no par value, to the IFC pursuant to a Subscription Agreement dated December 18, 2006. The common stock was priced at $3.00 per share resulting in proceeds to us of approximately $19.5 million. The offering was placed directly by us and there were no placement fees. The remaining $100.5 million portion of IFC financing consists of $30.5 million of debt facilities for IFC’s own account and $70 million of debt facilities for the account of third-party financial institutions. Syndication of the third-party debt component is expected to take place during the second quarter of 2007. The remaining debt portion of the financing is subject to identification of the lending syndicate members and subsequent negotiation and approval of the necessary loan documentation.
In connection with the July 19, 2005 private placement of 11,466,000 common shares, the Company was obligated to prepare and file with the SEC a Registration Statement on Form S-1 and to use its best efforts to cause the Registration Statement to be declared effective by the SEC no later than ninety days from July 19, 2005. The Registration Statement was not declared effective by the required date and the Company became liable to the investors for liquidated damages in an amount equal to 1.0% of the purchase price of the shares, approximately $343,980, for each thirty day period until the Registration Statement is declared effective by the SEC. Certain of the private placement investors, totaling 79% of the aggregate private placement investment, agreed to accept common stock in lieu of cash for a maximum period of 90 days. The 90-day period ended on February 14, 2006 and the Company began paying the full amount of liquidating damages in cash. A new agreement was entered into on April 17, 2006 with certain private placement investors, totaling 76% of the aggregate private placement investment to accept common stock in lieu of cash until the Registration Statement on Form S-1 is declared effective by the SEC. On November 8, 2006, the SEC declared effective the Registration Statement on Form S-1 covering the common shares issued in connection with the July 19, 2005, March 10, 2006, and June 30, 2006, private placements. As a result, the Company is no longer subject to the liquidated damages described above.
In connection with the March 10, 2006 private placement of 1,670,000 common shares, the Company was obligated to prepare and file with the SEC a Registration Statement on Form S-1 and to use its best efforts to cause the Registration Statement to be declared effective by the SEC no later than ninety days, from March 8, 2006. The Registration Statement was not declared effective by the required date and the Company became liable to the investors for liquidated damages in an amount equal to 1.0% of the purchase price of the shares, approximately $50,100, for each thirty day period until the Registration Statement is declared effective by the SEC. Such liquidated damages are payable in common stock or cash at
the Company’s discretion. On November 8, 2006, the SEC declared effective the Registration Statement on Form S-1 covering the common shares issued in connection with the July 19, 2005, March 10, 2006, and June 30, 2006, private placements. As a result, the Company is no longer subject to the liquidated damages described above.
On December 20, 2006, the Company completed a private placement of 6,500,000 shares of common stock, no par value, to an accredited investor pursuant to a Subscription Agreement dated December 18, 2006. The common stock was priced at $3.00 per share resulting in proceeds to us of approximately $19.5 million. No warrants or dilutive securities were issued in connection with the offering. The offering was placed directly by the Company and there were no placement fees.
The Company will continue to make commitments in the ordinary course of business as it pursues its development plans for the properties.
Note 14 - Legal Proceedings
SEC Inquiry of Navidec
Navidec was advised in February 2004 that the SEC was conducting an informal inquiry to determine whether Navidec had violated federal securities laws. Based on the information made available to the Company, it believes the SEC’s investigation relates, at least in part, to the restatement of Navidec’s reported earnings for the first and second quarters of 2003. This restatement was reported in Navidec’s Form 10-Q for the third quarter of 2003 filed on December 11, 2003.
In December 2004, the Company received notice that the SEC had issued an Order Directing a Private Investigation and Designating Officers to Take Testimony and would be conducting a formal investigation. Pursuant to the Merger Agreement, the Company has been indemnified by NFS for the costs of the SEC investigation, and NFS has borne the costs incurred to date. The Company is not aware of the future actions, if any, which the SEC intends to pursue in this matter, but no assurance can be given that the investigation has been and will be resolved without negative consequences to the Company.
Transfer of Ownership in NFS
On July 8, 2004, Navidec and BPZ-Texas entered into a Merger Agreement which was consummated on September 10, 2004. The Merger Agreement provided that all of the pre-merger business operations, assets and liabilities of Navidec would be transferred to a wholly-owned subsidiary, Navidec Financial Services, Inc. (“NFS”), followed by the transfer of NFS to the pre-merger shareholders of record as of September 9, 2004, the day prior to the consummation of the Merger. See “Business and Properties-Navidec Merger Transaction,” “Risk Factors-Risk Relating to the Offering-The transfer of NFS could result in liability to us because the shares transferred were not registered with the SEC,” and Note 2 to the Consolidated Financial Statements, included in this filing, for detailed discussion regarding the Merger.
The Merger Agreement provided that the transfer of all of the pre-merger business operations, assets and liabilities of NFS was effective as of September 9, 2004. Accordingly, the Company originally believed that it had no continuing ownership of NFS and, therefore, did not account for the post-merger operations of NFS in the presentation of its financial statements. After receipt of comments from the SEC in connection with its review of the Company’s registration statement on Form SB-2 originally filed on July 27, 2005 and further review of this issue, the Company concluded it was the record, but not beneficial, owner of NFS shares, and that any ownership interest was at most temporary.
In part because of difficulty obtaining necessary information from NFS to clarify the ownership issue, the Company commenced an action against NFS (the “Action”) on or about February 13, 2006, in District Court, Arapahoe County, Colorado (the “Court”), seeking dissolution of NFS, the appointment of a receiver, and access to NFS corporate records. The Company commenced the Action uncertain whether or when the required spin-off of NFS shares pursuant to the terms and conditions of the Merger had occurred under Colorado corporate law. The Company asserted in the Action that it believed it was a record shareholder of NFS as of the date of the request and had standing for the relief sought. NFS denied that the Company had standing to act as a shareholder and asserted that the Company had not been a shareholder of NFS since September 9, 2004. The Action was settled amongst the parties on May 19, 2006. In connection with the settlement, a Finding of Fact and Conclusions of Law (the “Order”) was issued by the Court stating that the Company was not a shareholder of NFS at any time after September 9, 2004.
Note 15 - Minimum Lease Payments
The Company leases office space in Houston, Texas under a five-year operating lease. We also have offices in Lima, Peru and Quito, Ecuador, both of which are under a month-to-month operating lease. Total rent expense incurred for the
years ended December 31, 2006, 2005 and 2004 was approximately $252,000, $98,000 and $18,000, respectively. Minimum non-cancelable lease commitments under these agreements for the years ending December 31 are as follows:
Note 16 - Subsequent Events
In July 2004, the Company granted options to purchase 1,000,000 shares of common stock at an exercise price of $1.30 per share to the former CEO of Navidec in connection with his service as a director and financial consultant to the Company. On the date of the Merger, 500,000 of such stock options became fully vested. Vesting of the remaining 500,000 stock options is contingent upon the receipt of additional investment proceeds totaling $6 million, including proceeds from the exercise of outstanding warrants. As of the date of this filing, Mr. McKowen has fulfilled his obligation to raise $6,000,000 under the above agreement and as such, has vested in the remaining 500,000 stock options.
Note 17 - Supplemental Oil and Gas Disclosures (Unaudited)
Oil and Natural Gas Producing Activities
The following disclosures for the Company are made in accordance with SFAS No. 69, “Disclosures About Oil and Natural Gas Producing Activities (an amendment of FASB Statements 19, 25, 33 and 39)”. 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.
Proved reserves represent estimated quantities of natural gas and crude oil 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.
No assessment of proved or unproved reserves has been made to date.
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; and
· review by our senior reservoir engineer and his staff of the independent reservoir engineers’ reserves reports for completion and accuracy.
Market prices as of each year-end will be 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.
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, 2006 and 2005:
Pursuant to SFAS No. 143 “Accounting for Asset Retirement Obligations”, net capitalized cost includes asset retirement cost. However, due to the fact that we have not yet begun operations, we do not have sufficient information to determine the timing, nor calculate the present value of the obligation.
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, 2006 and 2005:
(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 exclude interest charges and general and administrative expenses. Sales are based on market prices.
(1) Investment in Ecuador Property
Net Proved and Proved Developed Reserve Summary
The following table sets forth the Company’s net proved and proved developed reserves at December 31, 2006, 2005 and 2004, and the changes in the net proved reserves for each of the three years in the period then ended.
(1) Thousands of cubic feet.
(2) Barrels.
(3) Includes crude oil, condensate and natural gas liquids.
(4) 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.
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 by SFAS No. 69 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 natural gas and crude oil reserves for the years ended December 31, 2006, 2005 and 2004:
(1) Investment in Ecuador Property
Note 18 - Quarterly Results of Operations
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, 2006 our disclosure controls and procedures 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.
(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, 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
(c) Management’s Report on Internal Control over Financial Reporting and Report of Independent Registered Public Accounting Firm 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, 2006.
Johnson Miller & Co., CPA’s PC, the independent registered public accounting firm who also audited our Consolidated Financial Statements, has issued an attestation report on management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, 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
BPZ Energy, Inc. and Subsidiaries
(An Exploration Stage Company)
We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that BPZ Energy, Inc. and Subsidiaries (An Exploration Stage Company)(the “Company”) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria) . The Company’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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and 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 accounting principles generally accepted in the United States of America. 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 accounting principles generally accepted in the United States of America, 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, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2006, and for the period from August 20, 2001 (Inception) through December 31, 2006, and our report dated March 14, 2007, expressed an unqualified opinion.
/s/ Johnson Miller & Co., CPA’s PC
Midland, Texas
March 14, 2007
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 and to the information set forth in Item 1 of this report
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
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this report:
1. Financial Statements.
Our consolidated financial statements are included in Part II, Item 8 of this report:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity (Deficit)
Consolidated Statements of Cash Flows
Notes to the Consolidated Financial Statements
Management’s Report on Internal Control Over Financial Reporting
Report of Independent Registered Public Accounting Firm
2. Financial Statements Schedules and supplementary information required to be submitted:
None.
3. Exhibits
A list of the exhibits filed or furnished with this report on Form 10-K ( or incorporated by reference to exhibits previously filed or furnished by us) is provided in the Exhibit Index beginning on page 84 of this report. Those exhibits incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. Otherwise, the exhibits are filed herewith.
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, 2007.
Pursuant to the requirements of the Securities Act of 1934, this registration statement was signed by the following persons 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
Vice President-Finance and Chief Accounting Officer
March 16, 2007
(Principal Accounting and Financial Officer)
March 16, 2007
/s/ DR. FERNANDO ZÚÑIGA Y RIVERO
/s/ GORDON GRAY
Dr. Fernando Zúñiga y Rivero
Gordon Gray
Director and Chairman of the Board
Director
March 16, 2007
March 16, 2007
/s/ E. BARGER MILLER III
/s/ JOHN J. LENDRUM, III
E. Barger Miller III
John J. Lendrum, III
Director
Director
March 16, 2007
March 16, 2007
/s/ DENNIS G. STRAUCH
Dennis G. Strauch
Director
March 16, 2007
INDEX OF EXHIBITS
Exhibit Number
Description
3.1
Third Amended and Restated Articles of Incorporation of BPZ Energy, Inc. (incorporated by reference to Exhibit 3.1 to BPZ Energy, Inc.’s Registration Statement on Form SB-2 Amendment No. 2 (SEC File No. 333-122816)).
3.2
Amended and Restated Bylaws (incorporated by reference to Exhibit 3.2 to the Company’s Form SB-2 (SEC File No. 333-14497) filed on October 18, 1996).
3.3
Amendment to Second Amended and Restated Articles of Incorporation of Navidec, Inc. (incorporated by reference to Exhibit 3.4 to the Company’s Form SB-2 (SEC File No. 333-122816) filed on February 14, 2005).
4.1
Form of Certificate for Common Stock of BPZ Energy, Inc., a Colorado corporation (incorporated by reference to Exhibit 4.1 to the Company’s Form SB-2 (SEC File No. 333-122816) filed on February 14, 2005).
4.2
BPZ Energy, Inc. 2005 Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 4.1 to the Company’s Form S-8 (SEC File No. 333- 126388) filed on July 5, 2005).
10.1
Merger Agreement between Navidec, Inc. and BPZ, Inc. dated July 8, 2004 (incorporated by reference to Exhibit 10.1 from the Company’s Form 8-K filed July 13, 2004).
10.2
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 September 14, 2004).
10.3
Business Consulting Agreement dated July 8, 2004 by and between BPZ Energy, Inc., a Colorado corporation, and Navidec Financial Services, Inc., a Colorado corporation (incorporated by reference to Exhibit 10.3 to the Company’s Form SB-2 (SEC File No. 333-122816) filed on February 14, 2005).
10.4
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 (SEC File No. 333-122816) filed on February 14, 2005).
10.5
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).
10.6
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 (SEC File No. 333-122816) filed on February 14, 2005).
10.7
Technical Evaluation Agreement from the Government of Peru for Area VI dated December 12, 2003 (incorporated by reference to Exhibit 10.7 to the Company’s Form SB-2 (SEC File No. 333-122816) filed on February 14, 2005).
10.8
Promotional Technical Evaluation Agreement from the Government of Peru for Area XVI dated December 12, 2003 (incorporated by reference to Exhibit 10.8 to the Company’s Form SB-2 (SEC File No. 333-122816) filed on February 14, 2005).
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).
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 Vice President - Finance and Chief Accounting 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 Vice President - Finance and Chief Accounting Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (filed herewith).