ITEM 1. BUSINESS
Overview
BPZ Resources, Inc., a Texas corporation, is based in Houston, Texas with offices in Lima, Peru and Quito, Ecuador. We are focused on the exploration, development and production of oil and natural gas in Peru and Ecuador. We also intend to utilize part of our planned future natural gas production as a supply source for the complementary development of a Company owned gas-fired power generation facility.
We maintain a subsidiary registered in Peru through our wholly owned subsidiary BPZ Energy, Inc., a Texas corporation (“BPZ - Texas”). 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 four blocks, in northwest Peru. Our license contracts cover 100% ownership of Block Z-1 (739,205 acres), Block XIX (472,860 acres), Block XXII (948,000 acres, also referred to as Area VI in previous filings) and Block XXIII (248,000 acres). The Block Z-1 contract was signed in November 2001, the Block XIX contract was signed in December 2003 and Blocks XXII and XXIII were both signed in November 2007. Our license contracts provide for an initial exploration period of seven to thirteen years for Block Z-1and seven to ten years for Blocks XIX, XXII and XXIII. In addition, they require that we conduct specified activities on the properties during this period. If the exploration activities are successful, our total contract term can extend up to 30 years for oil exploration and production and up to 40 years for gas exploration and production.
Additionally, through our wholly owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, we 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 initial stages of developing our oil and natural gas reserves and have recently begun producing oil under an extended well test program from our recent discoveries. To date our activities in Peru have been primarily limited to analysis and evaluation of technical data on our properties, 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, bringing production on-line and securing the required capital and financing to conduct the current plan of operation. In March 2007, after a total of six drill stem tests were conducted on separate potential pay zones from the Lower and Upper Zorritos formations, our first well the CX11-21 XD well, tested positive for both gas and oil at commercially producible quantities. Subsequently, in June 2007 we successfully recompleted the Corvina CX11-16X well as a natural gas producing well and completed a total of four drill stem tests on various zones in the well including one in a formation previously untested in the entire basin. In October 2007, we completed seven drill stem tests on the CX11-14D well in the Corvina Field. The first six tests were conducted in the Upper Zorritos formation, with the first two testing the oil zone and the other four testing the gas zone, while the seventh test targeted the Cardalitos formation located immediately above the Upper Zorritos. The CX11-14D well tested positive for both gas and oil at commercially producible quantities. On November 29, 2007, we commenced drilling on the CX11-18XD well. The well reached total depth of 8,792 feet (measured depth) on January 1, 2008, approximately one month ahead of schedule. We have recently performed a series of safety and integrity
tests on the CX-11 Corvina platform including the surface equipment. As part of the integrity testing of the service equipment, we perforated the lower prospective oil sands identified in the CX11-18XD well. These lower sands tested oil and the results assisted in validating our Corvina geologic model.
On June 13, 2007, we entered into a capital lease agreement, with an option to purchase, for two barges to assist in the development of the Corvina Field. Each of these barges has a capacity of approximately 40,000 barrels. The two barges were towed to Peru where one barge, the Nu’ uanu, is currently being used to transport oil between the CX11 platform and the refinery in Talara. The other barge, the Nomoku, is currently being fitted with the required equipment for its intended use as a floating production, storage and offloading facility (“FPSO”) that will be moored next to the CX11 platform. However, we have encountered some scheduling delays in deploying this barge. We expect the Nomoku to be fully fitted and operational by the end of the first or beginning of the second quarter of 2008. Until such time the Nomoku is fitted with the permanent production equipment, we are anticipating pumping oil directly to the Nu’uanu using temporary production equipment and then transporting the oil to the Talara refinery.
We started producing oil from the CX11 platform under an extended well testing program beginning on November 1, 2007. By December 31, 2007, we produced approximately 40,989 barrels of oil and sold approximately 28,741 barrels to a refinery in Talara. Our oil is delivered to the refinery by barge approximately 100 miles south of the platform. The remainder was kept in production inventory until such time it was delivered to Talara in early 2008.
On October 24, 2007, our primary marine transportation contractor entered into two short term agreements with the commercial division of the Peruvian Navy to lease two tankers to transport oil to market. However, on January 30, 2008, one of the tankers, the Supe, sank after catching fire. At the time of the incident the Supe tanker contained approximately 1,300 barrels of oil, most of which is believed to have been burned in the fire. Initial assessments show that environmental issues have been adequately controlled. No Company employees were injured.
Currently all production (which had reached approximately 4,200 barrels of oil per day by late January 2008) is shut-in due to the incident involving the Navy tanker. At the request of the OSINERGMIN, the government agency responsible for auditing the safety of energy investments in Peru, we successfully performed a series of safety and integrity tests on the facilities at the CX-11 Corvina platform, including the equipment that was being used for the ongoing long-term testing of the 21XD and 14D wells. We confirmed that the well testing equipment was in operational condition. On March 12, 2008 we received clearance from the OSINERGMIN, to resume operations at the CX-11 platform, including the scheduled 18XD well drill stem test. However, the four Corvina wells are currently shut-in while we complete the installation of sea-bed pipelines connecting the platform to the transport barge, along with the required mooring systems, that will allow for an improved long-term testing program. Additionally, we are waiting for final clarification from the appropriate authorities in Peru regarding the transportation of our crude oil to the refinery.
We have submitted all the requested reports and documentation generated during the investigation of the January 30, 2008 sinking of the Peruvian Navy tanker, the Supe. A number of organizations involved in the investigation have issued reports concluding there was no environmental damage due to the incident. Additionally, we assisted the Peruvian Navy in conducting an underwater survey of the Supe, which established that the vessel does not represent a hazard to navigation nor a marine pollution threat, because all its tanks were found to be empty. The CX-11 Corvina platform and all its facilities, as well as the BPZ-01 tender barge, the four Corvina wells, and all the vessels supporting the operations have now been certified to be in operational condition. See Note 14 “Commitments and Contingencies”, in the Notes to the Consolidated Financial Statements below, for further discussion.
Consequently (through our primary marine transportation contractor) we are now leasing only one vessel from the Navy having a capacity of approximately 6,000 barrels. The lease is set to expire at the end of March 2008.
Reincorporation, Name Change and Internal Restructuring
On October 11, 2007, BPZ Energy, Inc., a Colorado corporation, formerly named Navidec, Inc., completed a reincorporation from Colorado to the State of Texas pursuant to the Plan of Conversion as approved by the shareholders at the 2007 annual meeting of shareholders held on August 17, 2007. The related filings with the Secretary of State of Texas also included a change of the Company’s name from BPZ Energy, Inc. to BPZ Resources Inc., in connection with an ongoing review of certain internal reorganization matters related to our international tax planning and corporate structure. The Company continues to do business under the name BPZ Energy in its regular business operations.
No changes to the members of the Board of Directors, the management, or the operations of the Company were made in connection with the conversion from a Colorado corporation to a Texas corporation. The Company remains as the same business entity following the reincorporation to Texas, with all of the assets, rights, privileges and powers of, and all
property owned by, all debts due to, as well as any causes of action belonging to the predecessor Colorado entity. As part of the reincorporation, a new Certificate of Formation and new Bylaws were adopted, which now govern the rights of holders of the Company’s common stock. At the effective time of the reincorporation, each outstanding share of the Colorado entity prior to the reincorporation was automatically converted into one share of the Texas entity.
As part of the restructuring, we have created two British Virgin Island limited partnership holding companies for various BPZ entities. Each holding company is owned 90% by BPZ Energy, Inc. as general partner and, in compliance with local requirements, 10% by an individual nominee limited partner, one of whom is our President and Chief Executive Officer. Although 10% of each of the holding companies is nominally owned by an individual, these individuals have agreed to enter into nominee agreements to assign all associated economic interest back to us, and consequently we treat these subsidiary holding companies and their subsidiaries as “wholly-owned” for accounting purposes. By the time we complete the restructuring, we intend to replace the individual nominees with another wholly-owned subsidiary to serve as limited partner of the holding companies.
Navidec Merger Transaction
On September 10, 2004, BPZ Energy, Inc., a Texas corporation, consummated a reverse merger with Navidec, whereby BPZ-Texas became a wholly owned subsidiary of Navidec (the “Merger”). As a result of the Merger, the shareholders of BPZ-Texas received the majority of the voting interest control of the Board of Directors and management of the combined entity and on February 4, 2005, Navidec changed its name to BPZ Energy, Inc. For accounting purposes, BPZ-Texas was treated as the acquiring entity. All financial statements herein represent the historical financial statements of the accounting acquirer, BPZ-Texas. 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 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 achieved 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 were contingent on the Company becoming 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. In November 2007 this production target was achieved based on certification by an independent engineering firm that the Company’s production in Peru has met or exceeded the required level of production.
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 as contingent merger consideration. 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.
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, 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. The SEC also 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
Intense competition exists in the oil and gas industry with respect to the acquisition of producing properties, undeveloped acreage, and rights to explore for such 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 specifically in Peru and Ecuador.
We believe our efforts in and unique knowledge of our targeted areas have given us a competitive advantage in Peru, and to a lesser extent, Ecuador. Although un-leased tracts exist within our target area, we believe 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 un-leased 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, in addition to better name recognition and longer
operating histories. As a result, we may not be able to compete successfully to acquire additional oil and gas properties in desirable locations.
Intense competition for access to drilling and other contract services and experienced technical and operating personnel needed to drill and complete wells also exists in the oil and gas industry. In the past, for example, we have 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 are adjusting our operating plans and timelines to adapt to this changing environment. However, 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.
Customers
To date, all of our sales of oil in Peru have been made under a short-term contract to the Peruvian national oil company, Petroperu.
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 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 as well as 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 with the appropriate governmental authorities. 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 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, the nature of 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 OSINERGMIN 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 compatible with Peru’s interests. We only operate under license contracts and do not foresee operating under any services contracts. 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.
BPZ Energy, Inc. (Texas) and its corresponding subsidiary or branch in 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 subsidiary or 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.
Until August 1993, 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 uncertainty as to exactly how the licensing procedures will function in the future.
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. A potential deferment period for a maximum of ten years is also available 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 four license contracts. As of March 14, 2008, we believe we were in compliance with all of the material requirements of each such contract. We have executed certain letters of guaranty to insure our performance under the license contracts and a drilling service agreement. At December 31, 2007, we had $6.0 million in bonds posted at various dates, to secure our obligation under the license contract for Block XIX, Z-1, XXII and XXIII and a drilling service agreement. The license contract bonds and the service agreement bond are partially secured by the deposit of restricted cash with the financial institutions which issued the bonds in the amount of $2.8 million and $1.0 million, respectfully. Should we fail to fulfill our obligations under any of our license contracts or service agreement without technical justification or other good cause, Perupetro and/or our service provider could seek recourse to the bond or terminate the license and/or the service contract.
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 they operate. 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 or has been relinquished, 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.
The Constitution of Peru and Legislative Decree Nos. 677 and 892 gives employees working in private companies engaged in activities generating income classified as third category income by the Income Tax Law the right to share in the company’s profits. This profit sharing is carried out through the distribution by the company of a percentage of the annual income before tax. According to Article 3 of the United Nations International Standard Industrial Classification, BPZ Resources, Inc.’s tax percentage is classified under the “mining companies” section, which sets the rate at 8%. The benefit granted by the law to employees is calculated on the basis of the “net income subject to taxation” and not on the net business or accounting income of companies. “Net income” is obtained after deducting from total revenues subject to income tax, the expenses required to produce them or maintain the source thereof.
The following factors are taken into account regarding the profit sharing system: (1) calculation of profits to be distributed to each employee is based on two criteria (a) the number of days actually worked by each employee, and (b) in proportion to the remunerations of each employee; (2) number of days actually worked (including leave of absence, temporary shutdown of the workplace, and days not worked due to improper suspension by the employer); (3) remuneration (the full amount received by the employee for his services); (4) maximum profit share limit of 18 monthly remunerations; (5) remainder between the maximum percentage of company profits to be distributed and the maximum limit of the percentage corresponding to all employees); (6) timing of distributions should be made within thirty calendar days after expiration of the term for the filing of the Annual Income Tax Return; (7) default interest; (8) evidence of settlement of profits; and (9) deductible expenses.
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 a 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. OSINERGMIN 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. For example, 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 offshore Peru where we intend to conduct oil and gas operations. 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 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 in the future experience in the future delays in obtaining permits and authorizations in Peru necessary for our operations.
Compliance with Existing Legislation in Peru
Although we believe 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., our wholly owned subsidiary, has held its 10% non-operating interest in the Santa Elena oil fields since 1997. We acquired all of the common stock of SMC Ecuador Inc. in 2004. 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 in 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.
In addition to certain pollution coverage related to our surface facilities, we also maintain insurance coverage for seepage and pollution, cleanup and contamination from our wells. Regardless, no such coverage can insure us fully against all environmental risks. We are not aware of any environmental claims which would have a material impact upon our financial position or results of operations.
We 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. As part of this effort 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 cost to date for these studies and assistance related to the Block Z-1 Corvina and Albacora fields and Block XIX are approximately $791,808. We are currently assessing what studies are necessary and the associated cost estimate for Blocks XXII and XXIII.
In January, 2008 one of the chartered Navy tankers that our primary marine transportation contractor was chartering from the Peruvian Navy’s commercial branch sunk after catching fire. The 7,500 barrel capacity “Supe”, that was moored near the Corvina CX-11 platform and was being used to store oil produced from Corvina’s 21XD and 14D wells, caught fire and later sank approximately one and a half miles from the platform. At the time of the incident the Supe tanker contained approximately 1,300 barrels of oil, most of which is believed to have been burned in the fire. Initial assessments show that environmental issues have been adequately controlled. No Company employees were injured.
There was no damage to our platform, barges, drilling and well testing equipment, or other facilities we own and the damage has been limited mostly to the Supe, which was anchored at a distance from the platform and directed away after it caught fire. We contracted the services of Clean Caribbean and Americas (“CCA”) to conduct an environmental damage assessment in and around the area surrounding the incident. CCA concluded that the majority of the crude oil contained in the Navy tanker was burned-off during the fire subsequent to the explosion. This was confirmed after divers inspected the sunken tanker, which is resting 200 feet underwater, and reported that no crude oil or fuel was detected in any of the tanks. Our environmental consultants, as well as several independent organizations, conducted additional lab tests on seawater and marine life within the potentially affected area and these lab results indicated no contamination related to the incident.
We do not believe compliance with national, 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 are 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 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, 2007.
(1) Dr. Zúñiga y Rivero is the father of the Company’s President, Chief Executive Officer and Director, Mr. Zúñiga-Pflücker. There are no other family relationships between any directors or executive officers of the Company.
(2) Appointed Chief Financial Officer as of May 24, 2007.
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. Dr. Zúñiga y Rivero served as a director of Transmeridian Exploration, Inc., a public oil and gas company with operations in Kazakhstan, from April 2005 until May 2007.
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 (which is no longer active), in 1989.
Edward G. Caminos, Chief Financial Officer. Mr. Caminos was appointed as Chief Financial Officer of the Company, effective May 24, 2007. Mr. Caminos served as Vice President-Finance and Chief Accounting Officer since October 30, 2006 until his appointment as Chief Financial Officer. Mr. Caminos also served as interim Chief Financial Officer from June 15, 2006 to October 29, 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. Mr. Caminos is a Certified Public Accountant and holds a Bachelor’s Degree in Business Administration - Accounting from Bloomsburg University of Pennsylvania.
Employees
As of December 31, 2007, we employed 23 full-time employees (of which 3 are executive officers) in our Houston office and 44 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 currently 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 and development activities. Although BPZ-Texas was formed in 2001, we are in the initial stages of developing our oil and natural gas reserves and have recently begun producing oil from our recent discoveries under an extended well test program. 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, in particular, 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. Since the merger with Navidec, Inc. (“Navidec”) on September 10, 2004 (the “Merger”) we have funded our operations with the net proceeds of approximately $112 million in various private placements of our common stock and $15.5 million in convertible debt financing from the “International Finance Corporation (“IFC”). We have recently begun to generate revenues from operations. With these funds we have begun to implement our plans to develop our existing oil and gas properties, but we will need significant additional financing to fully implement our plan of operation. If we are unable to timely obtain adequate funds to finance our exploration and development, our ability to develop our oil and natural gas reserves may be limited or substantially delayed. Such limitations or delays could result in the potential loss of our oil and gas properties if we were unable to meet our obligations under the license agreements, which could, in turn, limit our ability to repay our debts. Inability to timely obtain funds also could cause us to delay, scale back or abandon our plans for construction of our power generation facility, pipelines, and gas processing facility.
Future amounts required to fund our foreign activities may be obtained through additional equity and debt financing, joint venture arrangements, the sale of oil and gas interests, and/or future cash flows from operations. However, adequate funds may not be available when needed or may not be available on favorable terms. The exact nature and terms of such funding sources are unknown at this time, and there can be no assurance that we will obtain such funding or have adequate funding available to finance our future operations.
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. No assurance can be given that we can produce sufficient revenue to operate our existing properties or acquire additional oil and gas producing properties and leases. We may not discover or successfully produce any recoverable reserves in the future, or we may not be able to make a profit from the reserves that we may discover. In 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.
Experiencing any of these operating risks could lead to problems with any well bores, platforms, gathering systems and processing facilities, which could adversely affect any drilling operations we may commence. Affected drilling operations could further lead to substantial losses as a result of:
· injury or loss of life;
· severe damage to and destruction of property, natural resources and equipment;
· pollution and other environmental damage;
· clean-up responsibilities;
· regulatory investigation and penalties;
· suspension of our operations;
· repairs to resume operations;
· environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases.
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 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, tankers and barges, as well as interrupt operations. As a result, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, exploitation and acquisitions or result in loss of equipment and properties.
Disruption of services provided by our barges and tankers could temporarily impair our operations. 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. In addition, we have two barges under capital lease to use as a floating production, storage and offloading facility (“FPSO”) and a transport barge in our continuing development of oil production operations, and we have one Peruvian Navy tanker under short-term lease through our primary marine transportation contractor, to assist in the transport of oil from our offshore platforms. These vessels are an important element in our strategy to control drilling, storage and transportation costs by allowing the use of existing platforms and avoiding the use of high-priced ships or barges. Any disruption or delay of the services to be provided by our barges or tanker because of adverse weather conditions, accidents, mechanical failures, insufficient personnel or other events could temporarily impair our operations, delay implementation of our business plan, and increase our costs. For example, in January 2008 we lost the use of a Peruvian Navy tanker that our primary marine tranporation contractor had under short-term lease for our benefit when it sank after catching on fire. In addition, our insurance may not be adequate to cover any resulting losses.
Our reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors, that may turn out to be inaccurate. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and the calculation of the present value of reserves shown in this report.
In order to prepare the reserve estimates included in this report, our independent petroleum engineer must project production rates and timing of development expenditures as well as analyze available geological, geophysical, production
and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from our estimates, and those variances may be material. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, our independent petroleum engineer may adjust estimates of proved reserves to reflect production history, drilling results, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
You should not assume that the pre-tax net present value of our proved reserves prepared in accordance with SEC guidelines referred to in this report is the current market value of our estimated oil reserves. We base the pre-tax net present value of future net cash flows from our proved reserves on the date of estimate. Actual future prices, costs, taxes and the volume of produced reserves may differ materially from those used in the pre-tax net present value estimate.
Future oil and natural gas declines or unsuccessful exploration efforts may result in a write-down of our asset carrying values. We follow the successful efforts method of accounting for our investments in oil and natural gas properties. Under this method, oil and gas lease acquisition costs and intangible drilling costs associated with exploration efforts that result in the discovery of proved reserves and costs associated with development drilling, whether or not successful, are capitalized when incurred. Certain costs of exploratory wells are capitalized pending determinations that proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed.
The capitalized costs of our oil and natural gas properties, on a field basis, cannot exceed the estimated undiscounted future net cash flows of that field. If net capitalized costs exceed future net revenues, we must write down the costs of each such field to our estimate of its fair market value. Unproved properties are evaluated at the lower of cost or fair market value. Accordingly, a significant decline in oil or natural gas prices or unsuccessful exploration efforts could cause a future write-down of capitalized costs.
We evaluate impairment of our proved oil and gas properties whenever events or changes in circumstances indicate an asset’s carrying amount may not be recoverable. In addition, write-downs would occur if we were to experience sufficient downward adjustments to our estimated proved reserves or the present value of estimated future net revenues. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date even if oil or natural gas prices increase.
As of December 31, 2007, approximately 75% of our estimated net proved reserves were undeveloped. There can be no assurance that all of these reserves will ultimately be developed or produced. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. We have prepared estimates of our natural gas and oil reserves and the costs associated with theses reserves in accordance with industry standards. However, the estimated costs may not be accurate, development may not occur as scheduled, or the actual results may not be as estimated. We may not have or be able to obtain the capital we need to develop these proved reserves.
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 construction and future 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.
We may experience delays in delivering our oil to be sold. Our oil from the Corvina Field is delivered by barge to the refinery in Talara approximately 100 miles south of the platform where the oil is sold at current market prices. As a result of the location, we may experience delays or interruptions in delivering our oil due to severe weather, accidents or mechanical failures to our barges, or delays to dock in Talara. Any prolonged delay or interruption of delivery of our oil could adversely impact our business and our revenues.
Our success depends in part 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. Although we plan to enter into long-term contracts to sell a significant part of our future power production, there can be no assurance that we will be successful in obtaining such contracts or that they will be on favorable terms. 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 political or regulatory environment.
Because all our properties could experience the same conditions at the same time, these conditions could have a relatively greater impact on our results of operations than they might have on other operators who have properties over a wider geographic area.
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. 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. Furthermore, 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, as well as any adverse change in the interpretation of existing laws or our failure to comply with existing legal requirements may harm our results of operations and financial condition. In addition, there is indication that the current administration in Ecuador is likely to increase state intervention in the economy via new legislation and tightening control of areas such as energy, which could have a significant impact on our ability to operate in that country. We may be required to make large and unanticipated 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 the Foreign Corrupt Practices Act (the “FCPA”) and our failure to comply with the laws and regulations thereunder could result in penalties which could harm our reputation and have a material adverse effect on our business, results of operations and financial condition. We are subject to the FCPA, which generally prohibits companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business and/or other benefits. Since all of our oil and gas properties are in Peru and Ecuador, there is a risk of potential FCPA violations. We have a FCPA policy and a limited compliance program designed to ensure that the Company, its employees and agents comply with the FCPA. We believe our policy and compliance program are adequate given the small size of our company. However, there is no assurance that such policy or program will work effectively all of the time or protect us against liability under the FCPA for actions taken by our agents, employees and intermediaries with respect to our business or any businesses that we acquire. Any violation of these laws could result in monetary penalties against us or our subsidiaries and could damage our reputation and, therefore, our ability to do business.
We are subject to complex environmental regulatory and permitting laws and regulations that can adversely affect the cost, manner and feasibility of our planned operations. The exploration for, and the development, production and sale of, oil and gas in South America 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 offshore Peru, where we intend to conduct future oil and gas operations. Additionally, 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 and we believe the costs incurred by these policies and procedures so far have been necessary business costs in the oil and gas industry. However, there is no assurance that changes in or additions to laws or regulations regarding the protection of the environment will not increase such compliance costs, or have a material adverse effect upon our capital expenditures, earnings or competitive position.
Our oil and gas operations involve substantial costs and are subject to various economic risks. Our oil and gas operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire producing properties and to drill exploratory wells. The cost and length of time necessary to produce any reserves may be such that it will not be economically viable. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause our exploration, development and production activities to be unsuccessful. In addition, the cost and timing of drilling, completing and operating wells is often uncertain. We also face the risk that the oil and/or gas reserves may be less than anticipated, that we will not have sufficient funds to successfully drill on the property, that we will not be able to market the oil and/or gas due to a lack of a market and that fluctuations in the prices of oil and/or gas will make development of those leases uneconomical. This could result in a total loss of our investment.
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. We actively compete with other companies in our industry when acquiring new leases or oil and gas properties. Competition in our business activities has increased and will increase further, as existing and new participants expand their activities as a result of these regulatory changes. Many of our competitors possess and employ financial resources that allow them to obtain substantially greater technical and personnel resources than we have. For example, if several companies are interested in an area, Perupetro 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 and unique expertise in the type of endeavors we presently conduct and the geographical areas in which we conduct them. We do not maintain any life insurance against the loss of any of these individuals. To the extent their services become unavailable, we will be required to retain other qualified personnel. There can be no assurance we will be able to recruit and hire qualified persons 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, environmental damage and reservoir loss or damage. Further, no such insurance coverage can insure for all operational or environmental risks. The occurrence of an event that is not insured or not fully insured could result in losses to us. For example, uninsured or under insured environmental damages, property damages or damages related to personal injuries could divert capital needed to implement our plan of operation. If any such uninsured losses are significant, we may have to curtail or suspend our drilling 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 or natural gas prices may adversely affect our business, financial condition, cash flow, liquidity or results of operations as well as our ability to meet our capital expenditure obligations and financial commitments to implement our business plan. Any revenues, cash flow, profitability and future rate of growth we achieve will be greatly dependent upon prevailing prices for oil and gas. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms is also expected to be dependent on oil and gas prices. 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 replace our reserves. Our future success will depend upon our ability to find, acquire and develop oil and gas reserves that are economically recoverable. Any reserves we develop will decline as they are produced unless we are able to conduct successful revitalization activities, or are able to 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. We can give no assurance that our planned development, revitalization, and acquisition activities will result in significant reserves replacement or that we will have success in discovering and producing reserves 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 or develop 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 $58.3 million through December 31, 2007. To date we have had limited revenue and no earnings from operations. There can be no assurances that sufficient revenue to cover total expenses can be achieved until we fully implement our operational plan.
Additional infusions of capital may have a dilutive effect on existing shareholders. To finance our operations we may sell additional shares of our stock. We currently have $266 million in common stock available under an effective shelf registration statement, which we may sell from time to time in one or more offerings pursuant to underwritten public offerings, negotiated transactions, block trades or a combination of these methods. 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, 2007, we had 73,914,471 shares of common stock issued and outstanding. In addition, we have outstanding 5,917,267 shares of other potentially dilutive securities, which mainly consist of Long-Term Incentive Shares. We also have an additional 3,152,450 common shares available under our Long-Term Incentive Compensation Plan and Directors Compensation Incentive Plan. In addition, we have $15.5 million of convertible debt outstanding under the “C” loan agreement with the IFC, which can be converted to approximately 1.5 million shares of our common stock pursuant to the terms of the agreement. 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 19.8% of our common stock issued as of December 31, 2007. 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 Navidec Financial Services, Inc. (“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 10-SB 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. 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 and 2,580 square feet of adjacent office space under a two-year sublease which expires on February 28, 2009. 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.
Properties in Peru
We currently have exclusive rights to four properties in northwest Peru. We have a 100% working interest in license contracts for Block Z-1, Block XIX, Block XXII and Block XXIII. The license contracts afford an initial exploration period of seven to ten years (seven to thirteen for Block Z-1), 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. 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. As of December 31, 2007 only acreage in Block Z-1 has been partially developed.
(1) Does not include the CX11-16X of which the tests produced quantities of gas we believe to be in commercial amounts.
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 ranging from 500 feet up to 1,000 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 (“Belco”). 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.
In the Corvina Field, five wells were drilled, including two wells drilled by Tenneco in the mid-1970’s and three wells drilled by 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 shut-in. In June 2007 we successfully recompleted the Corvina CX11-16X well as a natural gas producing well and completed a total of four DST’s on various zones in the well including one in a formation previously untested in the entire basin. The tests produced quantities of gas we believe to be in commercial amounts.
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 shut-in. We believe this well can be reestablished as a producing well.
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 third exploration period. The third exploration period was originally scheduled to begin 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, as a result of the drilling of our first well, the CX11-21XD, the $1.3 million performance bond and related cash posted as collateral was released. The third exploration period began in May 2007 and is scheduled to expire in December 2008. It will require the drilling of an additional exploratory well or other equivalent work commitments. A performance bond of $1.0 million was also posted for cash collateral of $750,000 as a result. The fourth and final exploration period is scheduled to begin in December 2008 and expire in December 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.
On November 21, 2007, we submitted a letter to Perupetro declaring a commercial discovery in the Block Z-1 field. We are currently putting together a field development plan which is required to be filed with Perupetro within 180 days of the declaration of the commercial discovery. The commercial development period of the contract will commence as soon as we receive approval of the field development plan. 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. Royalties start at 5% if and when production is less than 5,000 barrels of oil equivalent per day (boepd) and are capped at 20% if and when production surpasses 100,000 boepd.
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. Several older wells showed evidence of gas potential in the Mancora formation as well as oil show from the Heath Formation. The Tumbes and Talara Basins are primarily an exploratory area and have had limited drilling and seismic activity. However, the Mancora formation is expected to continue from offshore in Block Z-1 in Piedra Redonda through Block XXIII, also under license to us, and into Block XIX an area which spans approximately fifty miles
In February 2003, we entered into a Technical Evaluation Agreement with Perupetro for Block XIX. In December 2003, we signed a license contract whereby we acquired a 100% interest in Block XIX. The term for the exploration period is seven years and can be extended under certain circumstances for an additional period of up to 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. Royalties start at 5% if and when production is less than 5,000 barrels of oil equivalent per day (boepd) and are capped at 20% if and when production surpasses 100,000 boepd.
The seven year exploration phase is divided into five periods of 18 months, 24 months, 15 months, 15 months and 12 months, respectively. As of December 31, 2007 we had a $585,000 bond posted for $247,000 in cash collateral. We are currently in the third exploration period, which is scheduled to end in May of 2009. During the third exploration period, we are required to drill and test one well. Drilling of this well is scheduled to commence during the fourth quarter of 2008. In connection with the third exploration period, which began in February 2008, we posted a $585,000 performance bond and the performance bond associated with the second exploration period was released. The fourth exploration period is scheduled to begin in May 2009 and will require a performance bond of $585,000. The fifth and final exploration period is scheduled to begin in August 2010 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 and License Contract
On November 21, 2007, we signed a license contract whereby we acquired a 100% interest in Block XXII (formerly known as Area VI). 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. The southern sector of this block also covers the productive Talara basin of northwest Peru, near the Talara Refinery. The exploration period of the license contract extends over a seven year period divided into five periods or four periods of 18 months and a final period of 12 months. Under certain circumstances, the exploration periods may be extended for an additional period of up to three years. The first period requires that we purchase, process and interpret 200 kms of 2-D seismic data. We will also be required to prepare a comprehensive geological and engineering study for the area. In each subsequent period after the first 18 month period we are required to drill an exploratory well. 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 15% to 30% based on production volumes. Royalties start at 15% if and when production is less than 5,000 barrels of oil equivalent per day (boepd) and are capped at 30% if and when production surpasses 100,000 boepd.
In connection with the first exploration period, we were required to obtain a cash collateralized $600,000 bond for cash collateral in the amount of $300,000. 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.
Description of Block XXIII and License Contract
In July 2006, Perupetro informed BPZ that its proposal for Block XXIII, which consists of approximately 248,000 acres and is located onshore in northwest Peru between Blocks Z-1 and XIX, was the winning bid in their recent tender process. This block is located in the Tumbes basin, although in its southern section Talara basin sediments maybe found deeper. The Tumbes and Talara Basins are primarily an exploratory area and have had limited drilling and seismic activity.
On November 21, 2007, we signed a license contract whereby we acquired a 100% interest in Block XXIII. The exploration period of the license contract extends over a seven year period divided in to two periods of 18 months and two periods of 24 months. In addition, it 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 we posted a performance bond to guarantee our various obligations and commitments. If a commercial discovery is made during the exploration period, the contract will allow for the exploration and production of oil for a period of 30 years from the effective date of the contract and the exploration and production of gas for a period of 40 years. Royalties under the contract vary from 15% to 30% based on production volumes. Royalties start at 15% if and when production is less than 5,000 barrels of oil equivalent per day (boepd) and are capped at 30% if and when production surpasses 100,000 boepd.
In connection with the first exploration period, we were required to obtain a cash collateralized $3,075,000 bond in the amount of $1,537,500. 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.
Proved Reserves
Our estimated proved oil reserve quantities were prepared by Netherland, Sewell & Associates, Inc., (“NSAI”) independent petroleum engineers. NSAI was chosen. based on their knowledge and experience of the region in which we operate. Numerous uncertainties arise in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. These uncertainties are greater for properties which are undeveloped or have a limited production history, such as in Northern Peru. Our actual reserves, future rates of production and timing of development expenditures may vary substantially from these estimates. All of our proved reserves are in the Corvina Field. Our net quantities of proved developed and undeveloped reserves of crude oil and standardized measure of future net cash flows are reflected in the table below. See further information about the basis of presentation of theses amount in Note 18 “Supplemental Oil and Gas Disclosures (Unaudited)” to our Consolidated Financial Statements provided herein.
As of December 31, 2007, we owned a 100% working interest in the Corvina Field, subject to Peruvian government royalties of 5% to 20% net revenue interest depending on the level of production. The effect of these interest deductions is reflected in the calculation of our net proved reserves. Our estimate of proved reserves have been prepared under the assumption
that our license contract will allow production for the expected 30-year term for oil and 40-year term for gas, as more fully discussed under “Description of Block Z-1” above. Based on forecast production volumes, the average royalty over the term of the license contract associated with proved reserves is expected to be 5.0%.
Net Proved Crude Oil and Natural Gas Reserves and Future Net Cash Flows
As of December 31, 2007
(Quantities in barrels)
Note: PV-10 (pre-tax) is a non-GAAP financial measure because it excludes income tax effects from the calculation of net cash flows. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. PV-10 (pre-tax) is not a measure of financial or operating performance under GAAP. The most directly comparable GAAP financial measure is the standardized measure of discounted future net cash flows after deduction for income taxes shown above. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
Acreage
The following table shows the number of developed and undeveloped acres in the Corvina Field as of December 31, 2007:
Drilling Activity
The following lists our successful exploratory and development wells that were drilled in 2007:
(1) Recompleted gas well
Drilling activity refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. For the purpose of this table, the term “completed” refers to the installation of permanent equipment for the production of oil or natural gas.
Present Activities
In November 2007, we commenced drilling on the CX11-18XD well. The well reached total depth of 8,792 feet (measured depth) on January 1, 2008, approximately one month ahead of schedule. We recently performed a series of safety and integrity tests on the CX-11 Corvina platform including the surface equipment. As part of the integrity testing of the surface equipment, we perforated the lower prospective oil sands identified in the CX11-18XD well. These lower sands tested oil and the results assisted in validating our Corvina geologic model.
Currently all production (which had reached approximately 4,200 barrels of oil per day by late January 2008) is shut-in due to the incident involving the Navy tanker. At the request of the OSINERGMIN, the government agency responsible for auditing the safety of energy investments in Peru, we successfully performed a series of safety and integrity tests on the facilities at the CX-11 Corvina platform, including the equipment that was being used for the ongoing long-term testing of the 21XD and 14D wells. We confirmed that the well testing equipment was in operational condition. On March 12, 2008 we received clearance from the OSINERGMIN, to resume operations at the CX-11 platform, including the scheduled 18XD well drill stem test. However, the four Corvina wells are currently shut-in while we complete the installation of sea-bed pipelines connecting the platform to the transport barge, along with the required mooring systems, that will allow for an improved long-term testing program. Additionally, we are waiting for final clarification from the appropriate authorities in Peru regarding the transportation of our crude oil to the refinery.
Property in Ecuador
Through our wholly-owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, we also own a 10% non-operated 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 1,600 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. 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.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY 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. Between December 27, 2005 and January 12, 2007, our common stock was traded on the Pink Sheets under the symbol “BPZI.PK”.
The following table sets forth, for the periods indicated, the high and low prices of a share of our Common Stock as reported on the AMEX 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 29, 2008, we had approximately 293 shareholders of record, and 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 or other dividends on our stock. For the foreseeable future, we intend to retain earnings, if any, to meet our working capital requirements and to finance future operations. Accordingly, we do not plan to declare or distribute cash dividends to the holders of our common stock in the foreseeable future. As of the date of this filing, we have not repurchased any of our equity securities and have not adopted a stock repurchase program.
Equity Compensation Plan
The BPZ Resources, Inc. 2007 Long-Term Incentive Compensation Plan (the “LTIP” or “Plan”) permits our Board of Directors to award eligible employees, employee directors and consultants with incentive-based and non-incentive-based compensation and our Directors Compensation Incentive Plan permits our Board of Directors to award non-employee directors with equity based compensation.
The following table summarized our equity securities authorized for issuance under our equity compensation plan as of December 31, 2007.
(1) Pursuant to a Director’s Agreement related to a former director.
Recent Sales of Unregistered Securities
On May 4, 2007, with an over-allotment purchase that closed on June 15, 2007, we completed a private placement of 7,170,000 shares of common stock, no par value, to an accredited investor pursuant to a Subscription Agreement. The common stock was priced at $5.25 per share and the over-allotment was priced at $5.40 per share resulting in proceeds to us of approximately $37.7 million. No warrants or dilutive securities were issued in connection with the offering. The offering was placed directly by the Company. A placement fee of 2% of the gross proceeds of this transaction was paid to Morgan Keegan for investment services and consulting related to the offering.
We closed our “C” Loan with the IFC on November 19, 2007. The loan consists of $15.5 million of convertible debt. The outstanding debt may be converted at any time prior to the date all amounts payable under the terms of the loan have been paid by the Company under certain circumstances and by the IFC at any time. The conversion price is $10.39 per share, as may be adjusted under the terms of the loan, and the Company may force the conversion if the average closing price of the Company’s common stock over twenty consecutive business days exceeds $18.19 per share.
In November 2007, we issued 9,000,000 shares of common stock as contingent merger consideration in connection with the second earn-out provision in The Merger Agreement. This transaction is more fully described in “Business-Navidec Merger Transaction” included herein.
The securities 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).
Performance Graph
The following graph compares the cumulative total shareholder return for the Company’s Common Stock to that of (i) the Russell 2000 Stock Index, and (ii) a Company peer group of five independent oil and gas exploration companies
selected by us, for the period indicated as prescribed by the SEC’s rules. The companies in our selected peer group are Transmeridian Exploration, Inc., Contango Oil & Gas, Co, Harvest Natural Resources, Inc., Far East Energy Corp, and Carrizo Oil & Co Inc. “Cumulative total return” is defined as the change in share price during the measurement period, plus
cumulative dividends for the measurement period (assuming dividend reinvestment), divided by the share price at the beginning of the measurement period. The graph assumes $100 was invested on January 1, 2002 in our Common Stock, the Russell 2000 Stock Index and a Company peer group.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operation” and the consolidated financial statements and the notes thereto included under “Item 8. Financial Statements and Supplementary Data.”
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited consolidated financial statement and related notes contained elsewhere in this report. The following discussion
includes forward-looking statement that reflect our plans, estimations and beliefs. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, those discussed below and elsewhere in this report
Overview
We are an independent oil and gas company focused on the exploration, development and production of oil and natural gas in Peru and Ecuador. We also intend to utilize part of our planned future natural gas production as a supply source for the complementary development of a Company owned gas-fired power generation facility. We have the exclusive rights and license agreements for oil and gas exploration and production covering approximately 2.4 million acres in four blocks in northwest Peru and off the northwest coast of Peru in the Gulf of Guayaquil. We also own a 10% non-operated working interest in an oil and gas producing property, Block 2, located in the southwest region of Ecuador (the “Santa Elena Property”).
We are in the initial stages of developing our oil and natural gas reserves and in November 2007we began producing oil under an extended well testing program from our recent discoveries. 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 two of our offshore platforms, procuring machinery and equipment for an extended drilling campaign, obtaining all necessary environmental and operating permits, procuring development and transportation equipment and securing the required capital and financing to complete the current plan of operation. In March 2007, after a total of six drill stem tests were conducted on separate potential pay zones from the Lower and Upper Zorritos formations, the CX11-21 XD well, our first well, tested positive for both gas and oil in commercially producible quantities. Subsequently, in June 2007 we successfully recompleted the Corvina CX11-16X well as a natural gas producing well and completed a total of four drill stem tests on various zones in the well including one in a formation previously untested in the entire basin. In October 2007 we completed seven drill stem tests on the CX11-14D well in the Corinva Field. The first six tests were conducted in the Upper Zorritos formation, with the first two testing the oil zone and the other four testing the gas zone, while the seventh test targeted the Cardalitos formation located immediately above the Upper Zorritos. The CX11-14D well tested positive for both gas and oil in quantities at commercially producible quantities. On November 29, 2007, we commenced drilling on the CX11-18XD well. The well reached total depth of 8,792 feet (measured depth) on January 1, 2008, approximately one month ahead of schedule. We recently performed a series of safety and integrity tests on the CX-11 Corvina platform including the surface equipment. As part of the integrity testing of the surface equipment, we perforated the lower prospective oil sands identified in the CX11-18XD well. These lower sands tested oil and the results assisted in validating our Corvina geologic model. All wells tested positive for oil and/or gas at commercially producible quantities. We did not drill any other wells in 2007.
On June 13, 2007, we entered into a capital lease agreement, with an option to purchase, for two barges to assist in the development of the Corvina Field. Each of these barges has a capacity of approximately 40,000 barrels. The two barges were towed to Peru where one barge, the Nu’ uanu, is currently being used to transport oil between the CX11 platform and the refinery in Talara. The other barge, the Nomoku, is currently being fitted with the required equipment for its intended use as a floating production, storage and offloading facility (“FPSO”) that will be moored next to the CX11 platform. However, we have encountered some scheduling delays in deploying this barge. We expect the Nomoku to be fully fitted and operational by the end of the first or beginning of the second quarter of 2008. Until such time as the Nomoku is fitted with the permanent production equipment, we are anticipating pumping oil directly to the Nu’ uanu using temporary production equipment and then transporting the oil to the Talara refinery.
We started producing oil from the CX11 platform under an extended well testing program beginning on November 1, 2007. By December 31, 2007, we produced approximately 40,989 barrels of oil and sold approximately 28,741 barrels to a refinery in Talara at current market prices. Our oil is delivered to the refinery by barge approximately 100 miles south of the platform. The remainder was kept in production inventory until such time as it was delivered to Talara in early 2008.
On October 24, 2007, our primary marine transportation contractor entered into two short term agreements with the commercial division of the Peruvian Navy to lease two tankers on our behalf to transport oil to market. However, on January 30, 2008, one of the tankers sank after catching fire.
Currently all production, which had reached approximately 4,200 barrels of oil per day by late January 2008, is shut-in due to the incident involving a Navy tanker being used to transport our oil to market that caught fire and sank near our CX-11 Corvina platform. At the request of the OSINERGMIN, the government agency responsible for auditing the safety of energy investments in Peru, we successfully performed a series of safety and integrity tests on the facilities at the CX-11 Corvina
platform, including the equipment that was being used for the ongoing long-term testing of the 21XD and 14D wells. We confirmed that the well testing equipment was in operational condition.
Currently all production (which had reached approximately 4,200 barrels of oil per day by late January 2008) is shut-in due to the incident involving the Navy tanker. At the request of the OSINERGMIN, the government agency responsible for auditing the safety of energy investments in Peru, we successfully performed a series of safety and integrity tests on the facilities at the CX-11 Corvina platform, including the equipment that was being used for the ongoing long-term testing of the 21XD and 14D wells. We confirmed that the well testing equipment was in operational condition. On March 12, 2008 we received clearance from the OSINERGMIN, to resume operations at the CX-11 platform, including the scheduled 18XD well drill stem test. However, the four Corvina wells are currently shut-in while we complete the installation of sea-bed pipelines connecting the platform to the transport barge, along with the required mooring systems, that will allow for an improved long-term testing program. Additionally, we are waiting for final clarification from the appropriate authorities in Peru regarding the transportation of our crude oil to the refinery.
Consequently, through our marine transportation contractor, we are now leasing only one vessel from the Navy having a capacity of approximately 6,000 barrels. The lease is set to expire at the end of March 2008.
Results of Operations
Year Ended December 31, 2007 Compared to Year Ended December 31, 2006
Our operating and administrative expenses to date have consisted principally of general and administrative costs as well as geological, geophysical and engineering costs. However, due to commencement of production from the CX11 platform, we have incurred lease operating expense of $754,833 during the year ended December 31, 2007 compared to no operating expenses incurred during the year ended December 31, 2006. General and administrative costs have increased significantly from $8,306,356 during the year ended December 31, 2006 to $11,508,862 during the year ended December 31, 2007 as a result of our increased activity levels, necessary additional personnel and costs associated with being a public company listed on the American Stock Exchange. We incurred $4,045,381 of geological, geophysical and engineering costs during the year ended December 31, 2007 primarily related to the oil discovery in Corvina and to the continued development of our Corvina Gas-to-Power project and 2-D seismic expense on Block XIX, compared to $2,048,742 during the year ended December 31, 2006 primarily as a result of the commencement of our Corvina Gas-to-Power project.
Stock-based compensation expense for year ended December 31, 2007 was approximately $7,039,603 compared to $3,225,508 during the year ended December 31, 2006. Stock based compensation expense is primarily related to our restricted stock grants, accrued stock-based compensation under our 2007 Long-Term Incentive Plan and the recognition of Incentive Earn-out Stock Compensation for two of our executive officers, in the third quarter of 2007due to the achievement of the entitlement to the right to production of 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 received net cash distributions from our investment in Ecuador property of $546,847 during the year ended December 31, 2007, compared to net cash distributions of $1,291,547 million during the year ended December 31, 2006. The decrease in income primarily relates to capacity problems at the local refinery in Ecuador. As a result, oil sales for the year ended December 31, 2007 were significantly less than for the year ended December 31, 2006. 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 each of the years ended December 31, 2007 and December 31, 2006.
We incurred interest expense of $930,786 during the year ended December 31, 2007, all of which was capitalized to construction in progress, compared with $15,815 for the year ended December 31, 2006. The difference is primarily due to interest associated with the purchase of two vessels under capital lease obligation in 2007 compared to other debt related to acquiring furniture and fixtures during 2006. See Note 9 “Debt” to the Consolidated Financial Statements below.
We did not incur any registration delay expense for the year ended December 31, 2007. During the year 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 is declared effective by the SEC. In addition, in connection with the private placement of 4,482,000 common shares in March 2006, we were obligated to prepare and file with the SEC a Registration Statement on Form S-1 within ninety days from closing, and to use our 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 $50,010, for each thirty day period until the Registration Statement 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, we were no longer subject to the liquidated damages described above
As a result of our cash balances from the various private placements of our common stock during 2005, 2006 and 2007, we received interest income of $854,905 during the year ended December 31, 2007 and $787,455 during the twelve months ended December 31, 2006.
We realized federal income tax expense of $39,001 during the year ended December 31, 2007. The tax is related to the revenues from our 10% non-operated working interest in the Santa Elena Property in southwestern Ecuador. No tax expense was incurred during the year ended December 31, 2006.
During the year ended December 31, 2007, we recognized a foreign exchange gain of approximately $190,000 compared to approximately $56,000 during the year ended December 31, 2006. This is primarily as a result of our collection of Value Added Tax in Peru ( “ IGV”) under the early recovery program. IGV is denominated in local currency and the Peruvian Nuevo Soles has become stronger against the U. S. Dollar over the past year.
We realized a net loss of $20,509,983 or $(0.30) per share during the year ended December 31, 2007, compared to a net loss of $15,487,459 or $(0.29) per share for the year ended December 31, 2006.
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 development 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 translation 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 as compared to registration delay expense of $515,967 during the twelve months ended December 31, 2005. 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, we were obligated to prepare and file with the SEC a Registration Statement on Form S-1 within ninety days, and to use our 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, we were 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 $(0.29) per share for the year ended December 31, 2006, compared to a net loss of $6,406,989, or $(0.16) per share, for the same period in 2005.
Project Capital Budget
We established an initial 2008 capital budget of approximately $215 million. Approximately half of this budget is related with our gas-to-power initiative, of which all of the associated capital expenditures are expected to be funded by IFC. We increased our projected capital budget to reflect the drilling of three additional wells at the Corvina platform based on the favorable results of the three recently completed wells and the potential to further delineate the oil and gas discoveries. We also intend to begin our drilling program in the Albacora Field in late 2008 as well as other prospects in Block XIX and Piedra Redonda at an additional capital expenditure of $43.0 million. Detail of our Projected Capital Budget is as follows:
Liquidity, Capital Resources and Capital Expenditures
As of February 29, 2008, our cash balance was approximately $4.2 million.
Production
In November 2007, we began producing oil from the CX11-21 XD and 14D wells in the Corvina Field under an extended well testing program. By December 31, 2007, we produced approximately 40,989 barrels of oil and sold approximately 28,741 barrels to a refinery in Talara. The oil is delivered to the refinery by barge approximately 100 miles south of the platform. The remainder was kept in production inventory until such time it was delivered to Talara in early 2008.
As a result of the commencement of oil production we achieved the rights to the entitlement of production goal as set forth in the Merger Agreement as a requirement for the issuance of 9,000,000 additional shares of common stock as contingent merger consideration. Accordingly, as required under the Merger Agreement between Navidec and BPZ-Texas in 2004, we issued an additional 9,000,000 shares of common stock to the former shareholders of BPZ-Texas. The issuance of these earn-out shares was required 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 of 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.
The production goal under the Merger Agreement was the same under an Incentive Earn-out share arrangement with two executive officers. The total of such incentive awards related to the Merger Agreement was 450,000 shares. Stock compensation expense for the incentive earn-out shares was approximately $1,980,000 during the year ended December 31, 2007.
Capital Raises and Debt Activity
On May 4, 2007, with an over-allotment purchase that closed on June 15, 2007, we completed a private placement of 7,170,000 shares of common stock, no par value, to accredited investors pursuant to a Subscription Agreement. The common stock was priced at $5.25 per share and the over-allotment was priced at $5.40 per share resulting in proceeds to us of approximately $37.7 million. No warrants or dilutive securities were issued in connection with the offering. The offering was placed directly by us. A placement fee of 2% of the gross proceeds of this transaction was paid to Morgan Keegan for investment services and consulting related to the offering. The registration statement was declared effective by the Securities and Exchange Commission on June 14, 2007, and the related prospectus was filed on June 21, 2007.
On October 22, 2007, we entered into a non-binding debt term sheet with the IFC, the private sector division of the World Bank Group based in Washington, D.C., delineating the key terms and conditions for the first tranche (see Loan “C” immediately below) of a debt package with IFC. Previously, we announced a total debt package, approved by IFC, of $100.5 million. However, we are actively negotiating with IFC to increase the debt package to an estimated $165 million for further development of our assets.
The initial $120 million aggregate debt and equity financing package was approved by the Credit Committee of the IFC on November 29, 2006, and included an investment by IFC in BPZ’s common stock which took place on 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. IFC currently holds approximately 9% equity position in the Company with 6.5 million shares of our common stock. In addition, IFC has a preemptive right to purchase its pro rata share of common stock or securities convertible into common stock that are issued and sold by the Company (except for certain issuances of securities, such as pursuant to stock splits, stock dividends, acquisitions by the Company or under the Company’s incentive compensation plan). IFC’s total equity and senior debt investment in the Company, based upon execution and funding of the increased debt agreement, as described above, may reach approximately $185 million. Any increase in funding of the debt package is subject to final internal approvals by the appropriate representatives of both IFC and BPZ. It is uncertain if such approval will occur, or if approved, the timing or amount of such approvals. The $165 million facility is expected to consist of the following:
· Loan “C”, which closed on November 19, 2007, consists of $15.5 million of convertible debt. The terms of the loan agreement stipulated a conversion price is $10.39 per share as may be adjusted under the terms of the loan and includes a forced conversion exercisable at the Company’s option if the the average closing price of the Company’s common stock exceeds $18.19 per share over twenty consecutive business days. The instrument has a 10 year term with a variable interest rate of 2% per annum above 6-month LIBOR. The loan from the IFC is unsecured, but restricts our ability to pledge assets to another lender unless certain conditions are met. The IFC loan does not restrict our ability to issue additional capital stock, but does call for an adjustment in its conversion price into BPZ common stock based on the terms of any subsequent equity offering. The agreement contains customary default and cross-default provisions along with covenants restricting our ability to pay dividends and the disposition of assets. We are required to maintain a required ratio of Balance Sheet Liabilities to Tangible Net Worth (as defined in the Loan Agreement), calculated quarterly, of no greater than 70:30. As of December 31, 2007 and as of March 14, 2008, we were in compliance with all financial covenants.
· Loan “A”, which is for IFC’s own account, is expected to consist of $34.5 million in secured long-term senior debt. This second tranche is expected to be closed during the second quarter of 2008. The terms of the instrument are still being negotiated.
· Loan “B”, comprised of senior debt to be syndicated by IFC, is projected to be approximately $115 million. This third tranche is expected to close late in the third quarter of 2008. This remaining debt portion of the financing will be subject to identification of the lending syndicate members and subsequent negotiation and approval of the necessary loan documentation.
As of March 14, 2008, the final “A” and “B” Loan documents have not yet been completed.
During the year ended December 31, 2007, we incurred capital expenditures of approximately $56.4 million primarily related to drilling, completion and testing activity on the three Corvina wells as well as $6.2 million being primarily related to the capital lease of two barges to be used for production, storage and delivery of oil produced from Corvina oil and $0.5 million for miscellaneous property and equipment. In comparison, during the year 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.
As of December 31, 2007, in connection with our Peru properties, we obtained five performance bonds totaling $6.0 million to insure certain obligations and commitments, of which four related to performance obligations under the license contracts for Blocks Z-1, XIX, XXII and XXIII. As of December 31, 2007, we had restricted cash deposits of approximately $3.8 million which partially collateralize the performance bonds. We were required to deposit approximately $0.8 million as restricted cash to collateralize a performance bond of $1.0 million in connection with the beginning of the third exploration period under the Block Z-1 license contract, which began in June 2007. In addition, we were required to deposit approximately $0.2 million as restricted cash to collateralize performance bonds of $0.4 million under the Block XIX license contract in connection with the first exploration period. We were also required to post a $1.0 million performance bond to guarantee payment under a service agreement, which expired in January 2008. The $1.0 million cash collateral was released to us and the performance bond was cancelled. In connection with signing the license contracts for Blocks XXII and XXIII in November 2007, we were required to post $0.3 million and $1.5 million, respectively in restricted cash to collateralize $0.6
million and $3.1 million, bonds respectively, in connection with the first exploration period. The performance bonds were issued by Peruvian banks and their terms are governed by the corresponding license contract or agreement.
Equipment Activity
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 employees, 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 had 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 March 14, 2008, 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. A mandatory dry-dock is scheduled for the third quarter 2008 at which time a full survey of the barge will be conducted and an insurance claim is expected to be filed. 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 did not have a material impact on our operations or business plan.
In connection with the Block XIX license contract, we have recently completed shooting 200 kilometers of 2-D seismic. The cost to acquire this seismic data was approximately $3.6 million. Processing and interpretation of the data was completed in late January 2008. Based on the results of the 2-D seismic surveys and in order to comply with the requirements under the next phase of the related license contract, we plan to drill a well in Block XIX in late 2008 at an estimated cost of $8.0 million.
On June 13, 2007, the Company entered into a capital lease agreement, with an option to purchase, for two barges to assist in the development of the Corvina oil. The two barges were towed to Peru where one barge, the Nu’ uanu, is currently being used to transport oil between the CX11 platform and the refinery in Talara, approximately 100 miles south. The Nomoku is currently being fitted with the required equipment for its intended use as a floating production, storage and offloading facility (“FPSO”) that will be moored next to the CX11 platform. However, we have encountered some deployment delays due to scheduling. We expect the Nomoku to be fully fitted and operational by the end of the first or beginning of the second quarter 2008.
On October 24, 2007, the Company’s primary marine transportation contractor entered into two short term agreements with the commercial division of the Peruvian Navy to lease two tankers, on our behalf, to transport oil to market earlier than scheduled. The two tankers leased from the Navy each had capacity of approximately 7,000 barrels. This enabled us to produce oil into the Nu’ uanu, using temporary production equipment. The oil is then transported to the Talara refinery. However, on January 30, 2008, the “Supe”, which was moored near the Corvina CX-11 platform and was being used to store oil produced from Corvina’s 21XD and 14D wells, caught fire and later sank approximately one and a half miles from the platform.
At the time of the incident the Supe tanker contained approximately 1,300 barrels of oil, most of which is believed to have been burned in the fire. Initial assessments show that environmental issues have been adequately controlled. No Company employees were injured. No damage to the Company’s platform, barges, drilling and well testing equipment, or other facilities owned by the Company resulted from the incident and the Company understands that damage has been limited mostly to the Supe, which was anchored at a distance from the platform and directed away after it caught fire. Initial assessments show that environmental issues have been adequately controlled. We hired a third party environmental consultant to conduct an environmental damage assessment in and around the area surrounding the incident. The results from our environmental consultant, as well as several other independent organizations, indicate that there was no contamination to the seawater and marine life related to the incident. However, production from the 21XD and 14D wells, approximately 4,200 barrels of oil per day at the time, as well as the testing operations on the 18XD well have been temporarily suspended until a full assessment of the situation has been completed. We believe potential costs associated with environmental cleanup, business interruption, and equipment damages associated with this incident will be reimbursed through insurance. 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. We do not expect this incident to have a material impact on our future operations or overall business plan.
Our major sources of funding to date, has been through equity raises and, to a lesser extent, debt financing activities. With our current cash balance, proceeds from the expected IFC debt facilities, current and prospective Corvina Oil development cash flow, other potential third-party financing and potential financing from future equity raises, we believe we will have sufficient capital resources to execute our initial Corvina oil development project and gas-to-power project as we currently envision it as well as service our current debt obligations. However, the timing and execution of our project is dependent on a variety of factors, including the 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.
Subsequent Events
In February 2008, we entered into a lease-purchase agreement to acquire a deck barge (“BPZ 02”), of approximately 330 feet in length, to assist in the drilling activities in the Albacora field as well as to assist in future drilling and development activities. In the near term, the BPZ 02 will be used to act as a tender assist for the Petrex drilling rig as it is moved to the Albacora field in third quarter 2008. During that time, as mentioned in Note 14 “Commitment and Contingencies”, the BPZ 01 will be placed in drydock to repair damages sustained when it ran aground in late 2006. The acquisition of the BPZ 02 allows the Company better asset maintenance scheduling and will aid in the support of increased offshore exploration and development activities. The terms of the lease-purchase stipulate a 19% rate of interest over a one year term at which point, title to the BPZ 02 will transfer to the Company upon final payment of the lease. The Company will account for the transaction as a Capital Lease in accordance to SFAS 13, “Accounting For Leases (As Amended)” under the criteria the barge will transfer title at the end of the lease period and, as a result, depreciation will be calculated over the economic life of the asset.
Off-Balance Sheet Arrangements
As of December 31, 2007, 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) 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.
(2) Includes IFC convertible debt agreement of $15.5 million which began on November 19, 2007 and matures in 10 years. Interest is paid annually and principal is paid on the maturity date. Also, includes capital lease for two production and storage barges which began in August 2007 and is set to expire in November 2009. Lease payments totaling $6.0 million are variable, based on the working status of the barges, with a purchase option of $5,000,000 after the first year of the lease and $4,000,000 after the maturity date of the lease. The capital lease for office furniture in our executive office in Houston, Texas expiring in 2010 is also included.
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.
Revenue Recognition
The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.
The Company sells its production in the Peruvian domestic market on a contract basis. Revenue is recorded net of royalties when the purchaser takes delivery of the oil. At the end of the period, oil that has been produced but not sold is recorded as inventory at the lower of cost or market. Cost is determined on a weighted average based on production costs.
Impairment of Long-Lived Assets
We periodically evaluate the recoverability of the carrying value of our long-lived assets and identifiable intangibles by monitoring and evaluating changes in circumstances that may indicate that the carrying amount of the asset may not be recoverable. Examples of events or changes in circumstances that indicate the recoverability of the carrying amount of an asset should be assessed include, but are not limited to, (a) a significant decrease in the market value of an asset, (b) a significant change in the extent or manner in which an asset is used or a significant physical change in an asset, (c) a significant adverse change in legal factors or in the business climate that could affect the value of an asset or an adverse action or assessment by a regulator, (d) an accumulation of costs significantly in excess of the amount originally expected to acquire or construct an asset, and/or (e) a current period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with an asset used for the purpose of producing revenue.
We consider historical performance and anticipated future results in our evaluation of potential impairment. Accordingly, when indicators of impairment are present, we evaluate the carrying value of these assets in relation to the operating performance of the business and future discounted and non-discounted cash flows expected to result from the use of these assets. Impairment losses are recognized when the expected future cash flows from an asset are less than its carrying value.
Future Dismantlement, Restoration, and Abandonment Costs
The accounting for future development and abandonment costs changed on January 1, 2003, with the issuance of 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 will be required to plug and abandon those wells and restore the well sites and power generation site upon abandonment if they are abandoned prior to the end of the contract period. See Note 8 “Asset Retirement Obligation” to the Consolidated Financial Statements provided herein for further detail.
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 6 “Investment in Ecuador Property and Note Payable” 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
Staff Accounting Bulletin 110 “Share-Based Payment.”
On December 21, 2007, the SEC released Staff Accounting Bulletin, (“SAB 110”) “Share-Based Payment” which will no longer allow the use of the “Simplified” method to estimate the expected terms as on the variables to determine the fair value of share-based payments. With a limited number of exceptions, companies can continue to use the simplified method. However, doing so requires the types of grants for which the Simplified method is used if not for all grants, and the periods for which the Simplified method is being used. The adoption of this Staff Accounting Bulletin is not expected to have a material impact on our consolidated financial position, results of operations, or cash flows.
SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”).
In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements. SFAS 157 defines fair value as used in numerous accounting pronouncements, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosure requirements related to the use of fair value measures in financial statements. SFAS 157 will be effective for the Company’s financial statements for the fiscal year beginning January 1, 2008; however, earlier application is encouraged. We are currently evaluating the impact that adoption might have on its financial position or results of operations, although we do not expect any impact to be significant.
FAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (“FAS 159”).
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115, which will become effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets, financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis, that are otherwise not permitted to be accounted for at fair value under other generally accepted accounting principles. The fair value measurement election is irrevocable and subsequent changes in fair value must be recorded in earnings. We will adopt this statement in the first quarter of 2008 and we do not expect to elect the fair value option for any eligible financial instruments and other items.
SFAS No. 141 (revised 2007), “Business Combinations, which replaces FASB Statement No. 141. SFAS 141(R”).
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations, which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired. SFAS 141(R) also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008, which will be the company’s fiscal year 2009. We do not expect the adoption of SFAS No. 141R to have a material impact on the our consolidated financial position, results of operations or cash flows.
SFAS No. 160,” Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51.”
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51. SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. We do not expect the adoption of SFAS No. 160 to have a material impact on our 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, 2007, the Company had long-term debt of $15.5 million and current maturities of long-term debt of $6.2 million, consisting of an IFC loan, a capital lease obligation for the two barges to be used in the Corvina oil
production as well as two secured loans for the purchase of office furniture. The loan from the IFC, Loan “C”, was closed on November 19, 2007 and comprised of $15.5 million convertible debt. The terms of the loan agreement stipulates a conversion price is $10.39 per share as may be adjusted under the terms of the loan, and includes a forced conversion exercisable by the Company if the average closing price of its common stock exceeds $18.19 per share over twenty consecutive business days. The instrument has a 10 year term with a variable interest rate of 2% per annum above 6-month LIBOR. The capital lease obligation has an imputed interest rate of 18.00% over a lease term of 27 months and includes a purchase option which we anticipate for accounting purposes we will exercise on the 15th month of the lease term. The other two 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. We do not expect a significant change in the market interest rate to impact the interest on our term debt. However, significant changes in market interest rates may significantly affect the level of financing that 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. Transaction differences have steadily increased as our expected activities in Peru continue to escalate. During the year ended December 31, 2007, we incurred an exchange rate gain of approximately $190,000, primarily related to the early recovery of Value Added Taxes in Peru (“IGV”).
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
BPZ Resources, Inc. and Subsidiaries
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2007 and 2006
Consolidated Statements of Operations for the Years Ended December 31, 2007, 2006 and
Consolidated Statements of Stockholders’ Equity (Deficit) for the Years Ended December 31, 2007, 2006 and 2005
Consolidated Statements of Cash Flows for the Years Ended December 31, 2007, 2006 and
Notes to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
To the Board of Directors
BPZ Resources, Inc. and Subsidiaries
We have audited the accompanying consolidated balance sheets of BPZ Resources, Inc. and Subsidiaries as of December 31, 2007 and 2006 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, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BPZ Resources, Inc. and Subsidiaries at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), BPZ Resources, Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2007, 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 12, 2008, expressed an unqualified opinion thereon.
Johnson Miller & Co., CPA’s PC
Midland, Texas
March 12, 2008
BPZ Resources, Inc. and Subsidiaries
Consolidated Balance Sheets
The accompanying notes are an integral part of these consolidated financial statements.
BPZ Resources, Inc. and Subsidiaries
Consolidated Statements of Operations
The accompanying notes are an integral part of these consolidated financial statements.
BPZ Resources, Inc. and Subsidiaries
Consolidated Statements of Stockholders’ Equity (Deficit)
Years Ended December 31, 2007, 2006 and 2005
The accompanying notes are an integral part of these consolidated financial statements.
BPZ Resources, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these consolidated financial statements.
BPZ Resources, Inc and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2007
Note 1 - Basis of Presentation and Significant Accounting Policies
Organization
BPZ Resources, Inc., (the “Company” or “BPZ”) a Texas corporation, is based in Houston, Texas with offices in Lima, Peru and Quito, Ecuador. The Company is focused on the exploration, development and production of oil and natural gas in Peru and Ecuador. It also intends to utilize part of our planned future natural gas production as a supply source for the complementary development of a Company owned gas-fired power generation facility.
The Company maintains a subsidiary registered in Peru through our wholly owned subsidiary BPZ Energy, Inc., a Texas corporation (“BPZ - Texas”). Currently, BPZ Energy has exclusive rights and license agreements for oil and gas exploration and production covering a total of approximately 2.4 million acres, in four blocks, in northwest Peru. The Company’s license contracts cover 100% ownership of Block Z-1 (739,205 acres), Block XIX (472,860 acres), Block XXII (948,000 acres, also referred to as Area VI in previous filings) and Block XXIII (248,000 acres). The Block Z-1 contract was signed in November 2001, the Block XIX contract was signed in December 2003 and Blocks XXII and XXIII were both signed in November 2007. The Company’s license contracts provide for an initial exploration period of seven to thirteen years for Block Z-1and seven to ten years for Blocks XIX, XXII and XXIII. In addition, they require that the Company 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.
Through its wholly owned subsidiary, SMC Ecuador Inc., a Delaware corporation, and its registered branch in Ecuador, the Company owns 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.
The Company is in the initial stages of developing its oil and natural gas reserves and has recently begun producing oil under an extended well testing program from our recent discoveries. To date its 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 two of our offshore platforms, procuring machinery and equipment for an extended drilling campaign, obtaining all necessary environmental and operating permits procuring development equipment and securing the required capital and financing to conduct the current plan of operation. In March 2007, after a total of six drill stem tests were conducted on separate potential pay zones from the Lower and Upper Zorritos formations, the CX11-21 XD well, the Company’s first well, tested positive for both gas and oil at commercially producible quantities. Subsequently, in June 2007 the Company successfully recompleted the Corvina CX11-16X well as a natural gas producing well and completed a total of four drill stem tests on various zones in the well including one in a formation previously untested in the entire basin. In October, we completed seven drill stem tests on the CX11-14D well in the Corinva Field. The CX11-14D well tested positive for both gas and oil at commercially producible quantities. The first six tests were conducted in the Upper Zorritos formation, with the first two testing the oil zone and the other four testing the gas zone, while the seventh test targeted the Cardalitos formation located immediately above the Upper Zorritos. On November 29, 2007, BPZ commenced drilling on the CX11-18XD well. The well reached total depth of 8,792 feet (measured depth) on January 1, 2008, approximately one month ahead of schedule. The Company recently performed a series of safety and integrity tests on the CX-11 Corvina platform including the surface equipment. As part of the integrity testing of the service equipment, it perforated the lower prospective oil sands identified in the CX11-18XD well. These lower sands tested oil and the results assisted in validating the Company’s Corvina geologic model.
The Company started producing oil from the CX11 platform under an extended well testing program beginning on November 1, 2007. By December 31, 2007, it produced approximately 40,989 barrels of oil and sold approximately 28,741 barrels to a refinery in Talara. The oil is delivered to the refinery by barge approximately 100 miles south of the platform. The remainder was kept in production inventory until such time it was delivered to Talara in early 2008.
Prior to December 2007, the Company had no significant revenues and was considered an exploratory stage company. However, in December 2007, the Company delivered 28,741 barrels of oil. As a result, the Company is no longer considered an exploratory stage company as of December 31, 2007.
On June 13, 2007, the Company entered into a capital lease agreement, with an option to purchase, for two barges to assist in the development of the Corvina Field. The two barges were towed to Peru where one barge, the Nu’ uanu, is currently being used to transport oil between the CX11 platform and the refinery in Talara, approximately 100 miles south. The other barge, the Nomoku, is currently being fitted with the required equipment for its intended use as a floating production, storage and offloading facility (“FPSO”) that will be moored next to the CX11 platform. However, we have encountered some delays in deploying this barge due to scheduling. The Company expects the Nomoku to be fully fitted and operational by the end of the first or beginning of the second quarter of 2008. Until such time the Nomoku is fitted with the permanent production equipment, the Company is anticipating pumping oil directly to the Nu’ uanu using temporary production equipment and then transporting the oil to the Talara refinery.
On October 24, 2007, the Company’s primary marine transportation contractor entered into two short term agreements with the commercial division of the Peruvian Navy to lease two tankers to transport oil to market. However, on January 30, 2008, one of the tankers sank after catching fire. Consequently, through its primary marine transportation contractor, the Company is now leasing only one vessel from the Navy having a capacity of approximately 6,000 barrels. The lease is set to expire at the end of March 2008.
Currently all production (which had reached approximately 4,200 barrels of oil per day by late January 2008) is shut-in due to the incident involving the Navy tanker. At the request of the OSINERGMIN, the government agency responsible for auditing the safety of energy investments in Peru, we successfully performed a series of safety and integrity tests on the facilities at the CX-11 Corvina platform, including the equipment that was being used for the ongoing long-term testing of the 21XD and 14D wells. We confirmed that the well testing equipment was in operational condition. On March 12, 2008 we received clearance from the OSINERGMIN, to resume operations at the CX-11 platform, including the scheduled 18XD well drill stem test. However, the four Corvina wells are currently shut-in while we complete the installation of sea-bed pipelines connecting the platform to the transport barge, along with the required mooring systems, that will allow for an improved long-term testing program. Additionally, we are waiting for final clarification from the appropriate authorities in Peru regarding the transportation of our crude oil to the refinery.
The Company has submitted all the requested reports and documentation generated during the investigation of the January 30, 2008 sinking of the Peruvian Navy tanker, Supe. A number of organizations involved in the investigation have issued reports concluding there was no environmental damage due to the incident. Additionally, the Company assisted the Peruvian Navy in conducting an underwater survey of the Supe, which established that the vessel does not represent a hazard to navigation nor a marine pollution threat, as all its tanks were found to be empty. The CX-11 Corvina platform and all its facilities, as well as the BPZ-01 tender barge, the four Corvina wells, and all the vessels supporting the operations have now been certified to be in operational condition.
Reincorporation, Name Change and Internal Restructuring
On October 11, 2007, BPZ Energy, Inc., a Colorado corporation, formerly named Navidec, Inc., (“Navidec”), completed a reincorporation from the State of Colorado to the State of Texas pursuant to the Plan of Conversion as approved by the shareholders at the 2007 annual meeting of shareholders held on August 17, 2007. The related filings with the Secretary of State of Texas also included a change of the company’s name from BPZ Energy, Inc. to BPZ Resources, Inc., in connection with an ongoing review of certain internal reorganization matters related to our international tax planning and corporate structure. The Company continues to do business under the name BPZ Energy in its regular business operations.
No changes to the members of the Board of Directors, the management, or the operations of the Company were made in connection with the reincorporation from a Colorado corporation to a Texas corporation. The Company remains the same business entity following the reincorporation to Texas, with all of the assets, rights, privileges and powers of, and all property owned by, all debts due to, as well as any other causes of action belonging to the predecessor Colorado entity. As part of the reincorporation, a new Certificate of Formation and new Bylaws were adopted, and now govern the rights of holders of the Company’s common stock. At the effective time of the reincorporation, each outstanding share of the Colorado entity prior to the reincorporation was automatically converted into one share of the Texas entity.
As part of the restructuring, we have created two British Virgin Island limited partnership holding companies for various BPZ entities. Each holding company is owned 90% by BPZ Energy, Inc. as general partner and, in compliance with local requirements, 10% by an individual nominee limited partner, one of whom is our President and Chief Executive Officer. Although 10% of each of the holding companies is nominally owned by an individual, these individuals have agreed to enter into nominee agreements to assign all associated economic interest back to us, and consequently we treat these subsidiary holding companies and their subsidiaries as “wholly-owned” for accounting purposes. By the time we complete the restructuring, we intend to replace the individual nominees with another wholly-owned subsidiary to serve as limited partner of the holding companies.
Navidec Merger Transaction
On September 10, 2004, BPZ Energy, Inc., a Texas (“BPZ-Texas”) corporation consummated a reverse merger with Navidec, whereby BPZ-Texas became a wholly owned subsidiary of Navidec (the “Merger”). As a result of the Merger, the shareholders of BPZ-Texas received the majority of the voting interest and control of the Board of Directors and management
of the combined entity. For accounting purposes, BPZ-Texas was treated as the acquiring entity. All financial statements herein represent the historical financial statements of the accounting acquirer, BPZ - Texas. See “Business-Navidec Merger Transaction” for detailed discussion regarding the Merger. 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 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 achieved 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 were contingent on the Company becoming 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. In November 2007 this production target was achieved based on certification by an independent engineering firm that the Company’s production in Peru has met or exceeded the required level of production.
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 as contingent merger consideration. 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.
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 6 “Investment in Ecuador Property and Note Payable” 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.
Revenue Recognition
The Company does not recognize revenues until they are realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller’s price to the buyer is fixed or determinable and (iv) collectibility is reasonably assured.
The Company sells its production in the Peruvian domestic market on a contract basis. Revenue is recorded net of royalties when the purchaser takes delivery of the oil. At the end of the period, oil that has been produced but not sold is recorded as inventory at the lower of cost or market. Cost is determined on a weighted average based on production costs.
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, a translation gain of approximately $190,000 was recognized during the year ended December 31, 2007 and a translation gain $56,000 was recognized during the year 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 7, “Restricted Cash” contained herein under notes 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.
Allowance for Doubtful Accounts
Currently, the Company’s contract terms regarding oil sales have a relatively short settlement period. However, the Company regularly reviews all aged accounts receivables for collectability and establishes an allowance as necessary for balances greater than 90 days outstanding. Currently all receivables are current or were outstanding less than thirty days. It is the Company’s belief that there are no balances in accounts receivable that will not be collected and that an allowance was not necessary at December 31, 2007. There was no receivable balance as of December 31, 2006.
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, 2007, property and equipment consists of office equipment, vehicles and leasehold improvements made to the Company’s offices. All such values are stated at cost and are depreciated on a straight-line basis over the estimated useful life of the assets which is ranges between three and five years, or the term of the lease. Barges and related equipment are depreciated on a straight-line basis over the estimated useful life of the asset which is between fifteen and twenty years. Maintenance and repairs are expensed as incurred. Replacements, upgrades or expenditures which improve and extend the life of the assets are capitalized. When assets are sold, retired or otherwise disposed, the applicable costs and accumulated depreciation and amortization are removed from the appropriate accounts and the resulting gain or loss is recorded.
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.
Capitalized Interest
Certain interest costs have been capitalized as part of the cost of oil and gas properties under development, including wells in progress and related facilities. Total interest costs capitalized during the year ended December 31, 2007 was $0.9 million. No interest was capitalized during the years ended December 31, 2006 and 2005 due to the lack of operational debt during those periods.
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
Share Based Payments.
On December 21, 2007, the SEC released Staff Accounting Bulletin, (“SAB 110”) “Share-Based Payment” which will no longer allow the use of the “Simplified” method to estimate the expected terms as on the variables to determine the fair value of share-based payments. With a limited number of exceptions, companies can continue to use the simplified method. However, doing so requires the types of grants for which the Simplified method is used if not for all grants, and the periods for which the Simplified method is being used. The adoption of this Staff Accounting Bulletin is not expected to have a material impact on our consolidated 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.
The Fair Value Option for Financial Assets and Financial Liabilities
In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115, which will become effective on January 1, 2008. FAS 159 permits entities to measure eligible financial assets, financial liabilities and firm commitments at fair value, on an instrument-by-instrument basis, that are otherwise not permitted to be accounted for at fair value under other generally accepted accounting principles. The fair value measurement election is irrevocable and subsequent changes in fair value must be recorded in earnings. The Company will adopt this statement in the first quarter of 2008 and it does not expect to elect the fair value option for any eligible financial instruments and other items.
Business Combinations
In December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations, which replaces FASB Statement No. 141. SFAS 141(R) establishes principles and requirements for how an acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, any non- controlling interest in the acquiree and the goodwill acquired. SFAS 141(R) also establishes disclosure requirements that will enable users to evaluate the nature and financial effects of the business combination. SFAS 141(R) is effective for acquisitions that occur in an entity’s fiscal year that begins after December 15, 2008, which will be the company’s fiscal year 2009. The Company does not expect the adoption of SFAS No. 141R to have a material impact on the our consolidated financial position, results of operations or cash flows.
Noncontrolling Interests in Consolidated Financial Statements.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements-an amendment of ARB No. 51. SFAS 160 requires that accounting and reporting for minority interests will be recharacterized as noncontrolling interests and classified as a component of equity. SFAS 160 also establishes reporting requirements that provide sufficient disclosures that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS 160 applies to all entities that prepare consolidated financial statements, except not-for-profit organizations, but will affect only those entities that have an outstanding noncontrolling interest in one or more subsidiaries or that deconsolidate a subsidiary. This statement is effective for fiscal years beginning after December 15, 2008. The Company does not expect the adoption of SFAS No. 160 to have a material impact on our consolidated financial position, results of operations or cash flows.
Note 2 - Value Added Tax Receivable
Value-added tax (referred to as “IGV” in Peru) is generally imposed on goods and services at a rate of 19%. Peru currently has an IGV early recovery program for companies during the exploration phase. Under this program, IGV paid on the acquisition of certain goods and services used directly in hydrocarbon exploration activities can be recovered prior to a commercial discovery taking place or production and revenue billings begin. Because the Company has oil sales, it is no longer eligible for the IGV early recovery program.
The Company’s value added tax receivable balance as of December 31, 2007 was $7.5 million. Of this balance, the Company has filed claims with the Peruvian tax authority to recover approximately $2.9 million under the IGV early recovery program. During the year ended, December 31, 2007 the Company accrued approximately $11.4 million for IGV related to expenditures during the year and offset IGV by approximately $0.5 million related to the sale of oil in December 2007. Approximately $6.6 million of IGV has been collected during the year ended December 31, 2007.
During the year ended December 31, 2006 the Company received a refund of approximately $2.2 million under the IGV early recovery program. The Company’s value added tax receivable balance as of December 31, 2006 was $3.2 million.
Note 3 - Inventory
Inventories consist primarily of tubular goods, accessories and spare parts for production equipment, stated at the lower of average cost or market. The balance associated with tubular goods, accessories and spare parts inventory at December 31, 2007 and 2006 was $2.8 million and $2.0 million, respectfully.
The Company also maintains crude oil inventories in storage barges. These inventories are also stated at the lower of average cost or market value. Cost is determined on a weighted average basis based on production costs. The product inventory at December 31, 2007 consisted of approximately 12,248 barrels of crude oil at an estimated cost of $548,391 or $44.77 per barrel. There was no product inventory as of December 31, 2006.
Note 4 - Prepaid and Other Current Assets
Below is a summary of other current assets as of December 31, 2007 and 2006:
Prepaid expenses and other are primarily related to prepayments for drilling services, equipment rental and material procurement. Deposits are primarily rent deposits in connection with the Company’s offices in Houston and Peru. Prepaid insurance consists of premiums related to the Company’s operations as well as general liability and directors and officer’s insurance policies. Additional coverage was procured in response to increased business activity for the year ended December
31, 2007.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, 2007, 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 14 “Commitments and Contingencies”, included herein, for further discussion.
Note 5 - Property, Equipment and Construction in Progress
Below is a summary of property, equipment and construction in progress as of December 31, 2007 and 2006:
During the year ended December 31, 2007, the Company incurred costs of $63.1 million associated with its development initiatives for the exploration and production of natural oil and gas reserves and the complementary development of proprietary gas-fired power generation for sale in Peru.
The Company is in the initial stages of developing its oil and natural gas reserves and it has begun producing oil under an extended well testing program from its recent discoveries. 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 two 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. In March 2007, after a total of six drill stem tests were conducted on separate potential pay zones from the Lower and Upper Zorritos formations, the CX11-21 XD well, our first well, tested positive for both gas and oil in quantities that we believe to be commercially producible. Subsequently, in June 2007 we successfully recompleted the Corvina CX11-16X well as a natural gas producing well and completed a total of four drill stem tests on various zones in the well including one in a formation previously untested in the entire basin. In October, we completed seven drill stem tests on the CX11-14D well in the Corinva Field. The CX11-14D well tested positive for both gas and oil at commercially producible quantities. The first six tests were conducted in the Upper Zorritos Formation, with the first two testing the oil zone and the other four testing the gas zone, while the seventh test targeted the Cardalitos formation located immediately above the Upper Zorritos. On November 29, 2007, drilling commenced on the CX11-18XD well. The well reached total depth of 8,792 feet (measured depth) on January 1, 2008, approximately one month ahead of schedule. The Company recently performed a series of safety and integrity tests on the CX-11 Corvina platform including the surface equipment. As part of the integrity testing of the surface equipment, it perforated the lower prospective oil sands identified in the CX11-18XD well. The lower sands tested oil and the results assisted in validating our Corvina geologic model.
In conjunction with the gas-to-power project, the recent discovery of oil reserves in the Corvina field has prompted the Company to simultaneously direct its attention towards accelerating the development of potential oil production in the Corvina field. On June 13, 2007, the Company entered into a capital lease agreement, with an option to purchase, for two barges to assist in the development of the Corvina oil. The two barges were towed to Peru where they are being fitted with the required equipment for their intended use. One of these barges will be moored next to the CX11 platform, and will act as a floating production, storage and offloading facility (“FPSO”) for oil produced from the Corvina field. The Company has also identified and placed orders for the necessary oil production facilities to be installed on the FPSO barge. The second barge will be used to offload the produced oil from the FPSO and transport it to a refinery located approximately 100 miles to the south in the port of Talara. The capital lease for the two barges began in August 2007 and expires in November 2009.
Lease payments are variable based on the working status of the barges with a purchase option of $5.0 million after the first year of the lease and $4.0 million after the maturity date of the lease. The assets will be depreciated over the term of the capital lease obligation. The capital lease assets were recorded at $6.2 million, which represents the present value of the minimum lease payments, or the aggregate fair market value of the assets. See Note 9 “Debt”, included herein, for further discussion.
The Company began producing from the 21XD and the 14D wells under an extended well testing program. As a result, the costs associated with both wells, approximately $55.9 million was transferred from construction in progress to producing properties.
In addition, the Company incurred costs for office equipment and leasehold improvements for its offices in Houston, Peru and Ecuador. In accordance with “successful efforts” method of accounting, the Company capitalized $474,378 of depreciation expense related to support equipment to construction in progress as well as capitalized interest of approximately $930,786 to construction in progress during the year ended December 31, 2007.
Note 6 - 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 $1.6 million and $1.8 million as of December 31, 2007 and 2006, 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 in each of the years ended December 31, 2007 and 2006.
Note 7 - Restricted Cash
In connection with its properties in Peru, the Company has obtained five performance bonds totaling $6.0 million to insure certain obligations and commitments, of which one relates to a guarantee under a service contract and four relate to performance obligations under the license contracts for Blocks Z-1, XIX, XXII and XXIII.
As of December 31, 2007, the Company secured a $1.0 million performance bond to guarantee payment under a service agreement. The bond expired in January 2008 at which time the cash was refunded. Accordingly the amount was recorded as a current asset at December 31, 2007.
Additionally, as of December 31, 2007, the Company had restricted cash deposits of $2.8 million, which partially collateralizes the performance bonds under the License Contracts. In addition to the cash collateral posted by the Company, an individual shareholder of the Company had 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. During 2004, the Company issued 236,528 shares to that individual investor for $119,175 of cash proceeds and a subscription receivable of $230,825 for the guarantee. During the year ended December 31, 2007, the guarantee was replaced by a deposit of an additional $95,000 by the Company to the same financial institution and the Company received the $230,825 cash proceeds related to the subscription receivable. See, Note 14 “Commitment and Contingencies” below for further details of our performance bonds obligation.
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 8 -Asset Retirement Obligation
An obligation was recorded for the plug and abandonment of the producing oil wells, the 21XD and the 14D, in accordance with the provisions of SFAS No 143 “Accounting for Asset Retirement Obligations” (“ARO”). See Note 14 “Commitments and Contingencies”, included herein, for further discussion.
Activity related to the Company’s asset retirement obligation (“ARO”) for December 31, 2007 and 2006 is as follows:
Note 9 -Debt
The recent discovery of oil reserves in the Corvina field has prompted the Company to direct its attention towards accelerating the development of potential oil production in the Corvina field. On June 13, 2007 the Company entered into a capital lease agreement, with an option to purchase, for two barges to assist in the development of the Corvina oil. The capital lease for the two barges began in August 2007 and expires in November 2009. The lease contains a purchase option which the Company anticipates, for accounting purposes, it will exercise on the 15th month of the lease term. Lease payments are variable, based on the working status of the barges, with a purchase option of $5 million after the first year of the lease and $4 million after the maturity date of the lease. The capital lease obligation was recorded at the present value of the minimum lease payments at an imputed discount rate of 18%, which reflects the Company’s incremental borrowing rate for this transaction. The capital lease obligation was recorded at $6.2 million, which represents the present value of the minimum lease payments, or the fair market value of the debt obligation.
In addition, on December 31, 2007, the Company had long-term debt of approximately $15.5 million compared to $55,000 in long-term debt as of December 31, 2006. The difference in long-term debt is related to the IFC convertible debt. On November 19, 2007, a convertible debt agreement between IFC and the Company was entered into for approximately $15.5 million. The terms of the loan agreement stipulate a conversion price of $10.39 per share and includes a forced convert price of $18.19 per share, based on the average closing price over twenty consecutive business days. The instrument has a 10 year term with a variable interest rate of 2% per annum above 6-month LIBOR (6.863% at December 31, 2007). The loan from the IFC is unsecured, but restricts our ability to pledge assets to another lender unless certain conditions are met. The IFC loan does not restrict our ability to issue additional capital stock, but does call for an adjustment in its conversion price into BPZ common stock based on the terms of any subsequent equity offering. The agreement contains customary default and cross-default provisions along with covenants restricting our ability to pay dividends and the disposition of assets. We are required to maintain a required ratio of Balance Sheet Liabilities to Tangible Net Worth (as defined in the Loan Agreement), calculated quarterly, of no greater than 70:30. As of December 31, 2007, we were in compliance with all financial covenants.
Long-term debt for both 2007 and 2006 also includes 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.
Maturities of debt are as follows:
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 May 4, 2007, with an over-allotment purchase that closed on June 15, 2007, the Company completed a private placement of 7,170,000 shares of common stock, no par value, to accredited investors pursuant to a Subscription Agreement. The common stock was priced at $5.25 per share and the over-allotment was priced at $5.40 per share resulting in proceeds to the Company of approximately $37.7 million. No warrants or dilutive securities were issued in connection with the offering. The offering was placed directly by the Company. A placement fee of 2% of the gross proceeds of this transaction was paid to Morgan Keegan for investment services and consulting related to the offering. The registration statement was declared effective by the Securities and Exchange Commission on June 20, 2007.
Stock Subscription Receivable
During 2004, the Company issued 236,528 shares to an individual investor for $119,175 of cash proceeds and a subscription receivable of $230,825 for a guarantee letter. The guarantee letter was associated with the first exploration phase of Block Z-1. During the year ended December 31, 2007, the guarantee was replaced by a deposit of an additional $95,000 by the Company to the same financial institution. Additionally, during 2007 the Company received the $230,825 cash proceeds related to the subscription receivable. See Note 7 “Restricted Cash”, included herein, for further discussion.
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 No. 123(R)”), which establishes accounting for stock-based payment transactions for employee services and goods and services received from non-employees. SFAS No. 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 No. 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 No. 123. As allowed under SFAS No. 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 January 1, 2006, 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 January 1, 2006 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 No. 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 No. 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 No. 123(R). SFAS No. 123(R) requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods to reflect actual forfeitures. Currently, the Company’s forfeiture estimates are 1.5% for both stock options and restricted stock grants as a result of adopting SFAS No. 123(R).
The following table summarizes stock-based compensation costs recognized under SFAS 123 for the year ended December 31, 2005 and under SFAS 123(R) for year ended December 31, 2007 and 2006:
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 ratably over the vesting or service period, net of forfeitures; however, compensation cost related to performance shares will not be recorded or will be reversed if the Company does not believe it is probable that such performance criteria will be met or if the service provider (employee or otherwise) fails to meet such criteria.
A summary of the Company’s restricted stock award activity and related information is presented below:
As of December 31, 2007, there was $9.6 million of total unrecognized compensation cost related to nonvested restricted stock awards, which is expected to be recognized over a weighted-average period of 1.8 years.
No performance shares were outstanding as of December 31, 2007.
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 Company’s stock options generally vest over a two to three year period and expire ten years from the date of grant. Compensation cost related to stock options is recognized ratably 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 the year ended December 31, 2007. During the year ended December 31, 2007, 2,141,700 options were granted by the Company under the 2007 Long-term Incentive Plan. The expected life of the options represents the period of time the options are expected to be outstanding. For the year ended December 31 2007, 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. For the year ended December 31, 2006, the expected term of options granted was based on 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 for 2008. For the year ended December 31, 2007 and 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:
During the year ended December 31, 2007 a total of 1,868,752 options were exercised. As of December 31, 2007, there was approximately $14.4 million of total unrecognized compensation cost related to non-vested stock options which is expected to be recognized over a weighted-average period of approximately 1.5 years.
The following table summarizes information about stock options outstanding as of December 31, 2007:
The aggregate intrinsic value of stock options outstanding at December 31, 2007 was $20.4 million, of which $10.5 million relates to awards vested and exercisable and $9.9 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 31, 2007 exceeds the exercise price of the option.
Warrants
As of December 31, 2007, 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, 2007 and 2006. 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, 2007.
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 immediately below). However, one of the Company’s officers entitled to receive earn-out shares 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 were awarded to the officer’s successor to supplement a previous award of 35,000 shares. The second earn-out target provided for in the original merger agreement related to its merger with Navidec, Inc. In November 2007 the production target in the Merger Agreement dated July 8, 2004 was achieved. The determination was made by the Company’s Board of Directors based on certification by the independent engineering firm that the Company’s production in Peru has met or exceeded the required level of production.
The achievement of the required level of production resulted in the issuance of 450,000 shares. For accounting purposes, during the year ended December 31, 2007, $1,980,000 was recorded as 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 achieved 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 were contingent on the Company becoming 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. As mentioned above, in November 2007 the production target was achieved based on certification by an independent engineering firm that the Company’s production in Peru has met or exceeded the required level of production.
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 and Directors’ Compensation Incentive Plan
On August 17, 2007, the Company adopted the 2007 Long-Term Incentive Compensation Plan (the “2007 LTIP”), which is an amendment and restatement of the BPZ Energy, Inc. 2005 Long-Term Incentive Compensation Plan (the “2005 LTIP”). The amendment and restatement was recommended by the Board of Directors and adopted pursuant to the approval of the shareholders at the 2007 annual meeting of shareholders held on August 17, 2007. The 2007 LTIP supersedes and replaces the 2005 LTIP but will not impair the vesting or exercise of any award granted under the 2005 LTIP prior to the date the 2007 LTIP became effective. The provisions of the 2005 LTIP applicable to directors are set forth in a separate 2007 Directors’ Compensation Incentive Plan (the “Directors’ Plan”), which was also adopted by the Company pursuant to the approval of the shareholders at the 2007 annual meeting of shareholders held August 17, 2007.
The 2007 LTIP increases the amount of securities available for incentive awards to an aggregate of 4,000,000 shares, subject to adjustment to reflect stock splits and other similar events. The 2007 LTIP terminates on the earlier of (1) ten years from the date the 2007 LTIP becomes effective, or (2) at such time as no shares of common stock of the Company remain available for issuance through the plan. The Company’s officers, employees and consultant and the employees of certain of the Company’s affiliates are eligible to participate in the 2007 LTIP. The 2007 LTIP allows for the award of (1) incentive stock options under Section 422 of the Tax Code, (2) non-statutory stock options not covered under Section 422 of the Tax Code, (3) stock appreciation rights granting the recipient the right to receive an excess in the fair market value (as defined in the 2007 LTIP) of shares of stock over a specified reference price, (4) restricted stock, which will be subject to a risk of forfeiture and nontransferable until it vests over time, (5) qualified performance-based incentive to employees who qualify as covered employees within the meaning of Section 162(m) of the Tax Code, as amended, (6) unrestricted stock, which will be immediately transferable, and (7) other stock-based incentive awards. Any vesting provisions for an award made under the 2007 LTIP may be determined by the Compensation Committee. Awards will generally vest in four years unless otherwise determined by the Compensation Committee.
The Directors’ Plan supersedes and replaces the portions of the 2005 LTIP applicable to non-employee directors, but will not impair the vesting or exercise of any incentive granted to a director under the 2005 LTIP prior to the date the Directors’ Plan became effective. The Directors’ Plan will terminate on the earlier of (1) ten years from the date that the Directors’ Plan becomes effective, or (2) at such time as no shares of common stock of the Company remain available for issuance through the plan. The Company’s non-employee directors are eligible to participate in the Directors’ Plan. The Directors’ Plan provides for the issuance of up to 2,500,000 shares of the Company’s common stock to non-employee
directors, subject to adjustment to reflect stock splits and similar events. The Directors’ Plan allows for the award of (1) non-statutory stock options not covered under Section 422 of the Tax Code, (2) stock appreciation rights, granting the recipient the right to receive an excess in the fair market value (as defined in the Directors’ Plan) of shares of stock over a specified reference price, (3) restricted stock, which will be subject to a risk of forfeiture and nontransferable until it vests over time, (4) unrestricted stock, which will be immediately transferable, and (5) other stock-based incentive awards. Vesting under the Directors’ Plan will be determined by the Compensation Committee. Awards will generally vest in four years unless otherwise determined by the Compensation Committee.
Note 11 - Affiliate and Related Party Transactions
As of December 31, 2007 and December 31, 2006, the Company had not entered into any transactions with affiliates or related parties.
Note 12 - Income Taxes
For the year ended December 31, 2007, income tax of approximately $39,001 of taxes, penalties and interest were incurred related to our investment income in Ecuador. See Note 6 “Investment in Ecuador Property and Note Payable” to the Consolidated Financial Statements for further discussion regarding the Company’s investment in its Ecuador property. There was no income tax expense or benefit for the years ended December 31, 2007, 2006 and 2005 as shown in the following table:
The tax effects of the temporary differences that give 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 due to tax net operating loss carryforwards of approximately $35.5 million expiring in various amounts through 2027.
Note 13 - Business Segment Information
The Company determines and discloses its segments in accordance with SFAS No. 131 “Disclosures about Segments of an Enterprise and Related Information” which uses a “management” approach for determining segments. The management approach designates the internal organization that is used by management for making operating decisions and assessing parlance as the source of the Company’s reportable segments. SFAS No. 131 also requires disclosures about products or services, geographic areas, and major customers. The Company’s management reporting structure provided for only one segment for the years ended December 31, 2007, 2006 and 2005 and accordingly, no separate segment information is presented. In addition, the Company operates only in Peru and has only one customer for its production.
Segment Information:
Operating and geographic information: The Company operates primarily in one segment which involves the production of oil. All of the Company’s sales are made under a short-term contract to the Peruvian national oil company, Petroperu.. The majority of our long-lived assets are located in Peru.
Note 14 - Commitments and Contingencies
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 affected 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, 2007, in connection with its Peru properties, the Company obtained five performance bonds totaling $6.0 million to guarantee certain obligations and commitments, of which four related to performance obligations under the license contracts for Blocks Z-1, XIX, XXII and XXIII. As of December 31, 2007, the Company had restricted cash deposits of approximately $3.8 million which partially collateralize the performance bonds. The Company was also required to deposit approximately $0.8 million as restricted cash to collateralize a performance bond of $1.0 million in connection with the beginning of the third exploration period under the Block Z-1 license contract, which began in June 2007. In addition, it was required to deposit approximately $0.2 million as restricted cash to collateralize performance bonds of $0.4 million under the Block XIX license contract in connection with the first exploration period. The Company was also required to post a $1.0 million performance bond to guarantee payment under a service agreement, which is set to expire in January 2008. In connection with signing the license contracts for Blocks XXII and XXIII in November 2007, the Company was required to post $0.3 million and $1.5 million, respectively in restricted cash to collateralize $0.6 million and $3.1
million, bonds respectively, in connection with the first exploration period. The performance bonds were issued by Peruvian banks and their terms are governed by the corresponding license contract or agreement.
In connection with Block Z-1, in December, 2006, as a result of the drilling of the first well, the CX11-21XD, the $1.3 million performance bond and related cash posted as collateral was released. The third exploration period began in May 2007 and is scheduled to expire in December 2008. It will require the drilling of an additional exploratory well or other equivalent work commitments. A performance bond of $1.0 million was also posted for cash collateral of $750,000 as a result. The fourth and final exploration period is scheduled to begin in December 2008 and expire in December 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. On November 21, 2007, the Company submitted a letter to Perupetro declaring a commercial discovery in the Block Z-1 field. The Company is currently putting together a field development plan which is required to be filed with Perupetro within 180 days of the declaration of the commercial discovery. The commercial development period of the contract will commence as soon as the Company receives approval of the field development plan. 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.
In connection with the Block XIX license contract, the Company recently completed shooting 200 kilometers of 2-D seismic. The cost to acquire this seismic data was approximately $3.6 million. The Company has completed the processing and interpreting the data. Based on the results of the 2-D seismic survey and in order to comply with the requirements under the next phase of the license contract, the Company plans to drill a well in Block XIX in late 2008 at an estimated cost of $8.0 million. 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 15% to 30% based on production volumes. Royalties start at 5% if and when production is less than 5,000 barrels of oil equivalent per day (boepd) and are capped at 20% if and when production surpasses 100,000 boepd.
As part of the Block XXII License Contract which was signed on November 21, 2007, the Company was required to obtain a cash collateralized $0.6 million performance bond in connection with the first exploration period. The performance bond was purchased for $0.3 million and was issued by a Peruvian bank under terms governed by the license contract. The term of the license contract extends over a seven year period divided into five periods or four periods of 18 months and a final period of 12 months. Under certain circumstances, the exploration periods may be extended for an additional period of up to three years. Under each exploration period, a performance bond will be required. 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. Additionally, the first period requires that we purchase, process and interpret 200 kms of 2-D seismic data. The Company will also be required to prepare a comprehensive geological and engineering study for the area. In each subsequent period after the first 18 month period we are required to drill an exploratory well. 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 15% to 30% based on production volumes. Royalties start at 15% if and when production is less than 5,000 barrels of oil equivalent per day (boepd) and are capped at 30% if and when production surpasses 100,000 boepd.
In connection with the Block XXIII License Contract which was signed, on November 21, 2007, the Company was required to obtain a cash collateralized $3 million performance bond in connection with the first exploration period. The bond was purchased for $1.5 million and was issued by a Peruvian bank under terms governed by the license contract. The license contract extends over a seven year period divided in to two periods of 18 months and two periods of 24 months. Under each exploration period, a performance bond will be required. 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, it 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. 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 15% to 30% based on production volumes. Royalties start at 15% if and when production is less than 5,000 barrels of oil equivalent per day (boepd) and are capped at 30% if and when production
surpasses 100,000 boepd.
An obligation was recorded for the plug and abandonment of the producing oil wells, the 21XD and the 14D, in accordance with the provisions of SFAS No 143 “Accounting for Asset Retirement Obligations” (“ARO”) related to the plug and abandonment of our wells. However, the Company also acquired four offshore platforms in connection with its Block Z-1 property. The Company completed the refurbishment of one of the offshore platforms and intends to maintain all of the 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 No. 143 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 No. 143, and therefore recognition of an ARO is not required. Accordingly, no such provision for dismantling the platforms 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 $2.0 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 is utilizing the rig for the initial development of the Corvina 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 paid a $5.5 million fee to mobilize and upgrade the rig. In exchange, the Company received a discounted fixed day rate and exclusive rights to use the rig, at its option, during the two-year period which commenced in September 2006. In addition, after the guaranteed two-year period, the Company has the option to extend the contract for an additional year at market rates.
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 CX-11 platform. No injuries were sustained by any of our employees, 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 had 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 March 14, 2008, the Company has 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. A mandatory dry-dock is scheduled for the second quarter 2008 at which time a full survey of the barge will be conducted and an insurance claim is expected to be filed. 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 did not have a material impact on our operations or business plan.
Charter of Navy Tankers
On October 24, 2007, the Company’s primary marine transportation contractor entered into two short term agreements with the commercial division of the Peruvian Navy to lease two tankers to transport oil to market earlier than scheduled. The two tankers leased from the Navy each have capacity of approximately 7,000 barrels.
On January 30, 2008, one of the Navy tankers, the Supe, caught fire and sank into the ocean close to the CX11 platform. Although no BPZ employees or subcontractors directly managed by the Company were injured, there were injuries sustained by the Peruvian sailors including two fatalities. At the time of the incident the Supe tanker contained approximately 1,300 barrels of oil, most of which was burned in the fire. The Company believes that environmental issues have been adequately controlled and is continuing to monitor the situation. The Company’s platform, barges, drilling and well testing equipment, and other facilities were not damaged. Production from the 21XD and 14D wells, approximately 4,200 barrels of oil per day at the time, as well as the testing operations on the 18XD has been temporarily suspended
pending a complete investigation.
Currently all production (which had reached approximately 4,200 barrels of oil per day by late January 2008) is shut-in due to the incident involving the Navy tanker. At the request of the OSINERGMIN, the government agency responsible for auditing the safety of energy investments in Peru, we successfully performed a series of safety and integrity tests on the facilities at the CX-11 Corvina platform, including the equipment that was being used for the ongoing long-term testing of the 21XD and 14D wells. We confirmed that the well testing equipment was in operational condition. On March 12, 2008 we received clearance from the OSINERGMIN, to resume operations at the CX-11 platform, including the scheduled 18XD well drill stem test. However, the four Corvina wells are currently shut-in while we complete the installation of sea-bed pipelines connecting the platform to the transport barge, along with the required mooring systems, that will allow for an improved long-term testing program. Additionally, we are waiting for final clarification from the appropriate authorities in Peru regarding the transportation of our crude oil to the refinery.
The Company has submitted all the requested reports and documentation generated during the investigation. A number of organizations involved in the investigation have issued reports concluding there was no environmental damage due to the incident. Additionally, the Company assisted the Peruvian Navy in conducting an underwater survey of the Supe, which established that the vessel does not represent a hazard to navigation nor a marine pollution threat, as all its tanks were found to be empty. The CX-11 Corvina platform and all its facilities, as well as the BPZ-01 tender barge, the four Corvina wells, and all the vessels supporting the operations have now been certified to be in operational condition.
The ongoing investigation has not resulted in any sanctions against the Company for any wrong doing or for any inadequate safety and/or environmental procedures as a result of the fire. Nonetheless, the Company continues to try and improve safety as a result of the vessel incident and will continue to cooperate with officials who are investigating the incident. Other than the temporary suspension of operations, the incident is not expected to have a material impact on the Company’s future operations or business plan.
As noted above, the Company currently has two additional barges under a capital lease agreement. On June 13, 2007, the Company entered into a capital lease agreement, with an option to purchase, for two barges to assist in the development of the Corvina oil. The two barges were towed to Peru where one barge, the Nu’ uanu, is currently being used to transport oil between the CX11 platform and the refinery in Talara, approximately 100 miles south. The Nomoku is currently being out-fitted with the required equipment for its intended use as a floating production, storage and offloading facility (“FPSO”) that will be moored next to the CX11 platform. However, we have encountered some delays due to scheduling. We expect the FPSO to be fully out-fitted and operational by the end of the first quarter or beginning of the second quarter 2008.
The Company will continue to make commitments in the ordinary course of business as it pursues its development plans for the properties.
Financing Activities
On October 22, 2007, the Company entered into a non-binding term sheet agreement with the International Finance Corporation (“IFC”), the private sector arm of the World Bank Group based in Washington, D.C., delineating the key terms and conditions for the first tranche (see Loan “C” immediately below) of a debt package with IFC. Previously, the Company announced a total debt package, approved by IFC, of $100.5 million approved by the IFC but subject to final due diligence and documentation. The Company is actively negotiating with IFC to increase the debt package to an estimated $165 million for further development of our assets.
The initial $120 million financing package was approved by the Credit Committee of the IFC on November 29, 2006, which included an investment by IFC in BPZ’s common stock and took place on 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 the Company and there were no placement fees. IFC currently holds approximately a 9% equity position in the Company with 6.5 million shares of our common stock. In addition, IFC has a preemptive right to purchase its pro rata share of common stock or securities convertible into common stock that are issued and sold by the Company (except for certain issuances of securities, such as pursuant to stock splits, stock dividends, acquisitions by the Company or under the Company’s incentive compensation plan). IFC’s total equity and senior debt investment in the Company, subject to execution and funding of the increased debt agreement, as described above, will reach approximately $185 million. Any increased debt package will be subject to final internal approvals by appropriate representatives of both IFC and BPZ. It is uncertain if such approval will occur, or if approved, the timing or amount of such approvals. The proposed $165 million facility is anticipated to consist of the following:
· Loan “C”, which is comprised of $15.5 million of convertible debt, closed in early November 2007. The
conversion price is $10.39 per share and includes a forced conversion price of $18.19 per share, based on an average closing price over twenty consecutive business days. The instrument has a 10 year term with a variable interest rate of 2% per annum above 6-month LIBOR. The loan from the IFC is unsecured, but restricts our ability to pledge assets to another lender unless certain conditions are met. The IFC loan does not restrict our ability to issue additional capital stock, but does call for an adjustment in its conversion price into BPZ common stock based on the terms of any subsequent equity offering. The agreement contains customary default and cross-default provisions along with covenants restricting our ability to pay dividends and the disposition of assets. We are required to maintain a required ratio of Balance Sheet Liabilities to Tangible Net Worth (as defined in the Loan Agreement), calculated quarterly, of no greater than 70:30. As of December 31, 2007, we were in compliance with all financial covenants.
· Loan “A”, which is for IFC’s own account, is expected to consist of $34.5 million in long-term senior debt. This second tranche is expected to be closed during the second quarter of 2008. The terms of the instrument are still being negotiated.
· Loan “B”, comprised of senior debt to be syndicated by IFC, is projected to be approximately $115 million. This third tranche is expected to close in the third quarter 2008. This remaining debt portion of the financing will be subject to identification of the lending syndicate members and subsequent negotiation and approval of the necessary loan documentation.
As of March 14, 2008, the final loan documents for the “A” and “B” Loans have not been completed.
In conjunction with the gas-to-power project, the recent discovery of oil reserves in the Corvina field has prompted the Company to simultaneously direct its attention towards accelerating the development of potential oil production in the Corvina field. On June 13, 2007 the Company entered into a capital lease agreement, with an option to purchase, for two barges to assist in the development of the Corvina oil. The capital lease for the two barges began in August 2007 and expires in November 2009. Lease payments are variable, based on the working status of the barges with a purchase option of $5,000,000 after the first year of the lease and $4,000,000 after the maturity date of the lease. The capital lease obligation was recorded at the present value of the minimum lease payments at an imputed discount rate of 18%, which reflects the Company’s incremental borrowing rate for this transaction. The assets will be depreciated over the term of the capital lease obligation. The capital lease assets were recorded at $6,180,679, which represents the present value of the minimum lease payments, or the aggregate fair market value of the assets.
Note 15 - 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. 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-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. Based upon this provision of the Merger Agreement, the Company 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 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.
The Company commenced an action against NFS (the “Action”) on or about February 13, 2006, in District Court, Arapahoe County, Colorado (the “Court”), seeking a judicial resolution of this matter. 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 16 - 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, 2007, 2006 and 2005 was approximately $$324,000, $252,000 and $98,000, respectively. Minimum non-cancelable lease commitments under these agreements for the years ending December 31 are as follows:
Note 17 - Subsequent Events
In January 2008, 250,000 common stock warrants with a strike price of $3.00 per share where exercised by Morgan Keegan & Company, Inc. These warrants had been issued to Morgan Keegan & Company, Inc. in connection with its role as financial advisor to the Company, in connection with the private placements of 11,466,000 and 4,482,000 shares of common stock in July of 2005 and June of 2006, respectively. Net proceeds to the Company as a result of the exercise of these warrants were approximately $750,000. For more detail, see Note 10 “Stockholders’ Equity” to the Consolidated Financial Statements under “Warrants” above.
In February 2008, we entered into a lease-purchase agreement to acquire a deck barge (“BPZ 02”), of approximately 330 feet in length, to assist in the drilling activities in the Albacora field as well as to assist in future drilling and development activities. In the near term, the BPZ 02 will be used to act as a tender assist for the Petrex drilling rig as it is moved to the Albacora field in third quarter 2008. During that time, as mentioned in Note 14 “Commitment and Contingencies”, the BPZ 01 will be placed in drydock to repair damages sustained when it ran aground in late 2006. The acquisition of the BPZ 02 allows the Company better asset maintenance scheduling and will aid in the support of increased offshore exploration and development activities. The terms of the lease-purchase stipulate a 19% rate of interest over a one year term at which point, title to the BPZ 02 will transfer to the Company upon final payment of the lease. The Company will account for the transaction as a Capital Lease in accordance to SFAS 13, “Accounting For Leases (As Amended)” under the criteria the barge will transfer title at the end of the lease period and, as a result, depreciation will be calculated over the economic life of the asset.
Note 18 - 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.
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, 2007 and 2006:
(1) BPZ Energy purchased the Investment in Ecuador Property in 2004.
Pursuant to SFAS No. 143 “Accounting for Asset Retirement Obligations”, net capitalized cost includes asset retirement cost of $0.3 million as of December 31, 2007. No ARO was recorded as of December 31, 2006.
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, 2007 and 2006:
(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, 2007, 2006 and 2005, and the changes in the net proved reserves for each of the three years in the period then ended.
Net Proved Developed Reserves Summary
(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.
(5)
Billion cubic feet or billion cubic feet equivalent, as applicable
(6)
Based on a rollforward of the independent reservoir engineer’s report provided by the operator of the Santa Elena property.
(7)
We do not currently have the financial capacity or commitments for a development program of this magnitude for our gas reserves. Accordingly, the Company has not disclosed amounts of proved gas reserves in its SEC filings. At such time as we obtain sufficient financial commitments to proceed with the full development of the gas to power project and all other conditions necessary to record proved reserves are met, we expect to record SEC proved gas reserves as permitted under SEC rules and disclose such reserves in future SEC filings.
(8)
We did not have the financial capacity or commitments for a development program of this magnitude. Accordingly, the Company did not disclose amounts of proved reserves in its SEC filings for the years ended December 31, 2006 and 2005.
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, 2007, 2006 and 2005:
(1) Investment in Ecuador Property
(2) Based on a rollforward of the independent reservoir engineer’s report provided by the operator of the Santa Elena property.
Note 19 - Quarterly Results of Operations
As restated for retroactive stock dividend, see Note 10, “Merger Earn-out Shares” above for additional information.
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, 2007 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, 2007 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, 2007.
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, 2007, which is set forth below under “Attestation Report”.
(d) Attestation Report
Report of Independent Registered Public Accounting Firm
on Internal Control over Financial Reporting
To the Board of Directors and Shareholders
BPZ Resources, Inc. and Subsidiaries
We have audited BPZ Resources, Inc. and Subsidiaries’ internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). BPZ Resources, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Annual Report on Internal Control Over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, BPZ Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of BPZ Resources, Inc. and Subsidiaries as of December 31, 2007 and 2006, 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, 2007 and our report dated March 12, 2008 expressed an unqualified opinion thereon.
Johnson Miller & Co., CPA’s PC
Midland, Texas
March 12, 2008
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
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry that are used in this report.
Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent determined using the ratio of approximately six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Bopd. Barrels of oil per day.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Drill Stem Test. A test of the flow rates of a formation thru the drill pipe to determine the fluid and gas content, pressure and estimated production rates of the reservoir.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
Exploitation. A drilling or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.
Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of approximately six Mcf of natural gas to one Bbl of crude oil or other hydrocarbon.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
Oil. Crude oil, condensate and natural gas liquids.
Productive well. A well that is found to be capable of producing hydrocarbons.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has
confirmed through production response that increased recovery will be achieved. The SEC provides a complete definition of proved developed reserves in Rule 4-10(a)(3) of Regulation S-X.
Proved reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrates with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and cost as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions. The SEC provides a complete definition of proved reserves in Rule 4-10(a)(2) of Regulation S-X.
Proved undeveloped reserves. Proved oil and gas 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 shall be 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. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. The SEC provides a complete definition of proved undeveloped reserves in Rule 4-10(a)(4) of Regulation S-X.
PV-10 value. The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC (using prices and costs in effect as of the date of estimation) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.
Recompletion. The completion for production of an existing well bore in another formation from that which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Workover. A remedial operation on a completed well to restore, maintain or improve the well’s production.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on March 14, 2008.
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
Chief Financial Officer
March 14, 2008
March 14, 2008
/s/ DR. FERNANDO ZÚÑIGA Y RIVERO
/s/ GORDON GRAY
Dr. Fernando Zúñiga y Rivero
Gordon Gray
Director and Chairman of the Board
Director
March 14, 2008
March 14, 2008
/s/ E. BARGER MILLER III
/s/ JOHN J. LENDRUM, III
E. Barger Miller III
John J. Lendrum, III
Director
Director
March 14, 2008
March 14, 2008
/s/ DENNIS G. STRAUCH
Dennis G. Strauch
Director
March 14, 2008
INDEX OF EXHIBITS
Exhibit
Number
Description
2.1
Plan of Conversion for BPZ Energy, Inc. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on August 17, 2007).
3.1
Certificate of Formation of BPZ Resources, Inc. (incorporated by reference to Exhibit 3.1 to the Company’s Form 8-K filed on August 17, 2007).
3.2
Bylaws of BPZ Resources, Inc. (incorporated by reference to Exhibit 3.2 to the Company’s Form 8-K filed on August 17, 2007).
3.3
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 Resources, Inc., a Texas corporation (incorporated by reference to Exhibit 99.1 to the Company’s Form 10-Q filed on November 8, 2007).
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 filed on July 5, 2005 (SEC File No. 333- 126388)).
4.3*
BPZ Energy, Inc. 2007 Long-Term Incentive Compensation Plan (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on August 24, 2007).
4.4*
BPZ Energy, Inc. 2007 Directors Compensation Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on August 24, 2007).
10.1
Merger Agreement between Navidec, Inc. and BPZ Energy, Inc. dated July 8, 2004 (incorporated by reference to Exhibit 10.1 from the Company’s Form 8-K filed 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 filed on February 14, 2005 (SEC File No. 333-122816)).
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 filed on February 14, 2005 (SEC File No. 333-122816)).
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 filed on February 14, 2005 (SEC File No. 333-122816)).
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 filed on February 14, 2005 (SEC File No. 333-122816)).
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 filed on February 14, 2005 (SEC File No. 333-122816)).
10.9
License Contract from the Government of Peru for Block XXII dated November 21, 2007 (filed herewith)
10.10
License Contract from the Government of Peru for Block XXIII dated November 21, 2007 (filed herewith)
14.1
Code of Ethics for Executive Officers (incorporated by reference to Exhibit 14.1 to Form 10-KSB/A filed on September 26, 2006).
21.1
Subsidiaries of the Registrant (filed herewith).
23.1
Consent of Independent Registered Public Accounting Firm (filed herewith).
23.2
Consent of Independent Petroleum Engineers and Geologists (filed herewith).
31.1
Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (filed herewith).
31.2
Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. (filed herewith).
32.1
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (furnished herewith).
32.2
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (furnished herewith).
* - Management Contract or Compensatory Plan or Arrangement.