Item 1. Business
Overview
BMB Munai, Inc., is a Nevada corporation, that originally incorporated in the State of Utah in 1981. Our business activities focus on oil and natural gas exploration and production in the Republic of Kazakhstan (also referred to herein as the “ROK” or “Kazakhstan”). We hold an exploration contract that allows us to conduct exploration drilling and oil production in the Mangistau Province in the southwestern region of Kazakhstan. Since the date of execution of the original exploration contract, we have successfully negotiated several amendments to the contract that have extended the term of our contract to January 2013. The exploration territory of our contract area is approximately 850 square kilometers.
Our original contract area comprised the ADE Block. As a result of our drilling and exploration activities this block now contains our Aksaz, Dolinnoe and Emir oil and gas fields. During our 2005 fiscal year we were granted an area extension which we designated as the Southeast Block, which now includes our Kariman oil and gas field and our unexplored Borly and Yessen structures. During our 2009 fiscal year we successfully negotiated a second area extension, which we have designated the Northwest Block. All of our exploration territory is contiguous. The ADE Block, the Southeast Block and the Northwest Block are collectively referred to herein as “our properties.” For additional information regarding our contract and license to our properties please see Item 2. Properties below.
Our Strategy
Since 2004 we have been actively drilling wells in each field on the ADE Block and since 2005 we have been drilling in the Southeast Block in the Kariman field. Our activities have been funded through private placements of equity and debt securities as well as income generated from sales of our exploration stage oil production.
Our drilling activities have consisted of drilling an array of exploratory wells to delineate reservoir structures and developmental wells intended to provide income to the Company. Our operational focus during the last fiscal year has been to work on improving and stabilizing production from our existing wellstock, while temporarily postponing our drilling activities. Throughout the year we have completed a number of workover activities on existing wells. In addition to the workover activities completed this year, we have continued to research various production enhancement methods and technologies to increase production from existing wells. Currently, we have 1,230 gross (1,230 net) proved developed producing acres, plus 180 gross (180 net) acres of proved undeveloped reserves. We also hold approximately 112,260 gross (112,260 net) unproved, undeveloped acres.
During the year we have reduced capital expenditures to a minimum amount and managed to successfully fulfill working program requirements set forth in our contract with the government of Kazakhstan through the negotiating of a “roll forward” of previously drilled wells whereby we were allowed to count previously drilled wells as fulfillment of our drilling obligations under our minimum work program for fiscal year 2010. Such actions allowed us to achieve significant progress in remedying working capital problems we faced during fiscal year 2009. All free cash flow was diverted to reduction of accounts payable, which coupled with our other efforts allowed us to reduce accounts payable from $21.8 million at March 31, 2009, to $3.9 million at March 31, 2010.
Our strategy for the current year is to establish a sound financial basis to support our development of a long-term and profitable oil and gas exploration and production business. We intend to do this by focusing our attention in the next fiscal year on the following objectives:
Complete elimination of current accounts payable. We will continue efforts to eliminate current accounts payables barring those arising in the normal course of business.
Conduct field operations focused on stabilization and enhancement of production from existing wells. We will continue our efforts in researching and applying modern methods and technologies for maintaining and increasing production from existing wells. Such efforts may entail substituting the electric submersible pumps used on the Kariman field for more powerful and productive ones and finding the right methodology to enhance production from the Aksaz and Dolinnoe wells.
Conduct directional/horizontal drilling on existing wells. If we have sufficient funds, we plan to apply directional/horizontal drilling on the existing wells in the Kariman field during fiscal year 2011. We have plans for drilling two directional sidetracks on the Kariman existing wells. We plan to apply such technology with focus on significant production increases while keeping capital expenditures under control as such sidetracks cost significantly less than drilling of a vertical well. We also believe drilling two directional wells will contribute to the minimum working program requirements set for the current year.
Complete geological study of the ADE Block and Kariman field. Our existing wells are sufficient in number to allow us to integrate our geological and geophysical reports, seismic data, drilling logs and testing and production logs to create a complete profile of the ADE Block and Kariman field. Similar to most oil production in Kazakhstan, our oil is produced mainly from carbonate rocks of limestone and dolomite. These formations can present challenges when attempting to understand oil field structure, designate well locations and determine the number of wells required to develop a field. A full understanding of these issues is critical, as they can have a substantial impact on a field’s commercial viability and the expected return on investment. We plan to retain experts from the United States that have experience working in Kazakhstan to complete the geological study during fiscal year 2011.
Commence investigation of the Northwest Block. Our contract territory nearly doubled during the last fiscal year due to our successful negotiation of an amendment to our exploration contract to acquire rights to the Northwest Block. The Northwest Block did have limited Soviet-period exploration and drilling conducted on it, but needs further study if we are to start developing it. We commenced 3D seismic shooting during the year ended March 31, 2010. We anticipate that the seismic shooting, interpretation and subsequent resource potential evaluation report by Chapman Petroleum Engineering Ltd. will be complete during the summer of 2010.
Our strategy and plans for the 2011 fiscal year are contingent on our ability to renegotiate the terms of our 5.0% Convertible Senior Notes due 2012, as discussed in detail in the Liquidity and Capital Resources section of Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations beginning on page 47 of this report, and our having adequate funds to undertake such activities.
Oil and Natural Gas Reserves
Please see Item 2. Properties of this report for a complete description of our oil and gas reserves and related information.
Industry and Economic Factors
Our business is subject to many factors beyond our control. One such factor is the fluctuation of oil and gas prices. Historically, oil and gas markets have been cyclical and volatile. During fiscal year 2010 we experienced wide fluctuation in the world price for oil. We expect prices to continue to be difficult to predict.
While our revenues are a function of both production and prices, wide swings in commodity prices will likely continue to have a significant impact on our results of operations. We have not elected to engage in hedging transactions because we do not have the necessary infrastructure or the required flexibility in our rights to conduct export transactions.
Our operations entail significant complexities due to the depth and geological makeup of the structures we are entering. Advanced technologies requiring highly trained personnel are utilized in both exploration and development. Even when the technology is properly used we still may not know conclusively whether hydrocarbons will be present or the rate at which they may be produced when wells are completed. Despite our best efforts to limit our risks, exploration drilling is a high-risk activity that may not yield commercial production or reserves.
Marketing and Sales to Major Customers
There are a variety of factors which affect the market for oil and natural gas, including the extent of domestic production and imports, the availability, proximity and capacity of pipelines and other transportation facilities, demand, the marketing of competitive fuels and the effects of state and federal regulations on oil and natural gas production and sales.
In the exploration, development and production business, production is normally sold to relatively few customers. We are now exporting nearly all of our test production for sale in the world market. Currently, 95% of our production is being sold to one client, Titan Oil (formerly Euro-Asian Oil AG). Revenue from oil sold to Titan Oil made up 98% of our total revenue. The loss of Titan Oil may have a material adverse effect on our operations in the short-term. Based on current demand for crude oil and the fact that alternate purchasers are readily available, we believe the loss of Titan Oil would not materially adversely affect our operations long-term.
Distribution Method
Our crude oil exports are transported via the Aktau sea port to world markets. Pursuant to our agreement with Titan Oil, delivery is FCA (Incoterms 2000) at the railway station in Mangishlak. The oil is shipped via railway cars provided by Titan Oil. The volume and sales price are determined on a monthly basis, with all payments being covered by an irrevocable standby letter of credit opened through a first-class international bank. Sales prices is based on the average quoted Brent crude oil price from Platt's Crude Oil Marketwire for the three days following the bill of lading date less a discount for transportation expenses, freight charges and other expenses. The quality of crude oil supplied must meet minimum quality specifications.
Competition
Competition in Kazakhstan and Central Asia includes other junior hydrocarbons exploration companies, mid-size producers and major exploration and production companies. We compete for additional exploration and production properties with these companies who in many cases have greater financial resources and larger technical staffs than we do.
We face significant competition for capital from other exploration and production companies and industry sectors. At times, other industry sectors may be more in favor with investors, limiting our ability to obtain necessary capital.
We believe we have a competitive advantage in Kazakhstan in that our management team is comprised of Kazakh nationals who have developed trusted relationships with many of the departments and ministries within the government of Kazakhstan.
Government Regulation
Our operations are subject to various levels of government controls and regulations in both the United States and Kazakhstan. We focus on compliance with all legal requirements in the conduct of our operations and employ business practices that we consider to be prudent under the circumstances in which we operate. It is not possible for us to separately calculate the costs of compliance with environmental and other governmental regulations as such costs are an integral part of our operations.
In Kazakhstan, legislation affecting the oil and gas industry is under constant review for amendment or expansion. Pursuant to such legislation, various governmental departments and agencies have issued extensive rules and regulations which affect the oil and gas industry, some of which carry substantial penalties for failure to comply. These laws and regulations can have a significant impact that can adversely affect our profitability by increasing the cost of doing business and by imposition of new taxes, tax rates and tax schemes. Inasmuch as new legislation affecting the industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations.
Environmental Matters
Oil and gas operations are subject to numerous laws and regulations controlling the generation, use, storage and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may:
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require the acquisition of a permit or other authorization before construction or drilling commences;
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restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production, and natural gas processing activities;
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suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, areas inhabited by threatened or endangered species and other protected areas;
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require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells;
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restrict injection of liquids into subsurface strata that may contaminate groundwater; and
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impose substantial liabilities for pollution resulting from our operations.
Environmental permits that the operators of properties are required to possess may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines, and even criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on our operations as well as the oil and gas industry in general, and thus we are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations.
We are not currently involved in any administrative, judicial or legal proceedings arising under environmental protection laws and regulations, which would have a material adverse effect on our respective financial positions or results of operations. We do not maintain insurance against the costs of clean-up operations and we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area.
Employees
We have approximately 390 full-time employees. None of our employees are covered by collective bargaining agreements. From time to time we utilize the services of independent consultants and contractors to perform various professional services. Field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testing are generally provided by independent contractors.
Reports to Security Holders
We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other items with the Securities and Exchange Commission (“SEC”). We provide free access to all of these SEC filings, as soon as reasonably practicable after filing, on our Internet web site located at www.bmbmunai.com. In addition, the public may read and copy any documents we file with the SEC at the SEC's Public Reference Room at 100 F Street N.E., 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 maintains its Internet site www.sec.gov, which contains reports, proxy and information statements and other information regarding issuers like BMB Munai.
Item 1A.
Item 1A. Risk Factors
We do not currently have the funds, or the ability to raise the funds, necessary to repurchase the Notes.
In 2007 we raised $60,000,000 in connection with the issuance of 5.0% Convertible Senior Notes due 2012 (the “Notes”). The terms of the original indenture governing the Notes (the “Original Indenture”) provided for three put dates that allowed the holders of the Notes to redeem the Notes prior to their 2012 maturity date. The first two put dates passed unexercised. The third put date is July 13, 2010. In connection with ongoing negotiations with the holders of the Notes to restructure the Notes, we entered into a Supplemental Indenture which grants the Noteholders a fourth put date that commences on June 13, 2010 and expires on September 13, 2010. In exchange for the granting of the fourth put date, the Noteholders separately agreed they will not exercise their put option for the third put date and they will not exercise their put option for the fourth put date prior to September 1, 2010; provided, however, the Noteholders may exercise such put options at any time upon the occurrence of any of the following: (i) an default occurs under the Indenture, excluding certain defaults that occurred prior to June 7, 2010, (ii) failure by us or Emir to timely pay any Indebtedness (as defined in the Indenture) or any guarantee of any Indebtedness that exceeds U.S. $1,000,000, or any Indebtedness becomes due and payable prior to its stated maturity other than at our or Emir’s option, or (iii) the Noteholders holding a majority in outstanding principal amount of the Notes provide notice to us that negotiations with respect to restructuring the Notes have terminated. Therefore, it is possible the Noteholders could exercise a put option with respect to the Notes prior to September 1, 2010 if any of the foregoing events occur.
Prior to entering into the Supplemental Indenture, we were in default under certain covenants contained in Article 9 of the Indenture requiring us to maintain a minimum net debt to equity ratio and to comply with certain notice, delivery and other provisions. The Noteholders separately agreed to waive these defaults until the earlier of: (i) September 1, 2010 or (ii) the fourth put date, with the understanding that such waiver will not constitute a waiver of any default under the Indenture that remains ongoing as of September 1, 2010 or that occurs after June 8, 2010. We currently believe we will not be able to remedy the default of the net debt to equity ratio covenant by September 1, 2010 and, therefore, we anticipate we will be in default under the Indenture at September 1, 2010 unless a future waiver is obtained from the Noteholders. There is no assurance the Noteholders will provide any future waiver or any further extension of their redemption put rights under the Indenture. Moreover, there is no assurance that we will be successful in renegotiating the terms and conditions of the Notes.
If we are unable to extend the waiver of default beyond September 1, 2010, or at any time we are in default under the Indenture, the Noteholders have the right to accelerate the Notes and require us to make immediate payment of all unpaid interest and principal. As of March 31, 2010, the outstanding balance of unpaid principal and interest under the Notes was $62,819,786. If the Noteholders were to accelerate the Notes, we would have insufficient funds to pay the Notes. We do not anticipate obtaining sufficient funds to retire the Notes in the near future. If we default on the Notes, the Noteholders could seek any legal remedies available to them to obtain repayment of the Notes, including forcing us into bankruptcy, which would likely also result in Emir Oil being forced into bankruptcy. Pursuant to Kazakhstan law and the terms of our exploration license, the government of the Republic of Kazakhstan has the right to cancel our licenses to the ADE Block, the Southeast Block and the Northwest Block in the event Emir Oil becomes insolvent or enters into bankruptcy proceedings. If such were to happen, we would be left with limited assets, no operations and ability to generate revenue or otherwise repay the Notes.
Our ability to obtain additional financing or use our operating cash flow to fund operations may be adversely affected by our level of indebtedness.
Our level of indebtedness could have negative consequences, which include, but are not limited to, the following:
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Our ability to obtain additional financing to fund capital expenditures, acquisitions, working capital, repay debts or for other purposes may be impaired;
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Our ability to use operating cash flow in other areas of our business may be limited because we must dedicate a substantial portion of these funds to repay debt obligations;
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We may be unable to compete with others who may not be as highly leveraged; and
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Our debt may limit our flexibility to adjust to changing market conditions, changes in our industry and economic downturns.
The financial crisis and economic conditions have and may continue to have a material adverse impact on our business and financial condition that we cannot predict.
The global economic conditions have deteriorated during the past two fiscal years and continue to remain unstable. The global financial markets have experienced a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital, bankruptcy, failure, collapse or sale of financial institutions and an unprecedented level of intervention from the U.S. federal government and other governments. In particular, the cost of raising money in the debt and equity capital markets has increased substantially while the availability of funds from those markets generally has diminished significantly. As a result of the concerns about the stability of financial markets generally and the solvency of existing debtors specifically, the cost of obtaining money from credit markets has increased. Many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity and have either reduced or, in many cases, ceased to provide any new funding.
Although we cannot predict the impacts on us of the deteriorating economic conditions, they could materially adversely affect our business in the following ways:
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our ability to obtain credit and access the capital markets may continue to be restricted adversely affecting our financial position and our ability to continuing exploration and drilling activities on our territory;
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the values we are able to realize in transactions we engage in to raise capital may be reduced, thus making these transactions more difficult to consummate and more dilutive to our shareholders; and
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the demand for oil and natural gas may decline due to weak international economic conditions.
We may not be able to replace our reserves or generate cash flows if we are unable to raise capital.
In order to increase our asset base, we will need to make substantial capital expenditures for the exploration, development, production and acquisition of oil and gas reserves and the construction of additional facilities. These maintenance capital expenditures may include capital expenditures associated with drilling and completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved properties or our proved reserves to the extent such additions maintain our asset base. These expenditures could increase as a result of:
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changes in our reserves;
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changes in oil and gas prices;
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changes in labor and drilling costs;
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our ability to acquire, locate and produce reserves;
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changes in license acquisition costs; and
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government regulations relating to safety and the environment.
Our cash flow from operations and access to capital is subject to a number of variables, including:
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our proved reserves;
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the success or our drilling efforts;
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the level of oil and gas we are able to produce from existing wells;
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the prices at which our oil and gas is sold; and
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our ability to acquire, locate and produce new reserves.
Historically, we have financed these expenditures primarily with cash raised through the sale of our equity and debt securities and revenue generated by operations. If our revenues or borrowing base decreases, which is expected, as a result of lower oil and natural gas prices, operating difficulties or declines in reserves, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. Additional debt or equity financing or cash generated by operations may not be available to meet these requirements. Due to the current low prices for oil and gas and the restrictions in the capital markets largely caused by the global financial crisis, we anticipate that we will not have enough capital available during the upcoming fiscal year to make substantial capital expenditures.
Oil and gas prices are characteristically volatile, and if they remain low for a prolonged period, our revenues, profitability and cash flows will decline. A sustained period of low oil and natural gas prices would adversely affect our business operations, our asset values and our financial condition and ability to meet our financial commitments.
The global financial crises and economic downturn has resulted in a significant decline in oil and natural gas prices from their highs of 2008. The prices we receive for our oil and natural gas production heavily influence our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production, and the levels of our production, depend on a variety of additional factors that are beyond our control, such as:
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the domestic and foreign supply of and demand for oil and natural gas;
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the price and level of foreign imports of oil and natural gas;
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the level of consumer product demand;
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weather conditions;
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overall domestic and global economic conditions;
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political and economic conditions in oil and gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, acts of terrorism or sabotage;
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actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
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the impact of the U.S. dollar exchange rates on oil and gas prices;
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technological advances affecting energy consumption;
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domestic and foreign governmental regulations and taxation;
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the impact of energy conservation efforts;
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the costs, proximity and capacity of gas pipelines and other transportation facilities; and
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the price and availability of alternative fuels.
Our revenue, profitability and cash flow depend upon the prices and demand for oil and gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, price declines or sustained low prices for oil and gas will:
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negatively impact the value of our reserves because declines in oil and natural gas prices would reduce the amount of oil and natural gas we can produce economically;
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reduce the amount of cash flow available for capital expenditures; and
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limit our ability to borrow money or raise additional capital.
Future price declines may result in a write-down of our asset carrying values.
Lower oil and natural gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of oil and gas that we can produce economically. This may result in downward adjustments to our estimated proved reserves. Substantial decreases in oil and gas prices could render our future planned exploration and development projects uneconomical. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our properties for impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and may, therefore, require a write-down of such carrying value. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit agreements.
Unless we replace our oil and natural gas reserves, our reserves and future production will decline, which would adversely affect our cash flows and income.
Unless we conduct successful development, exploration and exploitation activities, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. If we are unable to develop, exploit, find or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of sustaining commercial production.
Drilling for and producing oil and gas is a costly and high-risk activity with many uncertainties that could adversely affect our financial condition or results of operations.
Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. The cost of drilling, completing and operating a well is often uncertain, and cost factors, as well as the market price of oil and natural gas, can adversely affect the economics of a well. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:
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high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;
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adverse weather conditions;
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equipment failures or accidents;
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pipe or cement failures or casing collapses;
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compliance with environmental and other governmental requirements;
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environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
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lost or damaged oilfield drilling and service tools;
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loss of drilling fluid circulation;
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unexpected operational events and drilling conditions;
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unusual or unexpected or difficult geological formations;
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natural disasters, such as fires;
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blowouts, surface cratering and explosions; and
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uncontrollable flows of oil, gas or well fluids.
A productive well may become uneconomical in the event deleterious substances are encountered which impair or prevent the production of oil or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other deleterious substances. We may drill wells that are unproductive or, although productive, do not produce oil or gas in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Furthermore, the successful completion of a well does not ensure a profitable return on the investment.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the size 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. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report.
In order to prepare estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. 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 most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues from our proved reserves referred to in this report is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If future values decline or costs increase, it could have a negative impact on our ability to finance operations; individual properties could cease being commercially viable; affecting our decision to continue operations on producing properties or to attempt to develop properties. All of these factors would have a negative impact on earnings and net income, and most likely the trading price of our securities.
We will be unable to produce up to 76% of our proved reserves if we are not able to obtain a commercial production contract or extend our current exploration contract, which would likely require us to terminate our operations.
Under our exploration contract on our properties we have the rights to produce oil and gas only until January 2013, yet 76% of our proved reserves are scheduled to be produced after January 2013. We have the exclusive right to negotiate a commercial production contract as per the terms of our exploration contract. The Ministry of Oil and Gas of the Republic of Kazakhstan (the “MOG”) does not make public its determinations on the granting of commercial production rights. Based on discussions with the MOG, we have learned that the primary factors used by the MOG in determining whether to grant commercial production rights are whether the contract holder has fulfilled its minimum work program commitments, proof of commercial discovery and submission of an approved development plan by a third-party petroleum institute in Kazakhstan to exploit the established commercial reserves. Typically, if commercial production rights are not granted it is because the contract holder has failed to make a commercial discovery within their contract territory and had decided to abandon the contract territory or the contract holder has insufficient funds to complete its minimum work program requirement and was unable to complete the necessary work to substantiate the presence of commercially producible reserves to the MOG. Our efforts are focused toward meeting our minimum work program requirements and making and substantiating commercial discoveries in as many of the identified structures as possible to support our application for commercial production rights. If we are not granted commercial production rights prior to the expiration of our exploration contract, we may lose our right to produce the reserves on our current properties. If we are unable to produce those reserves, we will be unable to realize revenues and earnings and to fund operations and we would most likely be unable to continue as a going concern.
Prospective properties that we decide to drill may not yield oil or natural gas in commercially viable quantities or quantities sufficient to meet our targeted rate of return.
The structures we have located on our territory are typically at a depth of 3,100 to 3,800 meters and some structures may be deeper in the Northwest Block. The rock is generally carbonates of limestone and dolomite, which can inhibit oil flow and well drainage and thereby results in higher risk drilling, reduced well drainage areas, lower production rates and higher than expected well decline rates. These factors in turn adversely affect the valuation of our reserve base. We attempt to address these challenges through careful selection of drilling sites and we are now in process of developing models of our oil fields that will guide our well locations, drilling activities and technology deployment.
A “prospect” is a property which, based on available seismic and geological data, we believe shows potential oil or natural gas. Our prospects are in various stages of evaluation and interpretation. There is no way to accurately predict in advance of incurring drilling and completion costs whether a prospect will be economically viable. Even with seismic data and other technologies and the study of producing fields in the same area, we cannot know conclusively prior to drilling whether oil or natural gas will be present or, if present, will be present in commercial quantities. The analysis that we perform using data from other wells, more fully explored prospects and producing fields may not be useful in predicting the characteristics and potential reserves associated with our drilling prospects. When we drill unsuccessful wells, our drilling success rate declines and we may not achieve our targeted rate of return.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:
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environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;
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abnormally pressured formations;
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mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
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fires and explosions;
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personal injuries and death; and
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natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses. In instances when we believe that the cost of available insurance is excessive relative to the risks presented we may elect not to obtain insurance. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.
We are subject to complex laws that can affect the cost, manner or feasibility of doing business.
Exploration, development, production and sale of oil and natural gas are subject to extensive governmental regulation. We may be required to make large expenditures to comply with these regulations. Matters subject to regulation include:
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discharge permits for drilling operations;
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reports concerning operations;
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the spacing of wells;
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unitization and pooling of properties; and
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taxation.
Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws may also result in the suspension or termination of our licenses or operations and could subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations. We believe that there is political and legal risk doing business in Kazakhstan, as the country has existed for less than two decades and is still in process of developing stable and predictable laws required to underpin a free market economy and foster private enterprise.
We may incur substantial liabilities to comply with environmental laws and regulations.
Our oil and natural gas operations are subject to governmental laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of investigatory or remedial obligations or even injunctive relief. Changes in environmental laws and regulations occur frequently. Any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as on the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or whether our operations were standard in the industry at the time they were performed.
Because of our lack of asset and geographic diversification, adverse developments in our operating area would adversely affect our results of operations.
Substantially all of our assets are currently located in southwestern Kazakhstan. As a result, our business is disproportionately exposed to adverse developments affecting this region. These potential adverse developments could result from, among other things, changes in governmental regulation, capacity constraints with respect to storage facilities, transportation systems and pipelines, curtailment of production, natural disasters or adverse weather conditions in or affecting these regions. Due to our lack of diversification in asset type and location, an adverse development in our business or the area in which we operate would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.
The unavailability or high price of transportation systems could adversely affect our ability to deliver our oil on terms that would allow us to operate profitably, or at all.
Because of the location of our properties, the crude oil we produce must be transported by truck or by rail. In the future it will likely also be transported by pipelines. These railways and pipelines are operated by state-owned entities or other third-parties, and there can be no assurance that these transportation systems will always be functioning and available, or that the transportation costs will not become cost prohibitive. In addition, any increase in the cost of transportation or reduction in its availability to us could have a material adverse effect on our results of operations. There is no assurance that we will be able to procure sufficient transportation capacity on economical terms, if at all.
We depend on one customer for sales of crude oil. A reduction by this customer in the volumes of oil it purchases could result in a substantial decline in our revenues and net income.
During the year ended March 31, 2010, we sold approximately 95% of our crude oil production to Titan Oil. Revenue from oil sold to Titan Oil made up 98% of our revenue during the year ended March 31, 2010. The loss of Titan Oil may have a material adverse effect on our operations in the short-term. Based on current demand for crude oil and the fact that alternate purchasers are readily available, we believe the loss of Titan Oil would not materially adversely affect our operations long-term.
If you purchase shares of our stock, your investment will be subject to the same risks inherent in international operations, including, but not limited to, adverse governmental actions, political risks, and expropriation of assets, loss of revenues and the risk of civil unrest or war.
While we have significant experience working in Kazakhstan, and feel we have good relationships with government agencies at many levels, we remain subject to all the risks inherent in international operations, including adverse governmental actions, uncertain legal and political systems, and expropriation of assets, loss of revenues and the risk of civil unrest or war. Our primary oil and gas properties are located in Kazakhstan, which until 1990 was part of the Soviet Union. Kazakhstan retains many of the laws and customs of the former Soviet Union, but has and is continuing to develop its own legal, regulatory and financial systems. As the political and regulatory environment changes, we may face uncertainty about the interpretation of our agreements; in the event of dispute, we may have limited recourse within the legal and political system.
Prior to the expiration of our exploration rights, we plan to make application for commercial production rights to the extent we have established commercially producible reserves on our properties. We have the exclusive right to negotiate a commercial production contract for the ADE Block, the Southeast Block and the Northwest Block and the government is required to conduct these negotiations under the “Law of Petroleum” in Kazakhstan. The terms of the commercial production contract will establish the Mineral Extraction Tax, Rent Export Tax and other payments due to the government in connection with commercial production. At the time the commercial production contract is issued, we will be required to begin repaying the government its historical investment costs of exploration and development of the ADE Block, the Southeast Block and the Northwest Block, as well as a Commercial Discovery Bonus. The historical investment costs associated with the ADE Block, the Southeast Block and the Northwest Block are approximately $6 million, $5.3 million and $5.4 million respectively. We currently do not know the amount of any required Commercial Discovery Bonus, but anticipate it could be as high as $3.2 million. If satisfactory terms for commercial production rights cannot be negotiated, it could have a material adverse effect on our financial position.
Risks Relating to Our Common Stock
Our stock price may be volatile.
The following factors could affect our stock price:
•
our operating performance and future prospects;
•
quarterly variations in the rate of growth of our financial indicators, such as net income per share, net income and revenues;
•
actual or anticipated variations in our reserve estimates and quarterly operating results;
•
fluctuations in oil and natural gas prices;
•
speculation in the press or investment community;
•
sales of our common stock by large block stockholders;
•
short-selling of our common stock by investors;
•
the outcome of current litigation;
•
issuance of a significant number of shares to raise additional capital to fund our operations;
•
changes in applicable laws or regulations;
•
changes in market valuations of similar companies;
•
additions or departures of key management personnel;
•
actions by our creditors; and
•
international economic, legal and regulatory factors unrelated to our performance.
It is unlikely that we will be able to pay dividends on our common stock.
We have never paid dividends on our common stock. We cannot predict with certainty that our operations will result in sufficient revenues to enable us to operate profitably and with sufficient positive cash flow so as to enable us to pay dividends to the holders of common stock.
The percentage ownership evidenced by the common stock is subject to dilution.
We are authorized to issue up to 500,000,000 shares of common stock and are not prohibited from issuing additional shares of such common stock. Moreover, to the extent that we issue any additional common stock, a holder of the common stock is not necessarily entitled to purchase any part of such issuance of stock. The holders of the common stock do not have statutory “preemptive rights” and therefore are not entitled to maintain a proportionate share of ownership by buying additional shares of any new issuance of common stock before others are given the opportunity to purchase the same. Accordingly, you must be willing to assume the risk that your percentage ownership, as a holder of the common stock, is subject to change as a result of the sale of any additional common stock, or other equity interests in the Company.
Our common stock is an unsecured equity interest.
Just like any equity interest, our common stock will not be secured by any of our assets. Therefore, in the event of our liquidation, the holders of our common stock will receive distributions only after all of our secured and unsecured creditors have been paid in full. There can be no assurance that we will have sufficient assets after paying its secured and unsecured creditors to make any distribution to the holders of our common stock.
Provisions in Nevada law could delay or prevent a change in control, even if that change would be beneficial to our stockholders.
Certain provisions of Nevada law may delay, discourage, prevent or render more difficult an attempt to obtain control of us, whether through a tender offer, business combination, proxy contest or otherwise. The provisions of Nevada law are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
Our properties comprise an 850 contiguous square kilometer area in the Mangistau Region of southwestern Kazakhstan.
Exploratory and Developmental Acreage
The following table summarizes our gross and net developed and undeveloped mineral acreage by block at March 31, 2010.
Development of Oil and Gas Properties in Kazakhstan
Under the statutory scheme in the Republic of Kazakhstan prospective oil fields are developed in two stages. The first stage is an exploration and appraisal stage during which a private contractor is given a license to explore for oil and gas on a territory for a set term of years. During this stage the primary focus is on the search for a commercial discovery, i.e., a discovery of a sufficient quantity of oil and gas to make it commercially feasible to pursue execution of, or transition to, a commercial production contract with the government. Under the terms of an exploration contract the contract holder has the right to sell all oil and natural gas produced during the term of the exploration contract.
We currently own a 100% interest in both a license to use subsurface mineral resources and a hydrocarbon exploration contract issued by the ROK in 1999 and 2000, respectively (collectively referred to herein as the “license” or the “exploration contract”). When initially granted, the exploration and development stage of our exploration contract had a five year term, with provision for two extensions for a period of two years each. On June 24, 2008 the MEMR (the predecessor to the MOG) agreed to extend the exploration stage of our exploration contract until January 2013.
Initially, the exploration contract granted us the right to engage in exploration and development activities in an area of approximately 200 square kilometers referred to herein as the “ADE Block.” The ADE Block is comprised of three fields, the Aksaz, Dolinnoe and Emir fields. During our 2006 fiscal year our exploration contract was expanded to include an additional 260 square kilometers of land adjacent to the ADE Block, which we refer to herein as the “Southeast Block”, which includes the Kariman oil and gas field and the Borly and Yessen structures. In October 2008 the MEMR granted a further extension of the territory covered under our exploration contract to include an additional 390 square kilometer area, bringing our total contract area to 850 square kilometers (approximately 210,000 acres). The additional territory is located to the north and west of our current exploration territory, extending the exploration territory toward the Caspian Sea and is referred to herein as the “Northwest Block.” The Southeast Block and the Northwest Block are governed by the terms of our exploration contract.
In order to be assured that adequate exploration activities are undertaken during exploration stage, the MOG establishes an annual mandatory minimum work program to be accomplished in each year of the exploration contract. Under the minimum work program the contractor is required to invest a minimum dollar amount in exploration activities within the contract territory, which may include geophysical studies, construction of field infrastructure or drilling activities. During the exploration stage, the contractor is also required to drill sufficient wells in each field to establish the existence of commercially producible reserves in any field for which it seeks a commercial production license. Failure to complete the minimum work program requirements for any particular field during the term of the exploration contract could preclude the contractor from receiving a longer-term production contract for such field, regardless the success of the contractor in proving commercial reserves during the partial fulfillment of the minimum work program.
The contract we hold follows the above format. The contract sets the minimum dollar amount we must expend during each year of our work program. Through July 2009, our work program year ended on July 9 each year. As a result of certain changes to our exploration license, our work program year end has now changed to January 9 of each year through January 9, 2013. Therefore our work program year does not coincide with our fiscal year. As a result of these timing differences, the amounts reflected in the table below as “Actually Made” may differ from amounts disclosed elsewhere in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations or the consolidated financial statements included in this report, which present figures based on our fiscal year rather than our work program year.
Amount of Expenditure
Mandated by Contract
Actually Made
Prior to July 2007
$40,200,000
$104,750,000
July 2007 to July 2008
$8,480,000
$115,040,000
July 2008 to July 2009
$1,845,000
$44,900,000
July 2009 to January 2010
$8,565,000
$15,970,000
January 2010 to January 2011
$21,520,000
$8,727,000*
January 2011 to January 2012
$27,300,000
$ -
January 2012 to January 2013
$14,880,000
$ -
Total
$122,790,000
$289,387,000
* Investment as of March 31, 2010
Under the rules of the MOG there is a process whereby expenditures above the minimum requirements in one period may be carried over to meet minimum obligations in future periods. As the above chart shows we have significantly exceeded the minimum expenditure requirement in each period of the contract and have more than doubled the total minimum capital expenditure requirement during the exploration stage.
In addition to mandatory minimum capital expenditures in each year, exploration contracts typically require the contract holder to drill a certain number of wells in each structure for which it plans to seek commercial production rights.
In Kazakhstan, typically, one exploratory well and two appraisal wells are sufficient to support a claim of commercially producible reserves in a particular field, although in some cases, commercial reserves have been demonstrated with fewer wells. The total number of wells the MOG requires during exploration stage is generally determined by the number of fields or structures identified by the seismic studies done on a territory. 3D seismic studies completed on the ADE Block and the Southeast Block, have identified six potential fields or structures. We plan to perform 3D seismic studies on the Northwest Block to identify potential structures in that Block.
To date, we have drilled a total of 24 wells as set forth in more detail below:
Structures
Aksaz
Dolinnoe
Emir
Kariman
Borly
Yessen
Northwest Block
Exploratory Wells
3(1)
Appraisal Wells
*
Existing Wells
Wells in Progress
Remaining Wells to
Drill by 2013
*
(1)
Addendum No. 6 to our exploratory contract requires the drilling of three exploratory wells. Depending upon the results of 3D seismic studies of the Northwest Block we may need to drill additional exploratory and appraisal wells in the Northwest Block.
*
Unknown at this time.
Pursuant to the terms of the extensions of our exploration contract, we will be required to drill not less than nine new wells by January 9, 2013. If we discover structures in the Northwest Block, we will need to drill additional wells to determine and establish the existence of commercially producible reserves within the various structures in our license territory.
The bottom half of the above chart shows current progress on drilling of exploratory and appraisal wells.
To date we have been conservative in our approach to exploration. It has been our practice to drill our first few wells serially. Our first well was the Dolinnoe-2 well drilled in 2004. This was followed by the Dolinnoe-3 well, and then the Aksaz-4 and Kariman-1 wells. While we have verified the presence of oil and gas in all our wells thus far, not all our wells produce oil at commercial levels. We have expended substantial time and money to study our wells.
The purpose of the exploration stage is to study the geology and geophysical characteristics of each field and individual well, with a view to qualifying for a longer-term production contract. Once drilling of a well is completed, our emphasis focuses on an extended period of testing a well’s production characteristics and capacities to determine the best method for producing oil from that well and to gain insight into the further development of the entire field. During exploration, oil production is subject to wide fluctuations caused by varying pressures commonly experienced in new wells and by significant periods of well closure to accommodate mandatory testing. Maximizing oil production only becomes the central focus during the post-exploration phase when exploiting the commercial discovery commences under a production contract.
Under our exploration contract, we have the exclusive right to apply for and negotiate a commercial production contract. The government is required to negotiate the terms of these rights in good faith in accordance with the Law of Petroleum of Kazakhstan. Based on discussions with the MOG, the primary factors used by the MOG in determining whether to grant commercial production rights are whether the contract holder has fulfilled the minimum work program commitments, proved the existence of a commercial discovery and submitted and received approval of a development plan prepared by a third-party petroleum institute in Kazakhstan for the exploitation of the established commercial reserves. All our efforts during exploration stage have and will continue to focus on meeting these criteria.
The terms of our commercial production rights will be negotiated at the time we apply to transition to commercial production. We became subject to a new tax code on January 1, 2009. Under the new tax code, the royalty we previously paid was replaced by a mineral extraction tax. The rate of the mineral extraction tax depends on annual production output. The new code currently provides for a 5% mineral extraction tax rate (6% starting from 2013 and 7% starting from 2014) on production sold to the export market, and a 2.5% tax rate (3% in 2013 and 3.5% starting from 2014) on production sold to the domestic market. The mineral extraction tax expense is reported as part of oil and gas operating expense. In January 2009 we also became subject for a rent export tax, which is calculated based on the export sales price. This tax ranges from as low as 0% if the price is less than $40 per barrel to as high as 32% if the price per barrel exceeds $190.
Drilling Operations
Over the past financial year we have concentrated our operational efforts on stabilizing and maintaining production through continuous work with the existing wellstock. No new wells were drilled due to the difficult financial situation we have experienced over the past fiscal year when most of our financial resources were diverted to alleviating working capital problem.
We have also continued our preparatory work for eventual transition of a portion of existing assets to commercial production. We have retained the services of a third-party independent consulting company to prepare a geological model of the Kariman, Aksaz and Dolinnoe fields. This work is ongoing and is expected to be completed prior to the end of fiscal year 2011. This step, in conjunction with cooperation with the Kazakhstani design institute, should prepare us for eventual transition to commercial production.
During fiscal year 2010 we signed a contract for the shooting of 3D seismic and interpretation over a portion of the Northwest Block with GeoSeismic LLP, a company affiliated with Mr. Toleush Tolmakov, General Director of Emir Oil LLP, and a Company shareholder. The total value of the contract is $3.8 million with GeoSeismic LLP agreeing to accept payment in BMB common stock in lieu of cash payment at the rate of $2.00 per share, at our option. We expect 3D seismic interpretation results to be completed in the first quarter of fiscal year 2011. Once the results are interpreted, we will furnish them to our independent petroleum engineers, Chapman Petroleum Engineering Ltd., and retain their services for assessing resource potential of the Northwest Block. We expect this project to be fully completed by the end of our second fiscal quarter 2011.
We are continuing the process of researching various available options for using different design pumps at the Dolinnoe and Aksaz fields, both of which have higher natural gas content making it impossible to utilize the type of electronic submersible pumps currently used on the Kariman field.
We expect to continue working with the existing wellstock for the remainder of the 2011 fiscal year with the intent of increasing and sustaining production rates from existing wells.
Well Performance and Production
The following table sets forth our gross and net working interests in exploratory and development wells drilled during the three years ended March 31, 2010:
As of the fiscal year ended March 31, 2010, each of the 24 wells identified above was in test production, testing or under or awaiting workover. Each of the above listed wells is Company operated.
According to the laws of the Republic of Kazakhstan, we are required to test every prospective target on our properties separately; this includes the completion of well surveys on different modes with various choke sizes on each horizon.
In the course of well testing, when the transfer from target to target occurs, the well must be shut in; oil production ceases for the period of mobilization/demobilization of the workover rig, pull out of the hole, run in the hole, perforation, packer installation time, etc. This has the effect of artificially diminishing production rates averaged over a set period of time.
During our fourth fiscal quarter 2010, our average daily crude oil production was 2,940 barrels per day. Following is a brief description of the production rates of each of our 24 wells during the fiscal year ended March 31, 2010.
Well
Single Interval Production
Rate for the year ended
March 31,
Average Daily Production
Rate for the quarter ended
March 31,
Diameter
Choke
Size
Aksaz
- 57 bpd
- 38 bpd
mm
Aksaz
0 - 13 bpd(1)
bpd(1)
mm
Aksaz-3
0 - 377 bpd(1)
- 296 bpd(1)
mm
Aksaz
- 57 bpd
bpd
mm
Aksaz
- 63 bpd
bpd
mm
Dolinnoe
0 - 157 bpd
bpd
mm
Dolinnoe
0 - 189 bpd(2)
- 69 bpd(2)
mm
Dolinnoe
0 - 176 bpd
0 - 176 bpd
mm
Dolinnoe
bpd
bpd
mm
Dolinnoe
0 - 94 bpd(2)
0 - 19 bpd(2)
mm
Dolinnoe
0 - 371 bpd(2)
0 - 371 bpd(2)
mm
Emir
bpd
bpd(3)
mm
Emir - 2
0 - 38 bpd
bpd(3)
mm
Emir
0 - 94 bpd
bpd(3)
mm
Kariman
0 - 63 bpd(4)
0 - 63 bpd(4)
mm
Kariman
0 - 660 bpd(4)
0 - 660 bpd(4)
mm
Kariman
0 - 50 bpd(5)
0 - 38 bpd(5)
mm
Kariman
- 403 bpd(4)
- 315 bpd(4)
mm
Kariman
0 - 132 bpd(5)
0 - 75 bpd(5)
mm
Kariman
0 - 409 bpd(4)
0 - 302 bpd(4)
mm
Kariman
0 - 415 bpd(4)
0 - 415 bpd(4)
mm
Kariman
0 - 434 bpd(4)
- 384 bpd(4)
mm
Kariman
0 - 321 bpd(4)
0 - 189 bpd(4)
mm
Kariman-11
0 - 346 bpd(4)
- 239 bpd(4)
mm
(1)
We have performed acid treatment at these wells.
(2)
We have performed workover at these wells and moved to new horizons.
(3)
Emir wells are on temporary abandonment as the Company is planning for submission of an application for pilot development project for this field.
(4)
We have installed centrifugal submersible pumps at these wells. After a brief period of testing and fine tuning, production from this well stabilized. Stabilized production rates are included in the table above.
(5)
We have installed beam pumpcentrifugal submersible pumps at these wells. After a brief period of testing and fine tuning, production from this well stabilized. Stabilized production rates are included in the table above.
We plan to continue working with the existing wellstock in the next fiscal year and are reviewing various alternatives for increasing production. We will have researched and, funds permitting, plan to employ directional/horizontal drilling on the existing wells on the Kariman field. We plan to complete directional drilling on one or two existing Kariman fields during fiscal year 2011.
Proved Reserves Disclosures
Recent SEC Rule-Making Activity. In December 2008, the SEC announced that it had approved revisions to modernize the oil and gas reserve reporting disclosures. The new disclosure requirements include provisions that:
·
Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.
·
Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices.
·
Permit companies to disclose their probable and possible reserves on a voluntary basis. In the past, proved reserves were the only reserves allowed in the disclosures. We have chosen not to make disclosure under these categories.
·
Requires companies to provide additional disclosure regarding the aging of proved undeveloped reserves.
·
Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
·
Replace the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test.
·
Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures regarding internal controls over reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.
We adopted the rules effective March 31, 2010.
The new rule does not allow for prior-year reserve information to be restated, so all information related to periods prior to 2010 is presented consistent with prior SEC rules for the estimation of proved reserves.
Oil and Natural Gas Reserves
The following table sets forth our estimated net proved oil and natural gas reserves and the standardized measure of discounted future net cash flows related to such reserves as of March 31, 2010. The standardized measure of discounted future net cash flows is not intended to represent the current market value of our estimated oil and natural gas reserves. The oil and natural gas reserve data included in, or incorporated by reference in this document, are only estimates and may prove to be inaccurate.
(1)
Under our exploration contract we have the right to sell the oil and natural gas we produce while we undertake exploration stage activities within our licensed territory. As discussed in more detail in “Risk Factors” and “Properties” we have the right to engage in exploration stage activities until January 9, 2013. To retain our rights to produce and sell oil and natural gas after that date, we must apply for and be granted commercial production rights by no later than January 2013 or obtain a further extension of our exploration contract. If we are not granted commercial production rights or another extension by that time, we would expect to lose our rights to the licensed territory and would expect to be unable to produce reserves after January 2013.
(2)
Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.
(3)
Proved undeveloped reserves are proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
(4)
Includes natural gas liquids.
(5)
The standardized measure of discounted future net cash flows represents the present value of future net cash flow net of all taxes.
As of March 31, 2010 our estimated proved reserves had a pre-tax PV10 value of approximately $422.1 million and a standardized measure of discounted future cash flows of approximately $268.3 million.
The following table summarizes our total net proved reserves, pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows as of March 31, 2010.
Oil
(Bbl)
Pre-Tax PV10 Value
Standardized Measure
of Discounted Future
Net Cash Flows
Oil and condensate (MBbls)(4)
22,726
$ 422,121
$ 268,322
Natural gas (MMcf)
-
-
-
Total BOE (MBbls)
22,726
$ 422,121
$ 268,322
Proved Undeveloped Reserves
Our reserve estimates as of March 31, 2010 and 2009 include 2.6 million BOE as proved undeveloped reserves, respectively. There were no changes in proved undeveloped reserves during the year ended March 31, 2010. We did not incur capital expenditures for conversion of proved undeveloped reserves to proved developed reserves as of year ended March 31, 2010.
Internal Controls Over Reserves Estimates.
We engaged Chapman Petroleum Engineering, Ltd. (“Chapman”), to estimate our net proved reserves, projected future production and the standardized measure of discounted future net cash flows as of March 31, 2010. Chapman’s estimates are based upon a review of production histories and other geologic, economic, ownership and engineering data provided by us. Chapman has independently evaluated our reserves for the past several years. In estimating the reserve quantities that are economically recoverable, Chapman used oil and natural gas prices in effect as of March 31, 2010 without giving effect to hedging activities. In accordance with requirements of the Securities and Exchange Commission (the “SEC”) regulations, no price or cost escalation or reduction was considered by Chapman. Our reserves estimates are reviewed and approved by our Chief Executive Officer and our President. Our Chief Financial Officer reviews the reserves estimates to assure compliance with SEC reporting requirements. A letter which identifies the professional qualifications of the individual who was responsible for overseeing the preparation of our reserve estimates as of March 31, 2010 has been filed as Exhibit 99.1 to this report.
Cost Information
Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves
The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped or proved developed non-producing to proved developed, as well as the estimated costs per year involved in such development.
Year
Total BOE
Estimated
Development Costs
3,074,000
1,170,000
1,175,000
600,000
6,868,000
1,720,000
-
-
-
-
Our average daily production for the month of March 31, 2010, was 2,685 Boe per day.
The reserve data set forth herein represents estimates only. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the present value thereof are based upon certain assumptions, including current prices, production levels and costs that may vary from what is actually incurred or realized.
No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the SEC.
In accordance with SEC regulations, the Chapman Report used oil and natural gas average prices in effect during the year ended March 31, 2010. The prices used in calculating the standardized measure of discounted future net cash flows attributable to proved reserves do not necessarily reflect market prices for oil and natural gas production subsequent to March 31, 2010. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will actually be realized for such production or that existing contracts will be honored or judicially enforced.
Capitalized Costs
Capitalized costs and accumulated depletion, depreciation and amortization relating to our oil and natural gas producing activities, all of which are conducted in the Republic of Kazakhstan, are summarized below:
As of March 31, 2010
As of March 31, 2009
Developed oil and natural gas properties
$ 246,979,803
$ 221,374,856
Unevaluated oil and natural gas properties
25,924,087
40,580,015
Accumulated depletion, depreciation and amortization
(34,302,048)
(23,226,458)
Net capitalized cost
$ 238,601,842
$ 238,728,413
Exploration, Development and Acquisition Capital Expenditures
The following table sets forth certain information regarding the total costs incurred associated with exploration, development and acquisition activities.
For the year ended
March 31, 2010
For the year ended
March 31, 2009
For the year ended
March 31, 2008
Acquisition costs:
Unproved properties
$ -
$ -
$ -
Proved properties
-
-
-
Exploration costs
-
2,275,021
3,024,386
Development costs
10,949,019
63,727,311
83,950,096
Subtotal
10,949,019
66,002,332
86,974,482
Asset retirement costs
-
86,438
1,300,576
Total costs incurred
$ 10,949,019
$ 66,088,770
$ 88,275,058
Oil and Natural Gas Volumes, Prices and Operating Expense
The following table sets forth certain information regarding production volumes, average sales price and average operating expense associated with our sale of oil and natural gas for the periods indicated.
For the Year Ended
March 31, 2010
For the Year Ended
March 31, 2009
For the Year Ended
March 31, 2008
Production:
Oil and condensate (Bbls)
1,016,221
1,080,895
907,823
Natural gas liquids (Bbls)
-
-
-
Natural gas (Mcf)
-
-
-
Barrels of oil equivalent (BOE)
1,016,221
1,080,895
907,823
Sales(1)(3):
Oil and condensate (Bbls)
1,036,070
1,073,754
896,256
Natural gas liquids (Bbls)
-
-
-
Natural gas (Mcf)
-
-
-
Barrels of oil equivalent (BOE)
1,036,070
1,073,754
896,256
Average Sales Price(1):
Oil and condensate ($ per Bbl)
$ 55.28
$ 64.84
$ 67.16
Natural gas liquids ($ per Bbl)
$ -
$ -
$ -
Natural gas ($ per Mcf)
$ -
$ -
$ -
Barrels of Oil equivalent ($ per BOE)
$ 55.28
$ 64.84
$ 67.16
Average oil and natural gas operating expenses
including production and ad valorem taxes
($ per BOE)(2)(3)
$ 8.27
$ 7.01
$ 6.15
(1)
During the years ended March 31, 2010, 2009 and 2008, the Company has not engaged in any hedging activities, including derivatives.
(2)
Includes transportation cost, production cost and ad valorem taxes (except for rent export tax).
(3)
We use sales volume rather than production volume for calculation of per unit cost because not all volume produced is sold during the period. The related production costs were expensed only for the units sold, not produced based on a matching principle of accounting. Therefore, oil and gas operating expense per BOE was calculated by dividing oil and gas operating expenses for the year by the volume of oil sold during the year.
Office Facilities
Our principal executive and corporate offices are located in an office building located at 202 Dostyk Avenue, in Almaty, Kazakhstan. We lease this space and believe it is sufficient to meet our needs for the foreseeable future.
We also maintain an administrative office in Salt Lake City, Utah. The address is 324 South 400 West, Suite 225, Salt Lake City, Utah 84101, USA.
Item 3.
Item 3. Legal Proceedings
See Note 23 “Commitments and Contingencies” to the notes to the consolidated financial statements under Part II - Item 8 of this report.
Item 4.
Item 4. [Removed and Reserved]
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is traded on the NYSE Amex under the symbol “KAZ.” Our shares are also traded on XETRA , the Deutsche Borse electronic trading system under SE code DL-,001 DMW US09656A1051.
The following table presents the high and low sales price for the fiscal year ended March 31, 2010 and March 31, 2009, as reported by the NYSE Amex.
Fiscal year ended March 31, 2010
High
Low
Fourth quarter
$ 1.45
$ 0.94
Third quarter
$ 1.31
$ 0.88
Second quarter
$ 1.14
$ 0.78
First quarter
$ 1.79
$ 0.56
Fiscal year ended March 31, 2009
Fourth quarter
$ 1.90
$ 0.36
Third quarter
$ 3.54
$ 0.80
Second quarter
$ 6.00
$ 2.96
First quarter
$ 7.88
$ 5.26
Holders
As of June 2, 2010, we had approximately 366 shareholders of record holding 51,865,015 shares of our common stock. The number of record holders was determined from the records of our stock transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies.
Dividends
We have not declared or paid a cash dividend on our common stock during the past two fiscal years. Our ability to pay dividends is subject to limitations imposed by Nevada law. Under Nevada law, dividends may be paid to the extent that a corporation’s assets exceed it liabilities and it is able to pay its debts as they become due in the usual course of business. At the present time, our board of directors does not anticipate paying any dividends in the foreseeable future; rather, the board of directors intends to retain earnings that could be distributed, if any, to fund operations and develop our business.
Performance Graph
We are a smaller reporting company, as defined in Rule 12b-2 promulgated under the Securities Exchange Act of 1934, and accordingly are not required to provide this information.
Recent Sales of Unregistered Securities
On January 1, 2010, we granted, subject to certain vesting requirements, restricted stock awards to certain executive officers, directors, employees and outside consultants of the Company pursuant to the BMB Munai, Inc. 2004 Stock Incentive Plan (the “2004 Plan.”) The total number of shares granted was 1,500,000. The restricted stock grants were valued at $1.14 per share, the closing price of our common stock on the date of grant.
Grants were made to 15 people, 13 of whom are non-U.S. persons. The restricted stock grants were made without registration pursuant to Regulation S of the Securities Act Rules and/or Section 4(2) under the Securities Act of 1933. Among the parties receiving restricted stock grants were the following:
Name
Position with Company
Restricted Stock Granted
Boris Cherdabayev
Chairman of the Board of Directors
280,000
Gamal Kulumbetov
Chief Executive Officer
80,000
Askar Tashtitov
President
230,000
Toleush Tolmakov
Director Emir Oil LLP
215,000
Evgeny Ler
Chief Financial Officer
110,000
Anuarbek Baimoldin
Chief Operating Officer
20,000
All of the restricted stock grants were awarded on the same terms and subject to the same vesting requirements. The restricted stock grants will vest to the grantees at such time as either of the following events occurs (the “Vesting Events”): i) the one-year anniversary of the grant date; or ii) the occurrence of an Extraordinary Event. An “Extraordinary Event” is defined in the restricted stock agreement as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to fifty percent (50%) or more of the outstanding stock of the Employer or any of its subsidiaries, or the sale of forty percent (40%) or more of the assets of the Employer or any of its subsidiaries, or one (1) person or more than one person acting as a group, acquires fifty percent (50%) or more of the total voting power of the stock of the Employer. In the event of an Extraordinary Event, the grants shall be deemed full vested one day prior to the effective date of the Extraordinary Event. The Board of Directors shall determine conclusively whether or not an Extraordinary Event has occurred and the grantees have agreed to be bound by the determination of the Board of Directors.
Issuer Purchases of Equity Securities
We did not repurchase any equity securities of the Company during the quarter ended March 31, 2010.
Item 6.
Item 6. Selected Financial Data
The selected consolidated financial information set forth below is derived from our consolidated balance sheets and statements of operations as of and for the years ended March 31, 2010, 2009, 2008, 2007 and 2006. The data set forth below should be read in conjunction with Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and the consolidated financial statements and related notes thereto included in this report.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
This discussion summarizes the significant factors affecting our consolidated operating results, financial condition, liquidity and capital resources during the fiscal years ended March 31, 2010, 2009 and 2008. This discussion should be read in conjunction with the consolidated financial statements and footnotes to the consolidated financial statements included in this report.
Results of Operations
This section includes a discussion of our results of operations for the fiscal years ended March 31, 2010, 2009 and 2008. The following table sets forth selected operating data for the fiscal years indicated:
For the year ended
March 31, 2010
For the year ended
March 31, 2009
For the year ended
March 31, 2008
Revenues:
Oil and gas sales
$ 57,274,526
$ 69,616,875
$ 60,196,626
Expenses:
Rent export tax
10,032,857
467,359
-
Export duty
-
6,783,278
-
Oil and gas operating(1)
8,568,453
7,530,653
5,515,403
Depletion
11,075,590
10,403,328
9,419,655
Interest expense
4,604,446
1,138,874
-
Depreciation and amortization
613,953
324,028
239,155
Accretion
448,351
449,025
254,572
General and administrative
14,042,577
22,262,248
14,747,754
Net Production Data:
Oil (Bbls)
1,016,221
1,080,895
907,823
Natural gas (Mcf)
-
-
-
Barrels of Oil equivalent (BOE)
1,016,221
1,080,895
907,823
Net Sales Data(3):
Oil (per Bbl)
1,036,070
1,073,754
896,256
Natural gas (Mcf)
-
-
-
Barrels of Oil equivalent
1,036,070
1,073,754
896,256
Average Sales Price:
Oil (per Bbl)
55.28
64.84
67.16
Natural gas (per Mcf)
-
-
-
Equivalent price (per BOE)
55.28
64.84
67.16
Expenses ($ per BOE) (3):
Oil and gas operating(1)
8.27
7.01
6.15
Depreciation, depletion and
amortization(2)
10.69
9.69
10.51
(1)
Includes transportation cost, production cost and ad valorem taxes (excluding rent export tax).
(2)
Represents depletion of oil and gas properties only.
(3)
We use sales volume rather than production volume for calculation of per unit cost because not all volume produced is sold during the period. The related production costs are expensed only for the units sold, not produced, based on a matching principle of accounting. Oil and gas operating expense per BOE is calculated by dividing oil and gas operating expenses for the year by the volume of oil sold during the year.
Year ended March 31, 2010 compared to the year ended March 31, 2009.
Revenue and Production
The following table summarizes production volumes, average sales prices and operating revenue for our oil and natural gas operations for the year ended March 31, 2010 and the year ended March 31, 2009.
(1)
At times, we may produce more barrels than we sell in a given period. The average sales price is calculated based on the average sales price per barrel sold, not per barrel produced.
(2)
We did not engage in hedging transactions, including derivatives, during the year ended March 31, 2010 or the year ended March 31, 2009.
Revenue. We generate revenue under our exploration contract from the sale of oil recovered during test production. During the year ended March 31, 2010 our oil production decreased 6% compared to the year ended March 31, 2009.
During the year ended March 31, 2010 we realized revenue from oil sales of $57,274,526 compared to $69,616,875 during the year ended March 31, 2009. The largest contributing factor to the 18% decrease in revenue was a 15% decrease in the price per barrel we received for oil sales during the year ended March 31, 2010 compared to the fiscal year ended March 31, 2009. During the fiscal years ended March 31, 2010 and 2009 we exported 95% and 81% of our oil, respectively, to the world markets and realized the world market price for those sales. Revenue from oil sold to the world markets made up 98% and 94% of total revenue, respectively, during the years ended March 31, 2010 and 2009. Revenue also decreased as a result of a 6% decrease in production during the 2010 fiscal year.
As discussed above, our revenue is sensitive to changes in prices received for our oil. Political instability, the economy, changes in legislation and taxation, reductions in the amount of oil we are allowed to export to the world markets, weather and other factors outside our control may also have an impact on both supply and demand and on revenue.
Costs and Operating Expenses
The following table presents details of our expenses for the years ended March 31, 2010 and 2009:
For the year ended
March 31, 2010
For the year ended
March 31, 2009
Expenses:
Rent export tax
$ 10,032,857
$ 467,359
Export duty
-
6,783,278
Oil and gas operating(1)
8,568,453
7,530,653
General and administrative
14,042,577
22,262,248
Depletion
11,075,590
10,403,328
Interest expense
4,604,446
1,138,874
Accretion expenses
448,351
449,025
Amortization and depreciation
613,953
324,028
Consulting expenses
-
8,662,500
Total
$ 49,386,227
$ 58,021,293
Expenses ($ per BOE):
Oil and gas operating(1)
$ 8.27
$ 7.01
Depletion (2)
$ 10.69
$ 9.69
(1)
Includes transportation cost, production cost and ad valorem taxes (excluding rent export tax).
(2)
Represents depletion of oil and gas properties only.
Rent export tax. Rent export tax is calculated based on the export sales price and ranges from as low as 0% if the export sales price is less than $40 per barrel to as high as 32% if the price per barrel exceeds $190. During the year ended March 31, 2010 rent export tax paid to the government amounted to $10,032,857 compared to $467,359 for the year ended March 31, 2009. This increase was due to increased realized price for oil during the fiscal year ended 2010, and the fact that we were not subject to rent export tax during the first three fiscal quarters of the year ended March 31, 2009.
Export Duty. On April 18, 2008 the government of the Republic of Kazakhstan introduced an export duty on several products (including crude oil). We became subject to the duty in June 2008. In December 2008 the government of the Republic of Kazakhstan repealed the export duty effective January 26, 2009. We are now subject to a new tax code that went into effect on January 1, 2009, as discussed in more detail below. As a result of the export duty being repealed, we paid no export duty during the year ended March 31, 2010 compared to $6,783,278 during year ended March 31, 2009. Export duty was not recorded as part of oil and gas operating expense and was not included in oil and gas operating expense per BOE calculation.
Oil and Gas Operating Expenses. During the year ended March 31, 2010 we incurred $8,568,453 in oil and gas operating expenses compared to $7,530,653 during the year ended March 31, 2009. This increase is primarily the result of increased production and transportation expense.
Oil and gas operating expenses for the year ended March 31, 2010 and 2009 consist of the following expenses:
The 102% increase in production expense during the year ended March 31, 2010 was due to the purchase of light crude oil for blending purposes from a third party in the amount of $877,603.
Transportation expenses decreased $1,039,080 or 23% as a result of the decreased volume of oil we produced and transported, as well as the consequences of a cost-cutting policy implemented by the Company. We anticipate transportation expenses will continue to fluctuate in proportion to production volume.
The mineral extraction tax replaced the royalty we were paying under prior tax code. The rate of this tax depends on annual production output. The new code currently provides for a 5% mineral extraction tax rate (6% starting from 2013 and 7% starting from 2014) on production sold to the export market, and a 2.5% tax rate (3% in 2013 and 3.5% starting from 2014) on production sold to the domestic market. The mineral extraction tax expense is reported as part of oil and gas operating expense.
During the year ended March 31, 2010 mineral extraction tax paid to the government amounted to $3,509,611, which presents increase of 581% compared to $515,032 paid during the fiscal year ended March 31, 2009. The increase was due to the fact that we were not subject to the mineral extraction tax during the first three fiscal quarters of the year ended March 31, 2009.
We calculate oil and gas operating expense per BOE based on the volume of oil actually sold rather than production volume because not all volume produced during the period is sold during the period. The related production costs are expensed only for the units sold, not produced. Expense per BOE is a function of total expense divided by the number of barrels of oil we sell. During the year ended March 31, 2009 we sold 1,073,754 barrels of oil, during the year ended March 31, 2010 we sold 1,036,070 barrels of oil. The 4% decrease in sales volume coupled with the 14% increase in oil and gas operating expenses resulted in a $1.26, or 18%, increase in oil and gas operating expense per BOE.
General and Administrative Expenses. General and administrative expenses during the year ended March 31, 2010 were $14,042,577 compared to $22,262,248 during the year ended March 31, 2009. This represents a 37% decrease. This decrease in general and administrative expenses was the result of:
•
a 57% decrease in non-cash compensation expense as the price for our stock declined and the non-cash compensation expense we incurred decreased significantly;
•
a 53% decrease in professional services resulting from decreased legal fees incurred in our ongoing litigation as we changed the legal firm providing those services and decreased audit consulting expenses;
•
a 27% decrease in business trip and related transportation expenses;
•
an 11% decrease in payroll expenses;
•
a 68% decrease in environmental payments for flaring of unused natural gas resulting from production, such decrease in the amount of environmental payments totaling $208,087 and $652,026 during the year ended March 31, 2010 and 2009, respectively; and
•
a 27% decrease in rent expenses.
During the year ended March 31, 2010 we recognized non-cash compensation expense in the amount of $3,171,633 resulting from restricted stock grants previously made to executive officers, directors, employees and outside consultants of the Company. By comparison, during the year ended March 31, 2009 we recognized non-cash compensation expense in the amount of $7,450,211 for restricted stock grants previously made to employees and outside consultants.
Depletion. Depletion expense for the year ended March 31, 2010 increased by $672,262 compared to the year ended March 31, 2009. The increase in depletion expense was attributable to the fact that we continued workover on existing wells and developed additional infrastructure during fiscal year 2010.
Amortization and Depreciation. Amortization and depreciation expense for the year ended March 31, 2010 increased 89% compared to the year ended March 31, 2009. The increase resulted from purchases of fixed assets during the 2010 fiscal year.
Interest Expense. During the year ended March 31, 2010 we incurred interest expense of $4,604,446 compared to interest expense of $1,138,874 during the same period of 2009. We have not drilled any new wells since the end of the 2009 calendar year; therefore, all interest expense incurred in connection with our convertible notes since that time has been expensed.
Income from Operations. During the year ended March 31, 2010 we realized income from operations of $7,888,299 compared to income from operations of $11,595,582 during the year ended March 31, 2009. This decrease in income from operations during fiscal 2010 is primarily the result of the 18% decrease in revenue recognized during fiscal 2010, which was only partially offset by the 15% decrease in our total costs and operating expenses.
Other Expense. During the fiscal year ended March 31, 2010 we incurred total other expense of $446,888 compared to total other income of $4,533,704 during the fiscal year ended March 31, 2009. This change from income to expense is largely attributable to:
•
a $353,401 foreign exchange loss resulting from the strengthening of the Kazakh Tenge against the U.S. Dollar during the year ended March 31, 2010 compared with the foreign exchange gain in the amount $2,592,341 realized in year ended March 31, 2009;
•
the receipt of a one-time payment for disgorgement of funds received of $1,650,293 during the 2009 fiscal year, earned in violation of the short-swing profit rules of Section 16(b) of the Securities Exchange Act of 1934;
•
a $116,087 decrease in interest income; and
•
a $268,470 increase in other expense during the fiscal year ended March 31, 2010 compared the fiscal year ended March 31, 2009.
Net Income. For the foregoing reasons, during the year ended March 31, 2010 we realized net income of $8,993,473 or $0.18 per share compared to net income of $17,157,558 or $0.37 basic and diluted income per share for the fiscal year ended March 31, 2009.
Year ended March 31, 2009 compared to the year ended March 31, 2008.
Revenue and Production
The following table summarizes production volumes, average sales prices and operating revenue for our oil and natural gas operations for the year ended March 31, 2009 and the year ended March 31, 2008.
(1)
At times, we may produce more barrels than we sell in a given period. The average sales price is calculated based on the average sales price per barrel sold, not per barrel produced.
(2)
We did not engage in hedging transactions, including derivatives, during the year ended March 31, 2009 or the year ended March 31, 2008.
Revenue. We generate revenue under our exploration contract from the sale of oil recovered during test production. During the year ended March 31, 2009 our oil production increased 19% compared to the year ended March 31, 2008. This increase in production is primarily attributable to the fact that we had twenty four wells in testing or test production during all or some portion of the year ended March 31, 2009 compared to sixteen wells during all or some portion of the year ended March 31, 2008.
During the year ended March 31, 2009 we realized revenue from oil sales of $69,616,875 compared to $60,196,626 during the year ended March 31, 2008. The largest contributing factor to the 16% increase in revenue was a 20% increase in sales volume, which was partially offset by 3% decrease in the price per barrel we received for oil sales during the year ended March 31, 2009 compared to the fiscal year ended March 31, 2008. During the fiscal years ended March 31, 2009 and 2008 we exported 81% and 91% of our oil, respectively, to the world markets and realized the world market price for those sales. Revenue from oil sold to the world markets made up 94% and 96% of total revenue, respectively, during the years ended March 31, 2009 and 2008. We anticipate production to remain fairly constant and currently anticipate revenues will be flat in upcoming quarters.
As discussed above, our revenue is sensitive to changes in prices received for our oil. Most of our production is currently being sold at the prevailing world market price, which fluctuates in response to many factors that are outside our control. Imbalances in the supply and demand for oil can have a dramatic effect on the price we receive for our production. Similarly, if we were denied an export quota, our export quota were reduced or we were otherwise forced to sell all, or a significant portion, of our production to the domestic market in Kazakhstan. Historically the price per barrel of oil we receive for oil sold in Kazakhstan has been significantly lower than the price we realize for oil we export. For a period during the year, as a result of the material decline in world oil prices and the export duty enacted by the government, we realized greater returns by selling to the local market. As a result of the material drop in world oil prices our revenue decreased significantly during the year. Political instability, the economy, changes in legislation and taxation, weather and other factors outside our control may also have an impact on both supply and demand.
Historically, sales to the domestic market in Kazakhstan would have resulted in a significant reduction in revenue and income from operations because the domestic market price has been markedly lower than world oil prices. As the gap between world oil prices and domestic prices shrank and as a result of the export duty, we found it more financially attractive to sell our oil to the domestic market for the period from November 2008 through January 2009.
Costs and Operating Expenses
The following table presents details of our expenses for the years ended March 31, 2009 and 2008:
For the year ended
March 31, 2009
For the year ended
March 31, 2008
Expenses:
Rent export tax
$ 467,359
$ -
Export duty
6,783,278
-
Oil and gas operating(1)
7,530,653
5,515,403
General and administrative
22,262,248
14,747,754
Depletion
10,403,328
9,419,655
Interest expense
1,138,874
-
Accretion expenses
449,025
254,572
Amortization and depreciation
324,028
239,155
Consulting expenses
8,662,500
-
Total
$ 58,021,293
$ 30,176,539
Expenses ($ per BOE):
Oil and gas operating(1)
7.01
6.15
Depletion (2)
9.69
10.51
(1)
Includes transportation cost, production cost and ad valorem taxes (excluding rent export tax).
(2)
Represents depletion of oil and gas properties only.
Rent Export Tax. This tax is calculated based on the export sales price and ranges from as low as 0% if the export sales price is less than $40 per barrel to as high as 32% if the price per barrel exceeds $190. During the year ended March 31, 2009 rent export tax paid to the government amounted to $467,369. We were not subject to the rent export tax during the year ended March 31, 2008 or during the first three fiscal quarters of the year ended March 31, 2009.
Export Duty. On April 18, 2008 the government of the Republic of Kazakhstan introduced an export duty on several products (including crude oil). We became subject to the duty in June 2008. The export duty for year ended March 31, 2009 amounted to $6,783,278. The formula for determining the amount of the crude oil export duty was based on a sliding scale that was tied to the world market price for oil. The amount of the export duty changed with fluctuations in world oil prices. Fluctuations in the export duty, however, lagged behind fluctuations in world oil prices by about 90 days. In December 2008 the government of the Republic of Kazakhstan repealed the export duty effective January 26, 2009. We are now subject to the new tax code that went into effect on January 1, 2009, as discussed in more detail below.
Oil and Gas Operating Expenses. During the year ended March 31, 2009 we incurred $7,530,653 in oil and gas operating expenses compared to $5,515,403 during the year ended March 31, 2008. This increase is primarily the result of several factors, including increased production volumes, royalty payments, salary and transportation expenses and increased repair costs.
During the year ended March 31, 2009 royalty paid to the government increased by $186,688 or 12% compared to the year ended March 31, 2008. While royalty expenses increased, as a percentage of total revenue, royalty expense remained nearly unchanged. Royalties were replaced by a mineral extraction tax when we became subject to the new tax code effective January 1, 2009.
Mineral Extraction Tax. This tax replaced the royalty we were paying previously. The rate of this tax depends upon annual production output. At current production rates, we are subject to a 5% mineral extraction tax rate on production sold to the export market and a 2.5% tax rate on production sold to domestic market. The mineral extraction tax expense is reported as part of oil and gas operating expense. During the year ended March 31, 2009 mineral extraction tax paid to the government amounted to $515,032. As noted above, we were not subject to the mineral extraction tax during the year ended March 31, 2008 or during the first three fiscal quarters of year ended March 31, 2009.
During the year ended March 31, 2009 payroll and related payments to production personnel increased $158,816 or 24% compared to the year ended March 31, 2008. As production volume increased we retained additional production personnel during the year ended March 31, 2009.
Transportation expenses increased $1,154,715 or 35% as a result of the increased volume of oil we produced and transported. We anticipate transportation expenses will continue to fluctuate in proportion to production volume.
We calculate oil and gas operating expense per BOE based on the volume of oil actually sold rather than production volume because not all volume produced during the period is sold during the period. The related production costs are expensed only for the units sold, not produced.
While oil and gas operating expenses increased 37% during the year ended March 31, 2009 compared to the year ended March 31, 2008, expense per BOE increased only 14% from $6.15 per BOE during the year ended March 31, 2008 to $7.01 during the year ended March 31, 2009. During the year ended March 31, 2008 we sold 896,256 barrels of oil, during the year ended March 31, 2009 we sold 1,073,754 barrels of oil. As expense per BOE is a function of total expense divided by the number of barrels of oil sold, the 20% increase in sales volume more than offset the 45% increase in expenses resulting in the 14% increase in oil and gas operating expense per BOE.
General and Administrative Expenses. General and administrative expenses during the year ended March 31, 2009 were $22,262,248 compared to $14,747,754 during the year ended March 31, 2008. This represents a 51% increase in general and administrative expenses. This increase in general and administrative expenses was the result of several factors such as increases in non-cash compensation expense, payroll and related costs, rent expense and professional services. This increase was partially offset by a $332,516, or 34%, reduction in environmental payments for flaring of unused natural gas.
During the year ended March 31, 2009 we recognized non-cash compensation expense of $7,450,211 resulting from restricted stock grants made previously to employees. By comparison, during the year ended March 31, 2008 we recognized non-cash compensation expense in the amount of $2,303,078 for restricted stock grants issued to employees and outside consultants.
The increase in general and administrative expense during the 2009 year was also attributable to:
•
a 35% increase in rent expense from renting special equipment, apartments and additional vehicles;
•
a 32% increase in payroll and related costs as we hired additional administrative personnel to fulfill business needs, increased employee pay rates for existing employees;
•
a 30% increase in professional services resulting from legal fees incurred in our ongoing litigation.
Depletion. Depletion expense for the year ended March 31, 2009 increased by $983,673 compared to the year ended March 31, 2008. The major reason for this increase in depletion expense was a 20% increase in sales volume in fiscal 2009 compared to fiscal 2008. The increase in depletion expense was also attributable to the fact that we drilled additional wells, continued workover on existing wells and developed additional infrastructure during fiscal year 2009.
Depreciation and Amortization. Depreciation and amortization expense for the year ended March 31, 2009 increased 35% compared to the year ended March 31, 2008. The increase resulted from purchases of fixed assets during the year.
Consulting Expense. In November 2007 we retained a consultant to assist us in negotiating an extension of the exploration period of our contract and with potential acquisitions. On June 24, 2008, we were granted an extension of our existing exploration contract from July 2009 to January 2013. Compensation expense for consulting services was recorded in the amount of $11,727,500, which included $1,000,000 paid upon the execution of consulting agreement and non-cash share-based compensation in the amount of $10,727,500 as the success fee for the extension of time period for exploration. The share-based compensation represents 1,750,000 (500,000 shares for each additional year of the extension of exploration status) valued at $6.13 per share which was the closing market price of our common shares on June 24, 2008.
On September 16, 2008 this consulting agreement was revised and the parties agreed to decrease the number of shares issued for services provided by 500,000 shares. The non-cash compensation expenses for consulting services were reversed in the amount of $3,065,000 (500,000 shares valued at $6.13 per share which was the closing market price of our common shares on June 24, 2008) for the year ended March 31, 2009.
Income from Operations. During the year ended March 31, 2009 we realized income from operations of $11,595,582 compared to income from operations of $30,020,087 during the year ended March 31, 2008. This decrease in income from operations during fiscal 2009 is the result of the 92% increase in total expenses during fiscal 2009, which increase was only partially offset by a 16% increase in revenue.
Other Income. During the fiscal year ended March 31, 2009 we realized total other income of $4,533,704 compared to $1,186,895 during the fiscal year ended March 31, 2008. This 282% increase is largely attributable to a $2,592,341 foreign exchange gain resulting mainly from the revaluation of accounts payable denominated in Kazakhstani tenge and $1,650,293 we received from a shareholder of the Company as disgorgement of profits earned in violation of the short-swing profit rules of Section 16(b) of the Securities Exchange Act of 1934.
Net Income. For all of the foregoing reasons, during the year ended March 31, 2009 we realized net income of $17,157,558 or $0.37 basic and diluted income per share compared to a net income of $31,310,564 or $0.70 basic and diluted income per share for the year ended March 31, 2008.
Liquidity and Capital Resources
For the period from inception on May 6, 2003 through March 31, 2010, we have incurred capital expenditures of $289,387,000 for exploration, development and acquisition activities. Funding for our activities has historically been provided by funds raised through the sale of our common stock and debt securities and revenue from oil sales. From inception to March 31, 2010 we raised approximately $94.6 million through the sale of our common stock. Additionally, during the quarter ended December 31, 2007 we completed the placement of $60 million in principal amount of 5.0% Convertible Senior Notes due in 2012. The net proceeds from the Note issuance of approximately $56.2 million were used to pursue our drilling program. For additional detail regarding the Notes, including adjustments to the initial conversion price and the registration right of the Noteholders, see Note 11 to the notes to the consolidated financial statements, March 31, 2010, included in this report..
Problems in the credit markets, the significant declines in worldwide oil prices and volatility and downward trends in the stock markets have caused many junior exploration and production companies, including us, to seek additional capital in order to stay in business. Some companies have been acquired by larger companies and others have failed.
At March 31, 2010, our current assets exceeded current liabilities by $7,554,834.
In 2007 we raised $60,000,000 in connection with the issuance of 5.0% Convertible Senior Notes due 2012 (the “Notes”). The terms of the original indenture governing the Notes (the “Original Indenture”) provided for three put dates that allowed the holders of the Notes to redeem the Notes prior to their 2012 maturity date. The first two put dates passed unexercised. The third put date is July 13, 2010. In connection with ongoing negotiations with the holders of the Notes to restructure the Notes, we entered into a Supplemental Indenture which grants the Noteholders a fourth put date that commences on June 13, 2010 and expires on September 13, 2010. In exchange for the granting of the fourth put date, the Noteholders separately agreed they will not exercise their put option for the third put date and they will not exercise their put option for the fourth put date prior to September 1, 2010; provided, however, the Noteholders may exercise such put options at any time upon the occurrence of any of the following: (i) a default occurs under the Indenture, excluding certain defaults that occurred prior to June 7, 2010, (ii) failure by us or Emir to timely pay any Indebtedness (as defined in the Indenture) or any guarantee of any Indebtedness that exceeds U.S. $1,000,000, or any Indebtedness becomes due and payable prior to its stated maturity other than at our or Emir’s option, or (iii) the Noteholders holding a majority in outstanding principal amount of the Notes provide notice to us that negotiations with respect to restructuring the Notes have terminated. Therefore, it is possible the Noteholders could exercise a put option with respect to the Notes prior to September 1, 2010 if any of the foregoing events occur.
Prior to entering into the Supplemental Indenture, we were in default under certain covenants contained in Article 9 of the Indenture requiring us to maintain a minimum net debt to equity ratio and to comply with certain notice, delivery and other provisions. The Noteholders separately agreed to waive these defaults until the earlier of: (i) September 1, 2010 or (ii) the fourth put date, with the understanding that such waiver will not constitute a waiver of any default under the Indenture that remains ongoing as of September 1, 2010 or that occurs after June 8, 2010. We currently believe we will not be able to remedy the default of the net debt to equity ratio covenant by September 1, 2010 and, therefore, we anticipate we will be in default under the Indenture at September 1, 2010 unless a future waiver is obtained from the Noteholders. There is no assurance the Noteholders will provide any future waiver or any further extension of their redemption put rights under the Indenture. Moreover, there is no assurance that we will be successful in renegotiating the terms and conditions of the Notes.
If we are unable to extend the waiver of default beyond September 1, 2010, or at any time we are in default under the Indenture, the Noteholders have the right to accelerate the Notes and require us to make immediate payment of all unpaid interest and principal. As of March 31, 2010, the outstanding balance of unpaid principal and interest under the Notes was $62,819,786. If the Noteholders were to accelerate the Notes, we would have insufficient funds to pay the Notes. We do not anticipate obtaining sufficient funds to retire the Notes in the near future. If we default on the Notes, the Noteholders could seek any legal remedies available to them to obtain repayment of the Notes, including forcing us into bankruptcy, which would likely also result in Emir Oil being forced into bankruptcy. Pursuant to Kazakhstan law and the terms of our exploration license, the government of the Republic of Kazakhstan has the right to cancel our licenses to the ADE Block, the Southeast Block and the Northwest Block in the event Emir Oil becomes insolvent or enters into bankruptcy. If such were to happen, we would be left with limited assets, no operations and ability to generate revenue or otherwise repay the Notes.
Cash Flows
During the year ended March 31, 2010 cash was primarily used to fund exploration expenditures. See below for additional discussion and analysis of cash flow.
Year ended
Year ended
Year ended
March 31,
March 31,
March 31,
Net cash provided by operating activities
$ 14,094,980
$ 53,383,138
$ 49,981,194
Net cash used in investing activities
$ (11,410,131)
$ (63,916,431)
$ (101,454,730)
Net cash (used in)/provided by financing activities
$ (3,000,000)
$ 50,001
$ 56,539,433
NET CHANGE IN CASH AND CASH EQUIVALENTS
$ (315,151)
$ (10,483,292)
$ 5,065,897
Our principal source of liquidity during the year ended March 31, 2010 was cash and cash equivalents. At March 31, 2009 cash and cash equivalents totaled approximately $6.8 million. At March 31, 2010 cash and cash equivalents had decreased to approximately $6.4 million. During the year ended March 31, 2010 we spent approximately $11.4 million to fund our exploration and development activities.
Certain operating cash flows are denominated in local currency and are translated into U.S. dollars at the exchange rate in effect at the time of the transaction. Because of the potential for civil unrest, war and asset expropriation, some or all of these matters, which impact operating cash flow, may affect our ability to meet our short-term cash needs.
Contractual Obligations and Contingencies
The following table lists our significant commitments at March 31, 2010, excluding current liabilities as listed on our consolidated balance sheet:
(1)
Under the terms of our subsurface exploration contract we are required to spend a total of $55 million in exploration activities on our properties, including a minimum of $12.8 million by January 2011, $27.3 million by January 2012 and $14.9 million by January 2013. The rules of the MOG provide a process whereby capital expenditures in excess of the minimum required expenditure in any period may be carried forward to meet the minimum obligations of future periods. Our capital expenditures in prior periods have exceeded our minimum required expenditures by more than $200 million.
(2)
In connection with our acquisition of the oil and gas contract covering the ADE Block, the Southeast Block and the Northwest Block, we are required to repay the ROK for historical costs incurred by it in undertaking geological and geophysical studies and infrastructure improvements. Our repayment obligation for the ADE Block is $5,994,200, for the Southeast Block is $5,350,680 and our repayment obligation for the Northwest Block is $5,372,076. The terms of repayment of these obligations, however, will not be determined until such time as we apply for and are granted commercial production rights by the ROK. Should we decide not to pursue commercial production rights, we can relinquish the ADE Block, the Southeast Block and/or the Northwest Block to the ROK in satisfaction of their associated obligations. The recent addenda to our exploration contract which granted us with the extension of exploration period and the rights to the Northwest Block also require us to:
·
make additional payments to the liquidation fund, stipulated by the Contract;
·
make a one-time payment in the amount of $200,000 to the Astana Fund by the end of 2010; and
·
make annual payments to social projects of the Mangistau Oblast in the amount of $100,000 from 2010 to 2012.
(3)
On July 16, 2007 the Company completed the private placement of $60 million in principal amount of 5.0% convertible senior notes due 2012 (“Notes”). The Notes carry a 5% coupon and have a yield to maturity of 6.25%. Interest will be paid at a rate of 5.0% per annum on the principal amount, payable semiannually. The Notes are callable and subject to early redemption in July 2010. Unless previously redeemed, converted or purchased and cancelled, the Notes will be redeemed by the Company at a price equal to 107.2% of the principal amount thereof on July 13, 2012. The Notes constitute direct, unsubordinated and unsecured, interest bearing obligations of the Company. For additional details regarding the terms of the Notes, see Note 11 - Convertible Notes Payable to the notes to our consolidated financial statements.
Off-Balance Sheet Financing Arrangements
As of March 31, 2010, we had no off-balance sheet financing arrangements.
Critical Accounting Policies
We have identified the accounting policies below as critical to our business operations and an understanding of our financial statements. The impact of these policies and associated risks are discussed throughout Management’s Discussion and Analysis where such policies affect our reported and expected financial results. A complete discussion of our accounting policies is included in Note 2 of the notes to consolidated financial statements.
Foreign Exchange Transactions
Transactions denominated in foreign currencies are reported at the rates of exchange prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to United States Dollars at the rates of exchange prevailing at the balance sheet dates. Any gains or losses arising from a change in exchange rates subsequent to the date of the transaction are included as an exchange gain or loss in the Consolidated Statements of Operations.
Share-Based Compensation
We account for options granted to non-employees at their fair value in accordance with FASC Topic 718. Under FASC Topic 718, share-based compensation is determined as the fair value of the equity instruments issued. The measurement date for these issuances is the earlier of the date at which a commitment for performance by the recipient to earn the equity instruments is reached or the date at which the recipient’s performance is complete. Stock options granted to the “selling agents” in private equity placement transactions have been offset against the proceeds as a cost of capital. Stock options and stock granted to other non-employees is recognized in the Consolidated Statements of Operations.
We have stock option plans as described in Note 15. Compensation expense for options and stock granted to employees is determined based on their fair value at the time of grant, the cost of which is recognized in the Consolidated Statements of Operations over the vesting periods of the respective options.
Share-based compensation incurred for the years ended March 31, 2010, 2009 and 2008 was $3,171,633, $7,450,211 and $2,303,078, respectively.
Full Cost Method of Accounting
We follow the full cost method of accounting for oil and gas properties. Under this method, all costs associated with acquisition, exploration and development of oil and gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. These costs do not include any costs related to production, general corporate overhead or similar activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of our proved reserves are sold (greater than 25 percent), in which case a gain or loss is recognized.
Capitalized costs less accumulated depletion and related deferred income taxes shall not exceed an amount (the full cost ceiling) equal to the sum of:
a)
the present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions;
b)
plus the cost of properties not being amortized;
c)
plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;
d)
less income tax effects related to differences between the book and tax basis of the properties.
Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change. If oil and gas prices decline, even if only for a short period of time, it is possible that impairment of our oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the cost ceiling, revisions to proved oil and gas reserves occur or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.
All geological and geophysical studies, with respect to the licensed territory, have been capitalized as part of the oil and gas properties.
Our oil and gas properties primarily include the value of the license and other capitalized costs.
All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers.
Ceiling test
Capitalized oil and gas properties are subject to a “ceiling test.” The full cost ceiling test is an impairment test prescribed by Rule 4-10 of SEC Regulation S-X. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves. This ceiling is compared to the net book value of the oil and gas properties reduced by any related deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, impairment or non-cash write down is required. Ceiling test impairment can cause a significant loss for a particular period; however, future depletion expense would be reduced.
Recent Accounting Pronouncements
For details of applicable new accounting standards, please, refer to Recent accounting pronouncements in Note 2 of our consolidated financial statements.
Effects of Inflation and Pricing
The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices have an impact on revenue, estimates of future reserves, borrowing base calculations of bank loans and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel.
Item 7A.
Item 7A. Qualitative and Quantitative Disclosures about Market Risk
Our primary market risks are fluctuations in commodity prices and foreign currency exchange rates. We do not currently use derivative commodity instruments or similar financial instruments to attempt to hedge commodity price risks associated with future crude oil production.
Commodity Price Risk
Our revenues, profitability and future growth depend substantially on prevailing prices for crude oil. Prices also affect the amount of cash flow available for capital expenditures and our ability to either borrow or raise additional capital. Price affects our ability to produce crude oil economically and to transport and market our production either through export to international markets or within Kazakhstan. Our fiscal year 2010 crude oil sales in the international export market were based on prevailing market prices at the time of sale less applicable discounts due to transportation.
Historically, crude oil prices have been subject to significant volatility in response to changes in supply, market uncertainty and a variety of other factors beyond our control. Crude oil prices are likely to continue to be volatile and this volatility makes it difficult to predict future oil price movements with any certainty. Any declines in oil prices would reduce our revenues, and could also reduce the amount of oil that we can produce economically. As a result, this could have a material adverse effect on our business, financial condition and results of operations.
During the fiscal year ended March 31, 2010, we sold 1,036,070 barrels of oil and condensate. We realized an average sales price per barrel of $55.281. For purposes of illustration, assuming the same sales volume but decreasing the average sales price we receive from oil sales by $5.00 and $10.00 respectively would change total revenue from oil sales as follows:
Average Price
Per Barrel
Barrels of Oil Sold
Approximate Revenue from Oil Sold
(in thousands)
Reduction
in Revenue
(in thousands)
Actual sales for the year ended March 31, 2010
$55.281
1,036,070
$57,275
Assuming a $5.00 per barrel reduction in average price per barrel
$50.281
1,036,070
$52,094
$ 5,181
Assuming a $10.00 per barrel reduction in average price per barrel
$45.281
1,036,070
$46,914
$10,361
Foreign Currency Risk
Our functional currency is the U.S. Dollar. Emir Oil, LLP, our Kazakhstani subsidiary, also uses the U.S. dollar as its functional currency. To the extent that business transactions in Kazakhstan are denominated in the Kazakh Tenge we are exposed to transaction gains and losses that could result from fluctuations in the U.S. Dollar-Kazakh Tenge exchange rate. We do not engage in hedging transactions to protect us from such risk.
Our foreign-denominated monetary assets and liabilities are revalued on a monthly basis with gains and losses on revaluation reflected in net income. A hypothetical 10% favorable or unfavorable change in foreign currency exchange rate at March 31, 2010 would have affected our net income by less than $1 million.
Item 8.
Item 8. Financial Statements and Supplementary Data
The consolidated financial statements and supplementary data required by this item are included at page herein.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
During the fiscal year ended March 31, 2010 there were no changes in and disagreements with our independent registered public accounting firm on accounting and financial disclosure.
Item 9A.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), as of March 31, 2010. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2010, our disclosure controls and procedures were effective in (1) recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act and (2) ensuring that information disclosed by us in such reports is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Management's Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the company’s principal executive officer and principal financial officer and effected by the company’s board of directors, management and other personnel, 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 and includes those policies and procedures that:
•
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•
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
•
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.
Our management assessed the effectiveness of the Company’s internal control over financial reporting as of March 31, 2010. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control - Integrated Framework. Based on this assessment, our management concluded that as of March 31, 2010, our internal control over financial reporting is effective based on those criteria.
Hansen, Barnett & Maxwell, P.C. the independent registered public accounting firm that audited the consolidated financial statements included in this Annual Report on Form 10-K, has also audited management’s assessment of our internal control over financial reporting and the effectiveness of our internal control over financial reporting as of March 31, 2010, as stated in their report which is included herein.
Changes in Internal Control over Financial Reporting
There were no changes in our internal controls over financial reporting during the quarter ended March 31, 2010 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
HANSEN, BARNETT & MAXWELL, P.C.
A Professional Corporation
CERTIFIED PUBLIC ACCOUNTANTS
Triad Center, Suite 750
Salt Lake City, UT 84180-1128
Phone: (801) 532-2200
Fax: (801) 532-7944
www.hbmcpas.com
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of BMB Munai, Inc.
We have audited BMB Munai, Inc. and subsidiary’s internal control over financial reporting as of March 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). BMB Munai 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 Management’s 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 of internal control over financial reporting 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, BMB Munai, Inc. and subsidiary maintained, in all material respects, effective internal control over financial reporting as of March 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets and the related statements of income, stockholders’ equity and comprehensive income, and cash flows of BMB Munai, Inc. and subsidiaries, and our report dated June 23, 2010 expressed an unqualified opinion.
/s/ Hansen, Barnett & Maxwell, P.C.
HANSEN, BARNETT & MAXWELL, P.C.
Salt Lake City, Utah
June 23,
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance
The following table sets forth as of June 2, 2010 our directors and executive officers, promoters and control persons, their ages, and all offices and positions held. Directors are elected for a period of one year and thereafter serve until their successor is duly elected by the stockholders and qualified. Officers and other employees serve at the will of the board of directors.
Name of Director or
Executive Officer
Age
Positions with
the Company
Director Since
Officer Since
Gamal Kulumbetov
Chief Executive Officer
August
Askar Tashtitov
President and Director
May
May
Evgeniy Ler
Chief Financial Officer
April
Anuarbek Baimoldin
Chief Operating Officer
April
Boris Cherdabayev
Chairman of the Board of Directors
November
Jason Kerr
Independent Director
May
Troy Nilson
Independent Director
December
Daymon Smith
Independent Director
September
Leonard Stillman
Independent Director
October
Valery Tolkachev
Independent Director
December
A brief description of the background and business experience of each of the above listed individuals follows.
Gamal Kulumbetov. Mr. Kulumbetov graduated from the Kazakh National Technical University, Department of Oil and Gas Geology located in Almaty, Kazakhstan in 1997 where he was awarded a Bachelors degree in Geology. Mr. Kulumbetov is now in the process of completing a Ph.D. from the same university. Since graduating in 1997 Mr. Kulumbetov has completed various oil and gas and geological trainings from Japan National Oil Corporation, MI Drilling Fluids LLC of Germany, Chevron Texaco of Houston, Petroleum Industry Training Center of Almaty, Kazakhstan, and Ernst & Young Company of Almaty, Kazakhstan. In 2000 Mr. Kulumbetov was employed by Halliburton as a Surface Data Logging Engineer. From 2001 through April 2005 Mr. Kulumbetov was employed by LLP TengizChevroil (“TCO”) as the Deputy Manager of the TCO Fields Development Project. From April 2005 to December 2005 Mr. Kulumbetov was employed at Big Sky Energy Corporation as Chief Geologist. Mr. Kulumbetov joined BMB Munai, Inc. as a Vice President of Operations in December of 2005 and has served as CEO since August 2007.
Askar Tashtitov. Mr. Tashtitov has been with the Company since 2004 and has served as President since 2006 and as a director since May 2008. Prior to joining the Company, from 2002 to 2004, Mr. Tashtitov was employed by PA Government Services, Inc. Mr. Tashtitov worked as a management consultant specializing in oil and gas projects. In May 2002, Mr. Tashtitov earned a Bachelor of Arts degree from Yale University majoring in Economics and History. Mr. Tashtitov passed the AICPA Uniform CPA Examination in August, 2006. Mr. Tashtitov is not, nor has he in the past five years been, a director or nominee of any other SEC registrant.
Evgeniy Ler. Mr. Ler has been with the Company since 2006. Prior to being appointed as CFO Mr. Ler served in other capacities for the Company including Finance Manager and Reporting Manager. Prior to joining the Company, from 2002 to 2006, Mr. Ler was employed by Deloitte & Touche where he held the position of Senior Auditor in Financial Services & Industries Group, Audit. In that position he led large engagements for banks, financial institutions and oil and gas companies. In 2003 Mr. Ler was awarded a Bachelors degree in Financial Management from the Kazakh-American University located in Almaty, Kazakhstan. In 2008 Mr. Ler passed the AICPA Uniform CPA Examination. Mr. Ler has also completed trainings in London on oil and gas financial reporting in accordance with IFRS and US GAAP and internal Deloitte trainings on audit, financial reporting and due diligence.
Anuarbek Baimoldin. Mr. Baimoldin has been with the Company since October 2007. Prior to being appointed COO, Mr. Baimoldin served as the Company’s Facilities Manager. Prior to joining the Company, from March 2006 to November 2007, Mr. Baimoldin was the Managing Director of JSC National Innovation Fund where his responsibilities included researching potential innovation projects and performing project feasibility studies. From June 2005 through March 2006 Mr. Baimoldin served as the President of Caspiy Corporation LLP where he was responsible for general company management, financial and operational planning and coordination of the company’s departments. From August 2002 through June 2005 Mr. Baimoldin was employed by TengizChevroil LLP. From January 2003 to June 2005 he served as the Coordinator for the Field Development Project. His responsibilities included preparation and obtaining approval for the Second Generation Project, Gas Reinjection Project, Exploration and Development Program and compliance of operations and licensing with Kazakhstani authorities. From August 2002 through January 2003 Mr. Baimoldin served as Senior Specialist for Kazakhstani Companies Development Department and worked to replace foreign contractors with local contractors and assisted local contractors to enhance product and service quality. In 1999 Mr. Baimoldin received an Associate of Science in Management from Mount Ida College of Business located in Mount Ida, Massachusetts and in 2002 was awarded a Bachelors of Arts in International Economics from Boston University located in Boston, Massachusetts. In 2005 Mr. Baimoldin was awarded a Bachelors of Science in Exploration of Oil and Gas Fields from Atyrau Oil and Gas Institute located in Atyrau, Kazakhstan. Mr. Baimoldin has also received extensive trainings from the Ernst & Young Business Academy located in Almaty, Kazakhstan.
Boris Cherdabayev. Mr. Cherdabayev joined the Company’s board of directors and was appointed Chairman of the board of directors in November 2003. From May 2000 to May 2003, Mr. Cherdabayev served as Director at TengizChevroil LLP multi-national oil and gas company owned by Chevron, ExxonMobil, KazMunayGas and LukOil. From 1998 to May 2000, Mr. Cherdabayev served as a member of the Board of Directors, Vice-President of Exploration and Production and Executive Director on Services Projects Development for NOC “Kazakhoil”, an oil and gas exploration and production company. From 1983 to 1988 and from 1994 to 1998 he served as a people’s representative at Novouzen City Council (Kazakhstan); he served as a people’s representative at Mangistau Oblast Maslikhat (regional level legislative structure) and a Chairman of the Committee on Law and Order. For his achievements Mr. Cherdabayev has been awarded with a national “Kurmet” order. Mr. Cherdabayev earned an engineering degree from the Ufa Oil & Gas Institute, with a specialization in “machinery and equipment of oil and gas fields” in 1976. Mr. Cherdabayev also earned an engineering degree from Kazakh Polytechnic Institute, with a specialization in “mining engineer on oil and gas fields’ development.” During his career he also completed an English language program in the USA, the СНАМР Program (Chevron Advanced Management Program) at Chevron Corporation offices in San-Francisco, CA, USA, and the CSEP Program (Columbia Senior Executive Program) at Columbia University, New York, NY USA. Mr. Cherdabayev is not currently, nor has he in the past five years been, a director or nominee of any other SEC registrant.
Jason M. Kerr. Mr. Kerr graduated from the University of Utah in 1995 with a Bachelors of Science degree in Economics and in 1998 with a Juris Doctorate from the same university where he was named the William H. Leary Scholar. Since 2006 Mr. Kerr has been the associate general counsel of Basic Research, LLC, concentrating in intellectual property litigation. Prior to joining Basic Research, Mr. Kerr was a partner with the law firm of Plant, Christensen & Kanell in Salt Lake City, Utah. Mr. Kerr was employed with Plant, Christensen & Kanell from 1996 through 2001 and from 2004 to 2006. From 2001 through 2004 Mr. Kerr was employed as a commercial litigator with the Las Vegas office of Lewis and Roca. Mr. Kerr became a Company director in May 2008. Mr. Kerr is not currently, nor has he in the past five years been, a nominee or director of any other SEC registrant.
Troy F. Nilson, CPA. Since February 2001, Mr. Nilson has served as an Audit Partner with Chisholm, Bierwolf Nilson & Morrill, Certified Public Accountants, in Bountiful, Utah. From December 2000 to February 2001, he served as an Audit Manager for Crouch, Bierwolf & Associates, Certified Public Accountants, in Salt Lake City, Utah. Prior to that time, Mr. Nilson served as the Senior Auditor for Intermountain Power Agency in Salt Lake City, Utah from March 1995 to December 2000. In the past five years, Mr. Nilson has had extensive public and private company audit, audit review and Securities and Exchange Commission disclosure and reporting experience. Mr. Nilson received licensure as a Certified Public Accountant in 1997. Mr. Nilson earned a Masters of Science Degree in Business Information Systems from Utah State University in December 1992, and a Bachelor of Science in Accounting from Utah State University in August 1990. Mr. Nilson became a Company director in December 2004. Mr. Nilson is not currently, nor has he in the past five years been, a director or nominee of any other SEC registrant.
Daymon M. Smith. Dr. Smith is currently engaged in independent research and writing projects. From August 2007 to June 2009 Dr. Smith was a Visiting Assistant Professor at the University of Alabama-Birmingham, where he was a lecturer and researcher. He has also taught at Weber State University and at Utah Valley University, and has received numerous research grants and academic awards. From 2001 to 2007 Dr. Smith was a William Penn Fellow at the University of Pennsylvania. As a Fellow, Dr. Smith was responsible for conducting course instruction and evaluation, student assessments and ethnographic research. From 2006 to 2007 Dr. Smith was employed with the Corporation of the Presiding Bishop as an International Media Scientist. Here Dr. Smith served as lead analyst for the Audiovisual Department. He also served from 2005 to 2006 as a cultural materials consultant to SynTech Energy, an oil-shale extraction company, providing support in its dealings with major U.S. airlines and with Jordanian firms. Dr. Smith earned a Bachelors of Science degree in Anthropology from the University of Utah in 2001, and a PhD in Anthropology from the University of Pennsylvania in 2007. Dr. Smith is not currently, nor has he in the past five years been, a director or nominee of any other SEC registrant.
Leonard M. Stillman, Jr. Mr. Stillman received his Bachelor of Science degree in mathematics from Brigham Young University and Master of Business Administration from the University of Utah. He began his career in 1963 with Sperry UNIVAC as a programmer developing trajectory analysis software for the Sergeant Missile system. Mr. Stillman spent many years as a designer and teacher of computer language classes at Brigham Young University, where he developed applications for the Administrative Department including the school’s first automated teacher evaluation system. During that time, he was also a Vice-President of Research and Development for Automated Industrial Data Systems, Inc and the Owner of World Data Systems Company, which provided computerized payroll services for companies such as Boise Cascade. Mr. Stillman has over 35 years of extensive business expertise including strategic planning, venture capital financing, budgeting, manufacturing planning, cost controls, personnel management, quality planning and management, and the development of standards, policies and procedures. He has extensive skills in the design and development of computer software systems and computer evaluation. Mr. Stillman helped found Stillman George, Inc. in 1993. He has been employed with Stillman George, Inc., since that time. Mr. Stillman’s primary responsibilities include managing information, technical development and financial analysis projects and development as well as involved in general company management and consulting activities. Stillman George consolidates a broad variety of skills from a growing group of business professionals to provide needed support in finance, marketing, management, sales, planning, product development and more to businesses worldwide. Mr. Stillman is not currently, nor has he in the past five years been, a director or nominee of any other SEC registrant.
Valery Tolkachev. Since August 2009, Mr. Tolkachev has served as Advisor to the CEO at Moscow-based MaxWellBank. Mr. Tolkachev also serves on the board of directors at MaxWellBank and is waiting a pending appointment as CEO. From August 2008 to March 2009, Mr. Tolkachev was employed with Slavyansky Bank in Moscow, Russia, where he served as the Deputy Chairman. From 1991 to 2008, Mr. Tolkachev served in various positions with various employers including UniCreditAton, MDM Bank, InkomBank, InkomCapital and others. Mr. Tolkachev graduated with Honors from the High Military School in Kiev, USSR in 1989. In 2005 he completed his studies at the Academy of National Economy, as a qualified lawyer. Mr. Tolkachev serves on the Compensation Committee and the Corporate Governance and Nominating Committee of the Company. Mr. Tolkachev became a Company director in December 2003. Mr. Tolkachev also serves as a director of Caspian Services, Inc., and Bekem Metals, Inc. Both are SEC registrants. Other than as disclosed herein, Mr. Tolkachev is not currently, nor has he in the past five years been, a director or nominee of any other SEC reporting issuer.
When determining whether it is appropriate for a director to serve on the board of directors, the Company focuses primarily on the information provided in each of the director’s individual biographies set forth above and its knowledge of the character and strengths of the sitting directors. With regard to Mr. Cherdabayev, the Company considered his extensive experience in the oil and gas industry in the Republic of Kazakhstan. The Company considered Mr. Kerr’s educational background in economics and his professional experience as an attorney. Mr. Nilson’s experience as a U.S. Certified Public Accountant auditing SEC reporting issuers was taken into account in his appointment to the board. With regard to Mr. Smith the Company considered his background in anthropology and media messaging. Mr. Stillman’s training in business management, strategic planning, corporate finance and information management was considered a significant factor in his serving on the board. The board considered Mr. Tashtitov’s detailed understanding of the Company’s operations and strategic goals in connection with his appointment to the board. With regard to Mr. Tolkachev, the Company considered his extensive investment experience and his related finance and banking background.
Procedures for Security Holders to Nominate Candidates to the Board of Directors
There have been no material changes to the procedures set forth in our proxy statement filed with the SEC on November 18, 2009, by which security holders may recommend nominees to our board of directors.
Leadership Structure
We have separate individuals serving as Chairman of the Board as Chief Executive Officer and as President. The President and CEO are responsible for setting the strategic direction of the Company and managing the day-to-day leadership and performance of the Company, while the Chairman provides guidance to the CEO and the President, sets the agenda for meetings of the Board and presides over meetings of the full Board. The Company believes this structure strengthens the role of the board in fulfilling its oversight responsibility and fiduciary duties to the Company’s shareholders while recognizing the day-to-day management direction of the Company by its CEO Gamal Kulumbetov and its President Askar Tashtitov.
Oversight of Risk Management
Board-level risk oversight is primarily performed by our full Board, although the Audit Committee oversees our internal controls and regularly assesses financial and accounting processes and risks. Our risk oversight process includes an ongoing dialogue between management and the Board and the Audit Committee, intended to identify and analyze risks that face the Company. Through these discussions with management and their own business experience and knowledge, our directors are able to identify material risks for which a full analysis and risk mitigation plan are necessary. The Board (or the Audit Committee, with respect to risks related to internal controls, financial and accounting matters) monitors risk mitigation action plans developed by management, in order to ensure such plans are implemented and are effective in reducing the targeted risk.
Family Relationships
Our Chief Operating Officer, Anuarbek Baimoldin, is the nephew of Boris Cherdabayev, a Company director and Chairman of the board of directors. There are no other family relationships among our directors, executive officers and/or nominees.
Involvement in Certain Legal Proceedings
During the past ten years none of our executive officers, directors, promoters or control persons has been involved in any of the following events that could be material to an evaluation of his ability or integrity, including:
(1) Any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time.
(2) Any conviction in a criminal proceeding or being subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);
(3) Being subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from, or otherwise limiting the following activities:
(i) Acting as a futures commission merchant, introducing broker, commodity trading advisor, commodity poll operator, floor broker, leverage transaction merchant, and other person regulated by the Commodity Futures Trading Commission (“CFTC”), or an associated person of any of the foregoing, or as an investment adviser, underwriter, broker or dealer in securities, or as an affiliate person, director or employee of any investment company, bank savings and loan association or insurance company, or engaging in or continuing any conduct or practice in connection with such activity;
(ii) Engaging in any type of business practice; or
(iii) Engaging in any activity in connection with the purchase or sale of any security or commodity or in connection with any violation of Federal or State securities laws or Federal commodities laws.
(4) Being subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting for more than 60 days the rights of such person to engage in any activity described in (3)(i) above, or to be associated with persons engaged in any such activity.
(5) Being found by a court of competent jurisdiction in a civil action or by the Securities and Exchange Commission to have violated any Federal or State securities law, and the judgment in such civil action or finding by the Commission has not be subsequently reversed, suspended or vacated.
(6) Being found by a court of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any Federal commodities law, and the judgment in such civil action or finding by the Commodity Futures Trading Commission has not been subsequently reversed, suspended, or vacated.
(7) Being the subject of, or a party to any Federal or State judicial or administrative order, judgment, decree or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of:
(i) Any Federal or State securities or commodities law or regulations; or
(ii) Any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or
(8) Being the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act (15 U.S.C. 78c(a)(26)))), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act (7 U.S.C. 1(a)(29))), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.
BOARD COMMITTEES
The board has standing audit, compensation, and corporate governance and nominating committees. The board has adopted written charters for each of these committees. These charters are available on the Company’s website at www.bmbmunai.com.
Audit Committee
Our board of directors has adopted an audit committee charter and established an audit committee, whose principal functions are to:
●
assist the board in the selection, review and oversight of our independent registered public accounting firm;
●
approve all audit, review and attest services provided by the independent registered public accounting firm;
●
assess the integrity of our reporting practices and evaluate of our internal controls and accounting procedures; and
●
resolve disagreements between management and the independent registered public accountants regarding financial reporting.
The audit committee has the sole authority to retain and terminate our independent registered public accounting firm and to approve the compensation paid to our independent registered public accounting firm. The audit committee is responsible for the pre-approval of all non-audit services provided by our independent registered public accounting firm. Non-audit services are only provided by our independent registered public accounting firm to the extent permitted by law. The audit committee is comprised of three independent directors, Troy Nilson, Daymon Smith and Jason Kerr. Mr. Nilson has and will continue to act as chairman of the committee. Our board of directors has determined that Mr. Nilson qualifies as an “audit committee financial expert” under the rules of the SEC adopted pursuant to the requirements of the Sarbanes-Oxley Act of 2002. As discussed above, our board of directors has also determined that Mr. Nilson, Mr. Smith and Mr. Kerr each qualifies as “independent” in accordance with the applicable regulations adopted by the SEC and NYSE Amex.
Our board may establish other committees from time to time to facilitate our management.
CODE OF ETHICS
We have adopted a Code of Ethics that applies to our principal executive, financial and accounting officers and persons performing similar duties. The Code is designed to deter wrong-doing and promote honest and ethical behavior, full, fair, timely, accurate and understandable disclosure and compliance with applicable governmental laws, rules and regulations. It is also designed to encourage prompt internal reporting of violations of the Code to an appropriate person and provides for accountability for adherence to the Code. A copy of our Code of Ethics has been posted on our website and may be viewed at http://www.bmbmunai.com. A copy of the Code of Ethics will be provided to any person without charge upon written request to our Corporate Secretary at our U.S. offices, 324 South 400 West, Suite 225, Salt Lake City, Utah 84101.
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
Directors, executive officers and holders of more than 10% of our outstanding common stock are required to comply with Section 16(a) of the Securities Exchange Act of 1934, which requires generally that such persons file reports regarding ownership of and transactions in securities of the Company on Forms 3, 4, and 5. Based solely on management’s review of these reports during the year ended March 31, 2010, it appears that Daymon Smith filed a Form 3 in September 2009 disclosing his beneficial ownership of shares of our common stock on day late. It also appears that Askar Tashtitov filed a late Form 4 in July 2009 disclosing the acquisition of 10,000 shares in December 2007 pursuant to a restricted stock grant.
Item 11.
Item 11. Executive Compensation
We have a compensation committee of three independent directors. That committee has been delegated authority from our board of directors and its activities are governed by a compensation committee charter. One of the roles of the compensation committee under its charter is to review and approve annually all compensation decisions relating to our executive officers. Our compensation committee utilizes external analyses to inform its executive compensation decisions and processes.
Objectives and Philosophy of Our Executive Compensation Program
The primary objectives of our executive compensation program are to:
●
attract, retain and motivate skilled and knowledgeable executive talent;
●
ensure that executive compensation is aligned with our corporate strategies and business objectives;
●
promote the achievement of key strategic and financial performance measures by linking short-term and long-term cash and equity incentives to the achievement of measurable corporate and individual performance goals; and
●
align executives’ incentives with the creation of stockholder value.
In setting executive compensation our compensation committee has historically relied on compensation comparisons to energy industry companies with revenues between $25 million and $99.9 million. From time to time, the compensation committee has also considered a peer group of a few similarly sized oil and gas exploration companies in Kazakhstan to assist in establishing the compensation packages of its executive officers. Although the compensation committee did not consider the peer group during the 2010 fiscal year because of difficulty obtaining accurate compensation information of the compensation packages of the peer group companies during the year.
The compensation committee has historically tried to maintain total executive compensation within a range between the 25th percentile and the general industry average. To accomplish this objective, while at the same time recognizing the Company’s need for cash, the compensation committee has historically targeted total cash compensation within the 25th percentile of the general industry comparison. The committee has historically relied on setting long-term incentive compensation, in the form of restricted stock grants, above the industry average to provide a total compensation package in a range between the 25th percentile and the industry average.
While the compensation committee engages in compensation comparisons, it is not the sole, or even the principal factor they consider in setting executive compensation. The committee also takes into account a number of other factors, including key strategic, financial and operational goals set by our board of directors, such as satisfying our annual minimum work program or special achievements attained by executive management.
As discussed above, the compensation committee has historically provided a portion of executive compensation in the form of equity awards that vest over time. We believe this will help to retain our named executive officers and align their interests with those of our stockholders by allowing the executives to participate in our longer term success as reflected in asset growth and stock price appreciation.
Components of our Executive Compensation Program
At this time, the primary elements of our executive compensation program are:
●
base salaries;
●
nonequity incentive compensation;
●
bonuses;
●
equity incentive awards; and
●
benefits and other compensation.
We do not have any formal or informal policy or target for allocating compensation between long-term and short-term compensation, between cash and non-cash compensation or among the different forms of non-cash compensation. Instead, we determine subjectively on a case-by-case basis the appropriate level and mix of the various compensation components.
Base salaries
Base salaries are used to recognize the experience, skills, knowledge and responsibilities required of all our employees, including our named executive officers. Base salaries for our named executive officers typically have been set in our offer letter to the individual at the outset of employment. We rely on several factors to determine the base salaries of our executive officers. As noted above, our compensation committee considers various factors, including salaries paid by the energy industry comparison companies. The committee has historically attempted to maintain base salaries within the 25th percentile of the general industry average. While the committee relies upon compensation comparisons in determining base salaries, it is not the sole, or necessarily the principal factor determining base salaries. The principal factor in determining base salaries is the negotiation process between the Company and the named executive officer. While we have has historically stayed within the compensation levels discussed above, there may be instances when, based on an individual’s performance, experience or expertise, need, or local market or labor conditions the compensation committee may award base salaries that exceed the compensation it has historically relied on in order to retain current or attract new executive talent.
Under the terms of our employment agreements, consistent with our executive compensation program objectives, base salaries for our executives, together with other components of compensation, may be evaluated by our compensation committee for adjustment based on an assessment of an executive’s performance and compensation trends in our industry.
During the fiscal year ended March 31, 2010, the compensation committee awarded no base salary increases to any of the named executive officers except Evgeny Ler and Anuarbek Baimoldin, who were awarded base salary increases in connection with their promotions to CFO and COO, respectively.
Nonequity incentive compensation
From time to time we may make cash awards to our employees, including the named executive officers. Such awards may be designed to incentivize employees over a specified period of time pursuant to pre-established, performance-based criteria, the accomplishment of which is substantially uncertain at the time the criteria are established. In the event this type of cash award was made, it would be reflected in the “Summary Compensation Table” under a separate column entitled “Nonequity Incentive Plan Compensation.” We may use nonequity incentive compensation to incentivize our employees. The criteria for earning such nonequity incentive bonuses may be based on corporate financial performance measures that would be developed by our compensation committee at the time such nonequity incentive plan is established. Our compensation committee has discretion to determine the applicable performance measures and the appropriate weighting of such measures at the time it establishes any nonequity incentive plan. The compensation committee did not establish a nonequity incentive compensation plan during the fiscal year ended March 31, 2010 and no nonequity incentive compensation was awarded during the year.
Bonuses
We may also make cash awards to employees that are not part of any pre-established, performance-based criteria. Awards of this type are completely discretionary and subjectively determined by the compensation committee at the time they are awarded. Such awards are reported in the “Summary Compensation Table” in the column entitled “Bonus.” In 2008 and 2009 the compensation committee, of its own discretion, determined to award to each of the named executive officers a bonus equal to one month of the executive officer’s salary. The bonuses were not awarded pursuant to any pre-established, performance-based criteria set by the compensation committee, but in recognition of the growth in the Company’s production, revenue and net income during the year. The Company was under no obligation to award the cash bonuses. The compensation committee awarded no bonuses to any named executive officer during the fiscal year ended March 31, 2010.
Equity incentive awards
Our equity award program is the primary vehicle for offering long-term incentives to our executives. Our equity awards to executives have typically been made in the form of restricted stock grants and stock options. Although we do not have any equity ownership guidelines for our executives, we believe that equity grants provide our executives with a direct link to our long-term performance, create an ownership culture and align the interests of our executives and our stockholders. In addition, the vesting feature of our equity grants should further our objective of executive retention because this feature provides an incentive to our executives to remain in our employ during the vesting period.
In determining the size of equity grants to our executives, our compensation committee and board of directors consider comparative share ownership of executives in our energy industry comparison companies, the Company’s performance, the applicable executive’s performance, the amount of equity previously awarded to the executive, the vesting of such awards and the recommendations of management.
Grants of equity awards, including those to named executive officers, are all approved by our compensation committee and the board of directors and are granted based on the fair market value of our common stock. Vesting of equity awards has varied from immediate vesting to vesting of periods ranging from one to five years depending on the purpose of the award. When we have made equity awards that vested immediately, they were typically in recognition of services already rendered or goals already accomplished.
Generally, our compensation committee meets annually to review our executive compensation program objectives and make recommendations to our board of directors regarding equity awards and incentives to retain employees. We do not have a program, plan or practice of selecting grant dates for equity compensation to our executive officers in coordination with the release of material non-public information. Equity award grants are made from time to time in the discretion of our compensation committee consistent with our executive compensation program objectives. In January 2010, our board of directors, at the recommendation of the compensation committee, awarded restricted stock grants to certain executive officers, directors, employees and outside consultants of the Company in recognition of services rendered to the Company. The aggregate number of restricted common shares granted was 1,500,000. The total number of grant recipients was 15, including our named executive officers.
Benefits and other compensation
Under the terms of their employment contracts, our named executive officers are permitted to participate in such pension, profit sharing, bonus, life insurance, hospitalization, major medical and other employee benefit plans as may be in effect from time to time to the extent the executive is eligible under the terms of such plans.
Under the employment agreements with our named executive officers, we agree to pay all taxes and dues under applicable laws of Kazakhstan for our named executive officers including income and social taxes and government pension fund payments.
Income tax
As is the custom in Kazakhstan, we pay the income taxes of our employees, including the named executive officers. The income tax rate for individuals in Kazakhstan is currently 10%.
Social tax
We make payments of mandatory social tax in an amount 11% of employee wages. These costs are recorded in the period when they are incurred and presented as salary related tax expense in the income statement.
Pension fund payment
In accordance with the legislative requirements of the Republic of Kazakhstan we were required to pay into an employee pension fund an amount equivalent to 10% of each employee’s wages, up to a maximum of $700 per month. Pension fund payments are withheld from employees’ salaries and included with other salary costs in the income statement. We do not have any other liabilities related to any supplementary pensions, post retirement health care, insurance benefits or retirement indemnities.
Summary Compensation Table
The table below summarizes compensation paid to or earned by our Chief Executive Officer, our Chief Financial Officer and our other most highly compensated officers, who we refer to collectively as our “named executive officers.”
Name and
Principal Position
Year
Salary
($)
Bonus
($)
Stock
Awards(4)
($)
All Other
Compen-
sation
($)
Total
($)
Boris Cherdabayev
192,000
319,200
59,309
570,509
Chairman
228,000
20,000
1,659,000
67,054
1,974,054
263,184
20,000
73,123
356,307
Gamal Kulumbetov
96,873
91,200
31,448
219,521
CEO
147,581
13,000
553,000
48,705
762,286
148,066
10,000
48,162
206,228
Evgeny Ler
89,309
125,400
29,927
244,636
CFO(1)
73,117
5,000
442,400
30,762
551,279
59,773
5,000
28,145
92,918
Leonard Stillman
4,500
38,351
42,851
Former Interim
138,290
9,547
147,837
CFO(2)
Askar Tashtitov
115,200
262,200
37,417
414,817
President
130,255
10,000
774,200
44,570
959,025
138,153
10,000
44,292
192,445
Toleush Tolmakov
108,473
245,100
27,608
381,181
General Director of
127,841
829,500
32,550
989,891
Emir Oil LLP
137,508
27,580
165,088
Anuarbek Baimoldin
84,731
22,800
29,869
137,400
COO(3)
60,000
5,000
21,081
86,081
27,273
5,000
10,519
42,792
(1)
In April 2009 Mr. Ler was appointed CFO of the Company.
(2)
Mr. Stillman served as the Company’s interim CFO from June 17, 2008 to April 13, 2009. Mr. Stillman’s compensation for the 2009 fiscal year presented in the chart above is for the period from June 17, 2008 to March 31, 2009.
(3)
In April 2009 Mr. Baimoldin was appointed COO of the Company.
(4)
For details regarding the assumptions made in the valuation of stock award, please see “Valuation of Stock Awards” below.
(5)
For details regarding the assumptions made in the valuation of option awards, please see “Valuation of Option Awards” below.
Valuation of Stock Awards
On July 18, 2005, we awarded restricted stock grants to three officers of the under our 2004 Stock Incentive Plan (the “2004 Plan”). The total number of restricted stock grants was 90,000. The grants vested in three equal installments of 10,000 shares per year to each officer. The restricted stock grants were valued at $4.75 per share, the closing price of our common stock on the date of grant. Compensation expense for vested stock grants in the amount of $31,523 and $124,477 was recognized in the Consolidated Statements of Operations and Consolidated Balance Sheets for the years ended March 31, 2008 and 2007, respectively.
On June 20, 2006, we granted common stock to officers, directors and certain employees and consultants of the Company under the Plan. The total number of restricted common shares granted was 495,000. The restricted stock grants were valued at $7.00 per share, the closing price of our common stock on the date of grant. $3,465,000 was recognized in the Consolidated Statements of Operations and Consolidated Balance Sheet for the year ended March 31, 2007.
On March 30, 2007, we granted common stock to officers, employees and outside consultants of the Company under the 2004 Plan. The total number of restricted common shares granted was 950,000. The restricted stock grants were valued at $5.38 per share, the closing price of our common stock on the date of grant. The restricted stock grants will vest on the earlier of July 9, 2009 and the occurrence of an Extraordinary Event (as it is defined in the 2004 Plan).
Non-cash compensation expense related to the vesting of share-based compensation in the amount of $567,889, $2,271,556 and $2,303,078 was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the years ended March 31, 2010, 2009 and 2008, respectively.
On July 17, 2008, we granted, subject to certain vesting requirements, restricted stock awards to certain executive officers, directors, employees and outside consultants of the Company pursuant to the 2004 Plan. The total number of shares granted was 1,330,000. The restricted stock grants were valued at $5.53 per share, the closing price of our common stock on the date of Grant.
Non-cash compensation expense in the amount of $2,176,244 and $5,178,655 was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the years ended March 31, 2010 and 2009.
On January 1, 2010, we granted, subject to certain vesting requirements, restricted stock awards to certain executive officers, directors, employees and outside consultants of the Company pursuant to the 2004 Plan. The total number of shares granted was 1,500,000. The restricted stock grants were valued at $1.14 per share, the closing price of our common stock on the date of Grant.
As of March 31, 2010, there was $1,282,500 of total unrecognized non-cash compensation expense related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 0.75 years.
All Other Compensation
The table below provides additional information regarding “all other compensation” awarded to the named executive officers as disclosed in the “All Other Compensation” column of the “Summary Compensation Table” above.
Name
Year
Income
Tax
Social
Tax
Health
Insurance
Pension
Fund
Fitness Club
Membership
Non-Employee
Director Fees
Boris Cherdabayev
$27,119
$23,885
$912
$7,393
$-0-
$-0-
35,093
22,834
8,661
38,900
26,024
7,457
Gamal Kulumbetov
$11,254
$12,066
$735
$7,393
$-0-
$-0-
22,898
14,612
8,661
2,159
22,861
15,161
7,457
2,400
Evgeny Ler
$10,530
$11,269
$735
$7,393
$-0-
$-0-
11,765
7,802
8,661
2,159
9,967
8,038
7,457
2,400
Len Stillman
$-0-
$-0-
$-0-
$-0-
$-0-
$38,351
9,547(1)
Askar Tashtitov
$14,776
$14,513
$735
$7,393
$-0-
$-0-
20,380
12,995
8,661
2,159
19,931
14,221
7,457
2,400
Toleush Tolmakov
$9,881
$9,197
$-0-
$8,530
$-0-
$-0-
14,112
9,777
8,661
10,267
9,181
8,132
Anuarbek Baimoldin
$10,616
$11,125
$735
$7,393
$-0-
$-0-
7,682
5,687
7,379
3,595
3,677
3,121
(1)
Mr. Stillman served as the Company’s interim CFO from June 17, 2008 to April 13, 2009. Prior to June 17, 2008, Mr. Stillman served as a non-employee member of our board of directors and received non-employee director fees for his services.
Employment Agreements
We have employment agreements with each of our named executive officers.
On December 31, 2009, the Company entered into new employment agreements with the following executive officers of the Company, Gamal Kulumbetov, Askar Tashtitov, Evgeniy Ler and Anuarbek Baimoldin.
Except for annual salary, and as otherwise specifically addressed herein, the terms and conditions of the employment agreement of each of the executive and non-executive level officers are the same in all material respects. The employment agreements provide for an initial term of one year with three consecutive one-year renewals unless terminated by either party prior to the beginning of the renewal term. A form of the Employment Agreement was filed as an exhibit to the current report on Form 8-K we filed on January 6, 2010.
Under the agreements, salary is reviewable no less frequently than annually and may be adjusted up or down by the compensation committee in its sole discretion, but may not be adjusted below the initial annual salary amount listed in the agreement. The agreements provide that each of the officers is entitled to participate in such pension, profit sharing, bonus, life insurance, hospitalization, major medical and other employee benefit plans of the Company that may be in effect from time to time, to the extent the individual is eligible under the terms of those plans. The agreements provide that each officer is eligible at the discretion of the compensation committee and the board of directors to receive performance bonuses. Each officer is entitled to 28 days vacation in accordance with the vacation policies of the Company, as well as paid holidays and other paid leave set forth in the Company’s policies. There is no accrual of vacation days and holidays.
The agreements and all obligations thereunder may be terminated upon the occurrence of the following events: i) death, ii) disability; iii) for cause immediately upon notice from the Company or at such time as indicated by the Company in said notice; iv) for good reason upon not less than 30 days notice from an officer to the Company; v) an extraordinary event, unless otherwise agreed in writing.
Under the agreements the named executive officer may be deemed disabled if for physical or mental reasons he is unable to perform his duties for 120 consecutive days or 180 days during any 12 month period. Such disability will be determined by a jointly agreed upon medical doctor.
The agreements provide that any of the following will constitute “cause”: i) breach of the employment agreement; ii) failure to adhere to the written policies of the Company; iii) appropriation by the officer of a material business opportunity; iv) misappropriation of funds or property of the Company; v) conviction, indictment or the entering of a guilty plea or a plea of no contest to a felony.
“Good reason” under the agreements may mean any of the following: i) a material breach of the employment agreement; ii) assignment of the officer without his consent to a position of lesser status or degree of responsibility.; iii) relocation of the Company’s principal executive offices outside the Republic of Kazakhstan; iv) if the Company requires the officer to be based somewhere other than principal executive offices of the Company without the officer’s consent.
Each of the employment agreements, provides that an “extraordinary event” is defined as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to fifty percent (50%) or more of the outstanding stock of the Company or any of its subsidiaries, or the sale of forty percent (40%) or more of the assets of the Company or any of its subsidiaries, or if one or more persons, acting alone or as a group, acquires fifty percent (50%) or more of the total voting power of the Company. In addition to these provisions, the employment agreement of Mr. Tashtitov provides that the following events also constitute an extraordinary event: i) that a disposition by the Chairman of the Company’s board of directors or by the General Director of the Company’s subsidiary, of seventy five (75%) or more of the shares either individual currently owns, including stock attributed to either of them by Internal Revenue Code Section 318; or ii) should the Company terminate the registration of any of its securities under Section 12 of the Exchange Act of 1934, voluntarily ceases, or shall terminate its obligation to file reports with United States Securities Commission pursuant to Section 13 of the Exchange Act of 1934.
Potential Payments Upon Termination or Change in Control
The employment agreements of certain of our named executive officers provide for potential payments upon termination or change in control. The following table shows the cash and equity benefits payable to the named executive officers upon termination of employment for various reasons, including a change in control of the Company. For purposes of this table, it is assumed that the termination of employment occurred on March 31, 2010. The Company is not contractually obligated to make payments upon termination or change in control to any named executive officer not included in the table below.
Name
Termination Scenario
Cash Benefit
Equity Awards
Gamal Kulumbetov
For Good Reason(1)
$ 64,502
$ 0
For Cause(2)
$ 0
$ 0
Disability(3)
$ 64,502
$ 0
Death(4)
$ 0
$ 0
Extraordinary Event(5)
$ 385,722
$ 76,800(6)
Askar Tashtitov
For Good Reason(1)
$ 76,589
$ 0
For Cause(2)
$ 0
$ 0
Disability(3)
$ 76,589
$ 0
Death(4)
$ 0
$ 0
Extraordinary Event(5)
$ 3,000,000
$ 220,800(6)
Evgeny Ler
For Good Reason(1)
$ 60,722
$ 0
For Cause(2)
$ 0
$ 0
Disability(3)
$ 60,722
$ 0
Death(4)
$ 0
$ 0
Extraordinary Event(5)
$ 363,118
$ 105,600(6)
Anuarbek Baimoldin
For Good Reason(1)
$ 60,722
$ 0
For Cause(2)
$ 0
$ 0
Disability(3)
$ 60,722
$ 0
Death(4)
$ 0
$ 0
Extraordinary Event(5)
$ 363,118
$ 19,200(6)
Toleush Tolmakov
Termination for Any Reason
$ 7,000
$ 206,400
(1)
In the event of termination for good reason by the officer, the Company will pay the officer the remainder of his salary for the calendar month in which the termination is effective and for six consecutive calendar months thereafter. The officer shall also be entitled to any portion of incentive compensation for the year, prorated to the date of termination. Notwithstanding the foregoing, if the officer obtains other employment prior to the end of the six-month period, salary payments by the Company after he begins employment with a new employer shall be reduced by the amount of the cash compensation received from the new employer.
(2)
If the officer is terminated for cause, he will receive salary only through the date of termination and will not be entitled to any incentive compensation for the year in which his employment is terminated.
(3)
If the termination is the result of a disability, the Company will pay salary for the rest of the month during which termination is effective and for the shorter of six consecutive months thereafter or until disability insurance benefits commence.
(4)
If employment is terminated as a result of the death of the officer, his heirs shall be entitled to salary through the month in which his death occurs and to incentive compensation prorated through the month of his death.
(5)
If the employment is terminated as a result of an extraordinary event, the officer shall be entitled to severance pay as follows:
Completed Years of Employment
Service with the Employer
Severance Amount
Less than one (1) year
10% of Basic Compensation Salary
At least one (1) year but less than two (2) years
150% of Basic Compensation Salary
More than two years
299% of Basic Compensation Salary
As of March 31, 2009, each of the named executive officers had been employed with the Company more than two years.
(6)
This column reflects the dollar value of additional shares (if any) that would vest at such time as the occurrence of an extraordinary event, calculated at $0.96 per share, which was the closing price of the Company’s common stock on March 31, 2010.
All benefits terminate on the date of termination of the employment agreement. The named executive officer shall be entitled to accrued benefits pursuant to such plans as provided in such plans or grants thereunder. The named executive officer will not receive any payment or other compensation for vacation, holiday, sick leave, or other leave unused as of the date of the notice of termination.
On December 31, 2009 we entered into a Consulting Agreement with Boris Cherdabayev, the Chairman of the Company’s board of directors. Pursuant to the Consulting Agreement, in addition to his services as Chairman of the board of directors, Mr. Cherdabayev will provide such consulting and other services as may reasonably be requested by Company management. The Consulting Agreement became effective on January 1, 2010. The initial term of the agreement is five years unless earlier terminated as provided in the agreement. The initial term will automatically renew for additional one-year terms unless and until terminated. The agreement may be terminated for Mr. Cherdabayev’s death or disability and by the Company for cause. The Company may also terminate the agreement other than for cause, but will be required to pay the full fee required under the agreement, which would have been $912,000, if the agreement had been terminated as of March 31, 2010.
Pursuant to the Consulting Agreement, Mr. Cherdabayev will be paid a base compensation fee of $192,000 per year. This base compensation fee will be net of Social Tax and Social Insurance Tax in the Republic of Kazakhstan, which shall be paid by the Company. Mr. Cherdabayev will be responsible for Personal Income Tax and Pension Fund Tax. The success of projects involving Mr. Cherdabayev shall be reviewed on an annual basis to determine whether the initial base consulting fee should be increased.
The Consulting Agreement provides for an extraordinary event payment equal to the greater of $5,000,000 or the base compensation fee for the remaining initial term of the Consulting Agreement. The Consulting Agreement defines an extraordinary event as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to fifty percent (50%) or more of the outstanding stock of the Company or any of its subsidiaries, or the sale of forty percent (40%) or more of the assets of the Company or any of its subsidiaries, or if one or more persons, acting alone or as a group, acquires fifty percent (50%) or more of the total voting power of the Company.
Had a change in control event occurred as of March 31, 2010 an unvested restricted stock grant of 280,000 common shares made to Mr. Cherdabayev as of January 1, 2010 would have immediately vested to Mr. Cherdabayev. The value of the shares based on the closing market price of the Company’s common stock as of March 31, 2010 was $268,800.
Grants of Plan-Based Awards
Name
Grant Date
All Other Stock Awards: Number of Shares or Units of Stock(#)
Grant Date Fair Value of Stock Awards(1)
Boris Cherdabayev
01/01/2010
280,000
319,200
Gamal Kulumbetov
01/01/2010
80,000
91,200
Askar Tashtitov
01/01/2010
230,000
262,200
Evgeny Ler
01/01/2010
110,000
125,400
Toleush Tolmakov
01/01/2010
215,000
245,100
Anuarbek Baimoldin
01/01/2010
20,000
22,800
(1)
For details regarding the assumptions made in the valuation of stock award, please see “Valuation of Stock Awards” on page 71.
Outstanding Equity Awards at Fiscal Year End
The following table sets forth information regarding the outstanding stock options and unvested restricted stock grants held by our named executive officers as of March 31, 2009.
(1)
Option awards vested at the date they were granted. The options to acquire 150,000 shares at an exercise price of $7.00 expired unexercised on June 20, 2009.
(2)
The stock grants will vest on January 1, 2011.
Option Exercises and Stock Vested
During the 2010 fiscal year none of the named executive officers exercised options. The following table sets forth information regarding the restricted shares vested as of March 31, 2010:
Name
Number of Shares
Acquired on Vesting
(#)
Value Realized
On Vesting
($)
Boris Cherdabayev
150,000
127,500(1)
Boris Cherdabayev
300,000
258,000(2)
Gamal Kulumbetov
100,000
85,000(1)
Gamal Kulumbetov
100,000
86,000(2)
Askar Tashtitov
100,000
85,000(1)
Askar Tashtitov
140,000
120,400(2)
Evgeny Ler
80,000
68,800(2)
Toleush Tolmakov
100,000
85,000(1)
Toleush Tolmakov
150,000
129,000(2)
(1)
These shares vested on July 9, 2009. Value realized on vesting was calculated based on a closing market price of $0.85 per share, which was the closing market price of the Company’s common stock on the date the shares vested.
(2)
These shares vested on July 17, 2009. Value realized on vesting was calculated based on a closing market price of $0.86 per share, which was the closing market price of the Company’s common stock on the date the shares vested.
Pension Benefits
We do not currently offer pension benefits to any of our employees including the named executive officers.
Nonqualified Deferred Compensation
We offer no defined contribution or other plan that provide for the deferral of compensation on a basis that is not tax-qualified to any of our employees including the named executive officers.
Compensation of Directors
We use a combination of cash and equity-based compensation to attract and retain candidates to serve on our board of directors. We compensate the non-employee members of our board of directors.
Director Fees
Members of the board of directors who are not also employees of the Company or its subsidiary are paid a $40,000 stipend per year.
Meeting Fees
We also pay the non-employee members of our board of directors $1,000 for each directors meeting or shareholder meeting attended in person, plus airfare and hotel expenses.
Equity Compensation
We do not currently have a fixed plan for the award of equity compensation to our non-employee directors. Equity compensation of independent directors, if any, is typically recommended by the compensation committee or management and is subject to approval of the full board of directors. All equity grants to directors are granted at a price equal to the fair market value of our common stock on the date of the grant.
Director Compensation Table
The following table sets forth a summary of the compensation we paid to our non-employee directors for services on our board during our 2010 fiscal year. We do not compensate our employee directors for their services on our board of directors.
Name
Fees Earned
or Paid
in Cash
($)
Stock
Awards
($)
Option
Awards
($)
Non-Equity
Incentive Plan
Compensation
($)
Nonqualified
Deferred
Compensation
Earnings
($)
All Other
Compen-
sation
($)
Total
($)
Jason Kerr
40,000
40,000
Troy Nilson
40,000
40,000
Stephen Smoot(2)
16,739
16,739
Leonard Stillman
38,355
4,500(1)
42,855
Valery Tolkachev
40,000
40,000
Daymon Smith(2)
23,261
23,261
Boris Cherdabayev(3)
319,200
251,309
570,509
Askar Tashtitov(3)
262,200
152,617
414,817
(1)
Mr. Stillman served as interim CFO of the Company from June 2008 to April 2009. The amount disclosed in this table represents salary paid to Mr. Stillman as interim CFO during our 2010 fiscal year. For additional information regarding compensation paid to Mr. Stillman during the period he served as interim CFO, please see the “Summary Compensation Table” on page 69.
(2)
Mr. Stephen Smoot resigned as a Company director on August 31, 2009. On September 3, 2009 Mr. Daymon Smith was appointed to fill the vacancy created on the board of directors by Mr. Smoot’s resignation.
(3)
In addition to serving on the Company’s board of directors, Mr. Cherdabayev and Mr. Tashtitov are also employed by the Company. All compensation paid to these individual, as reflected in the above table, was paid in connection with their employment with the Company. For additional information regarding compensation paid to Mr. Cherdabayev and Mr. Tashtitov please see the “Summary Compensation Table” on page 69.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The following table sets forth as of June 2, 2010 the name and the number of shares of our common stock, par value of $0.001 per share, held of record or beneficially by each person who held of record, based on filings with the SEC, or was known by us to own beneficially, more than 5% of the 51,865,015 issued and outstanding shares of our common stock, and the name and shareholdings of each director and of all officers and directors as a group.
Type of Security
Name and Address
Amount & Nature of
Beneficial Ownership
% of Class(5)
Common
Anuarbek Baimoldin
20,000(4)
*
Dostyk Ave., 4th Floor
Almaty, Kazakhstan 050051
Common
Boris Cherdabayev
6,658,983(1)(4)
12.7%
Dostyk Ave, 4th Floor
Almaty, Kazakhstan 050051
Common
JSC Compass Asset Management
4,423,494
8.5%
V Furmanov Street
Almaty, Kazakhstan 050059
Common
Jason Kerr
*
South 750 East
Kaysville, Utah 84037
Common
Gamal Kulumbetov
280,000(4)
*
Dostyk Ave, 4th Floor
Almaty, Kazakhstan 050051
Common
Evgeniy Ler
190,000(4)
*
Dostyk Ave, 4th Floor
Almaty, Kazakh
Common
Troy Nilson
*
West 2600 South #250
Bountiful, Utah 84010
Common
Daymon M. Smith
*
East 426 North
Alpine, Utah 84004
* Less than 1%
(1)
The shares attributed to Mr. Cherdabayev include 4,128,601 shares held of record by Mr. Cherdabayev, 2,106,126 shares held of record by or for the benefit of Westfall Group Limited, 14,000 shares held of record by Asael T. Sorensen for the benefit of Boris Cherdabayev and immediately exercisable options held by Mr. Cherdabayev to acquire 410,256 shares of our common stock at an exercise price of $4.75. This option expires on July 18, 2010. Mr. Cherdabayev is the sole owner of Westfall Group Limited.
(2) The shares attributed to Mr. Tolkachev include 81,579 shares of common stock held of record by Mr. Tolkachev and immediately exercisable options to acquire 68,421 shares of our common stock at an exercise price of $4.75. This option expires on July 18, 2010.
(3) The shares attributed to Mr. Tolmakov include 3,265,365 shares held of record by Mr. Tolmakov and 2,986,595 shares held of record by Simage Limited. Simage Limited is a company owned by Mr. Tolmakov. Mr. Tolmakov is the General Director of our wholly-owned subsidiary Emir Oil LLP.
(4) This includes shares awarded as restricted stock grants on January 1, 2010. Please see the Recent Sales of Unregistered Securities section of Item 5 Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities on page 34 of this report for details regarding the amount, terms and conditions of such grants.
(5) The percentages reflect the increase in the number of common shares that would be issued in connection with the exercise of outstanding options held by the individual.
Mr. Baimoldin, Mr. Kulumbetov, Mr. Ler and Mr. Tashtitov are executive officers of the Company. Mr. Cherdabayev, Mr. Kerr, Mr. Nilson, Dr. Smith, Mr. Stillman, Mr. Tashtitov and Mr. Tolkachev comprise the board of directors of the Company.
Change in Control
To the knowledge of the management, there are no present arrangements or pledges of our securities the operation of which may at a subsequent date result in a change in control of the Company.
Securities Authorized for Issuance Under Equity Compensation Plans
As of June 2, 2010, shares of our common stock were subject to issuance upon the exercise of outstanding options or warrants as set forth below.
Plan category
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
(a)
Weighted-average
exercise price of
outstanding
options, warrants
and rights
(b)
Number of securities
remaining available for future issuance under equity
compensation plans
(excluding securities
reflected in columns (a))
(c)
Equity compensation plans approved by security holders
920,783
$5.04
4,025,000
Equity compensation plans not approved by security holders
n/a
n/a
Total
920,783
$5.04
4,025,000
On July 18, 2005 our Board of Directors approved stock option grants under our 2004 Stock Incentive Plan. The total number of option grants was 820,783. The options are exercisable at a price of $4.75, the closing price of our common stock on the OTCBB on July 18, 2005. The options expire five years from the grant date. The options vested immediately. Among the parties receiving stock options were the following executive officers and directors:
Name
Positions with Company
Options Granted
Boris Cherdabayev
Director
410,256
Valery Tolkachev
Director
68,421
In January 2006, we entered into a separation agreement with our former CFO, Anuar Kulmagambetov, to issue Mr. Kulmagambetov an option to purchase up to 100,000 shares of restricted common stock of the Company at $7.40 per share expiring five years from the date of grant.
Item 13.
Item 13. Certain Relationships and Related Transactions and Director Independence
Related Party Transactions
In accordance with the written policy adopted by our board of directors and the NYSE Amex listing standards, our audit committee is charged with monitoring and reviewing issues involving potential conflicts of interests and reviewing and approving all related party transactions. In general, for purposes of the Company’s written policy, a related party transaction is a transaction, or a material amendment to any such transaction, involving a related party and the Company involving $120,000 or more. Our policy requires the audit committee to review and approve related party transactions. In reviewing and approving any related party transaction or material amendment to any such transaction, the audit committee must satisfy itself that it has been fully informed as to the related party’s relationship to the Company and interest in the transaction and as to the material facts of the transaction, and must determine that the related party transaction is fair to the Company.
During our fiscal 2010, 2009 and 2008 we leased land, oil storage facilities and office and warehouse space in Aktau, Kazakhstan from Term Oil LLC. During the fiscal years ended March 31, 2010, 2009 and 2008 we paid Term Oil $96,541, $221,903 and $254,427, respectively for the use of these facilities. Toleush Tolmakov, a BMB shareholder and the General Director of Emir Oil, is the sole owner of Term Oil. We expect to continue to lease these facilities during our 2011 fiscal year.
On June 26, 2009 we entered into a Debt Purchase Agreement with Simage Limited, a British Virgin Islands international business corporation (“Simage”). Simage is a company owned by Toleush Tolmakov. Prior to the date of the Debt Purchase Agreement, Simage had acquired by assignment, certain accounts receivable owed by Emir to third-party creditors of Emir in the amount of $5,973,185 (the “Obligations”). Pursuant to the terms of the Agreement, Simage assigned to the Company all rights, title and interests in and to the Obligations in exchange for the issuance of 2,986,595 shares of common stock of the Company. The market value of the shares of common stock issued to Simage, at the agreement date, was $3,076,193. The market value was based on $1.03 per share, which was the closing market price of the Company’s shares on June 26, 2009.
As a result of this Agreement, the Company has effectively been released of accounts payable obligations amounting to $5,973,185. The Company has treated this Agreement as a related party transaction, due to the fact that Simage is owned by a Company shareholder. Therefore, the difference between the settled amount of accounts payable and the value of the common stock issued, which amounts to $2,896,997, has been treated as a capital contribution by the shareholder and recognized as an addition to additional-paid-in-capital rather than a gain on settlement of debt.
On March 31, 2010 Emir Oil entered into an agreement for the Conduction of 3D Seismic Survey with Geo Seismic Service LLP (“Geo Seismic”) to carry out 3D seismic exploration activities of the Begesh, Aday, North Aday and West Aksaz structures, an area of approximately 96 square kilometers within the Company’s Northwest Block. In exchange for these services, Emir will pay Geo Seismic 570,000,000 Kazakh tenge ($3,800,000 USD). In lieu of payment in Kazakh tenge, Emir, at its sole election, may deliver restricted shares of BMB common stock at the agreed value of the higher of: (i) the average closing price of BMB Munai, Inc. common shares over the five days prior to final acceptance by Emir of the 3D seismic work; or (ii) $2.00 per share. The maximum number of shares which may be delivered as payment in full shall not exceed 1,900,000 restricted common shares. Toleush Tolmakov is a 30% owner of Geo Seismic.
As discussed above in Item 11. Executive Compensation on December 31, 2009, we entered into a Consulting Agreement with Boris Cherdabayev, the Chairman of our board of directors. Pursuant to the Consulting Agreement, in addition to his services as Chairman of the board of directors, Mr. Cherdabayev will provide such consulting and other services as may reasonably requested by Company management. The Consulting Agreement is for an initial term of five years and provides for an annual salary, net of Kazakhstani social taxes and social insurance. We anticipate payments to Mr. Cherdabayev under the Consulting Agreement during our 2011 fiscal year will be at least $192,000. See Item 11. Executive Compensation beginning on page 64 of this report for additional information regarding the Consulting Agreement and compensation paid to Mr. Cherdabayev.
Director Independence
The board of directors has determined that Boris Cherdabayev the Chairman of our board of directors and Askar Tashtitov, our Company president would not be considered “independent directors” as that term is defined in the listing standards of the NYSE Amex. The board of directors has determined that Jason Kerr, Troy Nilson, Leonard Stillman, Daymon Smith and Valery Tolkachev are “independent directors” as that term is defined in the listing standards of the NYSE Amex. Such independence definition includes a series of objective tests, including that the director is not an employee of the company and has not engaged in various types of business dealings with the company. In addition, as further required by NYSE Amex listing standards, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board of directors, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.
Item 14.
Item 14. Principal Accountant Fees and Services
Hansen, Barnett and Maxwell, P.C. served as the Company’s independent registered public accounting firm for the years ended March 31, 2010 and 2009 and is expected to serve in that capacity for the 2011 fiscal year. Principal accounting fees for professional services rendered for us by Hansen, Barnett & Maxwell, P.C. for the years ended March 31, 2010 and 2009, are summarized as follows:
Fiscal
Fiscal
Audit
$ 231,949
$ 164,221
Audit related
37,225
13,585
Tax
34,444
2,777
All other
-
-
Total
$ 303,618
$ 180,583
Audit Fees. Audit fees were for professional services rendered in connection with the audit of the financial statements included in our Annual Report on Form 10-K and review of the financial statements included in our Quarterly Reports of Form 10-Q and for services normally provided by our independent registered public accounting firm in connection with statutory and regulatory filings or engagements and fees for Sarbanes-Oxley 404 audit work.
Tax Fees. Hansen Barnett & Maxwell, P.C. billed us an aggregate of $34,444 for professional services rendered for tax compliance, tax advice and tax planning within the United States for the fiscal year ended March 31, 2009.
Audit Committee Pre-Approval Policies and Procedures. The Audit Committee had not, as of the time of filing this Annual Report on Form 10-K with the Securities and Exchange Commission, adopted policies and procedures for pre-approving all audit services and permitted non-audit services to be performed by our independent auditors. Instead, the Audit Committee has adopted a practice to meet as a whole to pre-approve any such services prior to the time they are performed. In the future, our Audit Committee may adopt pre-approval policies and procedures to approve the services of our independent registered public accounting, provided the policies and procedures are detailed as to the particular service, the Audit Committee is informed of each service, and such policies and procedures do not include delegation of the Audit Committee’s responsibilities to our management.
The Audit Committee has determined that the provision of services by Hansen, Barnett & Maxwell, P.C. described above are compatible with maintaining Hansen, Barnett & Maxwell, P.C.’s independence as our independent registered public accounting firm.
Item 15.
Item 15. Exhibits, Financial Statement Schedules
(a) The following documents are filed as part of this report:
Financial Statements
Report of Independent Registered Public Accounting Firm - Hansen, Barnett & Maxwell, P.C. dated June 23, 2010
Consolidated Balance Sheets as of March 31, 2010 and 2009
Consolidated Statements of Operations for the years ended March 31, 2010, 2009 and
Consolidated Statements of Shareholders’ Equity for the years ended March 31, 2010, 2009 and
Consolidated Statements of Cash Flows for the years ended March 31, 2010, 2009 and
Notes to the Consolidated Financial Statements
Supplementary Financial Information of Oil and Natural Gas Exploration, Development and Production Activities (unaudited)
Financial Statement Schedules
Schedules are omitted because the required information is either inapplicable or presented in the consolidated financial statements or related notes.
Exhibits
Exhibit No.
Exhibit Description
2.1
Certificate of Merger dated February 15, 1994(1)
2.2
Plan and Agreement of Merger dated February 15, 1994(2)
2.3
Plan and Agreement of Merger(7)
3.1
Certificate of Incorporation of AU ‘N AUG dated February 15, 1994(1)
3.2
Certificate of Amendment to Certificate of Incorporation of AU ‘N AUG dated April 11, 1994(1)
3.3
Certificate of Amendment to Certificate of Incorporation of InterUnion Financial Corporation dated October 17, 1994(1)
3.4
Amended Certificate of Incorporation(8)
3.5
Articles of Incorporation of BMB Munai, Inc.(13)
3.6
Amendment to Articles of Incorporation of BMB Munai, Inc.(16)
3.7
Bylaws of InterUnion Financial Corporation(1)
3.8
Amended By-Laws(11)
3.9
By-Laws of BMB Munai, Inc. (as amended through January 13, 2005)(13)
3.10
By-Laws of BMB Munai, Inc. (as amended through June 23, 2006)(16)
3.11
Certificate of Amendment of By-Laws of BMB Munai, Inc. (as amended through March 26, 2008) (22)
4.1
Instruments Defining the Rights of Security Holders Including Indentures(2)
4.2
BMB Munai, Inc. 2004 Stock Incentive Plan(12)
4.3
Registration Rights Agreement dated December 2005(15)
4.4
Trust Deed Relating to U.S. $60,000,000 5.0 per cent Convertible Notes due 2012(19)
4.5
Registration Rights Agreement dated July 13, 2007(19)
4.6
Paying and Conversion Agency Agreement dated July 13, 2007(19)
4.7
Form of 5.0% Convertible Notes due 2012(19)
4.8
Indenture dated September 19, 2007(20)
4.9
Form of 5.0% Convertible Senior Note due 2012(20)
4.10
BMB Munai, Inc. 2009 Equity Incentive Plan(23)
10.1
ITM Software Development Agreement(2)
10.2
Letter of Understanding dated November 30, 1995(2)
10.3
Investment Management Agreement dated December 20, 1995(3)
10.4
Agreement between Havensight Holdings Ltd. and InterUnion Financial Corporation dated January 19, 1995(3)
10.5
Letter of Understanding dated September 26, 1996(4)
10.6
Letter Agreement dated January 7, 1997(4)
10.7
Amendment to Letter of Understanding dated April 16, 1997(5)
10.8
Services Agreement dated July 5, 2002(6)
10.9
Agency Agreement dated November 26, 2003(7)
10.10
Share Purchase and Sale Agreement dated May 24, 2004(9)
10.11
Addendum No.3 to Emir Oil Contract(14)
10.12
Form Restricted Stock Agreement of BMB Munai, Inc. dated March 30, 2007 (17)
10.13
Form Employment Agreement(18)
10.14
Placement Agreement dated July 13, 2007(19)
10.15
Indenture dated September 19, 2007(20)
10.16
Consulting Agreement dated November 19, 2007(21)
10.17
Addendum No. 5 to Emir Oil Contract(24)
10.18
Form Restricted Stock Agreement of BMB Munai, Inc. dated July 17, 2008 (25)
10.19
Employment Agreement - Leonard Stillman(25)
10.20
Revised Consulting Agreement dated September 16, 2008(26)
10.21
Addendum No. 6 to Emir Oil Contract(27)
10.22
Addendum No. 7 to Emir Oil Contract(28)
10.23
Contract No. EO-EAO/30-12 for the Sales and Purchase of Crude Oil (export) (29)
10.24
Additional Agreement #9A to the Contract No. EO-EAO/30-12(29)
10.25
Enclosure #1 to the Contract No. EO-EAO/30-12(29)
10.26
Additional Agreement #27A to the Contract No. EO-EAO/30-12(29)
10.27
Debt Purchase Agreement, dated June 26, 2009, between BMB Munai, Inc. and Simage Limited(30)
10.28
Form of BMB Munai, Inc. Restricted Stock Agreement dated January 1, 2010(31)
10.29
Form of Employment Agreement dated December 31, 2009(31)
10.30
Consulting Agreement, dated December 31, 2009, between BMB Munai, Inc. and Boris Cherdabayev(31)
10.31
Conduction of 3D Seismic Survey, dated March 31, 2010, between “Geo Seismic Services” LLP and “Emir-Oil” LLP(32)
10.32
Supplemental Indenture No. 1, dated June 1, 2010, between BMB Munai, Inc. and The Bank of New York Mellon, as trustee(33)
12.1
Computation of Earnings to Fixed Charges
14.1
Code of Ethics(10)
21.1
Subsidiaries
23.1
Consent of Chapman Petroleum Engineering Ltd., Independent Petroleum Engineers*
23.2
Consent of Hansen, Barnett & Maxwell, P.C., Independent Registered Public Accounting Firm*
31.1
Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002*
31.2
Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002*
32.1
Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2
Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
99.1
Chapman Petroleum Engineering Ltd. Letter on its estimation of our proved oil and gas reserves at March 31, 2010*
* Filed herewith.
(1) Incorporated by reference to the Registration Statement of the Registrant on Form 10-SB filed with the Commission on August 7, 1996.
(2) Incorporated by reference to the Amended Registration Statement of the Registrant on Form 10-SB/A filed with the Commission on November 14, 1996.
(3) Incorporated by reference to the Amended Registration Statement of the Registrant on Form 10-SB/A filed with the Commission on March 31, 1997.
(4) Incorporated by reference to the Amended Registration Statement of the Registrant on Form 10-SB/A filed with the Commission on April 15, 1997.
(5) Incorporated by reference to Registrant’s Annual Report on Form 10-KSB filed with the Commission on June 20, 1997.
(6) Incorporated by reference to the Registration Statement of the Registrant on S-8 filed with the Commission on August 30, 2002.
(7) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on December 11, 2003.
(8) Incorporated by reference to Registrant’s Quarterly Report on Form 10-QSB filed with the Commission on February 20, 2004.
(9) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on May 25, 2004.
(10) Incorporated by reference to Registrant’s Annual Report on Form 10-KSB filed with the Commission on June 29, 2004.
(11) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on September 3, 2004.
(12) Incorporated by reference to Registrant’s Definitive Proxy Statement on Schedule 14A filed with the Commission on September 20, 2004.
(13) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on January 18, 2005.
(14) Incorporated by reference to Registrant’s Quarterly Report on Form 10-QSB filed with the Commission on February 14, 2005.
(15) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on December 29, 2005.
(16) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on June 26, 2006.
(17) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on April 5, 2007.
(18) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on April 12, 2007.
(19) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on July 19, 2007.
(20) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on September 25, 2007.
(21) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on November 21, 2007.
(22) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on April 1, 2008.
(23) Incorporated by reference to Registrant’s Revised Definitive Proxy Statement on Schedule 14A filed with the Commission on June 23, 2008.
(24) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on June 25, 2008.
(25) Incorporated by reference to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 11, 2008.
(26) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on September 16, 2008.
(27) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on October 21, 2008.
(28) Incorporated by reference to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on February 6, 2009.
(29) Incorporated by reference to Registrant’s Annual Report on Form 10-K filed with the Commission on June 15, 2009.
(30) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on June 29, 2009.
(31) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on January 6, 2010.
(32) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on April 6, 2010.
(32) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on June 11, 2010.
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 by the undersigned, thereunto duly authorized.
BMB MUNAI, INC.
Date: June 23, 2010
By:
/s/ Gamal Kulumbetov
Gamal Kulumbetov
Chief Executive Officer
(Duly Authorized Representative)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dated indicated.
Signatures
Title
Date
/s/ Gamal Kulumbetov
Chief Executive Officer
June 23, 2010
Gamal Kulumbetov
/s/ Evgeny Ler
Chief Financial Officer
June 23, 2010
Evgeny Ler
/s/ Boris Cherdabayev
Chairman of the Board of Directors
June 23, 2010
Boris Cherdabayev
/s/ Jason Kerr
Director
June 23, 2010
Jason Kerr
/s/ Troy Nilson
Director
June 23, 2010
Troy Nilson
/s/ Daymon Smith
Director
June 23, 2010
Daymon Smith
/s/ Leonard Stillman
Director
June 23, 2010
Leonard Stillman
/s/ Askar Tashtitov
Director
June 23, 2010
Askar Tashtitov
/s/ Valery Tolkachev
Director
June 23, 2010
Valery Tolkachev
CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED MARCH 31, 2010, 2009 AND
Page
Report of Independent Registered Public Accounting Firm - Hansen, Barnett & Maxwell P.C.
Consolidated Balance Sheets as of March 31, 2010 and 2009
Consolidated Statements of Operations for the years ended March 31, 2010, 2009 and
Consolidated Statements of Shareholders’ Equity for the years ended March 31, 2010, 2009 and 2008
Consolidated Statements of Cash Flows for the years ended March 31, 2010, 2009 and
Notes to the Consolidated Financial Statements
Supplementary Financial Information on Oil and Natural Gas Exploration, Development, and Production Activities (unaudited)
HANSEN, BARNETT & MAXWELL, P.C.
A Professional Corporation
CERTIFIED PUBLIC ACCOUNTANTS
Triad Center, Suite 750
Salt Lake City, UT 84180-1128
Phone: (801) 532-2200
Fax: (801) 532-7944
www.hbmcpas.com
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of BMB Munai, Inc.
We have audited the accompanying consolidated balance sheets of BMB Munai, Inc. and subsidiary as of March 31, 2010 and 2009, and the related consolidated statements of operations, shareholder’s equity, and cash flows for each of the years in the three-year period ended March 31, 2010. BMB Munai, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BMB Munai, Inc. and subsidiary as of March 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended March 31, 2010 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), BMB Munai, Inc.’s internal control over financial reporting as of March 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated June 23, 2010 expressed an unqualified opinion.
/s/ Hansen, Barnett & Maxwell, P.C.
HANSEN, BARNETT & MAXWELL, P.C.
Salt Lake City, Utah
June 23,
BMB MUNAI, INC.
CONSOLIDATED BALANCE SHEETS
Notes
March 31, 2010
March 31, 2009
ASSETS
CURRENT ASSETS
Cash and cash equivalents
$ 6,440,394
$ 6,755,545
Trade accounts receivable
6,423,402
3,081,573
Prepaid expenses and other assets, net
4,083,917
3,054,078
Total current assets
16,947,713
12,891,196
LONG TERM ASSETS
Oil and gas properties, full cost method, net
238,601,842
238,728,413
Gas utilization facility
13,569,738
13,470,631
Inventories for oil and gas projects
13,717,847
14,002,146
Prepayments for materials used in oil and gas projects
141,312
122,040
Other fixed assets, net
3,815,422
3,629,108
Long term VAT recoverable
3,113,939
2,423,940
Convertible notes issue cost
1,201,652
2,490,370
Restricted cash
770,553
588,217
Total long term assets
274,932,305
275,454,865
TOTAL ASSETS
$ 291,880,018
$ 288,346,061
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable
$ 3,948,851
$ 21,771,137
Accrued coupon payment
641,667
641,667
Taxes Payable, Accrued liabilities and other payables
4,802,361
1,697,097
Total current liabilities
9,392,879
24,109,901
LONG TERM LIABILITIES
Convertible notes issued, net
62,178,119
61,331,521
Liquidation fund
4,712,345
4,263,994
Deferred taxes
4,964,382
6,516,444
Capital lease liability
369,801
-
Total long term liabilities
72,224,647
72,111,959
COMMITMENTS AND CONTINGENCIES
-
-
SHAREHOLDERS’ EQUITY
Preferred stock - $0.001 par value; 20,000,000 shares authorized; no shares issued or outstanding
-
-
Common stock - $0.001 par value; 500,000,000 shares authorized, 51,865,015 and 47,378,420
shares outstanding, respectively
51,865
47,378
Additional paid in capital
160,653,969
151,513,638
Retained earnings
49,556,658
40,563,185
Total shareholders’ equity
210,262,492
192,124,201
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY
$ 291,880,018
$ 288,346,061
The accompanying notes are an integral part of these consolidated financial statements.
BMB MUNAI, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
Notes
Year ended
March 31, 2010
Year ended
March 31, 2009
Year ended
March 31, 2008
REVENUES
$ 57,274,526
$ 69,616,875
$ 60,196,626
COSTS AND OPERATING EXPENSES
Rent export tax
10,032,857
467,359
-
Export duty
-
6,783,278
-
Oil and gas operating
8,568,453
7,530,653
5,515,403
General and administrative
14,042,577
22,262,248
14,747,754
Consulting expenses
-
8,662,500
-
Depletion
11,075,590
10,403,328
9,419,655
Interest expense
4,604,446
1,138,874
-
Amortization and depreciation
613,953
324,028
239,155
Accretion expense
448,351
449,025
254,572
Total costs and operating expenses
49,386,227
58,021,293
30,176,539
INCOME FROM OPERATIONS
7,888,299
11,595,582
30,020,087
OTHER INCOME / (EXPENSE)
Foreign exchange (loss)/gain, net
(353,401)
2,592,341
47,362
Disgorgement funds received
-
1,650,293
-
Interest income
275,136
391,223
1,257,666
Other expense, net
(368,623)
(100,153)
(118,133)
Total other (expense)/income
(446,888)
4,533,704
1,186,895
INCOME BEFORE INCOME TAXES
7,441,411
16,129,286
31,206,982
INCOME TAX BENEFIT
1,552,062
1,028,272
103,582
NET INCOME
$ 8,993,473
$ 17,157,558
$ 31,310,564
BASIC NET INCOME PER COMMON SHARE
$ 0.18
$ 0.37
$ 0.70
DILUTED NET INCOME PER COMMON SHARE
$ 0.18
$ 0.37
$ 0.70
The accompanying notes are an integral part of these consolidated financial statements.
BMB MUNAI, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
The accompanying notes are an integral part of these consolidated financial statements.
BMB MUNAI, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Notes
Year ended
March 31,
Year ended
March 31,
Year ended
March 31,
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income
$ 8,993,473
$ 17,157,558
$ 31,310,564
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion
11,075,590
10,403,328
9,419,655
Depreciation and amortization
613,953
324,028
239,155
Interest expense
4,604,446
1,138,874
-
Accretion expense
448,351
449,025
254,572
Stock based compensation expense
3,171,633
7,450,211
2,303,078
Stock issued for services
-
7,662,500
-
(Recovery of provision)/provision expense for uncollectible advances and prepayments
-
(121,302)
135,502
Loss on disposal of fixed assets
14,230
113,666
75,883
Income tax benefit
(1,552,062)
(1,028,272)
(103,582)
Changes in operating assets and liabilities
(Increase)/decrease in trade accounts receivable
(3,341,829)
2,784,139
(1,871,050)
(Increase)/decrease in prepaid expenses and other assets
(1,029,839)
482,485
(1,490,739)
(Increase)/decrease in VAT recoverable
(689,999)
5,682,457
(3,755,338)
(Decrease)/increase in current liabilities
(8,212,967)
884,441
13,463,494
Net cash provided by operating activities
14,094,980
53,383,138
49,981,194
CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase and development of oil and gas properties
(7,296,163)
(47,495,078)
(68,331,668)
Purchase of other fixed assets
(898,870)
(5,369,509)
(2,110,809)
Cash paid for convertible notes coupon, capitalized as oil and gas properties
-
(3,000,000)
(1,500,000)
Increase in inventories and prepayments for materials used in oil and gas projects
(2,957,762)
(8,086,324)
(26,394,755)
Increase in gas utilization facility/construction in progress
(75,000)
-
(2,798,498)
(Increase)/decrease in restricted cash
(182,336)
34,480
(319,000)
Net cash used in investing activities
(11,410,131)
(63,916,431)
(101,454,730)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of convertible debt
-
-
56,210,763
Proceeds from exercise of common stock options and warrants
-
50,001
328,670
Cash paid for convertible notes coupon
(3,000,000)
-
-
Net cash (used in)/provided by financing activities
(3,000,000)
50,001
56,539,433
NET CHANGE IN CASH AND CASH EQUIVALENTS
(315,151)
(10,483,292)
5,065,897
CASH AND CASH EQUIVALENTS at beginning of year
6,755,545
17,238,837
12,172,940
CASH AND CASH EQUIVALENTS at end of year
$ 6,440,394
$ 6,755,545
$ 17,238,837
The accompanying notes are an integral part of these consolidated financial statements.
BMB MUNAI, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
Year ended
March 31,
Year ended
March 31,
Year ended
March 31,
Non-Cash Investing and Financing Activities
Asset retirement obligation incurred in property development, net of estimate revision
$ -
$ 86,438
$ 1,308,130
Transfers from oil and gas properties, construction in progress and other fixed assets to gas utilization facility
24,107
13,470,631
-
Coupon payments on convertible notes, capitalized as part of oil and gas properties
-
2,250,000
2,141,667
Accretion of discount on convertible notes, capitalized as part of oil and gas properties
-
596,654
535,455
Amortization of convertible notes issue costs, capitalized as part of oil and gas properties
-
568,386
541,019
Depreciation on other fixed assets capitalized as oil and gas properties
454,174
353,545
180,804
Addition of other fixed assets under capital lease contract
369,801
-
-
Issuance of common stock for the settlement of liabilities
5,973,185
-
-
Transfer of inventory and prepayments for materials used in oil and gas projects to oil and gas properties
3,147,789
16,284,487
15,236,315
Supplemental Cash Flow Information
Cash paid for interest
$ 3,000,000
$ 3,000,000
$ 1,500,000
The accompanying notes are an integral part of these consolidated financial statements.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - DESCRIPTION OF BUSINESS
The corporation now known as BMB Munai, Inc. (“BMB Munai” or the “Company”), a Nevada corporation, was originally incorporated in Utah in July 1981. On February 7, 1994, the corporation changed its name to InterUnion Financial Corporation (“InterUnion”) and its domicile to Delaware. BMB Holding, Inc. (“BMB Holding”) was incorporated on May 6, 2003 for the purpose of acquiring and developing oil and gas fields in the Republic of Kazakhstan. On November 26, 2003, InterUnion executed an Agreement and Plan of Merger (the “Agreement”) with BMB Holding. As a result of the merger, the shareholders of BMB Holding obtained control of the corporation. BMB Holding was treated as the acquirer for accounting purposes. A new board of directors was elected that was comprised primarily of the former directors of BMB Holding and the name of the corporation was changed to BMB Munai, Inc. BMB Munai changed its domicile from Delaware to Nevada on December 21, 2004.
The Company’s consolidated financial statements presented are a continuation of BMB Holding, and not those of InterUnion Financial Corporation, and the capital structure of the Company is now different from that appearing in the historical financial statements of InterUnion Financial Corporation due to the effects of the recapitalization.
The Company has a representative office in Almaty, Republic of Kazakhstan.
From inception (May 6, 2003) through January 1, 2006 the Company had minimal operations and was considered to be in the development stage. The Company began generating significant revenues in January 2006 and is no longer in the development stage.
Currently the Company has completed twenty-four wells. As discussed in more detail in Note 2, the Company engages in exploration of its licensed territory pursuant to an exploration license and has not yet applied for or been granted a commercial production license.
NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES
Business condition
As further discussed in detail in Note 11, in July 2007 the Company issued 5.0% Convertible Senior Notes due 2012 in the amount of $60,000,000. Among other terms of the Notes, the Noteholders had the right to require the Company redeem all or a portion of the notes on three separate dates, including July 13, 2010. The first two dates passed without the redemption right being exercised. The Company and the Noteholders are in the process of negotiating a restructuring of the Notes and on June 7, 2010 entered into Supplemental Indenture No. 1 dated June 1, 2010 that grants a fourth put date that commenced June 13, 2010 and expires September 13, 2010. The intent of the fourth put date is to allow time to work out a debt restructuring agreeable to all parties.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
If the Company and Noteholders are not able to agree on a debt restructuring, and the Noteholders exercise their redemption right, the Company will need to pursue other financing options and there is no guarantee that they can be obtained.
Prior to entering into the Supplemental Indenture, the Company was in default under certain covenants contained in Article 9 of the Indenture requiring the Company to maintain a minimum net debt to equity ratio and to comply with certain notice, delivery and other provisions. In the context of the Indenture, the equity portion of the ratio is determined by reference to the market value of the Company’s common stock, not the Company’s book value. The market value of the Company’s stock has declined since the Notes were issued. The Noteholders have separately agreed to contingently waive these defaults until the earlier of: (i) September 1, 2010 or (ii) the fourth put date (as contained in the Supplemental Indenture), with the understanding that such waiver shall not constitute a waiver of any default under the Indenture that remains ongoing as of September 1, 2010 or occurs after June 8, 2010. The Company currently believes it will not be able to remedy the net debt to equity ratio covenant by September 1, 2010 and, therefore, anticipates it will be in default under the Indenture at that time unless a future waiver is obtained from the Noteholders. There is no assurance the Noteholders will provide any future waiver or any further extension of their redemption put rights under the Indenture.
Basis of consolidation
The Company’s consolidated financial statements present the consolidated results of BMB Munai, Inc., and its wholly owned subsidiary, Emir Oil LLP (hereinafter collectively referred to as the “Company”). All significant inter-company balances and transactions have been eliminated from the Consolidated Financial Statements.
Reclassifications
Certain reclassifications have been made in the financial statements for the year ended March 31, 2009 to conform to the March 31, 2010 presentation. The reclassifications had no effect on net income.
Use of estimates
The preparation of Consolidated Financial Statements in conformity with US GAAP requires management to make estimates and assumptions that affect certain reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements and revenues and expenses during the reporting period. Accordingly, actual results could differ from those estimates and affect the results reported in these Consolidated Financial Statements.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Concentration of credit risk and accounts receivable
Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and accounts receivable. The Company places its cash with high credit quality financial institutions. Substantially all of the Company’s accounts receivable are from purchasers of oil and gas. Oil and gas sales are generally unsecured. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectable. Accordingly, no allowance for doubtful accounts has been provided.
Licences and contracts
Emir Oil LLP is the operator of the Company’s oil and gas fields in Western Kazakhstan. The Government of the Republic of Kazakhstan (the “Government”) initially issued the license to Zhanaozen Repair and Mechanical Plant on April 30, 1999 to explore the Aksaz, Dolinnoe and Emir oil and gas fields (the “ADE Block” or the “ADE Fields”). On June 9, 2000, the contract for exploration of the Aksaz, Dolinnoe and Emir oil and gas fields was entered into between the Agency of the Republic of Kazakhstan on Investments and the Zhanaozen Repair and Mechanical Plant. On September 23, 2002, the contract was assigned to Emir Oil LLP. On September 10, 2004, the Government extended the term of the contract for exploration and License from five years to seven years through July 9, 2007. On February 27, 2007, the Ministry of Energy and Mineral Resources of the Republic of Kazakhstan (the “MEMR”) granted a second extension of the Company’s exploration contract. Under the terms of the contract extension, the exploration period was extended to July 2009 over the entire exploration contract territory. On December 7, 2004, the Government assigned to Emir Oil LLP exclusive right to explore an additional 260 square kilometers of land adjacent to the ADE Block, which is referred to as the “Southeast Block.” The Southeast Block includes the Kariman field and the Yessen and Borly structures and is governed by the terms of the Company’s original contract. On June 24, 2008, the MEMR agreed to extend the exploration stage of the Company’s contract from July 2009 to January 2013 in order to permit the Company to conduct additional exploration drilling and testing activities within the ADE Block and the Southeast Block.
On October 15, 2008, the MEMR approved Addendum # 6 to Contract No. 482 with Emir Oil LLP, dated June 09, 2000 extending Emir Oil LLP’s exploration territory from 460 square kilometers to a total of 850 square kilometers (approximately 210,114 acres). The additional territory is located to the north and west of the Company’s current exploration territory, extending the exploration territory toward the Caspian Sea and is referred to herein as the “Northwest Block.”
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
To move from the exploration stage to the commercial production stage, the Company must apply for and be granted a commercial production contract. The Company is legally entitled to apply for a commercial production contract and has an exclusive right to negotiate this contract. The Government is obligated to conduct these negotiations under the Law of Petroleum in Kazakhstan. If the Company does not move from the exploration stage to the commercial production stage, it has the right to produce and sell oil, including export oil, under the Law of Petroleum for the term of its existing contract.
Major customers
During the years ended March 31, 2010, 2009 and 2008, sales to one customer represented 95%, 81% and 91% of total sales, respectively. At March 31, 2010, 2009 and 2008, this customer made up 100%, 100% and 97% of accounts receivable, respectively. While the loss of this foregoing customer could have a material adverse effect on the Company in the short-term, the loss of this customer should not materially adversely affect the Company in the long-term because of the available market for the Company’s crude oil and natural gas production from other purchasers.
Foreign currency translation
Transactions denominated in foreign currencies are reported at the rates of exchange prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to United States Dollars at the rates of exchange prevailing at the balance sheet dates. Any gains or losses arising from a change in exchange rates subsequent to the date of the transaction are included as an exchange gain or loss in the Consolidated Statements of Operations.
Share-based compensation
The Company accounts for options granted to non-employees at their fair value in accordance with FASC Topic 718 - Stock Compensation. Share-based compensation is determined as the fair value of the equity instruments issued. The measurement date for these issuances is the earlier of the date at which a commitment for performance by the recipient to earn the equity instruments is reached or the date at which the recipient’s performance is complete. Stock options granted to the “selling agents” in the private equity placement transactions have been offset to the proceeds as a cost of capital. Stock options and stocks granted to other non-employees are recognized in the Consolidated Statements of Operations.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The Company has a stock option plan as described in Note 15. Compensation expense for options and stock granted to employees is determined based on their fair values at the time of grant, the cost of which is recognized in the Consolidated Statements of Operations over the vesting periods of the respective options.
Share-based compensation incurred for the years ended March 31, 2010, 2009 and 2008 was $3,171,633, $7,450,211 and $2,303,078, respectively.
Risks and uncertainties
The ability of the Company to realize the carrying value of its assets is dependent on being able to develop, transport and market oil and gas. Currently exports from the Republic of Kazakhstan are primarily dependent on transport routes either via rail, barge or pipeline, through Russian territory. Domestic markets in the Republic of Kazakhstan historically and currently do not permit world market price to be obtained. Management believes that over the life of the project, transportation options will improve as additional pipelines and rail-related infrastructure are built that will increase transportation capacity to the world markets; however, there is no assurance that this will happen in the near future.
Recognition of revenue and cost
Revenue and associated costs from the sale of oil are charged to the period when persuasive evidence of an arrangement exists, the price to the buyer is fixed or determinable, collectability is reasonably assured, delivery of oil has occurred or when ownership title transfers. Produced but unsold products are recorded as inventory until sold.
During the year ended March 31, 2010, the Company purchased light crude oil from a third party for the purpose of blending the oil with the Company’s own production. The cost of this purchased crude oil is recorded as part of oil and gas operating expenses.
Export duty
The formula for determining the amount of the crude oil export duty is based on a sliding scale that is tied to the world market price for oil. The amount of the export duty can change with fluctuations in world oil prices. The export duty fees are expensed as incurred and are classified as costs and operating expenses.
In December 2008 the Government of the Republic of Kazakhstan issued a resolution that cancelled the export duty effective January 26, 2009 for companies operating under the new tax code.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Mineral extraction tax
The mineral extraction tax replaced the royalty expense the Company had paid. The rate of this tax depends on annual production output. The new code currently provides for a 5% mineral extraction tax rate (6% starting from 2013 and 7% starting from 2014) on production sold to the export market, and a 2.5% tax rate (3% in 2013 and 3.5% starting from 2014) on production sold to the domestic market. The mineral extraction tax expense is reported as part of oil and gas operating expense.
Rent export tax
This tax is calculated based on the export sales price and ranges from as low as 0%, if the price is less than $40 per barrel, to as high as 32%, if the price per barrel exceeds $190. Rent export tax is expensed as incurred and is classified as costs and operating expenses.
Income taxes
Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred taxes are provided on differences between the tax bases of assets and liabilities and their reported amounts in the financial statements, and tax carryforwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.
Fair value of financial instruments
The carrying values reported for cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their respective fair values in the accompanying balance sheet due to the short-term maturity of these financial instruments. In addition, the Company has long-term debt with financial institutions. The carrying amount of the long-term debt approximates fair value based on current rates for instruments with similar characteristics.
Cash and cash equivalents
The Company considers all demand deposits, money market accounts and marketable securities purchased with an original maturity of three months or less to be cash and cash equivalents. The fair value of cash and cash equivalents approximates their carrying amounts due to their short-term maturity.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Prepaid expenses and other assets
Prepaid expenses and other assets are stated at their net realizable values after deducting provisions for uncollectible amounts. Such provisions reflect either specific cases or estimates based on evidence of collectability. The fair value of prepaid expense and other asset accounts approximates their carrying amounts due to their short-term maturity.
Prepayments for materials used in oil and gas projects
The Company periodically makes prepayments for materials used in oil and gas projects. These prepayments are presented as long term assets due to their transfer to oil and gas properties after materials are supplied and the prepayments are closed.
Inventories
Inventories of equipment for development activities, tangible drilling materials required for drilling operations, spare parts, diesel fuel, and various materials for use in oil field operations are recorded at the lower of cost and net realizable value. Under the full cost method, inventory is transferred to oil and gas properties when used in exploration, drilling and development operations in oilfields.
Inventories of crude oil are recorded at the lower of cost or net realizable value. Cost comprises direct materials and, where applicable, direct labor costs and overhead, which has been incurred in bringing the inventories to their present location and condition. Cost is calculated using the weighted average method. Net realizable value represents the estimated selling price less all estimated costs to completion and costs to be incurred in marketing, selling and distribution.
The Company periodically assesses its inventories for obsolete or slow moving stock and records an appropriate provision, if there is any. The Company has assessed inventory at March 31, 2010 and no provision for obsolete inventory has been provided.
Oil and gas properties
The Company uses the full cost method of accounting for oil and gas properties. Under this method, all costs associated with acquisition, exploration, and development of oil and gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. These costs do not include any costs related to production, general corporate overhead or similar activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s proved reserve are sold (greater than 25 percent), in which case a gain or loss is recognized.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Capitalized costs less accumulated depletion and related deferred income taxes shall not exceed an amount (the full cost ceiling) equal to the sum of:
a) the present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions;
b) plus the cost of properties not being amortized;
c) plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;
d) less income tax effects related to differences between the book and tax basis of the properties.
Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change. If oil and gas prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the cost ceiling, revisions to proved oil and gas reserves occur, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.
All geological and geophysical studies, with respect to the licensed territory, have been capitalized as part of the oil and gas properties.
The Company’s oil and gas properties primarily include the value of the license and other capitalized costs.
All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Liquidation fund
Liquidation fund (site restoration and abandonment liability) is related primarily to the conservation and liquidation of the Company’s wells and similar activities related to its oil and gas properties, including site restoration. Management assessed an obligation related to these costs with sufficient certainty based on internally generated engineering estimates, current statutory requirements and industry practices. The Company recognized the estimated fair value of this liability. These estimated costs were recorded as an increase in the cost of oil and gas assets with a corresponding increase in the liquidation fund which is presented as a long-term liability. The oil and gas assets related to liquidation fund are depreciated on the unit-of-production basis separately for each field. An accretion expense, resulting from the changes in the liability due to passage of time by applying an interest method of allocation to the amount of the liability, is recorded as accretion expenses in the Consolidated Statement of Operations.
The adequacies of the liquidation fund are periodically reviewed in the light of current laws and regulations, and adjustments made as necessary.
Other fixed assets
Other fixed assets are valued at historical cost adjusted for impairment loss less accumulated depreciation. Historical cost includes all direct costs associated with the acquisition of the fixed assets.
Depreciation of other fixed assets is calculated using the straight-line method based upon the following estimated useful lives:
Buildings and improvements
7-10 years
Machinery and equipment
6-10 years
Vehicles
3-5 years
Office equipment
3-5 years
Software
3-4 years
Furniture and fixtures
2-7 years
Maintenance and repairs are charged to expense as incurred. Renewals and betterments are capitalized as leasehold improvements, which are amortized on a straight-line basis over the shorter of their estimated useful lives or the term of the lease.
Other fixed assets of the Company are evaluated annually for impairment. If the sum of expected undiscounted cash flows is less than net book value, unamortized costs of other fixed assets will be reduced to a fair value. Based on the Company’s analysis at March 31, 2010, no impairment of other assets is necessary.
Convertible notes payable issue costs
The Company recognizes convertible notes payable issue costs on the balance sheet as deferred charges, and amortizes the balance over the term of the related debt. The Company classifies cash payments for bond issue costs as a financing activity. The Company capitalized cash payments for bond issue costs as part of oil and gas properties in periods of drilling activities.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Restricted cash
Restricted cash includes funds deposited in a Kazakhstan bank and is restricted to meet possible environmental obligations according to the regulations of the Republic of Kazakhstan.
Functional currency
The Company makes its principal investing and financing transactions in U.S. Dollars and the U.S. Dollar is therefore its functional currency.
Income per common share
Basic income per common share is computed by dividing net income by the weighted-average number of common shares outstanding during the period. Diluted income per share reflects the potential dilution that could occur if all contracts to issue common stock were converted into common stock, except for those that are anti-dilutive.
New accounting policies
In May 2008, the FASB issued guidance on accounting for convertible debt instruments that may be settled in cash upon conversion. The guidance clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement), which is not addressed by prior guidance. Additionally, the guidance specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The Company adopted this standard on April 1, 2009. The adoption of this standard did not have a material impact on consolidated financial position or results of operations.
In June 2008, the FASB issued guidance on determining whether instruments granted in share-based payment transactions are participating securities. The guidance applies to the calculation of earnings per share for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. The Company adopted this guidance on April 1, 2009 and has included certain share-based payment awards in its calculation of basic weighted average shares in the EPS calculation. Accordingly, all prior-period EPS data presented has been adjusted retrospectively to conform to the provisions of this guidance. Management has determined that the adoption of this guidance does not have a material impact on the Company’s financial position and results of operations, although prior-period EPS data is affected.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
In June 2009, the FASB established the FASB Accounting Standards Codification (Codification), which officially commenced July 1, 2009, to become the source of authoritative US GAAP recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative US GAAP for SEC registrants. Generally, the Codification is not expected to change US GAAP. All other accounting literature excluded from the Codification will be considered nonauthoritative. The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009. The Company adopted the new standards for its quarter ending December 31, 2009. All references to authoritative accounting literature are now referenced in accordance with the Codification.
In May 2009, the FASB issued new standards which establish the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. In particular, the new standards set forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements (through the date that the financial statements are issued or are available to be issued). The guidance also sets forth the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The Company adopted the new standards as of June 30, 2009. The adoption of this guidance did not have a material impact on the Company’s financial statements.
In December 2008, the SEC announced that it had approved revisions to modernize the oil and gas reserve reporting disclosures. The new disclosure requirements include provisions that:
·
Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.
·
Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices. The SEC indicated that they will continue to communicate with the FASB staff to align their accounting standards with these rules. The FASB currently requires a single-day, year-end price for accounting purposes.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
·
Permit companies to disclose their probable and possible reserves on a voluntary basis. In the past, proved reserves were the only reserves allowed in the disclosures.
·
Requires companies to provide additional disclosure regarding the aging of proved undeveloped reserves.
·
Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.
·
Replace the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test.
·
Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures regarding internal controls over reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.
The Company adopted these disclosure requirements in this Annual Report on Form 10-K for the fiscal year ended of March 31, 2010.
Recent accounting pronouncements
Accounting for Transfers of Financial Assets - In June 2009, the FASB issued accounting guidance which will require more information about transfers of financial assets, including securitization transactions, and where entities have continuing exposure to the risks related to transferred financial assets. It eliminates the concept of a “qualifying special-purpose entity”, changes the requirements for derecognizing financial assets, and requires additional disclosures. This guidance will be effective at the beginning of the first fiscal year beginning after November 15, 2009. Early application is not permitted. The Company is currently evaluating the new requirements.
Disclosures about Fair Value Measurements - In January 2010, the FASB issued guidance which requires an entity to disclose the following:
·
Separately disclose the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe reasons for the transfers.
·
Present separately information about purchases, sales, issuances and settlements, on a gross basis, rather than on one net number, in the reconciliation for fair value measurements using significant unobservable inputs (Level 3).
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
·
Provide fair value measurement disclosures for each class of assets and liabilities.
·
Provide disclosures about the valuation techniques and inputs used to measure fair value for both recurring and nonrecurring fair value measurements for fair value measurements that fall in either Level 2 or Level 3.
This guidance is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuance and settlement on the forward of activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years beginning after December 15, 2010. The Company is currently evaluating the new requirements.
NOTE 3 - CASH AND CASH EQUIVALENTS
As of March 31, 2010 and 2009 cash and cash equivalents included:
March 31, 2010
March 31, 2009
US Dollars
$ 3,476,741
$ 6,030,173
Foreign currency
2,963,653
725,372
$ 6,440,394
$ 6,755,545
As of March 31, 2010 and 2009, cash and cash equivalents included $1,321,774 and $2,371,558 placed in money market funds having 30 day simple yields of 0.01% and 0.13%, respectively.
NOTE 4 - PREPAID EXPENSES AND OTHER ASSETS
Prepaid expenses and other assets as of March 31, 2010 and 2009, were as follows:
March 31, 2010
March 31, 2009
Advances for services
$ 2,593,527
$ 2,740,915
Taxes prepaid
920,066
75,216
Other
570,324
237,947
$ 4,083,917
$ 3,054,078
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 5 - OIL AND GAS PROPERTIES
Oil and gas properties using the full cost method as of March 31, 2010 and 2009, were as follows:
March 31, 2010
March 31, 2009
Cost of drilling wells
$ 96,562,442
$ 96,203,705
Professional services received in exploration and development
activities
62,967,506
55,424,910
Material and fuel used in exploration and development activities
52,221,735
51,273,747
Subsoil use rights
20,788,119
20,788,119
Deferred tax
7,219,219
7,219,219
Geological and geophysical
7,883,856
7,870,516
Capitalized interest, accreted discount and amortised bond issue
costs on convertible notes issued
6,633,181
6,633,181
Infrastructure development costs
1,429,526
1,245,298
Other capitalized costs
17,198,306
15,296,176
Accumulated depletion
(34,302,048)
(23,226,458)
$ 238,601,842
$ 238,728,413
The purchase of Emir Oil LLP was accounted for as a non-taxable business combination. Since goodwill was not recognized in this stock-based subsidiary acquisition involving oil and gas properties, recognition of a deferred tax liability related to the acquisition increases the financial reporting basis of the oil and gas properties.
NOTE 6 - GAS UTILIZATION FACILITY
The Company has entered into an Agreement on Joint Business (the “Agreement”) with Ecotechnic Chemicals AG incorporated in Switzerland, for construction of a facility to utilize the associated gas from the Company’s fields (the “Facility”).
The Facility began operating in test mode on January 1, 2009. All costs associated with the completion of the Facility, which includes amounts previously classified as construction in progress, have been reported as Gas Utilization Facility on the balance sheet.
During the year ended March 31, 2010, the Company made an additional payment to Ecotechnic Chemicals AG in the amount of $75,000, and contributed property totalling $24,107 toward the completion of the Facility.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The Company continued to operate the Facility in test mode, during the year ended March 31, 2010, as the Facility was expanded in to handle additional capacity and as the Company was negotiating a sales contract with a potential customer. Therefore, no depreciation expense was recognized for Gas Utilization Facility during the year ended March 31, 2010. Subsequent to March 31, 2010, the Company entered into a gas sales contract. As a result of this sales contract, the Gas Utilization Facility has been put into operation as of May 1, 2010.
NOTE 7 - INVENTORIES FOR OIL AND GAS PROJECTS
As of March 31, 2010 and 2009 inventories included:
March 31, 2010
March 31, 2009
Construction material
$ 12,756,417
$ 12,962,397
Spare parts
87,722
84,524
Crude oil produced
2,895
5,029
Other
870,813
950,196
$ 13,717,847
$ 14,002,146
NOTE 8 - OTHER FIXED ASSETS
Buildings and improvements
Machinery and equipment
Vehicles
Office
equipment
Furniture and fixtures
Software
Total
Cost
at March 31, 2009
$ 2,056,325
$ 728,941
$ 1,418,147
$ 368,690
$ 374,888
$ 150,838
$ 5,097,829
Additions
228,555
102,608
879,492
40,994
16,755
1,268,671
Disposals
-
-
64,919
16,098
10,609
1,632
93,258
at March 31, 2010
2,284,880
831,549
2,232,720
393,586
381,034
149,473
6,273,242
Accumulated depreciation
at March 31, 2009
270,651
198,146
518,693
225,521
147,296
108,414
1,468,721
Charge for the period
438,459
204,863
280,420
84,095
30,627
29,663
1,068,127
Disposals
-
16,984
31,468
15,884
11,584
3,108
79,028
at March 31, 2010
709,110
386,025
767,645
293,732
166,339
134,969
2,457,820
Net book value at March 31, 2009
$ 1,785,674
$ 530,795
$ 899,454
$ 143,169
$ 227,592
$ 42,424
$ 3,629,108
Net book value at March 31, 2010
$ 1,575,770
$ 445,524
$ 1,465,075
$ 99,854
$ 214,695
$ 14,504
$ 3,815,422
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
In accordance with FASC № 932-360-25, Financial Accounting and Reporting by Oil and Gas Producing Companies, depreciation related to support equipment and facilities used in exploration and development activities in the amount of $454,174 was capitalized to oil and gas properties for the year ended March 31, 2010 and $353,545 for the year ended March 31, 2009.
NOTE 9 - LONG TERM VAT RECOVERABLE
As of March 31, 2010 and 2009 the Company had long term VAT recoverable in the amount of $3,113,939 and $2,423,940, respectively. The VAT recoverable is a Tenge denominated asset due from the Republic of Kazakhstan. The VAT recoverable consists of VAT paid on local expenditures and imported goods. VAT charged to the Company is recoverable in future periods as either cash refunds or offsets against the Company’s fiscal obligations, including future income tax liabilities. Management cannot estimate which part of this asset will be realized in the current year because in order to return funds or offset this tax with other taxes a tax examination must be performed by local Kazakhstan tax authorities. During the year ended March 31, 2010 the Company received refunds of VAT in the amount of $910,057.
NOTE 10 - RESTRICTED CASH
Under the laws of the Republic of Kazakhstan, the Company is obligated to set aside funds for required environmental remediation. As of March 31, 2010 and 2009 the Company had restricted $770,553 and $588,217, respectively, for this purpose.
NOTE 11 - CONVERTIBLE NOTES PAYABLE
On July 16, 2007 the Company completed the private placement of $60 million in principal amount of 5.0% Convertible Senior Notes due 2012 (“Notes”) to non-U.S. persons outside of the United States in accordance with Regulation S under the U.S. Securities Act of 1933, as amended (the “Securities Act”) and in compliance with the laws and regulations applicable in each country where the placement took place.
The Notes carry a 5% coupon and have a yield to maturity of 6.25%. Interest is paid at a rate of 5.0% per annum on the principal amount, payable semiannually in arrears on January 13 and July 13 of each year.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The Notes are convertible into the Company’s common shares. The initial conversion price was set at $7.2094 per share, subject to customary adjustments in certain circumstances, including but not limited to, changes of control and certain future equity financings. If the conversion price is adjusted pursuant to the conversion provisions, the conversion price shall not be adjusted below $6.95, provided that if the conversion price is adjusted due to (1) the payment of a dividend; (2) a bonus issue; (3) a consolidation or subdivision of the shares; (4) the issuance of shares, share-related securities, rights in respect of shares or rights in respect of share-related securities to all or substantially all of the shareholders as a class; (5) the issuance of other securities to substantially all shareholders as a class; or (6) other arrangements to acquire securities, then the minimum conversion price will be adjusted at the same time by the same proportion.
A change of control event occurs if an offer in respect of the Company’s common shares, for which the consideration is or can be received wholly or substantially in cash, has become or been declared unconditional in all respects and the Company becomes aware that the right to cast more than 50% of the votes which may ordinarily be cast on a poll at a general meeting of the shareholders has or will become unconditionally vested in the offeror and/or any associate(s) of the offeror, or an event occurs which has a like or similar effect. If a change of control event occurs, the conversion price in respect of a conversion date that occurs after the date on which notice of such change in control event is given by the Company, but on or prior to the 60th day following the date of such notice, shall become the product of (1) the conversion price that would otherwise apply on such conversion date in the absence of a change of control event and (2) the percentage determined in accordance with the following:
Conversion Date
Percentage
On or before July 13, 2008
81.6
Thereafter, but on or before July 13, 2009
86.2
Thereafter, but on or before July 13, 2010
90.9
Thereafter, but on or before July 13, 2011
95.5
Thereafter, and until Maturity Date
100.0
If a holder of Notes shall convert its notes following the date on which notice of a change in control event is given by the Company but on or prior to the 60th day following the date of such notice, then the Company shall pay to such holder the following U.S. Dollar amounts per U.S. Dollar of Notes held by the holder that are to be so converted:
Conversion Date
Amount
On or before July 13, 2008
$ 0.12239
Thereafter, but on or before July 13, 2009
$ 0.07246
Thereafter, but on or before July 13, 2010
$ 0.02250
Thereafter, but on or before July 13, 2011
$ -
Thereafter, and until Maturity Date
$ -
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The Notes are callable after three years at a price equal to 104% of the principal amount thereof plus any accrued and unpaid interest to the date fixed for redemption, subject to the share price trading at least 30% above the conversion price. Holders of the Notes will have the right to require the Company to redeem all or a portion of their Notes on July 13, 2010 at a price equal to 104% of the principal amount thereof plus any accrued and unpaid interest to the date fixed for redemption. Unless previously redeemed, converted or purchased and cancelled, the Notes will be redeemed by the Company at a price equal to 107.2% of the principal amount thereof on July 13, 2012. The Notes constitute direct, unsubordinated and unsecured, interest bearing obligations of the Company.
The net proceeds from the issuance of the Notes have been used for further exploration of the Company’s oil and gas drilling and production activities in western Kazakhstan.
The Company granted a registration right to the Noteholders. The Company agreed to file, pursue to effectiveness and maintain effective a registration statement in respect of the Notes and the underlying shares of common stock issuable upon the conversion of the Notes (collectively, the “Covered Securities”), until such time as all Covered Securities:
·
have been effectively registered under the Securities Act and disposed of in accordance with the registration statement relating thereto;
·
may be resold without restriction pursuant to Rule 144 under the Securities Act or any successor provision thereto;
·
(A) are not subject to the restrictions imposed by Rule 903(b)(3)(iii) under the Securities Act or any successor provision thereto and (B) may be resold pursuant to Rule 144 under the Securities Act or any successor provision thereto without being subject to the restrictions imposed by paragraphs (e), (f) and (h) of Rule 144 under the Securities Act or any successor provisions thereto; provided that the requirements set forth in paragraph (c) of Rule 144 under the Securities Act or any successor provision thereto are met as of such date; or
·
have been publicly sold pursuant to Rule 144 under the Securities Act or any successor provision thereto.
On October 19, 2007 the Company filed with the U.S. Securities and Exchange Commission (“SEC”) a registration statement on Form S-3, as amended on October 25, 2007 and January 23, 2008, (the “Shelf Registration Statement”) registering the Covered Securities for resale. The Shelf Registration Statement was declared effective by the SEC on January 25, 2008.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
As of March 31, 2010 and March 31, 2009 the convertible notes payable amount is presented as follows:
March 31, 2010
March 31, 2009
Convertible notes redemption value
$ 64,323,785
$ 64,323,785
Unamortized discount
(2,145,666)
(2,992,264)
$ 62,178,119
$ 61,331,521
As of March 31, 2010 and March 31, 2009 the Company has accrued interest of $641,667, relating to the convertible notes outstanding. The Company has also amortized the discount on the convertible notes (difference between the redemption amount and the carrying amount as of the date of issue) in the amount of $2,178,119 and $1,331,521 as of March 31, 2010 and March 31, 2009, respectively. The carrying value of convertible notes will be accreted to the redemption value of $64,323,785. During the years ended March 31, 2010 and 2009 the Company recorded interest expense in the amount of $4,604,446 and $1,138,874, respectively. On June 7, 2010, the Company entered into a Supplemental Indenture No. 1, dated as of June 1, 2010, between BMB Munai, Inc. and The Bank of New York Mellon, as trustee (the “Supplemental Indenture.”) The Supplemental Indenture amends and supplements the indenture dated September 19, 2007, between BMB Munai, Inc. and The Bank of New York Mellon, as trustee (the “Original Indenture”).
The Original Indenture provided for three put dates that allowed the holders of the Notes to redeem the Notes prior to their 2012 maturity date. The first two put dates passed unexercised. The third put date is July 13, 2010. In connection with ongoing negotiations to restructure the Notes, the Company entered into the Supplemental Indenture which grants the Noteholders a fourth put date that commences on June 13, 2010 and expires on September 13, 2010. In exchange for the granting of the fourth put date in the Supplemental Indenture, the Noteholders separately agreed they will not exercise their put option for the third put date and they will not exercise their put option for the fourth put date prior to September 1, 2010; provided, however, the Noteholders may exercise such put options at any time upon the occurrence of any of the following: (i) any default has occurred under the Indenture, excluding certain defaults that occurred prior to June 7, 2010, (ii) failure by the Company or any of its material subsidiaries to timely pay any Indebtedness (as defined in the Indenture) or any guarantee of any Indebtedness that exceeds U.S. $1,000,000, or any Indebtedness becomes due and payable prior to its stated maturity other than at the option of the Company or any of its material subsidiaries, or (iii) the Noteholders holding a majority in outstanding principal amount of the Notes provide notice to the Company that negotiations with respect to the restructuring have terminated. Therefore, it is possible the Noteholders could exercise a put option with respect to the Notes prior to September 1, 2010 if any of the foregoing events occur.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Prior to entering into the Supplemental Indenture, the Company was in default under certain covenants contained in Article 9 of the Indenture requiring the Company to maintain a minimum net debt to equity ratio and to comply with certain notice, delivery and other provisions. The Noteholders separately agreed to waive these defaults until the earlier of: (i) September 1, 2010 or (ii) the fourth put date (as contained in the Supplemental Indenture), with the understanding that such waiver shall not constitute a waiver of any default under the Indenture that remains ongoing as of September 1, 2010 or occurs after June 8, 2010. At March 31, 2010, the Notes have been classified as a long-term liability on the balance sheet as the defaults have been waived by the Noteholders and the put-option was not in place. The Company currently believes it will not be able to remedy the net debt to equity ratio covenant by September 1, 2010 and, therefore, anticipates it will be in default under the Indenture at that time unless a future waiver is obtained from the Noteholders. There is no assurance the Noteholders will provide any future waiver or any further extension of their redemption put rights under the Indenture. As such, the Company expects to reclassify the Notes as a current liability at September 1, 2010, unless additional waivers are obtained.
NOTE 12 - LIQUIDATION FUND
A reconciliation on the Liquidation Fund (Asset Retirement Obligation) at March 31, 2009 and 2010 is as follows:
Total
At March 31, 2008
$ 3,728,531
Revision of estimate
(757,047)
Accrual of liability
843,485
Accretion expenses
449,025
At March 31, 2009
$ 4,263,994
Accrual of liability
-
Accretion expenses
448,351
At March 31, 2010
$ 4,712,345
Management believes that the liquidation fund should be accrued for future abandonment costs of 24 wells located in the Dolinnoe, Aksaz, Emir and Kariman oil fields. Management believes that these obligations are likely to be settled at the end of the production phase at these oil fields.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
At March 31, 2010, undiscounted expected future cash flows that will be required to satisfy the Company’s obligation by 2013 for the Dolinnoe, Aksaz, Emir and Kariman fields, respectively, are $6,204,545. After application of a 10% discount rate, the present value of the Company’s liability at March 31, 2010 and 2009, was $4,712,345 and $4,263,994 respectively.
NOTE 13 - INCOME TAXES
The Company’s consolidated pre-tax income is comprised primarily from operations in the Republic of Kazakhstan. Pre-tax losses from United States operations of $7,275,579, $12,937,563, and $1,827,168, for the years ended March 31, 2010, 2009 and 2008, respectively, are also included in consolidated pre-tax income.
According to the Exploration Contract in the Republic of Kazakhstan, for income tax purposes the Company can capitalize the exploration and development costs and deduct all revenues received during the exploration stage to calculate taxable income. As long as the Company’s capital expenditures exceed generated revenues, the Company will not be subject to Kazakhstan income tax.
As discussed in Note 2, Licenses and contracts, the Company was granted an Exploration contract extension. According to the terms of the Exploration contract, the Company will continue to operate in the exploration phase until January 2013.
Undistributed earnings of the Company’s foreign subsidiaries since acquisition amounted to approximately $70,751,488 at March 31, 2010. Those earnings are considered to be indefinitely reinvested and, accordingly, no U.S. federal and state income taxes have been provided thereon. Upon distribution of those earnings, in the form of dividends or otherwise, the Company would be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the Republic of Kazakhstan. Determination of the amount of unrecognized deferred U.S. income tax liability is not practical because of the complexities associated with its hypothetical calculation; however, unrecognized foreign tax credits may be available to reduce a portion of the U.S. tax liability.
During the year ended March 31, 2010 the Company changed the method of tax accounting for the U.S. tax jurisdiction from a cash to accrual basis. The change in method was made because the Company exceeded the gross receipt threshold to be eligible for the cash method.
This change in tax method mainly resulted in the Company recognizing interest income from intercompany loans between the U.S. parent and its wholly owned foreign subsidiary, which amounts were previously deferred for income tax purposes under the cash method of accounting. The Company has calculated a Code Section 481 adjustment, to account for this change in method, in the amount of $25,116,879. The Code Section 481 adjustment primarily provides for all accrued intercompany interest amounts, previously deferred, to be recognized as taxable income, by the U.S. parent, during fiscal years 2010 through 2014. The yearly amount to be recognized is $6,279,219, which represents 25% of the total Code Section 481 adjustment.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Net operating losses of the Company in its U.S. tax jurisdiction for the year ended March 31, 2010 totalled $7,275,579. This loss has been offset with the recognized portion of the Code Section 481 adjustment of $6,279,219 which resulted in an adjusted net operating loss of $996,359.
Earnings and (losses) before income taxes derived from United States and foreign operations are as follows:
Year ended
March 31, 2010
Year ended
March 31, 2009
Year ended
March 31, 2008
United States
$ (7,275,579)
$ (12,937,563)
$ (1,827,168)
Kazakhstan
14,716,990
29,066,849
33,034,150
$ 7,441,411
$ 16,129,286
$ 31,206,982
The income tax benefit in the Consolidated Statements of Operations is comprised of:
Year ended
March 31, 2010
Year ended
March 31, 2009
Year ended
March 31, 2008
(Restated)
Current tax expense
$ -
$ -
$ -
Deferred tax benefit
(1,552,062)
(1,028,272)
(103,582)
$ (1,552,062)
$ (1,028,272)
$ (103,582)
The difference between the income tax expense/(benefit) reported and amounts computed by applying the U.S. Federal rate to pretax income consisted of the following:
Year ended
March 31, 2010
Year ended
March 31, 2009
Year ended
March 31, 2008
(Restated)
Tax at federal statutory rate (34%)
$ 2,530,505
$ 5,483,957
$ 10,610,374
Effect of lower foreign tax rates
(1,852,605)
(1,601,126)
(876,907)
Tax benefit from exploration stage
(3,577,975)
(7,243,413)
(10,301,168)
Effect of change from cash to accrual
basis of accounting
1,348,013
-
-
Non-deductible expenses
-
2,332,310
464,119
$ (1,552,062)
$ (1,028,272)
$ (103,582)
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Effective January 1, 2009, the Republic of Kazakhstan adopted a new tax code, which decreased the corporate income rate for legal entities to 20%.
Non-deductible expenses are comprised of the non-deductible portion of interest expense on intercompany loans accrued by subsidiary.
As of March 31, 2010, the Company had net operating loss carry forwards for income tax purposes of $13,547,692, which if unused, will expire in 2024, 2025, 2026, 2027, 2028, and 2029.
No valuation allowance was recorded against the deferred tax assets resulting from Net Operating Loss because the Company believes it will have sufficient future taxable domestic income to be offset with, primarily from accrued interest income related to loans to subsidiary.
Deferred taxes reflect the estimated tax effect of temporary differences between assets and liabilities for financial reporting purposes and those measured by tax laws and regulations. The components of deferred tax assets and deferred tax liabilities are as follows:
March 31, 2010
March 31, 2009
Deferred tax assets:
Stock based compensation
$ -
$ 185,418
Liquidation fund
353,088
236,505
Tax losses carried forward
4,606,215
6,867,054
Accrued interest expense
5,905,599
5,093,405
10,864,902
12,382,382
Deferred tax liabilities:
Oil and gas properties
5,879,053
6,972,564
Accrued interest income
9,950,231
11,926,262
15,829,284
18,898,826
Net deferred tax liability
$ 4,964,382
$ 6,516,444
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Deferred income taxes for US and Kazakhstan tax jurisdiction are as follows:
Accounting for Uncertainty in Income Taxes - In accordance with generally accepted accounting principles, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns. The Company’s U.S. federal income tax returns for the fiscal years ended March 31, 2006 through 2009 remain subject to examination. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon an audit. Therefore, the Company has no reserves for uncertain tax positions. No interest or penalties have been levied against the Company and none are anticipated, therefore no interest or penalties have been included in the provision for income taxes.
NOTE 14 - CAPITAL LEASE
In December 2009 the Company entered into a capital lease agreement with a vehicle leasing company for the lease of oil trucks in the amount of $554,820. The agreement is effective upon receiving oil trucks by the Company. The lease schedule is the following:
Year ended March 31,
Total Minimum Payments
$ 185,019
240,149
129,652
Net minimum lease payments
554,820
Less: Amount representing interest
(137,010)
Present value of net minimum lease payments
$ 417,810
Current portion of capital lease liability in amount of $185,019 as of March 31, 2010 was recognized as part of accounts payable. Non-current portion of Capital Lease Liability as of March 31, 2010 totals to $369,801.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 15 - SHARE AND ADDITIONAL PAID IN CAPITAL
Share-Based Compensation
On July 17, 2008 the shareholders of the Company approved the BMB Munai, Inc. 2009 Equity Incentive Plan (“2009 Plan”) to provide a means whereby the Company could attract and retain employees, directors, officers and others upon whom the responsibility for the successful operations of the Company rests through the issuance of equity awards. 5,000,000 common shares are reserved for issuance under the 2009 Plan. Under the terms of the 2009 Plan the board of directors determines the terms of the awards made under the 2009 Plan, within the limits set forth in the 2009 Plan guidelines.
Common Stock Grants
On March 30, 2007, the Company granted common stock to officers, employees and outside consultants of the Company under the Plan. The total number of restricted common shares granted was 950,000. The restricted stock grants were valued at $5.38 per share. The restricted stock grants were awarded on the same terms and subject to the same vesting requirements. Previous vesting conditions stated that the restricted stock grants will vest to the grantees at such time as either of the following events occurs (the "Vesting Events"): i) the Company enters commercial production and is granted a commercial production license from the Republic of Kazakhstan; or ii) the occurrence of an Extraordinary Event. An “Extraordinary Event” is defined in the restricted stock agreement as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to thirty percent (30%) or more of the outstanding stock of the Company or any of its subsidiaries, or the sale of all or substantially all of the assets of the Company or any of its subsidiaries. In the event of an Extraordinary Event, the grants shall be deemed full vested one day prior to the effective date of the Extraordinary Event. The board of directors shall determine conclusively whether or not an Extraordinary Event has occurred and the grantees have agreed to be bound by the determination of the board of directors. The grantees have the right to vote the shares, receive dividends and enjoy all other rights of ownership over the entire grant amount from the grant date, except for the right to transfer, assign, pledge, encumber, dispose of or otherwise directly or indirectly profit or share in any profit derived from a transaction in the shares prior to the occurrence of a Vesting Event. Shares will only vest to the grantee if the grantee is employed by the Company at the time a Vesting Event occurs. If a Vesting Event has not occurred at the time a grantee's employment with the Company ceases, for any reason, the entire grant amount shall be forfeited back to the Company. At the time the grants were made, it was anticipated that the grants would vest no later than July 9, 2009, the date the exploration stage of the Company’s exploration contract was scheduled to terminate. At the recommendation of the Compensation Committee, on September 11, 2008, the board of directors of the Company approved a change to the vesting conditions of the stock grants. The grants vested as of July 9, 2009.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Non-cash compensation expense in the amount of $567,889 was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the year ended March 31, 2010.
As of March 31, 2010, there was no unrecognized non-cash compensation expense related to non-vested share-based compensation arrangements granted under the Plan.
On June 24, 2008, the Company was granted an extension of its existing exploration contract from July 2009 to January 2013. In connection therewith, the Company became obligated to issue 1,750,000 common shares to a consultant as the success fee for assisting the Company to obtain the extension. The shares are valued at $6.13 per share, which was the closing market price of Company’s shares on June 24, 2008.
On September 16, 2008 this consulting agreement between the Company and the consultant discussed in the preceding paragraph was revised and parties agreed to decrease number of shares issued for services provided by 500,000 shares. The non-cash compensation expenses for consulting services were reversed in the amount of $3,065,000 (500,000 shares valued at $6.13 per share which was the closing market price of Company’s shares on June 24, 2008) for the three months ended December 31, 2008.
On July 17, 2008 at the recommendation of the compensation committee of the board of directors, the Company’s board of directors approved, subject to certain vesting requirements, restricted stock awards to certain executive officers, directors, employees and outside consultants of the Company pursuant to the BMB Munai, Inc. 2004 Stock Incentive Plan (the “2004 Plan”). The total number of shares granted was 1,330,000. Grants were made to 14 people, 12 of whom are non-U.S. persons. The restricted stock grants were made without registration pursuant to Regulation S of the Securities Act Rules and/or Section 4(2) under the Securities Act of 1933. The restricted stock grants will vest to the grantees at such time as either of the following events occurs (the “Vesting Events”): i) the one-year anniversary of the grant date; or ii) the occurrence of an Extraordinary Event. An “Extraordinary Event” is defined in the restricted stock agreement as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to thirty percent (30%) or more of the outstanding stock of the Company or any of its subsidiaries, or the sale of all or substantially all of the assets of the Company or any of its subsidiaries. In the event of an Extraordinary Event, the grants shall be deemed full vested one day prior to the effective date of the Extraordinary Event. The board of directors shall determine conclusively whether or not an Extraordinary Event has occurred and the grantees have agreed to be bound by the determination of the board of directors. The shares representing the restricted stock grants shall be issued as soon as practicable, will be deemed outstanding from the date of grant, and will be held in escrow by the Company subject to the occurrence of a Vesting Event. The grantees will have the right to vote the shares, receive dividends and enjoy all other rights of ownership over the entire grant amount from the grant date, except for the right to transfer, assign, pledge, encumber, dispose of or otherwise directly or indirectly profit or share in any profit derived from a transaction in the shares prior to the occurrence of a Vesting Event. Shares will only vest to the grantee if the grantee is employed by the Company at the time a Vesting Event occurs. If a Vesting Event has not occurred at the time a grantee’s employment with the Company ceases, for any reason, the entire grant amount shall be forfeited back to the Company. The grants vested as of July 17, 2009.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Non-cash compensation expense in the amount of $2,176,244 was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the year ended March 31, 2010.
As of March 31, 2010, there was no unrecognized non-cash compensation expense related to non-vested share-based compensation arrangements granted under the Plan.
On January 1, 2010 the Company entered into Restricted Stock Grant Agreements with certain executive officers, directors, employees and outside consultants of the Company. The stock grants were approved by the Company board of directors and recommended by the compensation committee of the Company’s board of directors. The total number of shares granted was 1,500,000.
All of the restricted stock grants were awarded on the same terms and subject to the same vesting requirements. The restricted stock grants will vest to the grantees at such time as either of the following events occurs (the “Vesting Events”): i) the one-year anniversary of the grant date; or ii) the occurrence of an Extraordinary Event. An “Extraordinary Event” is defined in the restricted stock agreement as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to fifty percent (50%) or more of the outstanding stock of the Employer or any of its subsidiaries, or the sale of forty percent (40%) or more of the assets of the Employer or any of its subsidiaries, or one (1) person or more than one person acting as a group, acquires fifty percent (50%) or more of the total voting power of the stock of the Employer. In the event of an Extraordinary Event, the grants shall be deemed fully vested one day prior to the effective date of the Extraordinary Event. The board of directors shall determine conclusively whether or not an Extraordinary Event has occurred and the grantees have agreed to be bound by the determination of the board of directors.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The shares representing the restricted stock grants (the “Restricted Shares”) shall be issued as soon as practicable, will be deemed outstanding from the date of grant, and will be held in escrow by the Company subject to the occurrence of a Vesting Event. The time between the date of grant and the occurrence of a Vesting Event is referred to as the “Restricted Period.” The grantees may not sell, transfer, assign, pledge or otherwise encumber or dispose of the Restricted Shares during the Restricted Period. During the Restricted Period, the grantees will have the right to vote the Restricted Shares, receive dividends paid or made with respect to the Restricted Shares, provided however, that dividends paid on unvested Restricted Shares will be held in the custody of the Company and shall be subject to the same restrictions that apply to the Restricted Shares. The Restricted Shares will only vest to the grantee if the grantee is employed by the Company at the time a Vesting Event occurs. If a Vesting Event has not occurred at the time a grantee’s employment with the Company ceases, for any reason, the entire grant amount shall be forfeited back to the Company.
Non-cash compensation expense in the amount of $427,500 was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the year ended March 31, 2010.
As of March 31, 2010, there was $1,282,500 of total unrecognized non-cash compensation expense related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 0.75 years.
Stock Options
On June 20, 2006 the Company granted stock options to directors of the Company under the Plan. The total number of options was 200,000. The options are exercisable at a price of $7.00 per share. All of the options vested immediately upon grant. Compensation expense for options granted is determined based on their fair value at the time of grant, the cost of which in the amount of $545,346 was recognized in the Consolidated Statements of Operations and Consolidated Balance Sheet for the year ended March 31, 2007. These granted stock options expired unexercised on June 20, 2009.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
On November 12, 2004, the Company granted stock options to its former corporate secretary for past services rendered. These options grant the employee the right to purchase up to 60,000 shares of the Company’s common stock at an exercise price of $4.00 per share. The options vested immediately and expire five years from the date of grant. In April 2006, options to acquire 7,200 common shares were exercised. In January 2008, options to acquire 3,000 common shares were exercised. Remaining granted stock options expired unexercised on November 14, 2009.
Stock options outstanding and exercisable as of March 31, 2010, were as follows:
Number of Shares
Weighted Average
Exercise Price
As of March 31, 2007
1,173,583
$ 5.33
Granted
-
-
Exercised
(3,000)
$ 4.00
Expired
-
-
As of March 31, 2008
1,170,583
$ 5.33
Granted
-
-
Exercised
-
-
Expired
-
-
As of March 31, 2009
1,170,583
$ 5.33
Granted
-
-
Exercised
-
-
Expired
(249,800)
$ 6.40
As of March 31, 2010
920,783
$ 5.04
Additional information regarding outstanding options as of March 31, 2010, was as follows:
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 16 - REVENUES
The Company exports oil for sale to the world markets via the Aktau sea port. Sales prices at the port locations are based on the average quoted Brent crude oil price from Platt’s Crude Oil Marketwire for the three days following the bill of lading date less discount for transportation expenses, freight charges and other expenses borne by the customer.
The Company recognized revenue from sales as follows:
Year ended March 31, 2010
Year ended March 31, 2009
Year ended March 31, 2008
Export sales
$ 56,135,006
$ 65,721,241
$ 57,626,429
Domestic sales
1,139,520
3,895,634
2,570,197
$ 57,274,526
$ 69,616,875
$ 60,196,626
NOTE 17 - RENT EXPORT TAX AND EXPORT DUTY
On April 18, 2008 the government of the Republic of Kazakhstan introduced an export duty on several products (including crude oil). The Company became subject to the duty beginning in June 2008. The formula for determining the amount of the crude oil export duty was based on a sliding scale that is tied to several factors, including the world market price for oil. As discussed in Note 2, in December 2008 the government of the Republic of Kazakhstan issued a resolution that cancelled the export duty effective January 26, 2009 for companies operating under the new tax code. As a result, the export duty for the year ended March 31, 2010 and 2009 was $0 and $6,783,278, respectively.
On January 1, 2009, the Company became subject to the new tax code of the Republic of Kazakhstan. Under the new tax code, the rent export tax replaced the export duty. The rent export tax is calculated based on the export sales price and ranges from as low as 0% if the export sales price is less than $40 per barrel to as high as 32% if the price per barrel exceeds $190. Rent export tax expense for the year ended March 31, 2010 and 2009 was $10,032,857 and $476,359 respectively.
NOTE 18 - CONSULTING EXPENSES
On November 19, 2007 the Company entered into a consulting agreement with Caspian Energy Consulting Ltd (“Consultant”). Upon the execution of the consulting agreement, the Company paid the Consultant $1,000,000. The consulting agreement also provided that in the event the Consultant was successful in negotiating an extension of the term of the Company’s existing exploration contract beyond July 2009, the Company would issue 500,000 common shares for each additional year of exploration status extension granted beyond July 2009.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
On June 24, 2008, the Company was granted an extension of its existing exploration contract from July 2009 to January 2013. The compensation expenses for consulting services were recorded in the amount of $11,727,500, which represents $1,000,000 paid upon the execution of consulting agreement and non-cash share-based compensation in the amount of $10,727,500 as the successful fee for extension of time period for exploration. The share-based compensation represents 1,750,000 (500,000 shares for each additional year of exploration status extension) valued at $6.13 per share which was the closing market price of Company’s shares on June 24, 2008.
On September 16, 2008 this consulting agreement was revised and the parties agreed to decrease the number of shares issued for services provided by 500,000 shares to 1,250,000 shares. Non-cash compensation expenses for consulting services were reversed in the amount of $3,065,000 (500,000 shares valued at $6.13 per share which was the closing market price of Company’s shares on June 24, 2008) for the three months ended September 30, 2008.
The agreement also has a provision for the Consultant to pursue new exploration contracts for new territories, which is described in Note 23.
NOTE 19 - FOREIGN CURRENCY GAIN
On February 3, 2009, the National Bank of Kazakhstan enacted a devaluation of Kazakh Tenge to US Dollar of approximately 25%. As a result of this devaluation, the Company realized a foreign currency gain of $2,592,341 for the year ended March 31, 2009, resulting from the revaluation of assets and liabilities denominated in Kazakh Tenge.
NOTE 20 - DISGORGEMENT FUNDS RECEIVED
In June 2008 the Company received a letter from a shareholder of the Company stating that the shareholder was returning realized profits from their trades of shares of the Company’s common stock during the nine month period preceding May 22, 2008 (the “Timeframe”). The shareholder also stated in the letter that during this Timeframe the shareholder was subject to Section 16 of the United States Security Exchange Act of 1934 (the “Exchange Act”) because it owned more than 10% of the shares of Company common stock. As such, the shareholder decided to voluntarily comply with Section 16(b) of the Exchange Act by returning the realized profits to the Company in the amount of $1,650,293, (the “Disgorgement Amount”) which is net of amounts paid for brokerage commissions on each of the executed trades during the Timeframe. The Company had received the Disgorgement Amount in full before June 30, 2008.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 21 - EARNINGS PER SHARE INFORMATION
The calculation of the basic and diluted earnings per share is based on the following data:
Year ended
March 31, 2010
Year ended
March 31, 2009
Year ended
March 31, 2008
Net income
$ 8,993,473
$ 17,157,558
$ 31,310,564
Basic weighted-average common shares
outstanding
50,018,895
46,797,351
44,697,364
Effect of dilutive securities
Warrants
-
1,860
55,008
Stock options
-
-
200,559
Non-vesting share grants
-
-
-
Dilutive weighted average common shares
outstanding
50,018,895
46,799,211
44,952,931
Basic income per common share
$ 0.18
$ 0.37
$ 0.70
Diluted income per common share
$ 0.18
$ 0.37
$ 0.70
The Company has adopted guidance from FASC Topic 260, relating to determining whether instruments granted in share-based payment transactions are participating securities, on April 1, 2009. Accordingly the Company included certain unvested share grants defined as “participating” in the basic weighted average common shares outstanding for the years ended March 31, 2010 and 2009, respectively. Prior period comparative data has been retrospectively presented to reflect the adoption of this standard.
The diluted weighted average common shares outstanding for the years ended March 31, 2010 and 2009 does not include the effect of potential conversion of certain warrants and stock options as their effects are anti-dilutive.
The dilutive weighted average common shares outstanding for the years ended March 31, 2010 and 2009, respectively, does not include the effect of the potential conversion of the Notes because the average market share price the years ended March 31, 2010 and 2009 was lower than potential conversion price of the convertible notes for this period.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The diluted weighted average common shares outstanding for the year ended March 31, 2008 does not include the effect of the potential conversion of the Notes because conversion of the Notes is not contingent upon any market event. Rather, the Notes are convertible to common stock upon the first to occur of (a) the tenth New York business day following the Shelf Registration Statement Effective Date and (b) 13 July 2008.
NOTE 22 - RELATED PARTY TRANSACTIONS
The Company leases ground fuel tanks and other oil fuel storage facilities and warehouses from Term Oil LLC. The lease expenses for the years ended March 31, 2010, 2009 and 2008, totaled $96,541, $221,903 and $254,427, respectively. Also the Company had advances paid to Term Oil LLC in the amount of $101,048 and $15,006 as of March 31, 2010 and 2009, respectively. Toleush Tolmakov, the General Director of Emir Oil, LLP, a wholly-owned subsidiary of the Company (“Emir”), is an owner of Term Oil LLC.
On June 26, 2009 the Company entered into a Debt Purchase Agreement (the “Agreement”) with Simage Limited, a British Virgin Islands international business corporation (“Simage”). Simage is a company owned by Toleush Tolmakov.
Prior to the date of the Agreement, Simage had acquired by assignment, certain accounts receivable owed by Emir to third-party creditors of Emir in the amount of $5,973,185 (the “Obligations”). Pursuant to the terms of the Agreement, Simage assigned to the Company all rights, title and interests in and to the Obligations in exchange for the issuance of 2,986,595 shares of common stock of the Company. The market value of the shares of common stock issued to Simage, at the agreement date, was $3,076,193. The market value was based on $1.03 per share, which was the closing market price of the Company’s shares on June 26, 2009.
As a result of this Agreement, the Company has effectively been released of accounts payable obligations amounting to $5,973,185. The Company has treated this Agreement as a related party transaction, due to the fact that Simage is owned by a Company shareholder. Therefore, the difference between the settled amount of accounts payable and the value of the common stock issued, which amounts to $2,896,997, has been treated as a capital contribution by the shareholder and recognized as an addition to additional-paid-in-capital rather than a gain on settlement of debt.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 23 - COMMITMENTS AND CONTINGENCIES
Consulting Agreement
On October 15, 2008 the MEMR increased Emir Oil LLP’s contract territory from 460 square kilometers to 850 square kilometers. In connection with this extension, and any other territory extensions or acquisitions, the Consultant will be paid a share payment in restricted common stock for resources and reserves associated with any acquisition. The value of any acquisition property will be determined by reference to a 3D seismic study and a resource/reserve report by a qualified independent petroleum engineer acceptable to the Company. The acquisition value (“Acquisition Value”) will be equal to the total barrels of resources and reserves, as defined and determined by the engineering report multiplied by the following values:
Resources at $.50 per barrel;
Probable reserves at $1.00 per barrel; and
Proved reserve at $2.00 per barrel.
The number of shares to be issued to the Consultant shall be the Acquisition Value divided by the higher of $6.50 or the average closing price of the Company’s trading shares for the five trading days prior to the issuance of the reserve/resource report, provided that in no event shall the total number of shares issuable to the Consultant exceed more than a total of 4,000,000 shares.
Historical Investments by the Government of the Republic of Kazakhstan
The Government of the Republic of Kazakhstan made historical investments in the ADE Block, the Southeast Block and the Northwest Block of $5,994,200, $5,350,680 and $5,372,076, respectively. When and if, the Company applies for and, when and if, it is granted commercial production rights for the ADE Block and Southeast Block, the Company will be required to begin repaying these historical investments to the Government. The terms of repayment will be negotiated at the time the Company is granted commercial production rights.
Capital Commitments
Prior to the extension of the exploration period granted to Emir Oil LLP in June 2008, the terms of its subsurface exploration contract required Emir Oil to spend a total of $48.8 million in exploration activities on the ADE Block and Southeast Block through July 2009.
In connection with the extensions granted in June and October 2008, the Company’s capital expenditure requirements have been revised. To retain its rights under the contract, the Company must spend $12.8 million between January 10, 2010 and January 9, 2011, $27.3 million between January 10, 2011 and January 9, 2012 and $14.9 million between January 10, 2012 and January 9, 2013.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Through March 31, 2010 the Company had spent a total of $289.4 million in exploration activity.
In addition to the minimum capital expenditure requirement, the Company must also comply with the other terms of the work program associated with the contract, which includes the drilling of at least ten new wells by January 9, 2013. The failure to meet the minimum capital expenditures or to comply with the terms of the work program could result in the loss of the subsurface exploration contract. The recent addenda to the exploration contract which granted the Company an extension of the exploration period and rights to the Northwest Block also require the Company to:
·
make additional payments to the liquidation fund, stipulated by the Contract;
·
make a one-time payment in the amount of $200,000 to the Astana Fund by the end of 2010; and
·
make annual payments to social projects of the Mangistau Oblast in the amounts of $100,000 from 2010 to 2012.
Capital Lease Agreement
In December 2009 the Company entered into a capital lease agreement with an oil tanks leasing company for the lease of oil tanks in the amount of $493,000. The agreement is effective upon receiving oil tanks by the Company. As of March 31, 2010 the Company had not received the oil tanks. The Company expects to receive the oil tanks in April 2010, at which time the capital lease will be recorded. The agreement calls for average monthly payments of $12,056 during the first year and average monthly payments of $15,010 during the second and third year.
Executive Contracts
On December 31, 2009, the Company entered into new employment agreements with the following executive officers of the Company, Gamal Kulumbetov, Askar Tashtitov, Evgeniy Ler and Anuarbek Baimoldin. Each of these individuals was serving in such capacity prior to entering the employment agreements.
Except for annual salary, and as otherwise specifically addressed herein, the terms and conditions of the employment agreement of each of the executive and non-executive level officers are the same in all material respects. The employment agreements provide for an initial term of one year with three consecutive one-year renewals unless terminated by either party prior to the beginning of the renewal term. A form of the Employment Agreement was filed as an exhibit to the current report on Form 8-K filed on January 6, 2010.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Under the agreements, salary is reviewable no less frequently than annually and may be adjusted up or down by the compensation committee in its sole discretion, but may not be adjusted below the initial annual salary amount listed in the agreement. The agreements provide that each of the officers is entitled to participate in such pension, profit sharing, bonus, life insurance, hospitalization, major medical and other employee benefit plans of the Company that may be in effect from time to time, to the extent the individual is eligible under the terms of those plans. The agreements provide that each officer is eligible at the discretion of the compensation committee and the board of directors to receive performance bonuses. Each officer is entitled to 28 days vacation in accordance with the vacation policies of the Company, as well as paid holidays and other paid leave set forth in the Company’s policies. There is no accrual of vacation days and holidays.
The agreements and all obligations thereunder may be terminated upon the occurrence of the following events: i) death, ii) disability; iii) for cause immediately upon notice from the Company or at such time as indicated by the Company in said notice; iv) for good reason upon not less than 30 days notice from an officer to the Company; v) an extraordinary event, unless otherwise agreed in writing.
Under the agreements the named executive officer may be deemed disabled if for physical or mental reasons he is unable to perform his duties for 120 consecutive days or 180 days during any 12 month period. Such disability will be determined by a jointly agreed upon medical doctor.
The agreements provide that any of the following will constitute “cause”: i) breach of the employment agreement; ii) failure to adhere to the written policies of the Company; iii) appropriation by the officer of a material business opportunity; iv) misappropriation of funds or property of the Company; v) conviction, indictment or the entering of a guilty plea or a plea of no contest to a felony.
“Good reason” under the agreements may mean any of the following: i) a material breach of the employment agreement; ii) assignment of the officer without his consent to a position of lesser status or degree of responsibility.; iii) relocation of the Company’s principal executive offices outside the Republic of Kazakhstan; iv) if the Company requires the officer to be based somewhere other than principal executive offices of the Company without the officer’s consent.
Each of the employment agreements, provides that an “extraordinary event” is defined as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to fifty percent (50%) or more of the outstanding stock of the Company or any of its subsidiaries, or the sale of forty percent (40%) or more of the assets of the Company or any of its subsidiaries, or if one or more persons, acting alone or as a group, acquires fifty percent (50%) or more of the total voting power of the Company. In addition to these provisions, the employment agreement of Mr. Tashtitov provides that the following events also constitute an extraordinary event: i) that a disposition by the Chairman of the Company’s board of directors of by the General Director of the Company’s subsidiary, of seventy five (75%) or more of the shares either individual currently owns, including stock attributed to either of them by Internal Revenue Code Section 318; or ii) should the Company terminate the registration of any of its securities under Section 12 of the Exchange Act of 1934, voluntarily ceases, or shall terminate its obligation to file reports with United States Securities Commission pursuant to Section 13 of the Exchange Act of 1934.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Upon termination of an employment agreement, the Company will make a termination payment to the officer in lieu of all other amounts and in settlement and complete release of all claims employee may have against the Company. In the event of termination for good reason by the officer, the Company will pay the officer the remainder of his salary for the calendar month in which the termination is effective and for six consecutive calendar months thereafter. The officer shall also be entitled to any portion of incentive compensation for the year, prorated to the date of termination. Notwithstanding the foregoing, if the officer obtains other employment prior to the end of the six month period, salary payments by the Company after he begins employment with a new employer shall be reduced by the amount of the cash compensation received from the new employer. If the officer is terminated for cause, he will receive salary only through the date of termination and will not be entitled to any incentive compensation for the year in which his employment is terminated. If the termination is the result of a disability, the Company will pay salary for the rest of the month during which termination is effective and for the shorter of six consecutive months thereafter or until disability insurance benefits commence. If employment is terminated as a result of the death of the officer, his heirs shall be entitled to salary through the month in which his death occurs and to incentive compensation prorated through the month of his death. The employment agreements of Mr. Kulumbetov, Mr. Ler and Mr. Baimoldin provide that if the employment agreement is terminated as a result of an extraordinary event, the officer shall be entitled to severance pay depending on the completed years of employment: i) 10% of Basic Compensation Salary if executive completed less than 1 year of employment; ii) 150% of Basic Compensation Salary if executive completed at least 1 year but not less than 2 years of employment; iii) 299% of Basic Compensation Salary if executive completed more than 2 years of employment.
The employment agreement of Mr. Tashtitov provides that in the event his employment agreement is terminated due to an extraordinary event, he will be entitled to receive a severance payment from the Company of $3,000,000.
All benefits terminate on the date of termination. The officer shall be entitled to accrued benefits, but is not entitled to compensation for unused vacation, holiday, sick leave or other leave.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The employment agreements also contain confidentiality, non-competition and non-interference provisions.
All benefits terminate on the date of termination. The officer shall be entitled to accrued benefits, but is not entitled to compensation for unused vacation, holiday, sick leave or other leave.
The employment agreements also contain confidentiality, non-competition and non-interference provisions and provide for certain of the Company’s executive officers to potentially receive payments upon termination or change in control.
Consulting Agreement with Boris Cherdabayev
On December 31, 2009 the Company entered into a Consulting Agreement with Boris Cherdabayev, the Chairman of the Company’s board of directors. The Consulting Agreement became effective on January 1, 2010. Pursuant to the Consulting Agreement, in addition to his services as Chairman of the board of directors, Mr. Cherdabayev will provide such consulting and other services as may reasonably be requested by Company management.
The initial term of the Consulting Agreement is five years unless earlier terminated as provided in the Consulting Agreement. The initial term will automatically renew for additional one-year terms unless and until terminated. The Consulting Agreement may be terminated for Mr. Cherdabayev’s death or disability and by the Company for cause. The Company may also terminate the Consulting Agreement other than for cause, but will be required to pay the full fee required under the Consulting Agreement.
Pursuant to the Consulting Agreement, Mr. Cherdabayev will be paid $192,000 per year. This base consulting fee will be net of Social Tax and Social Insurance Tax in the Republic of Kazakhstan, which shall be paid by the Company. Mr. Cherdabayev will be responsible for Personal Income Tax and Pension Fund Tax. The success of projects involving Mr. Cherdabayev shall be reviewed on an annual basis to determine whether the initial base consulting should be increased.
The Consulting Agreement provides for an extraordinary event payment equal to the greater of $5,000,000 or the base compensation fee for the remaining initial term of the Consulting Agreement. The Consulting Agreement defines an extraordinary event as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to fifty percent (50%) or more of the outstanding stock of the Company or any of its subsidiaries, or the sale of forty percent (40%) or more of the assets of the Company or any of its subsidiaries, or if one or more persons, acting alone or as a group, acquires fifty percent (50%) or more of the total voting power of the Company.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Litigation
In December 2003, a complaint was filed in the 15th Judicial Court in and for Palm Beach County, Florida, naming, among others, the Company and former directors, Georges Benarroch and Alexandre Agaian, as defendants. The plaintiffs, Brian Savage, Thomas Sinclair and Sokol Holdings, Inc. allege claims of breach of contract, unjust enrichment, breach of fiduciary duty, conversion and violation of a Florida trade secret statute in connection with a business plan for the development of the Aksaz, Dolinnoe and Emir oil and gas fields owned by Emir Oil, LLP. The parties mutually agreed to dismiss this lawsuit without prejudice.
In April 2005, Sokol Holdings, Inc., also filed a complaint in United States District Court, Southern District of New York alleging that BMB Munai, Inc., Boris Cherdabayev, and former BMB directors Alexandre Agaian, Bakhytbek Baiseitov, Mirgali Kunayev and Georges Benarroch wrongfully induced Toleush Tolmakov to breach a contract under which Mr. Tolmakov had agreed to sell to Sokol 70% of his 90% interest in Emir Oil LLP.
In October and November 2005, Sokol Holdings filed amendments to its complaint in the U.S. District Court in New York to add Brian Savage and Thomas Sinclair as plaintiffs and to add Credifinance Capital, Inc., and Credifinance Securities, Ltd. (collectively “Credifinance”) as defendants in the matter. The amended complaints alleged: i) tortious interference with contract, specific performance, breach of contract, unjust enrichment, unfair competition-misappropriation of labors and expenditures against all defendants; ii) breach of fiduciary duty, tortious interference with fiduciary duty and aiding and abetting breach of fiduciary duty by Mr. Agaian, Mr. Benarroch and Credifinance; and iii) breach of fiduciary duty by Mr. Cherdabayev, Mr. Kunayev and Mr. Baiseitov, in connection with a business plan for the development of the Aksaz, Dolinnoe and Emir oil and gas fields owned by Emir Oil, LLP. The plaintiffs have not named Toleush Tolmakov as a defendant in the action nor have the plaintiffs ever brought claims against Mr. Tolmakov to establish the existence or breach of any legally binding agreement between the plaintiffs and Mr. Tolmakov. The plaintiffs seek damages in an amount to be determined at trial, punitive damages, specific performance and such other relief as the Court finds just and reasonable.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
The Company moved for dismissal of the amended complaint or for a stay pending arbitration in Kazakhstan. That motion was denied, without prejudice to renewing it, to enable defendants to produce documents to plaintiffs relating to the issues raised in the motion. Following completion of document production, the motion was renewed. Briefing on the motion was completed on August 24, 2006. On June 14, 2007, the court ruled on the Company’s motion. The court (a) denied the motion to dismiss on the ground that Kazakhstan is a more convenient forum; (b) denied the motion to dismiss in favor of litigation in New York state court; (c) denied the motion to stay pending arbitration in Kazakhstan; and (d) denied the motion to dismiss on the ground that Mr. Tolmakov is an indispensable party. The court also (a) denied the motion (by defendants other than the Company) to dismiss for lack of personal jurisdiction and (b) granted the motion (by defendants other than the Company) to dismiss several claims for relief alleging breach of fiduciary duty, tortious interference with fiduciary duty and aiding and abetting breach of fiduciary duty. The court dismissed as moot the Company’s cross-motion to stay discovery and instructed the parties to comply with the Magistrate Judge’s discovery schedule.
The Company appealed the court’s refusal to stay the litigation pending arbitration in Kazakhstan. On September 28, 2008, the Court of Appeals issued a decision in which it (a) reversed the district court's refusal to stay the claim for specific performance pending arbitration and (b) affirmed the balance of the district court's order.
At the end of 2008, the Company changed legal counsel to represent all defendants in the lawsuit from Bracewell & Giuliani LLP in New York, New York to Manning, Curtis, Bradshaw & Bednar LLC in Salt Lake City, Utah.
On December 12, 2008, plaintiffs sought leave to file a Third Amended Complaint to add claims for (a) breach of fiduciary duty against defendants Cherdabayev, Kunayev, Baiseitov, Agaian, Benarroch and Credifinance based on these defendants’ alleged role as promoters of Sokol, (b) fraud against all defendants; and (c) promissory estoppel against defendants Cherdabayev, Kunayev and Baiseitov. Defendants opposed the Motion for Leave to Amend and leave to amend was denied. Fact and expert discovery has been completed. Plaintiffs have submitted an expert report on damages that claims damages of between $6.7 million and $10.9 million, plus interest. The Company disputes the plaintiffs’ damage claim, in addition to disputing liability. In November 2009, all defendants sought leave to file a Motion for Summary Judgment seeking judgment in favor of defendants on all claims. Briefing on defendants’ summary judgment motion was completed on January 27, 2010. The Court has not yet ruled on the summary judgment motion or set it for oral argument. No trial date has been established.
Other than the foregoing, to the knowledge of management, there is no other material litigation or governmental agency proceeding pending or threatened against the Company or its management.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Economic Environment
In recent years, Kazakhstan has undergone substantial political and economic change. As an emerging market, Kazakhstan does not possess a well-developed business infrastructure, which generally exists in a more mature free market economy. As a result, operations carried out in Kazakhstan can involve significant risks, which are not typically associated with those in developed markets. Instability in the market reform process could subject the Company to unpredictable changes in the basic business infrastructure in which it currently operates. Uncertainties regarding the political, legal, tax or regulatory environment, including the potential for adverse changes in any of these factors could affect the Company’s ability to operate commercially. Management is unable to estimate what changes may occur or the resulting effect of such changes on the Company’s financial condition or future results of operations.
Legislation and regulations regarding taxation, foreign currency translation, and licensing of foreign currency loans in the Republic of Kazakhstan continue to evolve as the central government manages the transformation from a command to a market-oriented economy. The various legislation and regulations are not always clearly written and their interpretation is subject to the opinions of the local tax inspectors. Instances of inconsistent opinions between local, regional and national tax authorities are not unusual.
Operating Lease
The Company leases its office spaces in Almaty from a third party. The lease term for the office spaces extend through December 31, 2010. The Company plans to continue leasing this office space for the next year. The Company incurred lease expense of $212,651, $308,325 and $291,672 for the years ended March 31, 2010, 2009 and 2008, respectively.
As described in Note 22, the Company leases oil storage facilities, an office building and a warehouse from a related party. Currently, this lease term is month-to-month, with monthly payments of $8,000, or $96,000 per year. The Company expects to continue to lease these facilities for the upcoming year, as well as the foreseeable future.
NOTE 24 - FINANCIAL INSTRUMENTS
As of March 31, 2010 and 2009 cash and cash equivalents included deposits in Kazakhstan banks in the amount $3,721,701 and $2,606,004, respectively and deposits in U.S. banks in the amount of $2,718,693 and $4,149,541, respectively. Kazakhstan banks are not covered by FDIC insurance, nor does the Republic of Kazakhstan have an insurance program similar to FDIC. Therefore, the full amount of our deposits in Kazakhstan banks was uninsured as of March 31, 2010 and 2009. The Company’s deposits in U.S. banks are also in non-FDIC insured accounts which means they too are not insured to the $250,000 FDIC insurance limit. To mitigate this risk, the Company has placed all of its U.S. deposits in a money market account that invests in U.S. government backed securities. As of March 31, 2010 and 2009 the Company made advance payments to Kazakhstan companies and government bodies in the amount $7,219,431 and $5,432,972, respectively. As of March 31, 2010 and 2009 restricted cash reflected in the long-term assets consisted of $770,553 and $588,217, respectively, deposited in a Kazakhstan bank and restricted to meet possible environmental obligations according to the regulations of Kazakhstan. Furthermore, the primary asset of the Company is Emir Oil LLP; an entity formed under the laws of the Republic Kazakhstan.
BMB MUNAI, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 25 - QUARTERLY FINANCIAL DATA (unaudited)
Quarterly financial information is presented in the following summary:
BMB MUNAI, INC.
SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited)
This footnote provides unaudited information required by FASC № 932-325-55, “Disclosures about Oil and Natural Gas Producing Activities.” The Company’s oil and natural gas properties are located in the Republic of Kazakhstan, which constitutes one cost centre.
Capitalized Costs - Capitalized costs and accumulated depletion, depreciation and amortization relating to oil and natural gas producing activities, all of which are conducted in the Republic of Kazakhstan, are summarized below:
March 31, 2010
March 31, 2009
Developed oil and natural gas properties
$ 246,979,803
$ 221,374,856
Unevaluated oil and natural gas properties
25,924,087
40,580,015
Accumulated depletion, depreciation and amortization
(34,302,048)
(23,226,458)
Net capitalized cost
$ 238,601,842
$ 238,728,413
Costs Incurred - Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below:
For the year ended
March 31, 2010
For the year ended
March 31, 2009
For the year ended
March 31, 2008
Acquisition costs:
Unproved properties
$ -
$ -
$ -
Proved properties
-
-
-
Exploration costs
-
2,275,021
3,024,386
Development costs
10,949,019
63,727,311
83,950,096
Subtotal
10,949,019
66,002,332
86,974,482
Asset retirement costs
-
86,438
1,300,576
Total costs incurred
$ 10,949,019
$ 66,088,770
$ 88,275,058
Results of Operations - Results of operations for the Company’s oil and natural gas producing activities are summarized below:
For the year ended
March 31, 2010
For the year ended
March 31, 2009
For the year ended
March 31, 2008
Oil and natural gas revenues
$ 57,274,526
$ 69,616,875
$ 60,196,626
Operating expenses:
Rent export tax
10,032,857
467,359
-
Export duty
-
6,783,278
-
Oil and natural gas operating expenses and ad valorem taxes
8,568,453
7,530,653
5,515,403
Accretion expense
448,351
449,025
254,572
Depletion expense
11,075,590
10,403,328
9,419,655
Results of operations from oil and gas producing activities
$ 27,149,275
$ 43,983,232
$ 45,006,996
BMB MUNAI, INC.
SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited)
Reserves - Proved reserves are estimated quantities of oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be, recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. Proved oil and natural gas reserve quantities and the related discounted future net cash flows before income taxes (see Standardized Measure) for the periods presented are based on estimates prepared by Chapman Petroleum Engineering Ltd., independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the SEC.
The Company’s net ownership in estimated quantities of proved oil reserves, and changes in net proved reserves, all of which are located in the Republic of Kazakhstan, is summarized below:
(1)
During the year ended March 31, 2009 four wells were drilled (gross and net) on the Kariman structure, one well (gross and net) on the Dolinnoe structure, one well (gross and net) on the Aksaz structure and one well (gross and net) on the Emir structure. These additions to the Kariman, Dolinnoe, Aksaz and Emir structures during the year ended March 31, 2009 resulted in an increase in estimated proved developed reserves of approximately 7.3 million BOE. These were the only extensions and discoveries made during the year ended March 31, 2009.
BMB MUNAI, INC.
SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited)
(2)
During the year ended March 31, 2008 four wells were drilled (gross and net) on the Kariman structure, one well (gross and net) on the Dolinnoe structure and one well (gross and net) on the Aksaz structure. These additions to the Kariman, Dolinnoe and Aksaz structures during the year ended March 31, 2008 resulted in an increase in our estimated proved developed reserves of approximately 4.5 million BOE and an increase in proved undeveloped reserves of approximately 4.9 million BOE. These were the only extensions and discoveries made during the year ended March 31, 2008.
(3)
During the year ended March 31, 2007 we drilled one well was drilled (gross and net) on the Kariman structure. The addition of the Kariman structure during the year ended March 31, 2007 resulted in an increase in estimated proved developed reserves of approximately 2.7 million BOE (barrels of oil equivalent) and no increase in proved undeveloped reserves. These were the only extensions or discoveries made during the year ended March 31, 2007.
Standardized Measure - The Standardized Measure of Discounted Future Net Cash Flows relating to the Company’s ownership interests in proved oil reserves for the year ended March 31, 2010, 2009 and 2008 is shown below:
For the year ended
March 31, 2010
For the year ended
March 31, 2009
For the year ended
March 31, 2008
Future cash inflows
$ 931,885,000
$ 652,739,000
$ 1,107,109,000
Future oil and natural gas operating expenses
157,667,000
144,661,000
83,380,000
Future development costs
30,890,000
33,403,000
89,350,000
Future income tax expense
279,763,000
41,520,000
249,884,000
Future net cash flows
463,565,000
433,155,000
684,495,000
10% discount factor
195,243,000
179,803,000
331,516,000
Standardized measure of discounted future net cash flows
$ 268,322,000
$ 253,352,000
$ 352,979,000
The Company’s standardized measure of discounted future net cash flows relating to proved oil reserves was prepared in accordance with the provisions of FASC № 932-325-55. Future cash inflows are computed by applying year end prices of oil and natural gas to year end quantities of proved oil and natural gas reserves. During the fiscal years ended March 31, 2010, 2009 and 2008 revenue from export sales accounted for 95%, 81% and 91%, respectively, of total revenue. To take into account the price differential for oil and natural gas exported versus sold domestically, the Company applies year end prices for export sales to 90% of the quantity of proved oil and natural gas reserves and the year end prices for domestic sales to 10% of the quantity of proved oil and natural gas reserves. Future oil and natural gas production and development costs are computed by estimating the expenditures to be incurred in producing and developing the proved oil and natural gas reserves at year end, based on year end costs and assuming continuation of existing economic condition.
BMB MUNAI, INC.
SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited)
Future income tax expenses are calculated by applying appropriate year end tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. The Standardized Measure of Discounted Future Net Cash Flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties.
Changes in Standardized Measure - Changes in Standardized Measure of Discounted Future Net Cash Flows relating to proved oil reserves are summarized below:
For the year ended
March 31, 2010
For the year ended
March 31, 2009
For the year ended
March 31, 2008
Changes due to current year operations:
Sales of oil and natural gas, net of oil and natural gas
operating expenses
$ (38,673,216)
$ (54,835,585)
$ (54,681,223)
Sales of oil and natural gas properties
-
-
-
Purchase of oil and gas properties
-
-
-
Extensions and discoveries
-
85,153,000
189,557,166
Net change in sales and transfer prices, net of production costs
163,113,547
(305,001,925)
154,594,264
Changes due to revisions of standardized variables
-
-
-
Prices and operating expenses
-
-
-
Revisions to previous quantity estimates
1,776,460
(21,739,505)
(77,465,492)
Estimated future development costs
1,426,515
30,020,093
(34,976,338)
Income taxes
(123,077,000)
104,421,000
(26,797,000)
Accretion of discount
25,335,200
35,297,900
17,126,500
Production rates (timing)
10,405,096
64,073,697
(26,973,812)
Other
(25,336,602)
(37,015,675)
41,329,935
Net Change
14,970,000
(99,627,000)
181,714,000
Beginning of year
253,352,000
352,979,000
171,265,000
End of year
$ 268,322,000
$ 253,352,000
$ 352,979,000
Sales of oil and natural gas, net of oil and natural gas operating expenses are based on historical pre-tax results. Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis, while the accretion of discount is presented on an after tax basis.
EXHIBIT INDEX
Exhibit No.
Exhibit Description
12.1
Computation of Earnings to Fixed Charges
21.1
Subsidiaries
23.1
Consent of Chapman Petroleum Engineering Ltd., Independent Petroleum Engineers
23.2
Consent of Hansen, Barnett & Maxwell, P.C., Independent Registered Public Accounting Firm
31.1
Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2
Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1
Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2
Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1
Chapman Petroleum Engineering Ltd. Letter on its estimation of proved oil and gas reserves at March 31, 2010