Freedom Holding Corp. - Annual Report: 2009 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

 

FORM 10-K

 

               For the fiscal year ended March 31, 2009

 

                For the transition period from ________ to _________

 

Commission File Number 001-33034

 

BMB MUNAI, INC.

(Exact name of registrant as specified in its charter)

 

 

+7 (727) 237-51-25

(Registrant’s telephone number, including area code)

 

Securities registered under Section 12(b) of the Exchange Act:

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.   

o Yes x No

 

 

 

 

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.          

 

 

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.              o

 

Indicate by check mark whether the registrant is a large accelerated filed, an accelerated filer, or non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.         

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.)            

 

As of September 30, 2008 the aggregate market value of the common voting stock held by non-affiliates of the issuer based upon the closing stock price of $4.15 per share was approximately $152,710,000.

 

As of May 28, 2009, the registrant had 47,378,420 shares of common stock, par value $0.001, issued and outstanding.

 

Documents Incorporated by Reference

Portions of the Registrant’s proxy statement for its 2009 Annual Meeting of Shareholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the Registrant’s fiscal year ended March 31, 2009 are incorporated by reference into Part III of this report.

 

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Table of Contents

 

 

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Forward Looking Information

 

This annual report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended that are based on management’s beliefs and assumptions and on information currently available to our management. For this purpose any statement contained in this annual report that is not a statement of historical fact may be deemed to be forward-looking, including, but not limited to, statements about our results of operations, cash flows, capital resources and liquidity, drilling plans and future exploration, production and well operations, reserves, licensing, commodity price environment, actions, intentions, plans, strategies and objectives. Without limiting the foregoing, words such as “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” or comparable terminology are intended to identify forward-looking statements. These statements by their nature involve substantial risks and uncertainties and actual results may differ materially depending on a variety of factors, many of which are not within our control. These factors include, but are not limited to, market factors, market prices (including regional basis differentials) of natural gas and oil, results for future drilling and marketing activity, future production and costs, economic conditions, competition, legislative requirements and changes and the effect of such on our business, sufficiency of future working capital, borrowings, capital resources and liquidity and other factors detailed herein and in our other Securities and Exchange Commission filings. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

 

Forward-looking statements are predictions and not guarantees of future performance or events. The forward-looking statements are based on current industry, financial and economic information, which we have assessed but which by their nature are dynamic and subject to rapid and possibly abrupt changes. Our actual results could differ materially from those stated or implied by such forward-looking statements due to risks and uncertainties associated with our business. We hereby qualify all our forward-looking statements by these cautionary statements.

 

These forward-looking statements speak only as of their dates and should not be unduly relied upon. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

 

Throughout this annual report, unless otherwise indicated by the context, references herein to the “Company”, “BMB”, “we”, our” or “us” means BMB Munai, Inc, a Nevada corporation, and its corporate subsidiaries and predecessors. Throughout this annual report all references to dollar amounts ($) refers to U.S. dollars unless otherwise indicated.

 

The following discussion should be read in conjunction with our financial statements and the related notes contained elsewhere in this report and in out our other filings with the Securities and Exchange Commission.

 

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PART I

 

 

Overview

 

BMB Munai, Inc., our company, is organized under the laws of the State of Nevada. Our business activities focus on oil and natural gas company exploration and production in the Republic of Kazakhstan (sometimes 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 the contract to January 2013 and extended the territory of the contract area to 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. We then 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.”

 

Industry and Economic Factors

 

Our business is subject to many factors beyond our control. Foremost is the fluctuation of oil and gas prices. Historically, oil and gas markets have been cyclical and volatile. During fiscal year 2009 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 nor 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.

 

Our business, as with other extractive industries, depletes our reserves and therefore oil and gas produced must be replaced for our Company to remain viable. During the past fiscal year we have realized a net increase in our reserves over the end of fiscal year 2008.

 

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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 Southwest 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 in 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 continue our practice of increasing our oil reserves by developing resource category assets to reserve category assets and proved undeveloped reserves to proved developed reserves. 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 last fiscal year we completed a very active three-year drilling program on our territory. During this time we drilled 17 wells to an average depth of 3,800 meters. Beginning in September of 2008 we began to phase out our new well drilling activities and we have released four large drilling rigs since that date as current drilling projects were completed.

 

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:

 

Reduce our current accounts payable. As a result of the collapse of world oil prices in 2008, depressed local oil prices, contractual commitments to drillers and the tax structure imposed on oil exporters by the ROK, we saw significant increase in our current accounts payable over our current assets. Responding to this financial stress has required us to seek special arrangements with creditors and to temporarily cease drilling new wells. We made significant progress in reducing our current accounts payable during the later part of the fiscal year.

 

Conduct field operations focused on maximizing production and field delineation. We will focus on increasing our oil production without substantial capital outlay during the next fiscal year. We are concentrating efforts on stabilizing production from our existing wells by using a smaller workover rig and by installing pumps on various wells to establish consistent production in each of our oil fields.

 

Our existing wells are sufficient in number to allow us to integrate our geological and geophysical reports, seismic data, drilling logs, 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 prove to be challenging when attempting to understand oil field structure, designate well locations and determination of 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 expect return on investment. We have engaged experts in the United States with experience working in Kazakhstan with these issues to assist our internal engineering staff.

 

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            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. It is our intention to review the historical geological records of the area and to conduct new 3D seismic studies of this Block during the coming fiscal year. We anticipate that the seismic work will be complete during the current fiscal year and that interpretation of the data will be available in the second calendar quarter of 2010.  

 

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, 2009. 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, 2009. 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, 2009 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. 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.

 

 

   

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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 prices in effect at March 31, 2009. 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, 2009. 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.

 

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 of oil and natural gas, the availability, proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels and the effects of state and federal regulations on oil and natural gas productions 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, 81% of our production is being sold to one client, Titan Oil (former Euro-Asian Oil AG). Revenue from oil sold to Titan Oil made up 94% 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 effect our operations long-term.

 

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Our crude oil exports are transported via the Aktau sea port to world markets. Pursuant to our agreement with Titan Oil (formerly Euro-Asian Oil AG), delivery is FCA (Incoterms 2000) at the railway station in Mangishlak. The oil is shipped via railway cars provided by Titan Oil (formerly Euro-Asian Oil AG). 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. However, we expect that our success and market exposure during the past several years has positioned us to seek financing to meet our business objectives.

 

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.

 

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Employees

 

We have approximately 360 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.

 

Executive Offices

 

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.

 

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.

 

 

Our current liabilities exceed our current assets which, if not resolved, may result in the Company being unable to satisfy its obligations or make suitable arrangements with creditors as obligations become due.

 

At March 31, 2009, our current liabilities exceeded our current assets by $11,218,705. This has created liquidity problems for the Company. This increase in current liabilities over current assets arose from the steep decline in world oil prices, a drop in oil production and the export duty imposed by the government at a time when we were under contractual obligation to drill wells at four locations on our contract territory. In an effort to correct this situation we have ceased drilling new wells and we are working with creditors to establish payment schedules or otherwise reduce our current liabilities while continuing operations. We have no assurance that we will be successful in negotiating favorable terms with our creditors.

 

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If we are unable to pay our debts or make suitable arrangement with creditors, this might be asserted to be an event of default under the Indenture governing our 5.0% convertible senior notes due 2012 (the “Notes”) and an event of default could result in the Notes becoming immediately due. We currently have insufficient funds to repay the Note principal. Given the current conditions in the credit and financial markets, we believe it would be difficult to obtain funding to retire the Notes if demand for payment were to be made prior to the scheduled maturity date.

 

The current 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 economic conditions in the United States and throughout the world have deteriorated during the past fiscal year. 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, the 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. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity and, have reduced and 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:  

 

 

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.

 

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The global financial crises and economic downturn has resulted in significantly 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:

 

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:

 

 

We may not have the funds, or the ability to raise the funds, necessary to repurchase the Notes when they become due.

 

The Notes mature in July 2012. However, the indenture agreement governing the Notes provides that following a change in control of the Company, or on July 13, 2010, holders of the Notes may require us to repurchase their Notes. We do not currently have funds to do so, nor do we expect to generate sufficient funds from operations by July 2010 to pay the repurchase price of any Notes if tendered.

 

Our failure to repurchase the Notes when required would result in an event of default with respect to the notes. Such an event of default could negatively affect the trading price of our common stock because the event of default could lead to the principal and accrued but unpaid interest on the outstanding notes becoming immediately due and payable.

 

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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.

 

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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Our cash flow from operations and access to capital is subject to a number of variables, including:

 

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 due to the global financial crisis, we anticipate that we will not have any significant capital available during the upcoming fiscal year to make substantial capital expenditures.

 

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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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.

 

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We will be unable to produce up to 68% 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 right to produce oil and gas only until January 2013, yet 68% 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 MEMR does not make public its determinations on the granting of commercial production rights. Based on discussions with the MEMR, we have learned that the primary factors used by the MEMR 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 MEMR. 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.

 

Prospects 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 effect 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

 

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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/or 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:

 

 

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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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.

 

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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, 2009, we sold approximately 81% of our crude oil production to Titan Oil (formerly Euro-Asian Oil AG). Revenue from oil sold to Titan Oil made up 94% of our revenue during the year ended March 31, 2009. 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 effect 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 and Extended Territory, and the

 

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government is required to conduct these negotiations under the “Law of Petroleum.”  The terms of the commercial production contract will establish the royalty 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 and the Extended Territory. Our obligation associated with the ADE Block is approximately $6 million. Our obligation associated with the Extended Territory is approximately $5.3 million. If satisfactory terms for commercial production rights cannot be negotiated, it could have a material adverse effect on our financial position.

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:

 

 

Risks Relating to Our Common Stock

 

Our stock price may be volatile.

 

The following factors could affect our stock price:

 

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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. Unresolved Staff Comments

 

 

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Item 2. Properties

 

 

 

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.

 

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We currently own a 100% interest in 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 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, bring our total contract area to 850 square kilometers (approximately 210,114 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 MEMR 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 our Management’s Discussion and Analysis or Consolidated Financial Statements, which present figures based on our fiscal year rather than our work program year.

 

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* Investment as of March 31, 2009.

 

As reflected in the above table, in connection with the extension of the term and territory of our exploration contract, we agreed to expend not less than $72.7 million dollars in additional work program activities through January 9, 2013.

 

Under the rules of the MEMR there is an option for expenditures above the minimum requirements in one period to 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 MEMR 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.

 

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To date, we have drilled a total of 24 wells as set forth in more detail below:

 

 

⁽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.

 

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.

 

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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 MEMR, the primary factors used by the MEMR 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% in 2010 and 7% starting from 2011) on production sold to the export market, and a 2.5% tax rate (3% in 2010 and 3.5% starting from 2011) on production sold to the domestic market. 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

 

During fiscal 2009 we completed six new wells in total. Three wells on the Kariman field, one well on the Dolinnoe field and two wells on the Aksaz field.

 

Our drilling strategy is aimed at geological exploratory drilling with the purpose of obtaining the in-depth information necessary for further exploration activities and transition to commercial production in the future, and drilling aimed at increasing production at the current stage.

 

Although not all of our wells have resulted in commercially viable production rates, drilling results have provided valuable information which we are using to construct geological and geophysical models of our fields, correction and amendments of 3D seismic results and more precise well location decision making procedures.

 

Well Performance and Production

 

The following table sets forth the number of oil and natural gas wells in which we owned an interest as of March 31, 2009.

 

 

As of the fiscal year ended March 31, 2009, each of the 24 wells identified above was in test production, testing or under/awaiting workover.

 

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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, our average daily crude oil production was 2,961 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, 2009.

 

 

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During the quarter ended December 31, 2008, we reduced our planned capital expenditure program for the remainder of the fiscal year and the upcoming fiscal year.

 

During the past several years we have pursued an aggressive capital expenditure and drilling program. We pursued this aggressive strategy, in part, to complete our mandated exploration activities and move our contract territory to commercial production by July 2009, as our rights to the contract territory could have been terminated and reverted back to the government of the Republic of Kazakhstan had we not done so. With the grant of the extension of time to complete exploration activities, to January 2013, we now have more flexibility in the pace of our exploration drilling efforts and application for transition to commercial production.

 

As a result of reduced world oil prices and, corresponding reduction in our revenues, we do not have sufficient capital available to continue to support the aggressive drilling strategy we pursued during the past several years. The reduction in anticipated revenues from production is due to several factors, including, the material drop in world oil prices; several wells we have recently completed have not generated substantial production; the decline rates on existing wells has, in many cases, been more steep than expected due to the need for reworking and treatment to remove paraffin buildup occurring during a colder than normal winter; and the imposition by the Republic of Kazakhstan of an export duty on all oil sold outside the domestic market in Kazakhstan.

 

Another reason for the decrease in production and revenue was a lack of oil storage capacity. Given world market prices during the quarter, we were unwilling to export crude oil to international market due to the negative netbacks realized after application of the high export duty imposed by the government of Kazakhstan shortly before world market prices plummeted in August 2008. Such circumstances forced us to supply 100% of

 

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our crude oil to domestic markets starting in late October 2008. This significant increase in the supply of crude oil to the domestic market in Kazakhstan led to low domestic prices and logistical issues as there is only one refinery that services western Kazakhstan oil producers. As a result several times during the quarter ending December 31, 2008, there were periods when we were unable to ship crude oil to the domestic market. This led to the crude oil inventories at the oil storage facility we lease to exceed storage capacity. As a result, we had to partially or completely (through choke scale down) shutdown several wells. Due to the pressure drop and paraffin build-up during such suspension of production, we were unable to return to the previous production rates at several wells.

 

We have developed and commenced a production restoration program based on installation and running of submersible centrifugal and bottom-hole pumps at non-producing or low-producing wells. We have completed installation of such pumps at the Kariman-4 and Kariman-7 wells during the fiscal quarter ending March 31, 2009. With the ingoing workover stimulation program we hope to restore the production level close to the levels experienced at the end of the fiscal quarter ending March 31, 2008.

 

Based on the successful results of centrifugal pumps usage, we have proceeded with extensive workover program at the existing Kariman wellstock. In the period following the fiscal year 2009 we have continued installation of the centrifugal pumps at the Kariman-10 and Kariman-11 wells. We are currently engaged in installation of the bottom-hole pumps at the Kariman-3 and Kariman-5 wells. We believe we have identified a technique for oil flow stimulation and intensification suitable for the peculiar needs of the Kariman field. We plan to continue with this program and will install centrifugal pumps on as-needed basis on the Kariman wells where we believe the use of pumps will result in greater production than the natural flow rate.

 

We are also in the process of researching various available options for using similarly-designed pumps at the Dolinnoe and Aksaz fields, both of which have higher natural gas content making it impossible to apply the same equipment currently used on the Kariman field.

 

We expect to continue working with the existing wellstock for the reminder of the fiscal year ending 2010 with the purpose of increasing and sustaining production rates from existing wells.

 

Cost Information

 

 

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:

 

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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.

 

 

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.

 

 

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Item 3. Legal Proceedings

 

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.

 

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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 our 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.

 

During the year, the Company changed its 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. That motion has been fully briefed but it has not yet been decided by the court. Fact discovery on the existing claims has been completed and the parties are now conducting expert discovery and reports. 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. 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 our management.

 

Item 4. Submission of Matters to a Vote of Security Holders

 

No matters were submitted to a vote of security holders during the quarter ended March 31, 2009.           

 

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PART II

 

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 Equities 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, 2009 and March 31, 2008, as reported by the NYSE Amex Equities.

 

 

Record Holders

 

As of May 28, 2009, we had approximately 363 shareholders of record holding 47,378,420 shares of our common stock. The number of record holders was determined from the records of our 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.

 

Stock Performance Graph

 

The performance graph below compares the cumulative total shareholder return of our common stock with the NYSE Amex Equity Composite Index and a peer group index. The graph assumes an investment of $100 on March 31, 2004 and reinvestment of dividends, if any, on the date of payment without commissions. The plot points were provided by Standard & Poor’s Institutional Market Services, Centennial, Colorado. The performance graph represents past performance, which may not be indicative of future performance.

 

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The peer group consists of Abraxas Petroleum Corp, American Oil & Gas, Inc., CanArgo Energy Corp, Gasco Energy Corp, Teton Energy Corp, Transmeridian Exploration Inc. (for the portions of the above periods during which such companies had publicly traded common stock).

 

Recent Sales of Unregistered Securities.

 

No instruments defining the rights of the holders of any class of registered securities were materially modified, limited or qualified during the quarter ended March 31, 2009.

 

We did not sell any equity securities during the quarter ended March 31, 2009.

 

Issuer Repurchases

 

We did not make any repurchases of our equity securities during the year ended March 31, 2009.

 

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, 2009, 2008, 2007, 2006 and 2005. The data set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes thereto included in this annual 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, 2009, 2008 and 2007. This discussion should be read in conjunction with the consolidated financial statements and footnotes to the consolidated financial statements included in this annual report.

 

 

Results of Operations

 

This section includes a discussion of our results of operations for the fiscal years ended March 31, 2009, 2008 and 2007. The following table sets forth selected operating data for the fiscal years indicated:

 

 

 

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.

 

 

 

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.

 

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            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:

 

 

 

 

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 $7,998,012 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 $467,359. 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.

 

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. Rent export tax is reported as part of oil and gas operating expense. During the year ended March 31, 2009 rent export tax paid to the government amounted to $515,032. 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.

 

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 45% during the year ended March 31, 2009 compared to the year ended March 31, 2008, expense per BOE increased only 21% from $6.15 per BOE during the year ended March 31, 2008 to $7.45 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 21% 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:

 

 

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 $0.38 basic and $0.37 diluted income per share compared to a net income of $31,610,563 or $0.71 basic and $0.70 diluted income per share for the year ended March 31, 2008.

 

Year ended March 31, 2008, compared to the year ended March 31, 2007.

 

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, 2008 and the year ended March 31, 2007.

 

 

 

 

Revenue. During the year ended March 31, 2008 our oil production increased 182% compared to the year ended March 31, 2007. This significant increase in production is primarily attributable to the fact that we had sixteen wells in testing or test production during all or some portion of the year ended March 31, 2008 compared to eight wells during all or some portion of the year ended March 31, 2007.

 

During the year ended March 31, 2008 we realized revenue from oil sales of $60,196,626 compared to $15,785,784 during the year ended March 31, 2007. The largest contributing factor to the 281% increase in revenue was a 184% increase in sales volume. Another factor contributing to the increase in revenues was a 34% increase in the price per barrel we received for oil sales during the year ended March 31, 2008 compared to the year ended March 31, 2007. During the fiscal years ended March 31, 2008 and 2007 we exported 91% and 100% 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 96% and 100% of total revenue, respectively, during the years ended March 31, 2008 and 2007.

 

 

Costs and Operating Expenses

 

The following table presents details of our expenses for the years ended March 31, 2008 and 2007:

 

 

Oil and Gas Operating Expenses. During the year ended March 31, 2008 we incurred $5,515,403 in oil and gas operating expenses compared to $2,272,251 during the year ended March 31, 2007. This significant increase is primarily the result of several factors, including increased royalty, salary and transportation expenses and increased repair costs.

 

During the year ended March 31, 2008 royalty paid to the government increased by $1,214,029 or 354% compared to the year ended March 31, 2007. The primary reason for the increase in royalty is two-fold. During the 2007 fiscal year, oil production increased 182% and our average sales price per barrel increased 34% as a result of exporting nearly all of our oil to the world markets during fiscal 2008. While royalty expenses increased significantly, as a percentage of total revenue royalty expense remained nearly unchanged.

 

During the year ended March 31, 2008 payroll and related payments to production personnel increased $142,418 or 28% compared to the year ended March 31, 2007. As production volume increased we retained additional production personnel during the year ended March 31, 2008.

 

Transportation expenses increased $1,886,705 or 133% as a result of the increased volume of oil we produced and transported.

 

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 143% during the year ended March 31, 2008 compared to the year ended March 31, 2007, expense per BOE decreased from $7.20 per BOE during the year ended March 31, 2007 to $6.15 during the year ended March 31, 2008. The reason expense per BOE decreased is that we increased our sales volume during the year ended March 31, 2008. During the year ended March 31, 2007 we sold 315,540 barrels of oil, during the year ended March 31, 2008 we sold 896,256 barrels of oil. As expense per BOE is a function of total expense divided by the number of barrels of oil sold, the 184% increase in sales volume more than offset the 143% increase in expenses resulting in the 15% decrease in oil and gas operating expense per BOE.

 

General and Administrative Expenses. General and administrative expenses during the year ended March 31, 2008 were $14,747,754 compared to $10,757,727 during the year ended March 31, 2007. This represents a 37% increase in general and administrative expenses. This increase in general and administrative expenses was the result of several factors such as increased payroll and related costs, rent expense, taxes and professional services.

 

We recognized compensation expense of $2,303,078 during the year ended March 31, 2008 resulting from restricted stock grants made to employees and outside consultants. By comparison, during the year ended March 31, 2007 we recognized compensation expense in the amount of $4,134,823 for restricted stock grants issued to employees and outside consultants.

 

The increase in general and administrative expense during the 2008 year was also attributable to:

 

 

These increases more than offset the 44% decrease in compensation expense realized during the year ended March 31, 2008.

 

Depletion. Depletion expense for the year ended March 31, 2008 increased by $7,412,821 compared to the year ended March 31, 2007. The major reason for this increase in depletion expense was a 184% increase in sales volume in fiscal 2008 compared to fiscal 2007. 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 2008.

 

 

Depreciation and Amortization. Depreciation and amortization expense for the year ended March 31, 2008 increased 40% compared to the year ended March 31, 2007. The increase resulted from purchases of fixed assets during the year.

 

Income from Operations. During the year ended March 31, 2008 we realized income from operations of $30,020,087 compared to income from operations of $404,843 during the year ended March 31, 2007. This increase in income from operations during fiscal 2008 is the result of the 281% increase in revenue during fiscal 2008, which was only partially offset by a 96% increase in total expenses.

 

Other Income. During the fiscal year ended March 31, 2008 we realized total other income of $1,186,895 compared to $1,487,928 during the fiscal year ended March 31, 2007. This 20% decrease is largely attributable to a $232,715 decrease in interest income and a $65,796 decrease in exchange gain resulting from fluctuations of foreign currency rates against the U.S. Dollar.

 

Net Income. For all of the foregoing reasons, during the year ended March 31, 2008 we realized net income of $31,610,563 or $0.71 per share compared to a net income of $1,039,491 or $0.02 for the year ended March 31, 2007.

 

Liquidity and Capital Resources

 

For the period from inception on May 6, 2003 through March 31, 2009, we have incurred capital expenditures of $238,728,413 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, 2009 we raised approximately $94.6 million through the sale of our common stock. Additionally during the quarter ended September 30, 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 and see Note 11 to the Notes to the Consolidated Financial Statements, March 31, 2009.

 

Problems in the credit markets, steep declines in worldwide oil prices and volatility and downward trends in the stock market evidence a weakening United States and global economy. In addition, these conditions 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, 2009, our current liabilities exceeded current assets by $11,218,705. This has created a liquidity problem for the Company in the near term. This increase in current liabilities over current assets arose from the steep decline in world oil prices, a drop in our current oil production and the export duty imposed by the government at a time when we were under contractual obligation to drill wells at four locations in the contract territory. In an effort to correct this situation we have ceased drilling new wells and we are working with creditors to establish payment schedules or other arrangements to reduce our current liabilities and continue operations. We have no assurance that we will be successful in negotiating favorable terms with our creditors.

 

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As world oil prices began to rebound during our fourth fiscal quarter 2009, in February 2009 we again began exporting oil to the world markets. The netback we receive from export sales is currently higher than the netback we receive on domestic sales which should help to improve our liquidity situation.

 

Cash Flows

 

During the year ended March 31, 2009 cash was primarily used to fund exploration and development expenditures. See below for additional discussion and analysis of cash flow.

 

Our principal source of liquidity during the year ended March 31, 2009 was cash and cash equivalents. At March 31, 2008 cash and cash equivalents totaled approximately $17.2 million. At March 31, 2009 cash and cash equivalents had decreased to approximately $6.8 million. During the year ended March 31, 2009 we spent approximately $63.9 million to fund our drilling 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, 2009, excluding current liabilities as listed on our consolidated balance sheet:

 

 

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Off-Balance Sheet Financing Arrangements

 

As of March 31, 2009, 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 the understanding of our financial statements. The impact of these policies and associated risks are discussed throughout Management’s Discussion and Analysis and Plan of Operations 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 SFAS No. 123R, Share Based Payment and EITF Abstracts Issue 96-18, Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services. Under SFAS No. 123R, 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.

 

We have a stock option plan as described in Note 14. 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, 2009, 2008 and 2007 was $7,450,211, $2,303,078 and $4,134,823, 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 reserve 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:

 

 

 

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.

 

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 SEC Regulation S-X Rule 4-10. 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 give us a significant loss for a particular period; however, future depletion expense would be reduced.

 

Recently Issued Accounting Pronouncements

 

In December 2007, the FASB issued a revision of Statement No. 141 (R), “Business Combinations”. This Statement establishes principles and requirements for how the acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is after the beginning of the first annual reporting period beginning after December 15, 2008. Management does not anticipate this Statement will impact the Company’s consolidated financial position or consolidated results of operations and cash flows.

 

In March 2008, the FASB issued Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”. This Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This

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disclosure better conveys the purpose of derivative use in terms of the risks that the entity is intending to manage. Disclosing the fair values of derivative instruments and their gains and losses in a tabular format should provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features should provide information on the potential effect on an entity’s liquidity from using derivatives. This Statement requires cross-referencing within the footnotes, which should help users of financial statements locate important information about derivative instruments. This Statement is effective for financial statements issued for the fiscal years and interim periods beginning after November 15, 2008. Management does not anticipate this Statement will impact the Company’s consolidated financial position or consolidated results of operations and cash flows.

 

In April 2008, FASB issued FASB Staff Position SFAS No. 142-3, Determination of the Useful Life of Intangible Assets (“FSP SFAS No. 142-3”). FSP SFAS No. 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognizable intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). The intent of FSP SFAS No. 142-3 is to improve the consistency between the useful life of a recognizable intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141(R), “Business Combinations” and other U.S. generally accepted accounting principles. FSP SFAS No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The Company does not anticipate that the adoption of FSP SFAS No. 142-3 will have an impact on its financial position or results of operations.

 

In May 2008, the FASB issued FASB Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)", or FSP No. APB 14-1. FSP No. APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14 “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants”. Additionally, the FSP 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. FSP No. APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Management is currently assessing the impact this standard will have on the Company’s consolidated financial position or results of operations.

 

In May 2008, the FASB issued Statement No. Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” This Statement identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States (the GAAP hierarchy). The Board does not expect that this Statement will result in a change in current practice. However, transition provisions have been provided in the unusual circumstance that the application of the provisions of this Statement results in a change in practice. This Statement is effective after 60 days following the SEC’s approval of the PCAOB amendment to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. Management does not anticipate this Statement will impact the Company’s consolidated financial position or consolidated results of operations and cash flows.

 

 

In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities”(“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “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. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. All prior-period EPS data presented shall be adjusted retrospectively to conform to the provisions of this FSP. The Company will apply the requirements of FSP EITF 03-6-1 upon its adoption beginning with the interim period ending June 30, 2009. Management does not expect the adoption of FSP EITF 03-6-1 to have a material impact on its financial position and results of operations, although prior-period EPS data will be affected.

 

In December 2008, the SEC issued the final rule, "Modernization of Oil and Gas Reporting," which adopts revisions to the SEC's oil and natural gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. Early adoption of the new rules is prohibited. The new rules are intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves to help investors evaluate their investments in oil and natural gas companies. The new rules are also designed to modernize the oil and natural gas disclosure requirements to align them with current practices and changes in technology. The new rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting disclosure of probable and possible reserves. The Company is currently evaluating the potential impact of these rules. The SEC is discussing the rules with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, the Company will begin complying with the disclosure requirements in our annual report on Form 10-K for the fiscal year ending March 31, 2010.

 

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. 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 2009 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, 2009, we sold 1,073,754 barrels of oil and condensate. We realized an average sales price per barrel of $64.835. 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:

 

 

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, 2009 would have affected our net income by less than $1 million.

 

 

Item 8. Financial Statements and Supplementary Data

 

The consolidated financial statements and supplementary data required by this item are included at page F-1 herein.

 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

During the fiscal year ended March 31, 2009 there were no changes in and disagreements with our independent registered public accounting firm on accounting and financial disclosure.

 

Item 9A. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

We carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Company’s “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of March 31, 2009. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that, as of March 31, 2009, the Company’s disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in the Company’s Securities and Exchange Commission (“SEC”) reports (i) is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms, and (ii) is accumulated and communicated to the Company’s management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure.

 

Management’s Report on Internal Control Over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with generally accepted accounting principles. 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 internal controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.

 

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management concluded that our internal control over financial reporting was effective as of March 31, 2009.

 

 

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, 2009, 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, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

54

 

 

 

 

 

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, 2009, 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, 2009, 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 10, 2009 expressed an unqualified opinion.

 

 

Salt Lake City, Utah

June 10, 2009

 

55

 

Item 9B. Other Information

 

 

PART III

 

Item 10. Directors, Executive Officers and Corporate Governance

 

The information regarding our directors and Executive Officers of the Registrant will be included in a proxy statement to be filed with the Commission prior to July 29, 2009 and upon the filing of such proxy statement, is incorporated by reference herein.

 

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.            We have also adopted charters for our Audit Committee, Compensation Committee, and Corporate Governance and Nominating Committee.

 

Copies of our Code of Ethics and our committee charters have been posted on our website and may be viewed at www.bmbmunai.com. Copies of our Code of Ethics and our committee charters 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. The information on our website is not incorporated by reference into this annual report on Form 10-K.

 

Item 11. Executive Compensation

 

The information regarding executive compensation will be included in a proxy statement to be filed with the Commission prior to July 29, 2009 and upon the filing of such proxy statement, is incorporated by reference herein.

 

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

The information regarding Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters will be included in a proxy statement to be filed with the Commission prior to July 29, 2009 and upon the filing of such proxy statement, is incorporated by reference herein.

 

Item 13. Certain Relationships and Related Transactions and Director Independence

 

The information regarding Certain Relationships and Related Transactions and Related Transactions will be included in a proxy statement to be filed with the Commission prior to July 29, 2009 and upon the filing of such proxy statement, is incorporated by reference herein.

 

56

Item 14. Principal Accounting Fees and Services

 

The information regarding Principal Accountant Fees and Services will be included in a proxy statement to be filed with the Commission prior to July 29, 2009 and upon the filing of such proxy statement, is incorporated by reference herein.

 

Item 15. Exhibits, Financial Statement Schedules

 

 

Financial Statements

 

Report of Independent Registered Public Accounting Firm – Hansen, Barnett & Maxwell, P.C. dated June 10, 2009

 

                Consolidated Balance Sheets as of March 31, 2009 and 2008

 

Consolidated Statements of Operations for the years ended March 31, 2009, 2008 and 2007

 

Consolidated Statements of Shareholders’ Equity for the years ended March 31, 2009, 2008 and 2007

 

Consolidated Statements of Cash Flows for the years ended March 31, 2009, 2008 and 2007

 

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.

 

57

 

                Exhibits

 

 

58

 

 

⁽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.

 

59

⁽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.

 

60

 

 

SIGNATURES

 

In accordance with Section 12 of the Securities Exchange Act of 1934, the registrant caused this registration statement to be signed on its behalf, thereunto duly authorized.

 

 

61

 

 

 

CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED MARCH 31, 2009, 2008 AND 2007

 

 

 

Table of Contents

 

 

 

 

 

 

 

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, 2009, 2008, and 2007, 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, 2009. 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, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended March 31, 2009 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, 2009, 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 10, 2009 expressed an unqualified opinion.

 

 

Salt Lake City, Utah

June 10, 2009

 

 

BMB MUNAI, INC.

 

CONSOLIDATED BALANCE SHEETS

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

 

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

F-7

 

 

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 acquiror 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

 

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.

 

 

 

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.

 

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 (“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.”

 

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, 2009, 2008 and 2007, sales to one customer represented 81%, 91% and 100% of total sales, respectively. At March 31, 2009, 2008 and 2007, this customer made up 100%, 97% and 100% 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 SFAS No. 123R, Share Based Payment and EITF Abstracts Issue 96-18, Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services. Under SFAS No. 123R, 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.

 

The Company has a stock option plan as described in Note 14. 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, 2009, 2008 and 2007 was $7,450,211, $2,303,078 and $4,134,823, 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 is 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 transferred. Produced but unsold products are recorded as inventory until sold.

 

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 Republic of Kazakhstan issued a resolution that cancelled the export duty effective January 26, 2009 for companies operating under the new tax code.

 

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% in 2010 and 7% starting from 2011) on production sold to the export market, and a 2.5% tax rate (3% in 2010 and 3.5% starting from 2011) 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 reported as part of oil and gas operating expense.

 

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 carry forwards. 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 Values 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.

 

 

 

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, 2009 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.

 

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.

 

 

 

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:

 

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.

 

A portion of the Company’s other fixed assets are used in the development of oil and gas properties. Accordingly, depreciation for those assets is capitalized as part of oil and gas properties subject to amortization. For the years ended March 31, 2009, 2008 and 2007 the Company had depreciation of $353,545, $180,804 and $145,628, respectively, that was included in oil and gas properties.

 

 

 

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. The Company’s annual evaluation resulted in no impairment at March 31, 2009.

 

Convertible notes payable issue costs

 

In accordance with the Accounting Principles Board Opinion 21 “Interest on Receivables and Payables”, 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 follows the guidance in the EITF 95-13 “Classification of Debt Issue Costs in the Statement of Cash Flows” and classifies cash payments for bond issue costs as a financing activity.

 

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 United States 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 September 2006, the FASB issued SFAS No. 157, “Fair Value Measurement.” This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but provides guidance on how to measure fair value by providing a fair value hierarchy used to classify the source of the information. We adopted SFAS No. 157 effective April 1, 2008 and the adoption did not have a significant effect on our consolidated results of operations, financial position or cash flows. In February 2008, the FASB issued FSP SFAS No. 157-2 which delays the effective date of SFAS No. 157 for all

 

 

 

non-financial assets and non-financial liabilities except those that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). This deferral of SFAS No. 157 primarily applies to our asset retirement obligation (ARO), which uses fair value measures at the date incurred to determine our liability. We are currently evaluating the impact of the pending adoption in 2009 of SFAS No. 157 non-recurring fair value measures.

 

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115,” effective on January 1, 2008, and permits companies to choose, at specified dates, to measure certain eligible financial instruments at fair value. The provisions of SFAS No. 159 apply only to entities that elect to use the fair value option and to all entities with available-for-sale and trading securities. At the effective date, companies may elect the fair value option for eligible items that exist at that date, and the effect of the first remeasurement to fair value must be reported as a cumulative-effect adjustment to the opening balance of retained earnings. The adoption of SFAS No. 159 has not had a material impact on the Company’s financial position or results of operations.

 

Effective January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109” (FIN 48), which clarifies the accounting and disclosure for uncertainty in tax positions. The Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns for the open tax years in such jurisdictions. The Company has identified its federal income tax return and its state income tax returns in Utah and Republic of Kazakhstan in which it operates as “major” tax jurisdictions. The Company has no significant reserves for uncertain tax positions and no adjustments to such reserves were required upon adoption of FIN 48. No interest or penalties have been levied against the Company and none are anticipated, therefore interest or penalty has been included in our provision for income taxes in the consolidated statements of operations.

 

Recent accounting pronouncements

 

In December 2007, the FASB issued a revision of Statement No. 141 (R), “Business Combinations”. This Statement establishes principles and requirements for how the acquirer recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to business combinations for which the acquisition date is after the beginning of the first annual reporting period beginning after December 15, 2008. Management does not anticipate this Statement will impact the Company’s consolidated financial position or consolidated results of operations and cash flows.

 

 

 

In March 2008, the FASB issued Statement No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”. This Statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This disclosure better conveys the purpose of derivative use in terms of the risks that the entity is intending to manage. Disclosing the fair values of derivative instruments and their gains and losses in a tabular format should provide a more complete picture of the location in an entity’s financial statements of both the derivative positions existing at period end and the effect of using derivatives during the reporting period. Disclosing information about credit-risk-related contingent features should provide information on the potential effect on an entity’s liquidity from using derivatives. This Statement requires cross-referencing within the footnotes, which should help users of financial statements locate important information about derivative instruments. This Statement is effective for financial statements issued for the fiscal years and interim periods beginning after November 15, 2008. Management does not anticipate this Statement will impact the Company’s consolidated financial position or consolidated results of operations and cash flows.

 

In April 2008, FASB issued FASB Staff Position SFAS No. 142-3, Determination of the Useful Life of Intangible Assets (“FSP SFAS No. 142-3”). FSP SFAS No. 142-3 amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognizable intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”). The intent of FSP SFAS No. 142-3 is to improve the consistency between the useful life of a recognizable intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS 141(R), “Business Combinations” and other U.S. generally accepted accounting principles. FSP SFAS No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. The Company does not anticipate that the adoption of FSP SFAS No. 142-3 will have an impact on its financial position or results of operations.

 

In May 2008, the FASB issued FASB Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement)", or FSP No. APB 14-1. FSP No. APB 14-1 clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement) are not addressed by paragraph 12 of APB Opinion No. 14 “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants”. Additionally, the FSP 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. FSP No. APB 14-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Management is currently assessing the impact this standard will have on the Company’s consolidated financial position or results of operations.

 

 

 

In May 2008, the FASB issued Statement No. Statement No. 162, “The Hierarchy of Generally Accepted Accounting Principles.” This Statement identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States (the GAAP hierarchy). The Board does not expect that this Statement will result in a change in current practice. However, transition provisions have been provided in the unusual circumstance that the application of the provisions of this Statement results in a change in practice. This Statement is effective after 60 days following the SEC’s approval of the PCAOB amendment to AU Section 411, The Meaning of Present Fairly in Conformity With Generally Accepted Accounting Principles. Management does not anticipate this Statement will impact the Company’s consolidated financial position or consolidated results of operations and cash flows.

 

In June 2008, the FASB issued Staff Position No. EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”). FSP EITF 03-6-1 applies to the calculation of earnings per share (“EPS”) described in paragraphs 60 and 61 of FASB Statement No. 128, “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. FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early adoption is prohibited. All prior-period EPS data presented shall be adjusted retrospectively to conform to the provisions of this FSP. The Company will apply the requirements of FSP EITF 03-6-1 upon its adoption beginning with the interim period ending June 30, 2009. Management does not expect the adoption of FSP EITF 03-6-1 to have a material impact on its financial position and results of operations, although prior-period EPS data will be affected.

 

In December 2008, the SEC issued the final rule, "Modernization of Oil and Gas Reporting," which adopts revisions to the SEC's oil and natural gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. Early adoption of the new rules is prohibited. The new rules are intended to provide investors with a more meaningful and comprehensive understanding of oil and natural gas reserves to help investors evaluate their investments in oil and natural gas companies. The new rules are also designed to modernize the oil and natural gas disclosure requirements to align them with current practices and changes in technology. The new rules include changes to the pricing used to estimate reserves, the ability to include nontraditional resources in reserves, the use of new technology for determining reserves and permitting

 

 

 

disclosure of probable and possible reserves. The Company is currently evaluating the potential impact of these rules. The SEC is discussing the rules with the FASB staff to align FASB accounting standards with the new SEC rules. These discussions may delay the required compliance date. Absent any change in the effective date, the Company will begin complying with the disclosure requirements in our annual report on Form 10-K for the fiscal year ending March 31, 2010.

 

NOTE 3 - CASH AND CASH EQUIVALENTS

 

As of March 31, 2009 and 2008 cash and cash equivalents included:

 

 

As of March 31, 2009 and 2008, cash and cash equivalents included $2,371,558 and $14,203,574 placed in money market funds having 30 day simple yields of 0.13% and 2.58%, respectively.

 

NOTE 4 - PREPAID EXPENSES AND OTHER ASSETS

 

Prepaid expenses and other assets as of March 31, 2009 and 2008, were as follows:

 

 

During the year ended March 31, 2009 reserves against uncollectible advances and prepayments were written-off in amount of $225,675 and remaining amount of $121,302 was reversed.

 

 

 

NOTE 5 - OIL AND GAS PROPERTIES

 

Oil and gas properties using the full cost method as of March 31, 2009 and 2008, were as follows:

 

 

The purchase of Emir Oil LLP has been accounted for as a non-taxable business combination. Since goodwill was not recognized in this stock based subsidiary acquisition involving oil and gas properties, a recognition of a deferred tax liability related to the acquisition increases the financial reporting basis of the oil and gas properties.

 

In November 2007 the Company entered into a consulting agreement with Caspian Energy Consulting Ltd. (“Consultant”). In addition to extending the existing exploration contract, which is described in Note 22, the consulting agreement provided that in the event the Consultant is successful in execution and delivery to the Company of a new exploration contract for a new contract territory, the Company will pay the amount of $4,000,000. As discussed in Note 17, the Consultant was successful in extending the Company’s contract territory. Due to the territory extension increasing the Company’s drilling area, as well as increasing possible reserves, these expenditures have been accrued and capitalized as part of oil and gas properties.

 

NOTE 6 – GAS UTILIZATION FACILITY

 

On April 13, 2006 the Company 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”).

 

 

 

In accordance with terms of the Agreement, the Company made payments of $7,261,561 for development of project documentation, purchase of equipment, transportation and customs, and construction of a gas pipe-line, during the year ended March 31, 2008.

 

During the fiscal year ended March 31, 2009, the Company transferred machinery and equipment previously classified as oil and gas properties and other fixed assets of $1,695,514 and $6,602,617, respectively, to the completion of the Facility.

 

The Facility was completed 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.

 

No depreciation expense was recognized for Gas Utilization Facility during the quarter ended March 31, 2009 because during this quarter it operated in the test mode.

 

NOTE 7 – INVENTORIES FOR OIL AND GAS PROJECTS

 

As of March 31, 2009 and 2008 inventories included:

 

 

 

 

 

NOTE 8 - OTHER FIXED ASSETS

 

 

In accordance with SFAS No. 19, 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 $353,545 was capitalized to oil and gas properties for the year ended March 31, 2009 and $180,804 for the year ended March 31, 2008.

 

NOTE 9 - LONG TERM VAT RECOVERABLE

 

As of March 31, 2009 and 2008 the Company had long term VAT recoverable in the amount of $2,423,940 and $8,106,397, 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, 2009 the Company received refunds of VAT in the amount of $7,461,139.

 

 

 

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, 2009 and 2008 the Company had $588,217 and $622,697, respectively, restricted 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.

 

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:

 

 

 

 

If a holder of notes shall convert its notes following the date on which notice of a change in control event is given by us but on or prior to the 60th day following the date of such notice, then we 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.

 

 

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:

 

 

 

 

 

 

 

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.

 

As of March 31, 2009 and March 31, 2008 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 $1,331,522 and $535,455 as of March 31, 2009 and March 31, 2008, respectively. The carrying value of convertible notes will be accreted to the redemption value of $64,323,785.

 

As of March 31, 2009 and March 31, 2008 the convertible notes payable amount is presented as follows:

 

 

In accordance with SFAS No. 34, Capitalization of Interest and FIN 33, Applying FASB Statement No. 34 to Oil and Gas Producing Operations Accounted for by the Full Cost Method and Interpretation of FASB Statement No. 34, coupon payments on convertible notes in the amount of $2,250,000 and accretion expense relating to the discount on convertible notes (difference between the redemption amount and the carrying amount as of the date of issue) in the amount of $596,654, was capitalized to oil and gas properties for the year ended March 31, 2009. During the years ended March 31, 2009 and 2008 the Company recorded interest expense in the amount of $1,138,874 and $0, respectively.

 

 

 

NOTE 12 - LIQUIDATION FUND

 

A reconciliation on the Liquidation Fund (Asset Retirement Obligation) at March 31, 2009, 2008 and 2007 is as follows:

 

 

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.

 

At March 31, 2009, 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, 2009 and 2008, was $4,263,994 and $3,728,531, respectively.

 

During the quarter ended March 31, 2009 the Company recorded a revision of estimate in the amount of $757,047 resulted from the decrease of abandonment costs of wells.

 

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 $12,937,563, $1,827,168 and $3,243,481, for the years ended March 31, 2009, 2008 and 2007, 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. Therefore, the Exploration Contract allows the Company to be exempt from Kazakhstan corporate income tax for the period of the exploration phase.

 

 

 

Undistributed earnings of the Company’s foreign subsidiaries since acquisition amounted to approximately $60,760,405 at March 31, 2009. 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.

 

The income tax provision/(benefit) in the Consolidated Statements of Operations is comprised of:

 

 

The following is a reconciliation of income taxes computed using the foreign Republic of Kazakhstan federal statutory rate and the domestic U.S. federal statutory rate to the provision/(benefit) for income taxes:

 

 

Effective January 1, 2009, the Republic of Kazakhstan adopted a new tax code, which decreased the corporate income rate for legal entities to 20%. The effect of the change in tax rate has been accounted for as part of “Other” in the reconciliation table above.

 

As of March 31, 2008, the Company had net operating loss carry forwards for income tax purposes of $20,197,220, which if unused, will expire in 2024, 2025, 2026, 2027 and 2028.

 

 

 

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:

 

 

Deferred income taxes for US and Kazakhstan tax jurisdiction are as follows:

 

 

 

NOTE 14 - 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 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 February 1, 2006, the Company granted common shares to the Company’s former chief finance officer for services rendered. He was granted 50,000 shares. The shares were valued at $7.40 per share. The stock grants vested immediately. Compensation expense in the amount of $370,000 was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the year ended March 31, 2006.

 

On June 20, 2006, the Company granted common stock to officers and 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. All of the restricted stock grants vested immediately upon grant. Compensation expense in the amount of $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, 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 will now vest on the earlier of July 9, 2009 and the occurrence of an Extraordinary Event.

 

Non-cash compensation expense in the amount of $2,271,556 and $2,303,078 was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the year ended March 31, 2009 and 2008, respectively.

 

As of March 31, 2009, there was $567,889 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 0.25 years.

 

As further discussed in Note 17, 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 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 Company’s shares on June 24, 2008) for the three months ended September 30, 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.

 

Non-cash compensation expense in the amount of $5,178,655 was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the year ended March 31, 2009.

 

As of March 31, 2009, there was $2,176,245 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 0.3 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. The options will expire three years from the grant date. 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.

 

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.

 

 

 

Stock options outstanding and exercisable as of March 31, 2009, were as follows:

 

 

Additional information regarding outstanding options as of March 31, 2009, was as follows:

 

 

The estimated fair value of the stock options issued were determined using Black-Scholes option pricing model with the following assumptions:

 

 

 

 

 

Warrants

 

On November 26, 2003, the Company granted warrants to placement agents in connection with funds raised on the Company’s behalf. These warrants granted the placement agents the right to purchase up to 142,857 shares of the Company’s common stock at an exercise price of $3.50 per share. These warrants have been offset to the proceeds as a cost of capital. On March 6, 2008 90,477 of these warrants were exercised. On July 28, 2008, 14,286 of these warrants were exercised. The remaining warrants for 38,094 shares expired at the end of November 2008.

 

On April 12, 2005, the Company granted warrants to placement agents in connection with funds raised on the Company’s behalf. These warrants granted the placement agents the right to purchase up to 110,100 shares of the Company’s common stock at an exercise price of $5.00 per share. These warrants have been offset to the proceeds as a cost of capital. In October 2005, warrants to purchase 60,000 shares were exercised. In April 2006, the remaining warrants to purchase 50,100 shares were exercised.

 

On December 31, 2005, the Company granted warrants to placement agents in connection with funds raised on the Company’s behalf. These warrants granted the placement agents the right to purchase up to 916,667 shares of the Company’s common stock at an exercise price of $6.00 per share. These warrants have been offset to the proceeds as a cost of capital. On May 13, 2006, these warrants were exercised.

 

Warrants outstanding and exercisable as of March 31, 2009 were as follows:

 

 

 

 

 

NOTE 15 - 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 sold its crude oil to the domestic market from November 2008 to January 2009, since netbacks on domestic market sales were more attractive than on export sales.

 

The Company recognized revenue as follows:

 

 

 

NOTE 16 – 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 export duty for the year ended March 31, 2009 amounted to $6,783,278, which is being reported as a part of operating expenses. 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.

 

NOTE 17 - 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.

 

 

 

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 22.

 

NOTE 18 – 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 19 – 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 they 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.

 

 

 

NOTE 20 - EARNINGS PER SHARE INFORMATION

 

The calculation of the basic and diluted earnings/loss per share is based on the following data:

 

 

The dilutive weighted average common shares outstanding for the year ended March 31, 2009 does not include the effect of the potential conversion of the Notes because the average market share price for the year ended March 31, 2009 was lower than potential conversion price of the convertible notes for this period.

 

The dilutive weighted average common shares outstanding for the year ended March 31, 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 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 21 - 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, 2009, 2008 and 2007, totaled $221,903, $254,427 and $203,686, respectively. Also the Company had advances paid to Term Oil LLC in the amount of $15,006 as of March 31, 2009 and accounts payable to Term Oil LLC in the amount of $53,624 as of March 31, 2008. A Company shareholder is an owner of Term Oil LLC.

 

The future minimum rental payments required under this operating lease amount to $146,453. The Company’s current lease term with Term Oil LLC expires on December 31, 2009. The Company intends to extend this contract, and if extended, would require additional future minimum lease payments.

 

NOTE 22 - 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 and the Southeast Block of $5,994,200 and $5,350,680, 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. Through March 31, 2009 the Company had spent a total of $259.5 million in exploration activity.

 

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 $9.1 million by January 9, 2010. The Company must spend an additional $21.5 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.

 

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 addendum to the Contract granting the territory extension also requires us to:

 

 

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.

 

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 our 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.

 

During the year, the Company changed its 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. That motion has been fully briefed but it has not yet been decided by the court. Fact discovery on the existing claims has been completed and the parties are now conducting expert discovery and reports. 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. 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 our management.

 

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.

 

 

 

NOTE 23 - FINANCIAL INSTRUMENTS

 

As of March 31, 2009 and 2008 cash and cash equivalents included deposits in Kazakhstan banks in the amount $2,606,004 and $2,211,353, respectively and deposits in U.S. banks in the amount of $4,149,541 and $15,027,484, 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, 2009 and 2008. 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, 2009 and 2008 the Company made advance payments to Kazakhstan companies and government bodies in the amount $5,432,972 and $21,266,329, respectively. As of March 31, 2009 and 2008 restricted cash reflected in the long-term assets consisted of $588,217 and $622,697, 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.

 

NOTE 24 - QUARTERLY FINANCIAL DATA (unaudited)

 

Quarterly financial information is presented in the following summary:

 

 

 

 

F-42

 

 

 

 

 

NOTE 25 – SUBSEQUENT EVENTS

 

On May 14, 2009, the Company’s Board of Directors (the “Board”) authorized the formation of a new Limited Liability Entity to operate the Gas Utilization Plant. Similarly, the Board also approved the execution, delivery, and performance of a purchase-sale agreement for the Gas Utilization Facility to the newly formed entity. The new entity will be consolidated in the Company’s future financial statements.

 

F-43

 

 

 

This footnote provides unaudited information required by SFAS No. 69, “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 center.

 

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:

 

 

Costs Incurred - Costs incurred in oil and natural gas property acquisition, exploration and development activities are summarized below:

 

 

F-44

 

 

 

 

Results of Operations – Results of operations for the Company’s oil and natural gas producing activities are summarized below:

 

 

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, are summarized below:

 

 

F-45

 

 

 

 

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, 2009, 2008 and 2007 is shown below:

 

 

Our standardized measure of discounted future net cash flows relating to proved oil reserves was prepared in accordance with the provisions of SFAS 69. 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, 2009, 2008 and 2007 revenue from export sales accounted for 94%, 91% and 100%, 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 80% of the quantity of proved oil and natural gas reserves and the year end prices for domestic sales to 20% 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.

F-46

 

 

 

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:

 

 

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.