Freedom Holding Corp. - Quarter Report: 2009 September (Form 10-Q)

 

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 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 November 2, 2009, the registrant had 50,365,015 shares of common stock, par value $0.001, issued and outstanding.

 

BMB MUNAI, INC.

FORM 10-Q

TABLE OF CONTENTS

 

 

 

2

PART I - FINANCIAL INFORMATION

Item 1 - Unaudited Consolidated Financial Statements

BMB MUNAI, INC.

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

 

 

 

3

 

 

 

4

 

5

 

 

 

6

 

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 six months ended September 30, 2009 and 2008, sales to one customer represented 89% and 96% of total sales, respectively. At September 30, 2009 and 2008, this customer made up 100% of accounts receivable. While the loss of this foregoing customer could have a material adverse effect on the Company in the short-term, the loss of this customer should not materially adversely affect the Company in the long-term because of the available market for the Company’s crude oil and natural gas production from other purchasers.

 

Foreign currency translation

 

Transactions denominated in foreign currencies are reported at the rates of exchange prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to United States Dollars at the rates of exchange prevailing at the balance sheet dates. Any gains or losses arising from a change in exchange rates subsequent to the date of the transaction are included as an exchange gain or loss in the Consolidated Statements of Operations.

 

Share-based compensation

 

The Company accounts for options granted to non-employees at their fair value in accordance with FASC Topic 718 – Stock Compensation. Share-based compensation is determined as the fair value of the equity instruments issued. The measurement date for these issuances is the earlier of the date at which a commitment for performance by the recipient to earn the equity instruments is reached or the date at which the recipient’s performance is complete. Stock options granted to the “selling agents” in the private equity placement transactions have been offset to the proceeds as a cost of capital. Stock options and stocks granted to other non-employees are recognized in the Consolidated Statements of Operations.

 

 

 

The Company has a stock option plan as described in Note 11. 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 six months ended September 30, 2009 and 2008 was $2,744,133 and $2,647,059, 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 transfers. Produced but unsold products are recorded as inventory until sold.

 

During the three months ended September 30, 2009, the Company purchased light crude oil from a third party for the purpose of blending the oil with the Company’s own production. The cost of this purchased crude oil is recorded as part of oil and gas operating expenses.

 

Export duty

 

The formula for determining the amount of the crude oil export duty is based on a sliding scale that is tied to the world market price for oil. The amount of the export duty can change with fluctuations in world oil prices. The export duty fees are expensed as incurred and are classified as costs and operating expenses.

 

In December 2008 the Government of the Republic of Kazakhstan issued a resolution that cancelled the export duty effective January 26, 2009 for companies operating under the new tax code.

 

 

 

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 carryforwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

 

Fair 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 September 30, 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.

 

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.

 

Convertible notes payable issue costs

 

The Company recognizes convertible notes payable issue costs on the balance sheet as deferred charges, and amortizes the balance over the term of the related debt. The Company classifies cash payments for bond issue costs as a financing activity.

 

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 May 2008, the FASB issued guidance on accounting for convertible debt instruments that may be settled in cash upon conversion. The guidance clarifies that convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement), which is not addressed by prior guidance. Additionally, the guidance specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The Company adopted this standard on April 1, 2009. The adoption of this standard did not have a material impact on consolidated financial position or results of operations.

 

In June 2008, the FASB issued guidance on determining whether instruments granted in share-based payment transactions are participating securities. The guidance applies to the calculation of earnings per share for share-based payment awards with rights to dividends or dividend equivalents. It states that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of EPS pursuant to the two-class method. The Company adopted this guidance on April 1, 2009 and has included certain share-based payment awards in its calculation of basic weighted average shares in the EPS calculation. Accordingly, all prior-period EPS data presented has been adjusted retrospectively to conform to the provisions of this guidance. Management has determined that the adoption of this guidance does not have a material impact on its financial position and results of operations, although prior-period EPS data is affected.

 

In June 2009, the FASB established the FASB Accounting Standards Codification (Codification), which officially commenced July 1, 2009, to become the source of authoritative US GAAP recognized by the FASB to be applied by nongovernmental entities.  Rules and interpretive releases of the SEC under authority of federal

 

 

 

securities laws are also sources of authoritative US GAAP for SEC registrants.  Generally, the Codification is not expected to change US GAAP.  All other accounting literature excluded from the Codification will be considered nonauthoritative.  The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009.  We adopted the new standards for our quarter ending September 30, 2009.  All references to authoritative accounting literature are now referenced in accordance with the Codification.

 

In May 2009, the FASB issued new standards which establish the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. In particular, the new standards set forth the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements (through the date that the financial statements are issued or are available to be issued). The guidance also sets forth the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and the disclosures that an entity should make about events or transactions that occurred after the balance sheet date. The Company adopted the new standards as of June 30, 2009. We have evaluated subsequent events after the balance sheet date of September 30, 2009 through the time of filing with the Securities and Exchange Commission (SEC) on November 9, 2009 which is the date the financial statements were issued.

 

Recent accounting pronouncements

 

In December 2008, the SEC announced that it had approved revisions to modernize the oil and gas reserve reporting disclosures. The new disclosure requirements include provisions that:

 

 

 

 

The Company will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ending March 31, 2010. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required.

 

The SEC is coordinating with the FASB to obtain the revision necessary to US GAAP concerning financial accounting and reporting by oil and gas producing companies and disclosures about oil and gas producing activities to provide consistency with the new rules. During September 2009, the FASB issued an exposure draft of a proposed Accounting Standards Update, “Oil and Gas Reserves Estimation and Disclosures”. The proposed Update would amend existing standards to align the reserves calculation and disclosure requirements under US GAAP with the requirements in the SEC rules. As proposed, the Update would be effective for annual reporting periods ending on or after December 31, 2009, and would be applied prospectively as a change in estimate. We are currently in the process of evaluating the new requirements.

 

NOTE 3 - CASH AND CASH EQUIVALENTS

 

As of September 30, 2009 and March 31, 2009 cash and cash equivalents included:

 

 

As of September 30, 2009 and March 31, 2009 cash and cash equivalents included $1,321,706 and $2,371,558 placed in money market funds having 30 day simple yields of 0.01% and 0.13%, respectively.

 

 

 

NOTE 4 - PREPAID EXPENSES AND OTHER ASSETS

 

Prepaid expenses and other assets as of September 30, 2009 and March 31, 2009, were as follows:

 

 

 

NOTE 5 - OIL AND GAS PROPERTIES

 

Oil and gas properties using the full cost method as of September 30, 2009 and March 31, 2009, were as follows:

 

 

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

 

NOTE 6 – GAS UTILIZATION FACILITY

 

The Company has entered into an Agreement on Joint Business (the “Agreement”) with Ecotechnic Chemicals AG incorporated in Switzerland, for construction of a facility to utilize the associated gas from the Company’s fields (the “Facility”).

 

 

 

The Facility 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.

 

During the six months ended September 30, 2009, the Company made payment to Ecotechnic Chemicals AG in the amount of $75,000 and contributed property totalling $24,107 to the completion of the Facility.

 

No depreciation expense was recognized for Gas Utilization Facility during the six months ended September 30, 2009 because during this period it operated in the test mode.        

 

NOTE 7 – INVENTORIES FOR OIL AND GAS PROJECTS

 

As of September 30, 2009 and March 31, 2009 inventories included:

 

 

 

NOTE 8 - LONG TERM VAT RECOVERABLE

 

As of September 30, 2009 and March 31, 2009 the Company had long term VAT recoverable in the amount of $3,271,288 and $2,423,940, respectively. The VAT recoverable is a Tenge denominated asset due from the Republic of Kazakhstan. The VAT recoverable consists of VAT paid on local expenditures and imported goods. VAT charged to the Company is recoverable in future periods as either cash refunds or offsets against the Company’s fiscal obligations, including future income tax liabilities. Management cannot estimate which part of this asset will be realized in the current year because in order to return funds or offset this tax with other taxes a tax examination must be performed by local Kazakhstan tax authorities. During the six months ended September 30, 2009 the Company received refunds of VAT in the amount of $161,828.

 

 

 

 

NOTE 9 - 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 September 30, 2009 and March 31, 2009 the convertible notes payable amount is presented as follows:

 

 

As of September 30, 2009 and March 31, 2009 the Company has accrued interest of $641,667 and $641,667, respectively, 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 $1,745,975 and $1,331,521 as of September 30, 2009 and March 31, 2009, respectively. The carrying value of convertible notes will be accreted to the redemption value of $64,323,785.

 

NOTE 10 - LIQUIDATION FUND

 

A reconciliation on the Liquidation Fund (Asset Retirement Obligation) at September 30, 2009 and March 31, 2009 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 September 30, 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 September 30, 2009 and March 31, 2009 was $4,482,719 and $4,263,994, respectively.

 

 

 

NOTE 11 - 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 March 30, 2007, the Company granted common stock to officers, employees and outside consultants of the Company under the Plan. The total number of restricted common shares granted was 950,000. The restricted stock grants were valued at $5.38 per share. The restricted stock grants were awarded on the same terms and subject to the same vesting requirements. Previous vesting conditions stated that the restricted stock grants will vest to the grantees at such time as either of the following events occurs (the "Vesting Events"): i) the Company enters commercial production and is granted a commercial production license from the Republic of Kazakhstan; or ii) the occurrence of an Extraordinary Event. An “Extraordinary Event” is defined in the restricted stock agreement as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to thirty percent (30%) or more of the outstanding stock of the Company or any of its subsidiaries, or the sale of all or substantially all of the assets of the Company or any of its subsidiaries. In the event of an Extraordinary Event, the grants shall be deemed full vested one day prior to the effective date of the Extraordinary Event. The Board of Directors shall determine conclusively whether or not an Extraordinary Event has occurred and the grantees have agreed to be bound by the determination of the Board of Directors. The grantees have the right to vote the shares, receive dividends and enjoy all other rights of ownership over the entire grant amount from the grant date, except for the right to transfer, assign, pledge, encumber, dispose of or otherwise directly or indirectly profit or share in any profit derived from a transaction in the shares prior to the occurrence of a Vesting Event. Shares will only vest to the grantee if the grantee is employed by the Company at the time a Vesting Event occurs. If a Vesting Event has not occurred at the time a grantee's employment with the Company ceases, for any reason, the entire grant amount shall be forfeited back to the Company. At the time the grants were made, it was anticipated that the grants would vest no later than July 9, 2009, the date the exploration stage of the Company’s exploration contract was scheduled to terminate.

 

 

 

At the recommendation of the Compensation Committee, on September 11, 2008, the board of directors of the Company approved a change to the vesting conditions of the stock grants. The grants vested as of July 9, 2009.

 

Non-cash compensation expense in the amount of $567,889 was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the six months ended September 30, 2009.

 

As of September 30, 2009, there was no unrecognized non-cash compensation expense related to non-vested share-based compensation arrangements granted under the Plan.

 

On June 24, 2008, the Company was granted an extension of its existing exploration contract from July 2009 to January 2013. In connection therewith, the Company became obligated to issue 1,750,000 common shares to a consultant as the success fee for assisting the Company to obtain the extension. The shares are valued at $6.13 per share, which was the closing market price of Company’s shares on June 24, 2008.

 

On September 16, 2008 this consulting agreement between the Company and the consultant discussed in the preceding paragraph was revised and parties agreed to decrease number of shares issued for services provided by 500,000 shares. The non-cash compensation expenses for consulting services were reversed in the amount of $3,065,000 (500,000 shares valued at $6.13 per share which was the closing market price of Company’s shares on June 24, 2008) for the three months ended 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. The grants vested as of July 17, 2009.

 

Non-cash compensation expense in the amount of $2,176,244 was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the six month ended September 30, 2009.

 

As of September 30, 2009, there was no unrecognized non-cash compensation expense related to non-vested share-based compensation arrangements granted under the Plan.

 

Stock Options

 

On June 20, 2006 the Company granted stock options to directors of the Company under the Plan. The total number of options was 200,000. The options are exercisable at a price of $7.00 per share. All of the options vested immediately upon grant. Compensation expense for options granted is determined based on their fair value at the time of grant, the cost of which in the amount of $545,346 was recognized in the Consolidated Statements of Operations and Consolidated Balance Sheet for the year ended March 31, 2007. These granted stock options expired unexercised on June 20, 2009.

 

 

 

Stock options outstanding and exercisable as of September 30, 2009, were as follows:

 

 

Additional information regarding outstanding options as of September 30, 2009, was as follows:

 

 

 

NOTE 12 – REVENUES

 

The Company exports oil for sale to the world markets via the Aktau sea port. Sales prices at the port locations are based on the average quoted Brent crude oil price from Platt’s Crude Oil Marketwire for the three days following the bill of lading date less discount for transportation expenses, freight charges and other expenses borne by the customer.

 

The Company recognized revenue from sales as follows:

 

 

 

 

 

NOTE 13 – EXPORT DUTY

 

On April 18, 2008 the government of the Republic of Kazakhstan introduced an export duty on several products (including crude oil). The Company became subject to the duty beginning in June 2008. The formula for determining the amount of the crude oil export duty was based on a sliding scale that is tied to several factors, including the world market price for oil.

 

As discussed in Note 2, in December 2008 the government of the Republic of Kazakhstan issued a resolution that cancelled the export duty effective January 26, 2009 for companies operating under the new tax code.

 

On January 1, 2009, the Company became subject to the new tax code. As a result, the export duty for the six months ended September 30, 2009 was $0.

 

NOTE 14 – 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 15 – 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 are also included in consolidated pre-tax income.

 

According to the Exploration Contract in the Republic of Kazakhstan, for income tax purposes the Company can capitalize the exploration and development costs and deduct all revenues received during the exploration stage to calculate taxable income. As long as the Company’s capital expenditures exceed generated revenues, the Company will not be subject to Kazakhstan income tax.

 

 

 

As discussed in Note 2, Licenses and contracts, the Company was granted an Exploration contract extension. According to the terms of the Exploration contract, the Company will continue to operate in the exploration phase until January 2013.

 

Earnings of the Company’s foreign subsidiaries, since acquisition, have been undistributed. 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.

 

Effective January 1, 2009, the Republic of Kazakhstan adopted a new tax code, which decreased the corporate income rate for legal entities to 20%.

 

No provision for income taxes has been recorded by the Company for the six months ended September 30, 2009.

 

NOTE 16 - EARNINGS PER SHARE INFORMATION

 

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

 

 

 

 

The Company has adopted guidance from FASC Topic 260, relating to determining whether instruments granted in share-based payment transactions are participating securities, on April 1, 2009. Accordingly the Company included certain unvested share grants defined as “participating” in the basic weighted average common shares outstanding for the three and six months ended September 30, 2009 and 2008, respectively. Prior period comparative data has been retrospectively presented to reflect the adoption of this standard.

 

The diluted weighted average common shares outstanding for the three and six months ended September 30, 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 three and six months ended September 30, 2009 and 2008, respectively, does not include the effect of the potential conversion of the Notes because the average market share price for three and six months ended September 30, 2009 was lower than potential conversion price of the convertible notes for this period.

 

The diluted weighted average common shares outstanding for the three and six months ended September 30, 2009 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 17 - 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 six months ended September 30, 2009 and 2008, totaled to $47,805 and $84,730, respectively. Also the Company had advances paid to Term Oil LLC in the amount of $147,192 and $15,006 as of September 30, 2009 and March 31, 2009, respectively. A Company shareholder is an owner of Term Oil LLC.

 

On June 26, 2009 the Company entered into a Debt Purchase Agreement (the “Agreement”) with Simage Limited, a British Virgin Islands international business corporation (“Simage”). Simage is a company owned by Toleush Tolmakov, a BMB shareholder and the General Director of Emir Oil, LLP, a wholly-owned subsidiary of the Company (“Emir”).

 

Prior to the date of the Agreement, Simage had acquired by assignment, certain accounts receivable owed by Emir to third-party creditors of Emir in the amount of $5,973,190 (the “Obligations”). Pursuant to the terms  of the  Agreement, Simage  assigned to  the  Company  all  rights,  title  and  interests  in  and  to  the

 

 

 

Obligations in exchange for the issuance of 2,986,595 shares of common stock of the Company. The market value of the shares of common stock issued to Simage, at the agreement date, was $3,076,193. The market value was based on $1.03 per share, which was the closing market price of the Company’s shares on June 26, 2009.

 

As a result of this Agreement, the Company has effectively been released of accounts payable obligations amounting to $5,973,190. The Company has treated this Agreement as a related party transaction, due to the fact that Simage is owned by a Company shareholder. Therefore, the difference between the settled amount of accounts payable and the value of the common stock issued, which amounts to $2,896,997, has been treated as a capital contribution by the shareholder and recognized as an addition to additional-paid-in-capital rather than a gain on settlement of debt.

 

NOTE 18 - 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.

 

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 $8.7 million by January 9, 2010. The Company must spend an additional $21.5 million between January 10, 2010 and January 9, 2011, $27.3 million between January 10, 2011 and January 9, 2012 and $14.9 million between January 10, 2012 and January 9, 2013.

 

Through September 30, 2009 the Company had spent a total of $273.8 million in exploration activity.

 

In addition to the minimum capital expenditure requirement, the Company must also comply with the other terms of the work program associated with the contract, which includes the drilling of at least ten new wells by January 9, 2013. The failure to meet the minimum capital expenditures or to comply with the terms of the work program could result in the loss of the subsurface exploration contract. The recent addenda to our exploration contract which granted us with the extension of the exploration period and rights to the Northwest Block also require 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 the Company’s motion. The court (a) denied the motion to dismiss on the ground that Kazakhstan  is a more convenient  forum; (b) denied the motion to dismiss in favor of litigation

 

 

 

in New York state court; (c) denied the motion to stay pending arbitration in Kazakhstan; and (d) denied the motion to dismiss on the ground that Mr. Tolmakov is an indispensable party. The court also (a) denied the motion (by defendants other than the Company) to dismiss for lack of personal jurisdiction and (b) granted the motion (by defendants other than the Company) to dismiss several claims for relief alleging breach of fiduciary duty, tortious interference with fiduciary duty and aiding and abetting breach of fiduciary duty. The court dismissed as moot the Company’s cross-motion to stay discovery and instructed the parties to comply with the Magistrate Judge’s discovery schedule.

 

The Company appealed the court’s refusal to stay the litigation pending arbitration in Kazakhstan. On September 28, 2008, the Court of Appeals issued a decision in which it (a) reversed the district court's refusal to stay the claim for specific performance pending arbitration and (b) affirmed the balance of the district court's order.

 

In December 2008, 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. On October 27, 2009, the District Court upheld the Magistrate Judge's denial of Plaintiffs' Motion to Amend to the extent that Defendants objected to the same.

 

Fact discovery has been completed. With respect to expert discovery, Plaintiffs initially designated one expert to testify on damages and Defendants designated one expert to testify on the law of Kazakhstan. Plaintiffs' expert on damages claims damages of between $6.7 million and $10.9 million, plus interest. Defendants deposed Plaintiffs' damages expert and then submitted reports from two of their own damages experts in opposition to Plaintiffs' damages claims. Defendants' primary damages expert identified errors in the Plaintiffs' report that undermine their claimed damages. Defendants also submitted the report of another of defendants’ experts, a petroleum engineer, on the quality of the reserve estimates available in August 2003, when the original transaction occurred and upon which Plaintiffs’ expert based his calculations of damages. The report of the petroleum engineer points out that the limited testing and production from the ADE fields made any reserves estimate highly uncertain. Plaintiffs submitted a rebuttal expert report on the law of Kazakhstan. All experts have been deposed and expert discovery on the existing claims is now complete.

 

 

 

At the present time, no trial date has been established. The Court has established November 27, 2009 as the date by which the parties shall file dispositive motions. The Company expects to file a Motion for Summary Judgment before that date.

 

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 19 - FINANCIAL INSTRUMENTS

 

As of September 30, 2009 and March 31, 2009 cash and cash equivalents included deposits in Kazakhstan banks in the amount $3,801,102 and $2,606,004, respectively, and deposits in U.S. banks in the amount of $2,208,641 and $4,149,541, respectively. Kazakhstan banks are not covered by FDIC insurance, nor does the Republic of Kazakhstan have an insurance program similar to FDIC. Therefore, the full amount of our deposits in Kazakhstan banks was uninsured as of September 30, 2009 and March 31, 2009. The Company’s deposits in U.S. banks are also in non-FDIC insured accounts which means they too are not insured  to the $250,000 FDIC  insurance limit. To mitigate  this risk, the Company  has placed  all of its U.S.

 

 

 

deposits in a money market account that invests in U.S. government backed securities. As of September 30, 2009 and March 31, 2009 the Company made advance payments to Kazakhstan companies and government bodies in the amount of $6,301,127 and $5,432,972, respectively. As of September 30, 2009 and March 31, 2009 restricted cash reflected in the long-term assets consisted of $589,970 and $588,217, respectively, deposited in a Kazakhstan bank and restricted to meet possible environmental obligations according to the regulations of Kazakhstan. Furthermore, the primary asset of the Company is Emir Oil LLP; an entity formed under the laws of the Republic of Kazakhstan.

 

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Consolidated Financial Statements and the accompanying notes included in this Form 10-Q contain additional information that should be referred to when reviewing this material and this document should be read in conjunction with the Form 10-K of the Company for the year ended March 31, 2009.

 

Cautionary Note Regarding Forward-Looking Statements

 

This report includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Rule 175 promulgated thereunder, that involve inherent risks and uncertainties. Words such as “expect,” “anticipate,” “intend,” “plan,” “believe,” “estimate,” “seek,” “could,” “should,” “predict,” “continue,” “future,” “may” and variations of such words and similar expressions are intended to identify such forward-looking statements. Forward-looking statements involve known and unknown risks, uncertainties, assumptions, estimates and other factors that could cause actual results, performance or events to differ materially from any results, performance or events expressed or implied by such forward-looking statements. All forward-looking statements are qualified in their entirety by reference to the factors discussed in this report and identified from time to time in our filings with the SEC including, among others, the following risk factors:

 

 

The above factors may affect future results, performance, events and the accuracy of any forward-looking statement. This list is illustrative but not exhaustive. In addition, new risks and uncertainties may arise from time to time. Accordingly, readers should not place undue reliance on any forward-looking statement.

 

 

Any forward-looking statement speaks only as of the date on which it is made and is expressly qualified by these cautionary statements. Except as may be required by law, we undertake no obligation to publicly update or revise any forward-looking statement for any reason or to update the reasons actual results could differ materially from those anticipated in such forward-looking statements, even if new information becomes available in the future.

 

Overview

 

BMB Munai, Inc. is organized under the laws of the State of Nevada. Our business activities focus on oil and natural gas 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 exploratory drilling and oil production in the Mangistau Province in the southwestern region of Kazakhstan. Since the date of execution of the original exploration contract, we have successfully negotiated several amendments to the contract that have extended the term of our exploration contract to January 2013 and extended the territory of the contract area to approximately 850 square kilometers, which is comprised of the “ADE Block”, the “Southeast Block” and the “Northwest Block”.

 

Exploration Stage Activities

 

Under the statutory scheme in Kazakhstan, prospective oil fields are developed in two stages. The first stage is exploration stage. During this stage the primary focus is on the search for commercial discoveries, i.e., discoveries of sufficient quantities of oil and gas to make it commercially feasible to pursue execution of, or transition to, the second stage, which is a commercial production contract with the government.

 

Minimum Work Program Requirements

 

In order to be assured that adequate exploration activities are undertaken during exploration stage, the Ministry of Energy and Mineral Resources of the ROK (“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 annual work program requirements could preclude the contractor from receiving a longer-term production contract, could result in penalties and fines or even in the loss of the contractor’s license.

 

The contract we hold follows the above format. Historically, our annual work program year ran from July 10 of each year to July 9 of the next year. In connection with a recent amendment to our contract, our work program year end was changed to January 9 of each year beginning in 2010. From the beginning of the exploration stage of our contract through July 9, 2009, our minimum mandatory expenditure requirement totaled

 

 

$50,525,000. During that time period, we expended $264,690,000 in exploration activities, including the drilling of 24 wells and starting from July 10, 2009 to September 30, 2009 we expended $9,124,000. Our minimum work program requirement for the current period, which runs from July 10, 2009 to January 9, 2010 is $8,565,000. Thereafter, our minimum annual expenditure requirements are: $21,520,000 from January 2010 to January 2011; $27,300,000 from January 2011 to January 2012; and $14,880,000 from January 2012 to January 2013.

 

We began drilling in the fields of the ADE block in 2004. Since 2005 we have been drilling in the Southwest Block in the Kariman field. 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. During fiscal 2009 we completed a very active three-year drilling program. 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 fiscal 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 during the fiscal year on the following objectives:

 

 

Drilling Operations, Well Performance and Production

 

As noted above, we have shifted our operational focus from growth through drilling to working closely with our existing wellstock to enhance production from existing wells. In particular, we have successfully tested and are actively implementing a strategy of installing centrifugal submersible pumps at the Kariman field. This strategy has resulted in stabilization of production rates from certain Kariman wells. We are in the process of researching various available options for increasing production from our other fields.

 

During the fiscal quarter ended September 30, 2009, our average daily crude oil production was 2,827 barrels per day. We expect our production to remain stable should our strategy of working with the centrifugal submersible pumps prove to be a long-lasting success. However, we do recognize that in order to significantly increase our production we will need to engage in additional exploration activities. Further exploration, including 3D seismic, re-opening of existing wells and drilling of new wells, will heavily depend on our ability to obtain additional funding. Given the unfavorable global economic outlook, the current status of the financial sector and our own current financial situation, it may be very difficult for us to obtain additional funding.

 

38

 

Results of Operations

 

Three months ended September 30, 2009, compared to the three months ended September 30, 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 three months ended September 30, 2009 and the three months ended September 30, 2008.

 

 

 

 

            Revenues. We generate revenue under our exploration contract from the sale of oil recovered during test production. As a result of decreases in reservoir pressure in some of our existing wells, during the three months ended September 30, 2009 our oil production decreased 16% compared to the three months ended September 30, 2008.

 

During the three months ended September 30, 2009 we realized revenue from oil sales of $16,074,217 compared to $22,758,160 during the three months ended September 30, 2008. The significant contributing factors to the 29% decrease in revenue were a 23% decrease in the price per barrel we received for oil sales because of decreased world oil prices and increased sales to the local market coupled with a 9% decrease in sales volume as a result of decreased production. During the three months ended September 30, 2009 and 2008 we exported 81% and 98% 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 97% and 99% of total revenue, respectively, during the three months ended September 30, 2009 and 2008. We anticipate production to remain fairly constant and currently anticipate revenues will be flat quarter-on-quarter in upcoming quarters and will continue to be lower compared to the comparable prior year quarter.

 

As discussed above, our revenue is sensitive to changes in prices received for our oil. Political instability, the economy, changes in legislation and taxation, reductions in the amount of oil we are allowed to export to the world markets, weather and other factors outside our control may also have an impact on both supply and demand and on revenue.

 

Costs and Operating Expenses

 

The following table presents details of our costs and expenses for the three months ended September 30, 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 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. 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. As a result of the export duty being repealed, we paid no export duty during the three months ended September 30, 2009 compared to $4,386,983 during three months ended September 30, 2008. Export duty was not recorded as part of oil and gas operating expense and was not included in oil and gas operating expense per BOE calculation.

 

Oil and Gas Operating Expenses. During the three months ended September 30, 2009 we incurred $4,807,760 in oil and gas operating expenses compared to $2,274,862 during the three months ended September 30, 2008. This increase is primarily the result of a 387% increase in payments to the government in the form of taxes and a 152% increase in production expense for the three months period ended September 30, 2009 compared to the three months ended September 30, 2008, and was partially offset by 39% decrease in transportation expense for the same period.

 

Oil and Gas Operating Expenses for the three months ended September 30, 2009 and 2008 consist of the following expenses:

 

 

The 152% increase in production expense during the three months ended September 30, 2009 compared to the quarter ended September 30, 2008 is due to purchase of light crude oil for blending purposes from a third party in amount of $465,832 during the three months ended September 30, 2009, and was partially offset by $94,506 or 39% decrease in payroll and related payments to production personnel during the three months ended September 30, 2009 compared to three months ended September 30, 2008. The decrease in payroll and related payments to production personnel is due to decreased production personnel as we have decreased our exploration activities.

 

 

Transportation expenses decreased by $522,237 or 39% as a result of the decreased volume of oil we produced and transported. We anticipate transportation expenses will continue to fluctuate in proportion to production volume.

 

The mineral extraction tax replaced the royalty we were paying under the prior version of the tax code. The rate of this tax depends upon 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. During the three months ended September 30, 2009 mineral extraction tax paid to the government amounted to $931,464. During the quarter ended September 30, 2008, royalty payments were $694,131.

 

Rent export tax is calculated based on the export sales price and ranges from as low as 0% if the export sales price is less than $40 per barrel to as high as 32% if the price per barrel exceeds $190. During the three months ended September 30, 2009 rent export tax paid to the government amounted to $2,446,476. We were not subject to the rent export tax during the three months ended September 30, 2008.

 

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.

 

As a result of our decreased production, while oil and gas operating expenses increased by 111% on a cumulative basis during the three months ended September 30, 2009, expense per BOE during the same period increased by 131%. Expense per BOE is a function of total expense divided by the number of barrels of oil we sell. During the three months ended September 30, 2008 we sold 309,521 barrels of oil, during the three months ended September 30, 2009 we sold 282,889 barrels of oil. The 16% decrease in production coupled with the 111% increase in oil and gas operating expenses resulted in a $9.65, or 131%, increase in oil and gas operating expense per BOE.

 

General and Administrative Expenses. General and administrative expenses during the three months ended September 30, 2009 were $2,952,173 compared to $6,247,879 during the three months ended September 30, 2008. This represents a 53% decrease. This decrease in general and administrative expenses was the result of an 84% decrease in non-cash compensation expense which was coupled with:

 

 

 

During the three months ended September 30, 2009 we recognized non-cash compensation expense of $342,557 resulting from restricted stock grants previously made to employees. By comparison, during the three months ended September 30, 2008 we recognized non-cash compensation expense in the amount of $2,079,170 for restricted stock grants previously made to employees and outside consultants.

 

Depletion. Depletion expense for the three months ended September 30, 2009 decreased by $216,412 compared to the three months ended September 30, 2008. The major reason for this decrease in depletion expense was a 9% decrease in sales volume during the three months ended September 30, 2009 compared to the three months ended September 30, 2008.

 

Amortization and Depreciation. Amortization and depreciation expense for the three months ended September 30, 2009 increased by a 95% compared to the three months ended September 30, 2008. The increase resulted from purchases of fixed assets.

 

Income from Operations. During the three months ended September 30, 2009 we realized income from operations of $4,026,811 compared to income from operations of $9,636,121 during the three months ended September 30, 2008. This decrease in income from operations during the three months ended September 30, 2009 is the result of the 29% decrease in revenue, which decrease was partially offset by an 8% decrease in total costs and operating expenses.

 

Other Income.During the three months ended September 30, 2009 we realized total other income of $13,198 compared to total other income of $193,905 during the three months ended September 30, 2008. The 93% decrease other income between the respective quarters is largely attributable to $176,899 interest income we received during the quarter ended September 30, 2008.

 

Net Income.For the foregoing reasons, during the three months ended September 30, 2009 we realized net income of $4,040,009 or $0.08 per share compared to net income of $9,830,026 or $0.21 per share for the three months ended September 30, 2008.

 

 

 

Results of Operations

 

Six months ended September 30, 2009, compared to the six months ended September 30, 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 six months ended September 30, 2009 and the six months ended September 30, 2008.

 

 

 

Revenues. We generate revenue under our exploration contract from the sale of oil recovered during test production. As a result of decreases in reservoir pressure in some of our existing wells, during the six months ended September 30, 2009 our oil production decreased 24% compared to the six months ended September 30, 2008.

 

 

During the six months ended September 30, 2009 we realized revenue from oil sales of $27,841,023 compared to $57,585,384 during the six months ended September 30, 2008. The significant contributing factors to the 52% decrease in revenue were a 39% decrease in the price per barrel we received for oil sales and a 21% decrease in sales volume as a result of decreased production. During the six months ended September 30, 2009 and 2008 we exported 89% and 96% of our oil, respectively, to the world markets and realized the world market price for those sales. Revenue from oil sold to the world markets made up 98% and 99% of total revenue, respectively, during the six months ended September 30, 2009 and 2008.

 

Costs and Operating Expenses

 

The following table presents details of our costs and expenses for the six months ended September 30, 2009 and 2008:

 

 

 

Export Duty. As noted above, in December 2008 the government 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 a result of the export duty being repealed, we paid no export duty during the six months ended September 30, 2009 compared to $5,739,900 during six months ended September 30, 2008. Export duty was not recorded as part of oil and gas operating expense and was not included in oil and gas operating expense per BOE calculation.

 

Oil and Gas Operating Expenses. During the six months ended September 30, 2009 we incurred $7,900,197 in oil and gas operating expenses compared to $4,615,705 during the six months ended September 30, 2008. This increase is primarily the result of a 247% increase in taxes paid to the government and a 75% increase in production expense for the six months period ended September 30, 2009 compared to the six months ended September 30, 2008, which was partially offset by 39% decrease in transportation expense for the same period.

 

 

 

Oil and Gas Operating Expenses for the six months ended September 30, 2009 and 2008 consist of the following expenses:

 

 

The 75% increase in production expense during the six months ended September 30, 2009 compared to the six months ended September 30, 2008 is due to purchase of light crude oil for blending purposes from a third party in amount of $465,832 during the six months ended September 30, 2009, and was partially offset by $132,286 or 30% decrease in payroll and related payments to production personnel during the six months ended September 30, 2009 compared to six months ended September 30, 2008. The decrease in payroll and related payments to production personnel is due to decreases in production personnel as we have decreased our exploration activities.

 

Transportation expenses decreased by $991,782 or 39% as a result of the decreased volume of oil we produced and transported. We anticipate transportation expenses will continue to fluctuate in proportion to production volume.

 

As noted above, in January 2009 the mineral extraction tax replaced the royalty we were paying under the prior version of the tax code. During the six months ended September 30, 2009 mineral extraction tax paid to the government amounted to $1,558,507. During the six ended September 30, 2008, royalty payments were $1,595,692.

 

During the six months ended September 30, 2009 rent export tax paid to the government amounted to $3,979,913. We were not subject to the rent export tax during the six months ended September 30, 2008.

 

We calculate oil and gas operating expense per BOE based on the volume of oil actually sold rather than production volume because not all volume produced during the period is sold during the period. The related production costs are expensed only for the units sold, not produced.

 

 

Expense per BOE is a function of total expense divided by the number of barrels of oil we sell. During the six months ended September 30, 2008 we sold 637,278 barrels of oil, during the six months ended September 30, 2009 we sold 505,439 barrels of oil. The 24% decrease in production coupled with the 71% increase in oil and gas operating expenses resulted in a $8.39, or 116%, increase in oil and gas operating expense per BOE.

 

General and Administrative Expenses. General and administrative expenses during the six months ended September 30, 2009 were $7,803,939 compared to $10,585,520 during the six months ended September 30, 2008. This represents a 26% decrease. This decrease in general and administrative expenses was the result of the following:

 

 

During the six months ended September 30, 2009 we recognized non-cash compensation expense of $2,744,133 resulting from restricted stock grants previously made to employees. By comparison, during the six months ended September 30, 2008 we recognized non-cash compensation expense in the amount of $2,647,059 for restricted stock grants previously made to employees and outside consultants.

 

Depletion. Depletion expense for the six months ended September 30, 2009 decreased by $1,306,397 compared to the six months ended September 30, 2008. The major reason for this decrease in depletion expense was a 21% decrease in sales volume during the six months ended September 30, 2009 compared to the six months ended September 30, 2008.

 

Amortization and Depreciation. Amortization and depreciation expense for the six months ended September 30, 2009 increased 100% compared to the six months ended September 30, 2008. The increase resulted from purchases of fixed assets.

 

Income from Operations. During the six months ended September 30, 2009 we realized income from operations of $4,219,243 compared to income from operations of $21,211,538 during the six months ended September 30, 2008. This decrease in income from operations during the six months ended September 30, 2009 is the result of the 52% decrease in revenue, which decrease was partially offset by a 35% decrease in total costs and operating expenses.

 

 

 

Other Income/(Expense). During the six months ended September 30, 2009 we realized total other expense of $148,452 compared to total other income of $1,939,811 during the six months ended September 30, 2008. The change from other income to other expense between the respective periods is largely attributable to $1,650,293 we received from a Company’s shareholder during the six ended September 30, 2008, as disgorgement of profits earned in violation of the short-swing profit rules of Section 16b of the Securities Exchange Act of 1934.

 

Net Income. For the foregoing reasons, during the six months ended September 30, 2009 we realized net income of $4,070,491 or $0.09 per share compared to a net income of $23,151,349 or $0.50 per share for the six months ended September 30, 2008.

 

Liquidity and Capital Resources

 

For the period from inception on May 6, 2003 through September 30, 2009, we have incurred capital expenditures of $262,694,464 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 September 30, 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, see Note 9 to the Notes to the Consolidated Financial Statements, September 30, 2009.

 

Problems in the credit markets, the significant declines in worldwide oil prices and volatility and downward trends in the stock markets have caused many junior exploration and production companies, including us, to seek additional capital in order to stay in business. Some companies have been acquired by larger companies and others have failed.

 

At September 30, 2009, our current liabilities exceeded current assets by $595,511. This continues to create liquidity problems for the Company in the near term. This gap 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.

 

 

Cash Flows

 

During the six months ended September 30, 2009 cash was primarily used to fund exploration expenditures. See below for additional discussion and analysis of cash flow.

 

	Six months ended			Six months ended
	September 30, 2009			September 30, 2008
Net cash provided by operating activities	$	8,521,241		$	44,873,497
Net cash used in investing activities	$	(7,767,043)		$	(50,202,387)
Net cash provided by financing activities	$	(1,500,000)		$	50,001
NET CHANGE IN CASH AND CASH EQUIVALENTS	$	(745,802)		$	(5,278,889)

Our principal source of liquidity during the six months ended September 30, 2009 was cash and cash equivalents. At March 31, 2009 cash and cash equivalents totaled approximately $6.8 million. At September 30, 2009 cash and cash equivalents had decreased to approximately $6 million. During the six months ended September 30, 2009 we spent approximately $7.8 million to fund our drilling and development activities.

 

Certain operating cash flows are denominated in local currency and are translated into U.S. dollars at the exchange rate in effect at the time of the transaction. Because of the potential for civil unrest, war and asset expropriation, some or all of these matters, which impact operating cash flow, may affect our ability to meet our short-term cash needs.

 

Contractual Obligations and Contingencies

 

The following table lists our significant commitments at September 30, 2009, excluding current liabilities as listed on our consolidated balance sheet:

 

 

(1)   Under the terms of our subsurface exploration contract we are required to spend a total of $72.7 million in exploration activities on our properties, including a minimum of $8.6 million by January 2010, $21.5 million by January 2011, $27.3 million by January 2012 and $14.9 million by January 2013. As of June 30, 2009, we have spent a total of $264.7 million in exploration activities.

 

 

(2)   In connection with our acquisition of the oil and gas contract covering the ADE Block, the Southeast Block and the Northwest Block, we are required to repay the ROK for historical costs incurred by it in undertaking geological and geophysical studies and infrastructure improvements. Our repayment obligation for the ADE Block is $5,994,200 and our repayment obligation for the Southeast Block is $5,350,680. We anticipate we will also be obligated to assume a repayment obligation in connection with the Northwest Block, although we do not yet know the amount of such obligation. The terms of repayment of these obligations, however, will not be determined until such time as we apply for and are granted commercial production rights by the ROK. Should we decide not to pursue commercial production rights, we can relinquish the ADE Block, the Southeast Block and/or the Northwest Block to the ROK in satisfaction of their associated obligations. The recent addenda to our exploration contract which granted us with the extension of exploration period and the rights to the Northwest Block also require us to:

 

Off-Balance Sheet Financing Arrangements

 

 

Item 3. 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 second fiscal quarter 2010 crude oil sales in the international export market were based on prevailing market prices at the time of sale less applicable discounts due to transportation.

 

 

Historically, crude oil prices have been subject to significant volatility in response to changes in supply, market uncertainty and a variety of other factors beyond our control. Crude oil prices are likely to continue to be volatile and this volatility makes it difficult to predict future oil price movements with any certainty. Any declines in oil prices would reduce our revenues, and could also reduce the amount of oil that we can produce economically. As a result, this could have a material adverse effect on our business, financial condition and results of operations.

 

During the fiscal quarter ended September 30, 2009, we sold 282,889 barrels of oil and condensate. We realized an average sales price per barrel of $56.82. 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 September 30, 2009 would have affected our net income by less than $1 million.

 

Item 4. Controls and Procedures

 

Evaluation of Disclosure Controls and Procedures

 

We maintain disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required financial disclosures. Because of inherent limitations, our disclosure controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of such disclosure controls and procedures are met.

 

As of the end of the period covered by this report we conducted an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(b) and 15d-15(b). Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of September 30, 2009.

 

Changes in Internal Control over Financial Reporting

 

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

 

 

PART II - OTHER INFORMATION

 

Item 1. Legal Proceedings

 

See Note 18“Commitments and Contingencies” to the Notes to the Consolidated Financial Statements under Part I – Item 1of this Form 10-Q.

 

Item 1A. Risk Factors

 

In addition to the other information set forth in this Quarterly Report, you should carefully consider the risks discussed in our 2009 Annual Report on Form 10-K, including under the heading “Item 1A. Risk Factors” of Part I, which risks could materially affect our business, financial condition or future results. These risks are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results.

 

Item 6. Exhibits

 

 

 

SIGNATURES

 

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