NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The Company’s unaudited condensed consolidated financial statements present the consolidated results of BMB Munai, Inc., and its wholly owned subsidiary, Emir Oil. All significant inter-company balances and transactions have been eliminated from the unaudited condensed consolidated financial statements.

Certain reclassifications have been made in the financial statements for the three months ended June 30, 2010 to conform to the June 30, 2011 classification of discontinued operations. These classifications were made because of the pending sale of Emir Oil.

Business condition

On February 14, 2011, the Company entered into the Purchase Agreement pursuant to which the Company has agreed to the Sale. Net losses and cash flow used in operations for the three months ending June 30, 2011 and 2010 are summarized as follows:

On March 8, 2011, the Company entered into agreements to restructure its outstanding U.S. $60 million aggregate principal amount 9.0% Convertible Senior Notes due 2012 (the “Original Notes”). In connection with restructuring the Original Notes (the “Note Restructure”), and as more fully described herein, the Company, among other things:

As provided in the Note Restructuring Agreement between the Company and the holders of the Original Notes (“Note Restructuring Agreement”), the Original Notes were delivered to the Trustee for cancellation and in substitution the Company issued $61.4 million in principal amount of 10.75% Convertible Senior Notes due 2013 (the “Senior Notes”) on a pro rata basis in accordance with the aggregate outstanding balances of the holders’ respective Original Notes. In connection with the issuance of the Senior Notes, (i) the Company entered into Supplemental Indenture No. 6 and an Amended Indenture with the Trustee and (ii) the terms of the Original Indenture governing the Original Notes were superseded by the terms of the Amended Indenture. The Amended Indenture is a continuation of, and not a novation of, the Original Indenture, although the terms of the Amended Indenture supersede in their entirety the terms of the Original Indenture from the date of Supplemental Indenture No. 6.

The Note Restructuring Agreement provides, subject to approval of the Company’s common stockholders and to the receipt of any necessary regulatory approvals, for a reduction in the future in the conversion price of the Senior Notes from $7.2094 per share to $2.00 per share with a corresponding reduction in the minimum conversion price of the Senior Notes from $6.95 per share to $1.00 per share (the “Conversion Price Reduction”). The Company’s common stockholders approved the Conversion Price Reduction at a special meeting of stockholders held on June 2, 2011.

In connection with the Note Restructure, the Amended Indenture provided approval by holders of the Senior Notes for the Sale. Upon consummation of the Sale, the Company is required to redeem each Senior Note for 100% of such Senior Note’s outstanding principal amount, together with interest accrued to such date, out of the proceeds of the Sale.

At a special meeting of Company stockholders held on June 2, 2011, approximately 63.2% of voting power of the Company as of the close of business on April 11, 2011, the special meeting record date, voted to approve the Sale of Emir Oil. In addition to approving the Sale of Emir Oil, approximately 62.7% of the votes cast at the meeting by stockholders of record as of the special meeting record date voted to approve the Conversion Price Reduction.

Going concern

If the Company does not complete the Sale, it anticipates it will lack sufficient funds to retire the Senior Notes when they become due. If the Company fails to attain commercial production rights on the Kariman, Dolinnoe and Aksaz fields, it will be unable to complete the Sale. There is substantial doubt that the Company will be able to continue as a going concern if it does not complete the Sale and it would likely be required to consider other liquidation alternatives, including a liquidation of its business under bankruptcy protection, because it will not have sufficient cash to repay the Senior Notes or continue operations. Moreover, if the Company completes the Sale, it will have no continuing operations that result in positive cash flow, which likewise raises substantial doubt about its ability to continue as a going concern.

Subsequent event

In accordance with ASC 855-10 Company management reviewed all material events through the date of issuance and there are no material subsequent events to report.

Use of estimates

The preparation of unaudited condensed 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 unaudited condensed 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 unaudited condensed 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.

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 unaudited condensed 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 private equity placement transactions have been offset against the proceeds as a cost of capital. Stock options and stocks granted to other non-employees are recognized in the unaudited condensed consolidated statements of operations.

The Company has a stock option plan as described in Note 8. 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 unaudited condensed consolidated statements of operations over the vesting periods of the respective options.

Share-based compensation incurred for the three months ended June 30, 2010 was $413,275. We did not incur any stock-based compensation expense for the three months ended June 30, 2011.

Oil and gas properties

The Company follows 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 reserves are sold (greater than 25 percent), in which case a gain or loss is recognized.

Capitalized costs less accumulated depletion and related deferred income taxes shall not exceed an amount (the full cost ceiling) equal to the sum of:

a) the present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions;

b) plus the cost of properties not being amortized;

c) plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;

d) less income tax effects related to differences between the book and tax basis of the properties.

Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change. If oil and gas prices decline, even if only for a short period of time, it is possible that impairment of the Company’s 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.

Ceiling test

Capitalized oil and gas properties are subject to a “ceiling test.” The full cost ceiling test is an impairment test prescribed by Rule 4-10 of SEC Regulation S-X. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves. This ceiling is compared to the net book value of the oil and gas properties reduced by any related deferred income tax liability. If the net book value reduced by the related deferred income taxes exceeds the ceiling, impairment or non-cash write down is required. Ceiling test impairment can cause a significant loss for a particular period; however, future depletion expense would be reduced.

Risks and uncertainties

The ability of the Company to realize the carrying value of its assets is dependent on being able to develop, transport and market oil and gas. Currently exports from the Republic of Kazakhstan are primarily dependent on transport routes either via rail, barge or pipeline, through Russian territory. Domestic markets in the Republic of Kazakhstan historically and currently do not permit world market price to be obtained. Management believes that over the life of the project, transportation options will improve as additional pipelines and rail-related infrastructure are built that will increase transportation capacity to the world markets; however, there is no assurance that this will happen in the near future.

Recognition of revenue and cost

Revenue and associated costs from the sale of oil are charged to the period when persuasive evidence of an arrangement exists, the price to the buyer is fixed or determinable, collectability is reasonably assured, delivery of oil has occurred or when ownership title transfers. Produced but unsold products are recorded as inventory until sold.

Export duty

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.

In July 2010 the Government of the Republic of Kazakhstan issued a resolution which reenacted export duty for several products (including crude oil). The Company became subject to the export duty in September 2010. The export duty is calculated based on a fixed rate of $20 per ton, or approximately $2.60 per barrel exported. The export duty fees are expensed as incurred and classified as costs and operating expenses.

In January 2011 the Government of the Republic of Kazakhstan increased the fixed rate for duty from $20 per ton to $40 per ton, or approximately $5.20 per barrel exported.

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 on production sold to the export market, and a 2.5% tax rate on production sold to the domestic market. The mineral extraction tax expense is reported as part of oil and gas operating expense.

Rent export tax

This tax is calculated based on the export sales price and ranges from as low as 0%, if the price is less than $40 per barrel, to as high as 32%, if the price per barrel exceeds $190. Rent export tax is expensed as incurred and is classified as costs and operating expenses.

Income taxes

Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes. Deferred taxes are provided on differences between the tax bases of assets and liabilities and their reported amounts in the financial statements, and tax carryforwards. Deferred tax assets and liabilities are included in the financial statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the provision for income taxes.

Fair value of financial instruments

The carrying values reported for cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate their respective fair values in the accompanying balance sheet due to the short-term maturity of these financial instruments. In addition, the Company has long-term debt with financial institutions. The carrying amount of the long-term debt approximates fair value based on current rates for instruments with similar characteristics.

Cash and cash equivalents

The Company considers all demand deposits, money market accounts and marketable securities purchased with an original maturity of three months or less to be cash and cash equivalents. The fair value of cash and cash equivalents approximates their carrying amounts due to their short-term maturity.

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 June 30, 2011 and no provision for obsolete inventory has been provided.

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 unaudited condensed consolidated statements 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. Based on the Company’s analysis at June 30, 2011, no impairment of other assets is necessary.

Convertible notes payable issue costs

The Company recognizes convertible notes payable issue costs on the balance sheet as deferred charges, and amortizes the balance over the term of the related debt. The Company classifies cash payments for bond issue costs as a financing activity. The Company capitalized cash payments for bond issue costs as part of oil and gas properties in periods of drilling activities.

Functional currency

The Company makes its principal investing and financing transactions in U.S. Dollars and the U.S. Dollar is therefore its functional currency.

Income per common share

Basic income per common share is computed by dividing net income by the weighted-average number of common shares outstanding during the period. Diluted income per share reflects the potential dilution that could occur if all contracts to issue common stock were converted into common stock, except for those that are anti-dilutive.

New accounting policies

Disclosures about Fair Value Measurements – In January 2010, the FASB issued new authoritative guidance regarding “Improving Disclosures about Fair Value Measurements and Disclosures” that requires additional disclosure of transfers in and out of Level 1 and 2 measurements and the reasons for the transfers, and a gross presentation of activity within the Level 3 roll forward. The guidance also includes clarifications to existing disclosure requirements on the level of disaggregation and disclosures regarding inputs and valuation techniques. The guidance is effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward information, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. The Company adopted the guidance on April 1, 2010, except for requirements regarding the gross presentation of Level 3 roll forward information, which the Company adopted on April 1, 2011. Because this guidance only requires additional disclosures, it did not have a significant impact on the Company’s financial statements, nor is it expected to have an impact in future periods.