FRHC 10-Q Quarterly Report Sept. 30, 2010

FREEDOM HOLDING CORP.

10-Ks and 10-Qs

10-Q	Quarter ended Sept. 30, 2025
10-Q	Quarter ended June 30, 2025
10-K	Fiscal year ended March 31, 2025
10-Q	Quarter ended Dec. 31, 2024
10-Q	Quarter ended Sept. 30, 2024
10-Q	Quarter ended June 30, 2024
10-K	Fiscal year ended March 31, 2024
10-Q	Quarter ended Dec. 31, 2023
10-Q	Quarter ended Sept. 30, 2023
10-Q	Quarter ended June 30, 2023
10-K	Fiscal year ended March 31, 2023
10-Q	Quarter ended Dec. 31, 2022
10-Q	Quarter ended Sept. 30, 2022
10-Q	Quarter ended June 30, 2022
10-K	Fiscal year ended March 31, 2022
10-Q	Quarter ended Dec. 31, 2021
10-Q	Quarter ended Sept. 30, 2021
10-Q	Quarter ended June 30, 2021
10-K	Fiscal year ended March 31, 2021
10-Q	Quarter ended Dec. 31, 2020
10-Q	Quarter ended Sept. 30, 2020
10-Q	Quarter ended June 30, 2020
10-K	Fiscal year ended March 31, 2020
10-Q	Quarter ended Dec. 31, 2019
10-Q	Quarter ended Sept. 30, 2019
10-Q	Quarter ended June 30, 2019
10-K	Fiscal year ended March 31, 2019
10-Q	Quarter ended Dec. 31, 2018
10-Q	Quarter ended Sept. 30, 2018
10-Q	Quarter ended June 30, 2018
10-K	Fiscal year ended March 31, 2018
10-Q	Quarter ended Dec. 31, 2017
10-Q	Quarter ended Sept. 30, 2017
10-Q	Quarter ended June 30, 2017
10-K	Fiscal year ended March 31, 2017
10-Q	Quarter ended Dec. 31, 2016
10-Q	Quarter ended Sept. 30, 2016
10-Q	Quarter ended June 30, 2016
10-K	Fiscal year ended March 31, 2016
10-Q	Quarter ended Dec. 31, 2015
10-Q	Quarter ended Sept. 30, 2015
10-Q	Quarter ended June 30, 2015
10-K	Fiscal year ended March 31, 2015
10-Q	Quarter ended Dec. 31, 2014
10-Q	Quarter ended Sept. 30, 2014
10-Q	Quarter ended June 30, 2014
10-K	Fiscal year ended March 31, 2014
10-Q	Quarter ended Dec. 31, 2013
10-Q	Quarter ended Sept. 30, 2013
10-Q	Quarter ended June 30, 2013
10-K	Fiscal year ended March 31, 2013
10-Q	Quarter ended Dec. 31, 2012
10-Q	Quarter ended Sept. 30, 2012
10-Q	Quarter ended June 30, 2012
10-K	Fiscal year ended March 31, 2012
10-Q	Quarter ended Dec. 31, 2011
10-Q	Quarter ended Sept. 30, 2011
10-Q	Quarter ended June 30, 2011
10-K	Fiscal year ended March 31, 2011
10-Q	Quarter ended Dec. 31, 2010
10-Q	Quarter ended Sept. 30, 2010
10-Q	Quarter ended June 30, 2010
10-K	Fiscal year ended March 31, 2010
10-Q	Quarter ended Dec. 31, 2009

PROXIES

DEF 14A	Filed on March 31, 2025
DEF 14A	Filed on July 29, 2024
DEF 14A	Filed on March 31, 2024
DEF 14A	Filed on Sept. 11, 2023
DEF 14A	Filed on March 31, 2023
DEF 14A	Filed on July 29, 2022
DEF 14A	Filed on July 29, 2021
DEF 14A	Filed on July 29, 2020
DEF 14A	Filed on July 26, 2019
DEF 14A	Filed on July 26, 2018
DEF 14A	Filed on April 19, 2011
DEF 14A	Filed on None

10-Q 1 q093010.htm FORM 10-Q ENDED SEPTEMBER 30, 2010 q093010.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2010

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period From ________ to _________

Commission File Number 001-33034

BMB MUNAI, INC.

(Exact name of registrant as specified in its charter)

Nevada

30-0233726

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

Identification No.)

202 Dostyk Ave, 4 th Floor

Almaty, Kazakhstan

050051

(Address of principal executive offices)

(Zip Code)

+7 (727) 237-51-25

(Registrant's telephone number, including area code)

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.

Yes

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.

Large accelerated Filer

Accelerated Filer

Non-accelerated Filer

Smaller Reporting Company

(Do not check if a smaller reporting company)

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

Exchange Act.)

Yes

As of November 15, 2010, the registrant had 51,840,015 shares of common stock, par value $0.001, issued and outstanding.

BMB MUNAI, INC.

FORM 10-Q

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION		Page

Item 1. Unaudited Consolidated Financial Statements

	Consolidated Balance Sheets as of September 30, 2010 and March 31, 2010	3

	Consolidated Statements of Operations for the Three and Six Months Ended September 30, 2010 and 2009	4

	Consolidated Statements of Cash Flows for the Six Months Ended September 30, 2010 and 2009	5

	Notes to Consolidated Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		39

Item 3. Qualitative and Quantitative Disclosures About Market Risk		56

Item 4. Controls and Procedures		57

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		57

Item 1A. Risk Factors		57

Item 2. Unregistered Sales of Equity Securities		58

Item 3. Defaults Upon Senior Securities		59

Item 6. Exhibits		59

Signatures		60

PART I - FINANCIAL INFORMATION

Item 1 - Unaudited Consolidated Financial Statements

BMB MUNAI, INC.

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	Notes	September 30, 2010 (unaudited)	March 31, 2010
ASSETS
CURRENT ASSETS
Cash and cash equivalents	3	$ 7,052,472	$ 6,440,394
Trade accounts receivable		5,540,968	6,423,402
Prepaid expenses and other assets, net	4	4,542,168	4,083,917

Total current assets		17,135,608	16,947,713

LONG TERM ASSETS
Oil and gas properties, full cost method, net	5	249,469,208	238,601,842
Gas utilization facility, net	6	13,004,333	13,569,738
Inventories for oil and gas projects	7	13,737,772	13,717,847
Prepayments for materials used in oil and gas projects		340,050	141,312
Other fixed assets, net		3,614,158	3,815,422
Long term VAT recoverable	8	3,817,310	3,113,939
Convertible notes issue cost		939,282	1,201,652
Restricted cash	9	768,672	770,553

Total long term assets		285,690,785	274,932,305

TOTAL ASSETS		$ 302,826,393	$ 291,880,018

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable		$ 10,582,095	$ 3,948,851
Accrued non-cash share based obligations	13	3,278,569	-
Accrued coupon payment	10	641,667	641,667
Taxes payable, accrued liabilities and other payables		4,089,562	4,802,361

Total current liabilities		18,591,893	9,392,879

LONG TERM LIABILITIES
Convertible notes issued, net	10	62,618,881	62,178,119
Liquidation fund	11	4,954,070	4,712,345
Deferred taxes	16	4,964,382	4,964,382
Capital lease liability	12	285,577	369,801

Total long term liabilities		72,822,910	72,224,647

COMMITMENTS AND CONTINGENCIES	19	-	-

SHAREHOLDERS’ EQUITY
Preferred stock - $0.001 par value; 20,000,000 shares authorized; no shares issued or outstanding		-	-
Common stock - $0.001 par value; 500,000,000 shares authorized, 51,840,015 and 51,865,015 shares outstanding, respectively		51,840	51,865
Additional paid in capital		161,487,644	160,653,969
Retained earnings		49,872,106	49,556,658

Total shareholders’ equity		211,411,590	210,262,492

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$ 302,826,393	$ 291,880,018

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

BMB MUNAI, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

		Three months ended September 30,		Six months ended September 30,
	Notes	2010 (unaudited)	2009 (unaudited)	2010 (unaudited)	2009 (unaudited)

REVENUES	14	$ 12,339,967	$ 16,074,217	$ 25,127,813	$ 27,841,023

COSTS AND OPERATING EXPENSES
Rent export tax		2,388,117	2,446,476	5,109,866	3,979,913
Export duty	15	177,803	-	177,803	-
Oil and gas operating		2,018,496	2,361,284	4,134,171	3,920,284
General and administrative		4,328,090	2,952,173	7,493,201	7,803,939
Depletion	5	2,197,826	2,869,424	4,541,164	5,112,728
Interest expense	10	1,100,382	1,145,331	2,203,132	2,293,378
Depreciation of gas utilization facility	6	339,243	-	565,405	-
Amortization and depreciation		152,747	161,840	303,306	292,813
Accretion expense	11	122,537	110,878	241,725	218,725

Total costs and operating expenses		12,825,241	12,047,406	24,769,773	23,621,780

(LOSS) / INCOME FROM OPERATIONS		(485,274)	4,026,811	358,040	4,219,243

OTHER (EXPENSE) / INCOME
Foreign exchange (loss)/gain, net		(170,013)	44,091	(266,417)	(38,230)
Interest income		107,199	46,277	208,663	79,437
Other (expense)/income, net		(8,332)	(77,170)	15,162	(189,659)
Total other (expense)/income		(71,146)	13,198	(42,592)	(148,452)

(LOSS) / INCOME BEFORE INCOME TAXES		(556,420)	4,040,009	315,448	4,070,791

INCOME TAX EXPENSE	16	-	-	-	-

NET (LOSS) / INCOME		$ (556,420)	$ 4,040,009	$ 315,448	$ 4,070,791

BASIC NET (LOSS) / INCOME PER COMMON SHARE	17	$ (0.01)	$ 0.08	$ 0.01	$ 0.09
DILUTED NET (LOSS) / INCOME PER COMMON SHARE	17	$ (0.01)	$ 0.08	$ 0.01	$ 0.09

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

BMB MUNAI, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

		Six months ended September 30,
	Notes	2010 (unaudited)	2009 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$ 315,448	$ 4,070,791
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion	5	4,541,164	5,112,728
Depreciation and amortization		868,711	292,813
Interest expense		2,248,942	2,293,378
Accretion expense	11	241,725	218,725
Stock based compensation expense	13	833,650	2,744,133
Loss on disposal of fixed assets		-	31,832
Changes in operating assets and liabilities:
Decrease/(increase) in trade accounts receivable		882,434	(3,937,262)
(Increase)/decrease in prepaid expenses and other assets		(501,805)	284,748
Increase in VAT recoverable		(703,371)	(847,348)
Increase/(decrease) in current liabilities		5,920,445	(1,743,297)

Net cash provided by operating activities		14,647,343	8,521,241

CASH FLOWS FROM INVESTING ACTIVITIES:
Purchase and development of oil and gas properties	5	(10,557,858)	(7,220,487)
Purchase of other fixed assets		(312,781)	(222,206)
Increase in inventories and prepayments for materials used in oil and gas projects		(1,580,027)	(322,597)
Decrease/(increase) in restricted cash		1,881	(1,753)

Net cash used in investing activities		(12,448,785)	(7,767,043)

CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of capital lease obligation		(86,480)	-
Cash paid for convertible notes coupon		(1,500,000)	(1,500,000)

Net cash used in financing activities		(1,586,480)	(1,500,000)

NET CHANGE IN CASH AND CASH EQUIVALENTS		612,078	(745,802)
CASH AND CASH EQUIVALENTS at beginning of period		6,440,394	6,755,545
CASH AND CASH EQUIVALENTS at end of period		$ 7,052,472	$ 6,009,743

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

BMB MUNAI, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(CONTINUED)

		Six months ended September 30,
	Notes	2010 (unaudited)	2009 (unaudited)

Non-Cash Investing and Financing Activities

Transfer of inventory and prepayments for materials used in oil and gas projects to oil and gas properties	5	$ 1,361,364	$ 639,246
Depreciation on other fixed assets capitalized as oil and gas properties		210,739	-
Transfers from oil and gas properties, construction in progress and other fixed assets to gas utilization facility		-	99,107
Accrued non-cash share based obligations capitalized as part of oil and gas properties	13	3,278,569	-
Issuance of common stock for the settlement of liabilities	13	-	5,973,185

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

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

NOTE 1 - DESCRIPTION OF BUSINESS

The corporation 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

Business condition

As discussed in further detail in Note 10, in July 2007 the Company issued 5.0% Convertible Senior Notes due 2012 in the amount of $60,000,000 (the “Notes”). Among other terms of the Notes, the holders of the Notes (the “Noteholders”) had the right to require the Company redeem all or a portion of the Notes on three separate dates, including July 13, 2010. The first two dates passed without the redemption right being exercised. In connection with negotiating a possible restructuring of the Notes, on June 7, 2010 the Company and the Noteholders entered into Supplemental Indenture No. 1 dated June 1, 2010 that granted a fourth put date that commenced June 13, 2010 and expired on September 13, 2010. The intent of the fourth put date was to allow time to work out a debt restructuring agreeable to all parties. Pursuant to the Company and the Noteholders reaching an agreement in principle on general terms for a proposed restructuring of the Notes, on September 10, 2010 the Company and the Noteholders entered into Supplemental Indenture No. 2. Supplemental Indenture No. 2 grants the Noteholders a fifth put date that commences on September 13, 2010 and expires on December 31, 2010. The intent of the fifth put date is to allow time to draft definitive Note restructuring agreements.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

Prior to entering into Supplemental Indentures No. 1 and No. 2, the Company was in default under certain covenants contained in Article 9 of the Indenture requiring the Company to maintain a minimum net debt to equity ratio and to comply with certain notice, delivery and other provisions. In the context of the Indenture, the equity portion of the ratio is determined by reference to the market value of the Company’s common stock, not the Company’s book value. The market value of the Company’s stock has declined since the Notes were issued. In connection with entering Supplemental Indenture No. 2, the Noteholders separately agreed to waive these defaults until the earlier of: (i) October 15, 2010 or (ii) the fifth put date (as contained in Supplemental Indenture No. 2), with the understanding that such waiver shall not constitute a waiver of any default under the Indenture that remains ongoing as of October 15, 2010 or occurs after September 10, 2010. The Company currently believes it will not be able to remedy the net debt to equity ratio covenant by October 15, 2010 and, therefore, anticipates it will be in default under the Indenture at that time unless a future waiver is obtained from the Noteholders.

Although the Company and the Noteholders have reached an agreement in principle as to the general terms for restructuring the Notes, there is no assurance the parties will enter into definitive agreements to restructure the Notes or that the parties will successfully close and consummate a restructuring of the Notes. Moreover, there is no assurance the Noteholders will provide any future waiver or any further extension of their redemption put rights under the Indenture. If the Company and Noteholders are unable to agree on a definitive debt restructuring agreements, and the Noteholders exercise their redemption right, the Company will need to pursue other financing options. There is no guarantee the Company can be successful in obtaining additional financing.

As such, the Company has reclassified the Notes as a current liability at October 15, 2010 unless or until additional waivers are obtained or the Notes are restructured.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

Basis of consolidation

The Company’s unaudited 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 Unaudited Consolidated Financial Statements.

Reclassifications

Certain reclassifications have been made in the financial statements for the six months ended September 30, 2009 to conform to the September 30, 2010 presentation. The reclassifications had no effect on net income.

Use of estimates

The preparation of Unaudited 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 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 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.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

Licences and contracts

Emir Oil LLP (“Emir Oil”) is the operator of the Company’s oil and gas fields in Western Kazakhstan. The Government of the Republic of Kazakhstan (the “Government”) initially issued the license to Zhanaozen Repair and Mechanical Plant on April 30, 1999 to explore the Aksaz, Dolinnoe and Emir oil and gas fields (the “ADE Block” or the “ADE Fields”). On June 9, 2000, the contract for exploration of the Aksaz, Dolinnoe and Emir oil and gas fields was entered into between the Agency of the Republic of Kazakhstan on Investments and the Zhanaozen Repair and Mechanical Plant. On September 23, 2002, the contract was assigned to Emir Oil LLP. On September 10, 2004, the Government extended the term of the contract for exploration and License from five years to seven years through July 9, 2007. On February 27, 2007, the Ministry of Energy and Mineral Resources of the Republic of Kazakhstan (the “MEMR”) granted a second extension of the Company’s exploration contract. Under the terms of the contract extension, the exploration period was extended to July 2009 over the entire exploration contract territory. On December 7, 2004, the Government assigned to Emir Oil LLP exclusive right to explore an additional 260 square kilometers of land adjacent to the ADE Block, which is referred to as the “Southeast Block.” The Southeast Block includes the Kariman field and the Yessen and Borly structures and is governed by the terms of the Company’s original contract. On June 24, 2008, the MEMR agreed to extend the exploration stage of the Company’s contract from July 2009 to January 2013 in order to permit the Company to conduct additional exploration drilling and testing activities within the ADE Block and the Southeast Block.

On October 15, 2008, the MEMR approved Addendum # 6 to Contract No. 482 with Emir Oil LLP, dated June 09, 2000 extending Emir Oil LLP’s exploration territory from 460 square kilometers to a total of 850 square kilometers (approximately 210,114 acres). The additional territory is located to the north and west of the Company’s current exploration territory, extending the exploration territory toward the Caspian Sea and is referred to herein as the “Northwest Block.” The Northwest Block is governed by the terms of the Company’s exploration stage contract on the ADE Block and the Southeast 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, 2010 and 2009, sales to one customer represented 98%. At September 30, 2010 and 2009, this customer made up 95% and 100% of accounts receivable, respectively. While the loss of this foregoing customer could have a material adverse effect on the Company in the short-term, the loss of this customer should not materially adversely affect the Company in the long-term because of the available market for the Company’s crude oil and natural gas production from other purchasers.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

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 13. 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, 2010 and 2009 was $833,650 and $2,744,133, respectively.

Risks and uncertainties

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

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

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.

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.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

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.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

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, 2010 and no provision for obsolete inventory has been provided.

Oil and gas properties

The Company uses the full cost method of accounting for oil and gas properties. Under this method, all costs associated with acquisition, exploration, and development of oil and gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. These costs do not include any costs related to production, general corporate overhead or similar activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s proved 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 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.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

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:

Buildings and improvements	7-10 years
Machinery and equipment	6-10 years
Vehicles	3-5 years
Office equipment	3-5 years
Software	3-4 years
Furniture and fixtures	2-7 years

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

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 September 30, 2010, no impairment of other assets is necessary.

Gas Utilization Facility

The gas utilization facility (the “GUF”) is valued at historical cost less accumulated depreciation. Historical cost includes all direct costs associated with the acquisition and construction of the GUF.

Depreciation of the GUF is calculated using the straight-line method based upon an estimated useful life of 10 years and is charged to operating expenses. Maintenance and repairs are charged to expense as incurred. Renewals and betterments are capitalized as part of the GUF and depreciated over the useful life of the GUF.

The GUF will be evaluated annually for impairment. If the sum of expected undiscounted cash flows is less than net book value, unamortized costs of the GUF will be reduced to fair value. At September 30, 2010, no impairment of the GUF was considered 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.

Restricted cash

Restricted cash includes funds deposited in a Kazakhstan bank and is restricted to meet possible environmental obligations according to the regulations of the Republic of Kazakhstan.

Functional currency

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

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

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 January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-03 (“ASU 2010-03”) to align the oil and natural gas reserve estimation and disclosure requirements of ASC Topic 932, Extractive Industries — Oil and Gas, with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and was effective for the year ended March 31, 2010. Modernization of the Oil and Gas Reporting Requirements was designed to modernize and update the oil and gas disclosure requirements to align with current practices and changes in technology. The Company implemented ASU 2010-03 prospectively as a change in accounting principle inseparable from a change in accounting estimate at March 31, 2010.

In January 2010, the FASB issued Accounting Standards Update 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements” (“ASU 2010-06”). ASU 2010-06 requires additional disclosures and clarifies existing disclosure requirements about fair value measurement as set forth in ASC Topic 820, Fair Value Measurements and Disclosures. The Company implemented the new disclosures and clarifications of existing disclosure requirements under ASU 2010-06 effective with the first quarter of 2011, except for certain disclosure requirements regarding activity in Level 3 fair value measurements which are effective for fiscal years beginning after December 15, 2010. The implementation of ASU 2010-06 had no impact on the Company’s financial position or results of operations.

NOTE 3 - CASH AND CASH EQUIVALENTS

As of September 30, 2010 and March 31, 2010, cash and cash equivalents included:

	September 30, 2010	March 31, 2010

US Dollars	$ 6,235,721	$ 5,264,496
Foreign currency	816,751	1,175,898

	$ 7,052,472	$ 6,440,394

As of September 30, 2010 and March 31, 2010, cash and cash equivalents included $21,822 and $1,321,774 placed in money market funds having 30 day simple yields of 0.01%.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

NOTE 4 - PREPAID EXPENSES AND OTHER ASSETS

Prepaid expenses and other assets as of September 30, 2010 and March 31, 2010, were as follows:

	September 30, 2010	March 31, 2010

Advances for services	$ 2,937,556	$ 2,593,527
Taxes prepaid	872,093	920,066
Other	732,519	570,324

	$ 4,542,168	$ 4,083,917

NOTE 5 - OIL AND GAS PROPERTIES

Oil and gas properties using the full cost method as of September 30, 2010 and March 31, 2010, were as follows:

	September 30, 2010	March 31, 2010

Cost of drilling wells	$ 99,957,763	$ 96,562,442
Professional services received in exploration and development activities	66,539,334	62,967,506
Material and fuel used in exploration and development activities	54,176,294	52,221,735
Subsoil use rights	20,788,119	20,788,119
Geological and geophysical	13,479,513	7,883,856
Deferred tax	7,219,219	7,219,219
Capitalized interest, accreted discount and amortized bond issue costs on convertible notes issued	6,633,181	6,633,181
Infrastructure development costs	1,481,244	1,429,526
Other capitalized costs	18,037,753	17,198,306
Accumulated depletion	(38,843,212)	(34,302,048)

	$ 249,469,208	$ 238,601,842

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

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

NOTE 6 – GAS UTILIZATION FACILITY

In 2006 the Company entered into an Agreement on Joint Business (the “Agreement”) with Ecotechnic Chemicals AG incorporated in Switzerland, for construction of a gas utilization facility (“GUF”) to utilize the associated gas from the Company’s fields.

The initial construction of the GUF was completed in January 2009. All costs associated with the completion of the GUF, which includes amounts previously classified as construction in progress, have been reported as the Gas Utilization Facility on the balance sheet.

During the year ended March 31, 2010, the Company made payment to Ecotechnic Chemicals AG in the amount of $75,000 and contributed property totaling $24,107 to the completion of the Facility.

In May 2010, the Company entered into an agreement with LLP Aktau Gas Processing Factory to sell gas. Gas sales are currently realized at price $40 per thousand of cubic meters or $6.79 per BOE. Under this agreement, the Company is obliged to pay $33,000 per month for technical support and maintenance of the GUF. This agreement to sell gas is valid through December 31, 2010.

The Company recently completed an expansion of the initial GUF, which commenced in the spring of 2010, to expand it to reach each producing well in the Company’s fields. The expanded system increases the capacity of the GUF to 150,000 cubic meters per day (approximately 5.3 million cubic feet). The increased capacity will accommodate anticipated increases in production leading up to the issuance of a production license by the Kazakhstan government.

Based on the selling agreement mentioned above, the Company officially placed the GUF into service on May 1, 2010 and is depreciating the GUF over an estimated useful life of 10 years. During the six months ended September 30, 2010, depreciation expense for the GUF was $565,405.

NOTE 7 – INVENTORIES FOR OIL AND GAS PROJECTS

As of September 30, 2010 and March 31, 2010 inventories included:

	September 30, 2010	March 31, 2010

Construction material	$ 12,598,804	$ 12,756,417
Spare parts	103,833	87,722
Crude oil produced	3,222	2,895
Other	1,031,913	870,813

	$ 13,737,772	$ 13,717,847

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

NOTE 8 - LONG TERM VAT RECOVERABLE

As of September 30, 2010 and March 31, 2010, the Company had long term VAT recoverable in the amount of $3,817,310 and $3,113,939, 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, 2010, the Company received refunds of VAT in the amount of $655,162.

NOTE 9 - RESTRICTED CASH

Under the laws of the Republic of Kazakhstan, the Company is obligated to set aside funds for required environmental remediation. As of September 30 and March 31, 2010 the Company had restricted $768,672 and $770,553, respectively, for this purpose.

NOTE 10 - 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”).

As of September 30, 2010 and March 31, 2010, the Notes payable amount is presented as follows:

	September 30, 2010	March 31, 2010

Convertible notes redemption value	$ 64,323,785	$ 64,323,785
Unamortized discount	(1,704,904)	(2,145,666)

	$ 62,618,881	$ 62,178,119

As of September 30, 2010 and March 31, 2010, the Company has accrued interest of $641,667 for both periods, relating to the Notes outstanding. The Company has also amortized the discount on the Notes (difference between the redemption amount and the carrying amount as of the date of issue) in the amount of $2,618,881 and $2,178,119 as of September 30, 2010 and March 31, 2010, respectively. The carrying value of Notes will be accreted to the redemption value of $64,323,785. During the six months ended September 30, 2010 and 2009 the Company recorded interest expense in the amount of $2,203,132 and $2,293,378, respectively.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

On June 7, 2010, the Company entered into a Supplemental Indenture No. 1, dated June 1, 2010, between BMB Munai, Inc. and The Bank of New York Mellon, as trustee. Supplemental Indenture No. 1 amends and supplements the indenture dated September 19, 2007, between BMB Munai, Inc. and The Bank of New York Mellon, as trustee (the “Indenture”).

The Indenture provided for three put dates that allowed the holders of the Notes to redeem the Notes prior to their 2012 maturity date. The first two put dates passed unexercised. The third put date was July 13, 2010. In connection with ongoing negotiations to restructure the Notes, the Company entered into Supplemental Indenture No. 1, which granted the Noteholders a fourth put date that commenced on June 13, 2010 and expired on September 13, 2010. In exchange for the fourth put date, the Noteholders separately agreed they would not exercise their put option for the third put date and they would not exercise their put option for the fourth put date prior to September 1, 2010; provided, however, the Noteholders could exercise such put options at any time upon the occurrence of certain events.

Prior to entering into Supplemental Indenture No. 1, the Company was in default under certain covenants contained in Article 9 of the Indenture requiring the Company to maintain a minimum net debt to equity ratio and to comply with certain notice, delivery and other provisions. In the context of the Indenture, the equity portion of the ratio is determined by reference to the market value of the Company’s common stock, not the Company’s book value. The market value of the Company’s stock has declined since the Notes were issued. The Noteholders separately agreed to waive these defaults until the earlier of: (i) September 1, 2010 or (ii) the fourth put date (as contained in the Supplemental Indenture No. 1, with the understanding that such waiver would not constitute a waiver of any default under the Indenture that remained ongoing as of September 1, 2010 or occurred after June 8, 2010. At March 31, 2010, the Notes had been classified as a long-term liability on the balance sheet as the defaults had been waived by the Noteholders and the Noteholders had agreed to forbear from exercising their put option as described in the preceding paragraph.

On September 10, 2010 the Company entered into a Supplemental Indenture No. 2, dated as of September 10, 2010, between the Company and The Bank of New York Mellon, as trustee (“Supplemental Indenture No. 2”). Supplemental Indenture No. 2 amends and supplements the Indenture, as previously amended by Supplemental Indenture No. 1. Supplemental Indenture No. 2 was entered into pursuant to the Company reaching an agreement in principle with the Noteholders on general terms for a proposed restructuring of the Notes.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

Supplemental Indenture No. 2 grants the Noteholders a fifth put date that commences on September 13, 2010 and expires on December 31, 2010. In exchange for the fifth put date, the Noteholders separately agreed they will not exercise their put options for the fourth put date and they will not exercise their put option for the fifth put date prior to October 15, 2010; provided, however, the Noteholders may exercise such put options at any time prior to their respective expiration dates upon the occurrence of any of the following: (i) a default occurs under the Indenture excluding certain defaults that occurred prior to September 10, 2010, (ii) failure by the Company or any of its material subsidiaries to timely pay any Indebtedness (as defined in the Indenture) or any guarantee of any Indebtedness that exceeds U.S. $1,000,000, or any Indebtedness becomes due and payable prior to its stated maturity other than at the option of the Company or any of its material subsidiaries, or (iii) the Noteholders holding a majority in outstanding principal amount of the Notes provide notice to the Company and the other Noteholders that negotiations with respect to the restructuring have terminated. Therefore, it is possible the Noteholders could exercise a put option with respect to the Notes prior to October 15, 2010 if any of the foregoing events occur.

Prior to entering into Supplemental Indenture No. 2, the Company was in default under certain covenants contained in Article 9 of the Indenture requiring the Company to maintain a minimum net debt to equity ratio and to comply with certain notice, delivery and other provisions. In connection with entering Supplemental Indenture No. 2, the Noteholders separately agreed to waive these defaults until the earlier of: (i) October 15, 2010 or (ii) the fifth put date (as contained in Supplemental Indenture No. 2), with the understanding that such waiver would not constitute a waiver of any default under the Indenture that remains ongoing as of October 15, 2010 or occurs after September 10, 2010. The Company currently believes it will not be able to remedy the net debt to equity ratio covenant by October 15, 2010 and, therefore, anticipates it will be in default under the Indenture at that time unless a future waiver is obtained from the Noteholders.

The Company and the Noteholders have reached an agreement in principle as to the general terms for restructuring the Notes, and are working towards finalizing definitive documents to restructure the Notes, but such documents have not yet been completed. Moreover, as of September 30, 2010, the Company has not requested, nor have the Noteholders granted, an extension of the waiver of the existing defaults or an extension of the Noteholders redemption put rights under the Indenture which are scheduled to expire on October 15, 2010

As such, the Company has reclassified the Notes as a current liability at October 15, 2010 unless or until additional waivers are obtained or the Notes are restructured.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

NOTE 11 - LIQUIDATION FUND

A reconciliation on the Liquidation Fund (Asset Retirement Obligation) at September 30, 2010 is as follows:

	Total

At March 31, 2010	$ 4,712,345

Accrual of liability	-
Accretion expenses	241,725

At September 30, 2010	$ 4,954,070

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, 2010, undiscounted expected future cash flows that will be required to satisfy the Company’s obligation by 2013 for the Dolinnoe, Aksaz, Emir and Kariman fields, respectively, are $6,204,545. After application of a 10% discount rate, the present value of the Company’s liability at September 30, 2010 and March 31, 2010 was $4,954,070 and $4,712,345, respectively.

NOTE 12 – CAPITAL LEASE

In December 2009 the Company entered into a capital lease agreement with a vehicle leasing company for the lease of oil trucks in the amount of $554,820. The Company did not put the oil trucks into operations as oil tanks have not been received yet. Accordingly, depreciation expense has not been recognized as the Company has not placed the oil trucks into service.

The capital lease payment schedule is as following:

Year ended September 30,		Total Minimum Payments

2011		$ 280,405
2012		283,872
2013		49,919

Net minimum lease payments		614,196
Less: Amount representing interest		(142,784)

Present value of net minimum lease payments		$ 471,412

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

The current portion of the capital lease liability in the amount of $185,835 is recognized as part of accounts payable as of September 30, 2010. The non-current portion of the capital lease liability as of September 30, 2010 totals to $285,577.

NOTE 13 - SHARE AND ADDITIONAL PAID IN CAPITAL

Share-Based Compensation

On July 17, 2008 the shareholders of the Company approved the BMB Munai, Inc. 2009 Equity Incentive Plan (“2009 Plan”) to provide a means whereby the Company could attract and retain employees, directors, officers and others upon whom the responsibility for the successful operations of the Company rests through the issuance of equity awards. 5,000,000 common shares are reserved for issuance under the 2009 Plan. Under the terms of the 2009 Plan the board of directors determines the terms of the awards made under the 2009 Plan, within the limits set forth in the 2009 Plan guidelines.

Common Stock Grants

On January 1, 2010 the Company entered into Restricted Stock Grant Agreements with certain executive officers, directors, employees and outside consultants of the Company. The stock grants were approved by the Company board of directors and recommended by the compensation committee of the Company’s board of directors. The total number of shares granted was 1,500,000.

All of the restricted stock grants were awarded on the same terms and subject to the same vesting requirements. The restricted stock grants will vest to the grantees at such time as either of the following events occurs (the “Vesting Events”): i) the one-year anniversary of the grant date; or ii) the occurrence of an Extraordinary Event. An “Extraordinary Event” is defined in the restricted stock agreement as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to fifty percent (50%) or more of the outstanding stock of the Employer or any of its subsidiaries, or the sale of forty percent (40%) or more of the assets of the Employer or any of its subsidiaries, or one (1) person or more than one person acting as a group, acquires fifty percent (50%) or more of the total voting power of the stock of the Employer. In the event of an Extraordinary Event, the grants shall be deemed fully vested one day prior to the effective date of the Extraordinary Event. The board of directors shall determine conclusively whether or not an Extraordinary Event has occurred and the grantees have agreed to be bound by the determination of the board of directors.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

The shares representing the restricted stock grants (the “Restricted Shares”) shall be issued as soon as practicable, will be deemed outstanding from the date of grant, and will be held in escrow by the Company subject to the occurrence of a Vesting Event. The time between the date of grant and the occurrence of a Vesting Event is referred to as the “Restricted Period.” The grantees may not sell, transfer, assign, pledge or otherwise encumber or dispose of the Restricted Shares during the Restricted Period. During the Restricted Period, the grantees will have the right to vote the Restricted Shares, receive dividends paid or made with respect to the Restricted Shares, provided however, that dividends paid on unvested Restricted Shares will be held in the custody of the Company and shall be subject to the same restrictions that apply to the Restricted Shares. The Restricted Shares will only vest to the grantee if the grantee is employed by the Company at the time a Vesting Event occurs. If a Vesting Event has not occurred at the time a grantee’s employment with the Company ceases, for any reason, the entire grant amount shall be forfeited back to the Company.

One of the employees left the Company on June 30, 2010. According to the vesting terms, his restricted stock grants have been forfeited back to the Company and non-cash compensation expense of $14,225 related to those restricted stock grants was reversed during six months period ended June 30, 2010.

Non-cash compensation expense in the amount of $833,650, which is net of the expense reversal discussed above, was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the six months ended September 30, 2010.

3D Seismic Survey Agreement

On March 31, 2010 the Company entered into an agreement for conducting a 3D seismic survey with Geo Seismic Service LLP (“Geo Seismic”). Mr. Toleush Tolmakov, the General Director of Emir Oil and a holder of more than 10% of the outstanding common stock of the Company, is a 30% owner of Geo Seismic.

The agreement provides that Geo Seismic will carry out 3D field seismic exploration activities of the Begesh, Aday, North Aday and West Aksaz structures, an area of approximately 96 square kilometers within the Company’s Northwest Block. In exchange for these services, Emir Oil will pay Geo Seismic 570,000,000 Kazakh tenge ($3,800,000). In lieu of payment in Kazakh tenge, Emir Oil, at its sole election, may deliver restricted shares of BMB common stock at the agreed value of the higher of: (i) the average closing price of BMB Munai, Inc. common shares over the five days prior to final acceptance by Emir Oil of the 3D seismic work; or (ii) $2.00 per share. The maximum number of shares which may be delivered as payment in full shall not exceed 1,900,000 restricted common shares. The 3D seismic study was completed in July 2010.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

As a result of this agreement, on July 20, 2010 the Company incurred an obligation to issue 1,900,000 common shares to GeoSeismic in exchange for 3D seismic exploration service. The obligation to issue the shares has been treated as an accrued non-cash share based obligation on the Company’s balance sheet, because as of September 30, 2010, the Company was still awaiting applicable regulatory and other approvals of the issuance of the shares. The shares have been valued at $0.56 which was the closing market price of Company’s shares on July 20, 2010. As a result of this transaction $1,064,000 was capitalized to oil and gas properties.

The Company has treated this transaction with Geoseismic as a transaction with related party.

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. With the completion of the 3D seismic study the resources associated with the territory extension have now been determined and we anticipate compensation due to the consultant will be approximately 4,000,000 shares. To date, the Consultant has not requested payment. The Company anticipates a request for payment will be forthcoming and anticipates issuing the shares during the upcoming fiscal quarter.

At July 20, 2010 the Company incurred an obligation to issue 3,947,538 common shares to the Consultant as the success fee for assisting the Company to obtain an extension of the territory for exploration. The calculation for amount of shares to be issued was based on resource report, which confirms 51,318,000 barrels of oil on extended territory multiplied by $0.5 rate as per contract divided by the $6.5. The obligation to issue the shares has been treated as an accrued non-cash share based obligation on the Company’s balance sheet, because as of September 30, 2010, the Company was still awaiting applicable regulatory and other approvals of the issuance the shares. The shares have been valued at $0.56 per share, which was the closing market price of Company’s shares on July 20, 2010. As a result of this transaction $2,214,569 was capitalized to oil and gas properties.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

Stock Options

On July 18, 2005 our Board of Directors approved stock option grants under our 2004 Stock Incentive Plan subject to acceptance of those grants by the parties to whom they were granted. The total number of options grants was 820,783. The options are exercisable at a price of $4.75, the closing price of the Company's common stock on the OTCBB on July 18, 2005. The options were exercisable for a period of five years from the grant date. On July 18, 2010 820,783 stock options expired unexercised.

Stock options outstanding and exercisable as of September 30, 2010 were as follows:

	Number of Shares	Weighted Average Exercise Price


As of March 31, 2010	920,783	$ 5.04

Granted	-	-
Exercised	-	-
Expired	820,783	$ 4.75

As of September 30, 2010	100,000	$ 7.40

Additional information regarding outstanding options as of September 30, 2010 is as follows:

Options Outstanding				Options Exercisable
Range of Exercise Price	Options	Weighted Average Exercise Price	Weighted Average Contractual Life (years)	Options	Weighted Average Exercise Price

$ 7.40	100,000	$ 7.40	5.00	100,000	$ 7.40

NOTE 14 – 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.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

The Company recognized revenue from sales as follows:

	Three months ended		Six months ended
	September 30, 2010	September 30, 2009	September 30, 2010	September 30, 2009

Export oil sales	$ 12,047,614	$ 15,647,125	$ 24,589,667	$ 27,413,931
Domestic oil sales	-	427,092	-	427,092
Domestic gas sales	292,353	-	538,146	-

	$ 12,339,967	$ 16,074,217	$ 25,127,813	$ 27,841,023

NOTE 15 – EXPORT DUTY

On April 18, 2008 the Government 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. In December 2008 the Government 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 issued a resolution which reenacted the 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 fixed rate of $20 per ton or approximately $2.60 per barrel exported. The export duty fees are expensed as incurred and will be classified as costs and operating expenses. The export duty for the six months ended September 30, 2010 amounted to $177,803.

NOTE 16 – 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.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

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, 2010 and the deferred tax liability of $4,964,382 has remained unchanged since March 31, 2010.

Accounting for Uncertainty in Income Taxes - In accordance with generally accepted accounting principles, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns. The Company’s U.S. federal income tax returns for the fiscal years ended March 31, 2006 through 2009 remain subject to examination. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon an audit. Therefore, the Company has no reserves for uncertain tax positions. No interest or penalties have been levied against the Company and none are anticipated, therefore no interest or penalties have been included in the provision for income taxes.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

NOTE 17 - EARNINGS PER SHARE INFORMATION

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

	Three months ended		Six months ended
	September 30, 2010	September 30, 2009	September 30, 2010	September 30, 2009

Net (loss)/income	$ (556,420)	$ 4,040,009	$ 315,448	$ 4,070,791

Basic weighted-average common shares outstanding	51,840,015	50,365,015	51,852,447	46,665,158

Effect of dilutive securities
Warrants	-	-	-	-
Stock options	-	-	-	-
Unvested share grants	-	-	-	-

Dilutive weighted average common shares outstanding	51,840,015	50,365,015	51,852,447	46,665,158

Basic (loss)/income per common share	$ (0.01)	$ 0.08	$ 0.01	$ 0.09

Diluted (loss)/income per common share	$ (0.01)	$ 0.08	$ 0.01	$ 0.09

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, 2010 and 2009, respectively. Prior period comparative data has been retrospectively presented to reflect the adoption of this standard.

The diluted weighted average common shares outstanding for the three and six months ended September 30, 2010 and 2009 does not include the effect of potential conversion of certain stock options as their effects are anti-dilutive.

The dilutive weighted average common shares outstanding for the three and six months ended September 30, 2010 and 2009, 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, 2010 was lower than potential conversion price of the Notes for this period.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

NOTE 18 - 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, 2010 and 2009, totaled to $48,930 and $47,805, respectively. Also the Company made advance payments to Term Oil LLC for leased facilities and fuel tanks in the amount of $53,212 and $101,048 as of September 30, 2010 and March 31, 2010, respectively. A Company shareholder is an owner of Term Oil LLC.

The Company has treated this transaction with Geoseismic as a transaction with related party.

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, the General Director of Emir Oil and a holder of more than 10% of the outstanding common stock of the Company.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

Prior to the date of the Agreement, Simage had acquired by assignment, certain accounts receivable owed by Emir to third-party creditors of Emir in the amount of $5,973,185 (the “Obligations”). Pursuant to the terms of the Agreement, Simage assigned to the Company all rights, title and interests in and to the Obligations in exchange for the issuance of 2,986,595 shares of common stock of the Company. The market value of the shares of common stock issued to Simage, at the agreement date, was $3,076,193. The market value was based on $1.03 per share, which was the closing market price of the Company’s shares on June 26, 2009.

As a result of this Agreement, the Company has effectively been released of accounts payable obligations amounting to $5,973,185. The Company has treated this Agreement as a related party transaction, due to the fact that Simage is owned by a Company shareholder. Therefore, the difference between the settled amount of accounts payable and the value of the common stock issued, which amounts to $2,896,997, has been treated as a capital contribution by the shareholder and recognized as an addition to additional-paid-in-capital rather than a gain on settlement of debt.

NOTE 19 - COMMITMENTS AND CONTINGENCIES

Historical Investments by the Government of the Republic of Kazakhstan

The Government of the Republic of Kazakhstan made historical investments in the ADE Block, the Southeast Block and the Northwest Block of $5,994,200, $5,350,680 and $5,372,076, respectively. When and if, the Company applies for and, when and if, it is granted commercial production rights for the ADE Block and Southeast Block, the Company will be required to begin repaying these historical investments to the Government. The terms of repayment will be negotiated at the time the Company is granted commercial production rights.

Capital Commitments

To retain its rights under the contract, the Company must spend $27.2 million between January 10, 2011 and January 9, 2012 and $14.8 million between January 10, 2012 and January 9, 2013.

In addition to the minimum capital expenditure requirement, the Company must also comply with the other terms of the work program associated with the contract, which includes the drilling of at least ten new wells by January 9, 2013. The failure to meet the minimum capital expenditures or to comply with the terms of the work program could result in the loss of the subsurface exploration contract. The recent addenda to the exploration contract which granted the Company an extension of the exploration period and rights to the Northwest Block also require the Company to:

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

·	make additional payments to the liquidation fund, stipulated by the Contract;

·	make a one-time payment in the amount of $200,000 to the Astana Fund by the end of 2010; and

·	make annual payments to social projects of the Mangistau Oblast in the amounts of $100,000 from 2010 to 2012.

During the six months ended September 30, 2010, the Company made payment in the amount of $100,000 to social projects of the Mangistau Oblast for 2010.

Capital Lease Agreement

In December 2009 the Company entered into a capital lease agreement with an oil tanks leasing company for the lease of oil tanks in the amount of $493,000. The agreement is effective upon receiving oil tanks by the Company. As of September 30, 2010 the Company had not received the oil tanks. The Company expects to receive the oil tanks in December 2010, at which time the capital lease will be recorded. The agreement calls for average monthly payments of $12,056 during the first year and average monthly payments of $15,010 during the second and third year.

Executive Contracts

On December 31, 2009, the Company entered into new employment agreements with the following executive officers of the Company, Gamal Kulumbetov, Askar Tashtitov, Evgeniy Ler and Anuarbek Baimoldin. Each of these individuals was serving in such capacity prior to entering the employment agreements.

Except for annual salary, and as otherwise specifically addressed herein, the terms and conditions of the employment agreement of each of the executive and non-executive level officers are the same in all material respects. The employment agreements provide for an initial term of one year with three consecutive one-year renewals unless terminated by either party prior to the beginning of the renewal term. A form of the Employment Agreement was filed as an exhibit to the Current Report on Form 8-K filed on January 6, 2010.

Under the agreements, salary is reviewable no less frequently than annually and may be adjusted up or down by the compensation committee in its sole discretion, but may not be adjusted below the initial annual salary amount listed in the agreement. The agreements provide that each of the officers is entitled to participate in such pension, profit sharing, bonus, life insurance, hospitalization, major medical and other employee benefit plans of the Company that may be in effect from time to time, to the extent the individual is eligible under the terms of those plans. The agreements provide that each officer is eligible at the discretion of the compensation committee and the board of directors to receive performance bonuses. Each officer is entitled to 28 days annual vacation in accordance with the vacation policies of the Company, as well as paid holidays and other paid leave set forth in the Company’s policies. There is no accrual of vacation days and holidays.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

The agreements and all obligations thereunder may be terminated upon the occurrence of the following events: i) death, ii) disability; iii) for cause immediately upon notice from the Company or at such time as indicated by the Company in said notice; iv) for good reason upon not less than 30 days notice from an officer to the Company; v) an extraordinary event, unless otherwise agreed in writing.

Under the agreements the named executive officer may be deemed disabled if for physical or mental reasons he is unable to perform his duties for 120 consecutive days or 180 days during any 12 month period. Such disability will be determined by a jointly agreed upon medical doctor.

The agreements provide that any of the following will constitute “cause”: i) breach of the employment agreement; ii) failure to adhere to the written policies of the Company; iii) appropriation by the officer of a material business opportunity; iv) misappropriation of funds or property of the Company; v) conviction, indictment or the entering of a guilty plea or a plea of no contest to a felony.

“Good reason” under the agreements may mean any of the following: i) a material breach of the employment agreement; ii) assignment of the officer without his consent to a position of lesser status or degree of responsibility; iii) relocation of the Company’s principal executive offices outside the Republic of Kazakhstan; iv) if the Company requires the officer to be based somewhere other than principal executive offices of the Company without the officer’s consent.

Each of the employment agreements, provides that an “extraordinary event” is defined as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to fifty percent (50%) or more of the outstanding stock of the Company or any of its subsidiaries, or the sale of forty percent (40%) or more of the assets of the Company or any of its subsidiaries, or if one or more persons, acting alone or as a group, acquires fifty percent (50%) or more of the total voting power of the Company. In addition to these provisions, the employment agreement of Mr. Tashtitov provides that the following events also constitute an extraordinary event: i) that a disposition by the Chairman of the Company’s board of directors of by the General Director of the Company’s subsidiary, of seventy five (75%) or more of the shares either individual currently owns, including stock attributed to either of them by Internal Revenue Code Section 318; or ii) should the Company terminate the registration of any of its securities under Section 12 of the Exchange Act of 1934, voluntarily ceases, or shall terminate its obligation to file reports with United States Securities Commission pursuant to Section 13 of the Exchange Act of 1934.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

Upon termination of an employment agreement, the Company will make a termination payment to the officer in lieu of all other amounts and in settlement and complete release of all claims employee may have against the Company. In the event of termination for good reason by the officer, the Company will pay the officer the remainder of his salary for the calendar month in which the termination is effective and for six consecutive calendar months thereafter. The officer shall also be entitled to any portion of incentive compensation for the year, prorated to the date of termination. Notwithstanding the foregoing, if the officer obtains other employment prior to the end of the six month period, salary payments by the Company after he begins employment with a new employer shall be reduced by the amount of the cash compensation received from the new employer. If the officer is terminated for cause, he will receive salary only through the date of termination and will not be entitled to any incentive compensation for the year in which his employment is terminated. If the termination is the result of a disability, the Company will pay salary for the rest of the month during which termination is effective and for the shorter of six consecutive months thereafter or until disability insurance benefits commence. If employment is terminated as a result of the death of the officer, his heirs shall be entitled to salary through the month in which his death occurs and to incentive compensation prorated through the month of his death. The employment agreements of Mr. Kulumbetov, Mr. Ler and Mr. Baimoldin provide that if the employment agreement is terminated as a result of an extraordinary event, the officer shall be entitled to severance pay depending on the completed years of employment: i) 10% of Basic Compensation Salary if executive completed less than 1 year of employment; ii) 150% of Basic Compensation Salary if executive completed at least 1 year but not less than 2 years of employment; iii) 299% of Basic Compensation Salary if executive completed more than 2 years of employment.

The employment agreement of Mr. Tashtitov provides that in the event his employment agreement is terminated due to an extraordinary event, he will be entitled to receive a severance payment from the Company of $3,000,000.

All benefits terminate on the date of termination. The officer shall be entitled to accrued benefits, but is not entitled to compensation for unused vacation, holiday, sick leave or other leave.

The employment agreements also contain confidentiality, non-competition and non-interference provisions and provide for certain of the Company’s executive officers to potentially receive payments upon termination or change in control.

Consulting Agreement with Boris Cherdabayev

On December 31, 2009 the Company entered into a Consulting Agreement with Boris Cherdabayev, the Chairman of the Company’s board of directors. The Consulting Agreement became effective on January 1, 2010. Pursuant to the Consulting Agreement, in addition to his services as Chairman of the board of directors, Mr. Cherdabayev will provide such consulting and other services as may reasonably be requested by Company management.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

The initial term of the Consulting Agreement is five years unless earlier terminated as provided in the Consulting Agreement. The initial term will automatically renew for additional one-year terms unless and until terminated. The Consulting Agreement may be terminated for Mr. Cherdabayev’s death or disability and by the Company for cause. The Company may also terminate the Consulting Agreement other than for cause, but will be required to pay the full fee required under the Consulting Agreement.

Pursuant to the Consulting Agreement, Mr. Cherdabayev will be paid $192,000 per year. This base consulting fee will be net of Social Tax and Social Insurance Tax in the Republic of Kazakhstan, which shall be paid by the Company. Mr. Cherdabayev will be responsible for Personal Income Tax and Pension Fund Tax. The success of projects involving Mr. Cherdabayev shall be reviewed on an annual basis to determine whether the initial base consulting should be increased.

The Consulting Agreement provides for an extraordinary event payment equal to the greater of $5,000,000 or the base compensation fee for the remaining initial term of the Consulting Agreement. The Consulting Agreement defines an extraordinary event as any consolidation or merger of the Company or any of its subsidiaries with another person, or any acquisition of the Company or any of its subsidiaries by any person or group of persons, acting in concert, equal to fifty percent (50%) or more of the outstanding stock of the Company or any of its subsidiaries, or the sale of forty percent (40%) or more of the assets of the Company or any of its subsidiaries, or if one or more persons, acting alone or as a group, acquires fifty percent (50%) or more of the total voting power of the Company.

Litigation

In December 2003, Brian Savage, Thomas Sinclair and Sokol Holdings, Inc. filed complaints against the Company, its founders, and former directors, Georges Benarroch and Alexandre Agaian. The complaints all arose from the acquisition of a controlling interest in Emir Oil, LLP (“Emir”). Emir controlled the right to explore for oil and gas in the Aksaz, Dolinnoe and Emir oil and gas fields in Kazakhstan. The original complaint was filed in the Fifteenth Judicial District Court in and for Palm Beach County, Florida, but was dismissed by agreement. Subsequent complaints were filed in United States District Court for the Southern District of New York. The procedural history of this litigation has been described in the Company’s annual and quarterly reports.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

The plaintiffs asserted claims for tortious interference with contract, breach of contract, unjust enrichment, unfair competition and breach of fiduciary duty. In November 2009 defendants moved for summary judgment on all claims. On June 29, 2010 the United States District Court issued an Opinion and Order granting in part and denying in part defendants’ summary judgment motion. The Court dismissed the breach of contract and fiduciary duty claims in their entirety. The Court allowed plaintiffs’ claim for tortuous interference with contract to proceed to trial and allowed the unfair competition and unjust enrichment claims to proceed on theories of misappropriation of or unjust enrichment from taking the “product of plaintiffs’ investment of labor, skill and expenditures with respect to a business plan, system, or venture, even absent a showing of ‘novelty.’”

The Court scheduled a jury trial for October 5, 2010. However, in a series of rulings on motions in limine and pursuant to the Court's Order to Show Cause in advance of trial, the Court granted summary judgment dismissing the claims for unjust enrichment and tortious interference with contract as to all defendants. The Court allowed the unfair competition claim to proceed to trial, but limited the damages recoverable from that claim to the value of plaintiffs’ investment of labor, skill and expenditures plaintiffs allegedly provided to defendants. Plaintiffs sought reconsideration of the Court’s rulings, which was denied.

After the Court reaffirmed its decisions, plaintiffs agreed that with respect to the unfair competition claim plaintiffs had no evidence of damages other than the evidence the District Court had excluded pursuant to its ruling on a motion in limine and therefore plaintiffs orally stipulated to the entry of summary judgment against plaintiffs on that count as well. A stipulation as to the remaining claim of unfair competition was read into the record and accepted by the Court on October 5, 2010, with the parties being directed to submit a written stipulation and final order for entry by the Court. Defendants prepared a written stipulation and final order and submitted it to plaintiffs. Plaintiffs have not executed the stipulation and order prepared by defendants. Therefore, as of the date of this Report a written stipulation and final written order have not been submitted to the Court for execution and entry.

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.

BMB MUNAI, INC.

NOTES TO THE UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

SEPTEMBER 30, 2010

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 20 - FINANCIAL INSTRUMENTS

As of September 30, 2010 and March 31, 2010 cash and cash equivalents included deposits in Kazakhstan banks in the amount $4,386,992 and $3,721,701, respectively, and deposits in U.S. banks in the amount of $2,665,480 and $2,718,693, 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, 2010 and March 31, 2010. 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, 2010 and March 31, 2010 the Company made advance payments to Kazakhstan companies and Government bodies in the amount of $8,598,754 and $7,219,431, respectively. As of September 30, 2010 and March 31, 2010 restricted cash reflected in the long-term assets consisted of $768,672 and $770,553, 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, 2010.

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:

	●	substantial or extended decline in oil prices;
	●	inaccurate reserve estimates;
	●	inability to enter a production contract with the Republic of Kazakhstan prior to the expiration of our exploration contract;
	●	drilled prospects may not yield oil in commercial quantities;
	●	substantial losses or liability claims as a result of operations;
	●	insufficient funds to meet our financial obligations as they become due;
	●	complex and evolving laws that could affect the cost of doing business;
	●	substantial liabilities to comply with environmental laws and regulations;
	●	the need to replenish older depleting oil reserves with new oil reserves;
	●	inadequate infrastructure in the region where our properties are located;
	●	availability and cost of drilling rigs, equipment, supplies, personnel and oil field services;
	●	availability and cost of transportation systems;
	●	competition in the oil industry; and
	●	adverse government actions, imposition of new, or increases in existing, taxes and duties, political risks and expropriation of assets.

The above factors may affect future results, performance, events and the accuracy of any forward-looking statement. This list is illustrative, 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. was 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 have 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 Oil and Gas, (formerly the Ministry of Energy and Mineral Resources) of the ROK 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. Our annual work program year ends on January 9 each year. From the beginning of the exploration stage of our contract through January 9, 2011, our minimum mandatory expenditure requirement totals $80,630,000. From the beginning of the exploration stage of our contract through September 30, 2010, we had expended $317,985,000 in exploration activities, including the drilling of 24 wells. Our minimum annual expenditure requirements are: $27,240,000 from January 2011 to January 2012; and $14,840,000 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:

●	Reduce current accounts payable;
●	Conduct field operations focused on maximizing production and field delineation; and
●	Continue investigation of the Northwest Block

Drilling Operations, Well Performance and Production

During the fiscal quarter ended September 30, 2010, we commenced operations aimed at increasing production through working with existing wellstock by means of drilling vertical and directional sidetracks.

The first directional sidetrack was drilled at the Kariman-3 well. The original vertical well drilled in 2007 was drilled behind a fault, which resulted in a low production rate of 13 bpd. We drilled 487 meters at a 30 degree angle at a depth of 3,275 meters. This allowed us to reach beyond the fault to a previously untested, area. Upon completion of drilling, the Kariman-3 well was shut in and an electronically driven centrifugal pump (ESP) was installed in the well. The well was reopened in November 2010. Production rates at the Kariman-3 well have stabilized at an average rate of 170 bpd.

Upon completion of the Kairman-3 directional drilling, we commenced drilling a vertical sidetrack at the Kariman-1 well. The Kariman-1 was drilled during the Soviet Period to a depth of 3,069 meters, targeting Jurassic formations. In 2006 we deepened the Kariman-1 well to 3,361 meters, penetrating the upper Triassic formation and 7 meters of the middle Triassic formation. Once the middle Triassic formation was pierced, abnormally high pressure and difficult well construction design rendered it impossible for us to continue further drilling. The upper Triassic pay zone was perforated and produced at a stable rate of approximately 52 bpd.

In August 2010, we commenced sidetrack drilling at the Kariman-1 well, targeting Middle Triassic layers. The sidetrack well was drilled to a depth of 3,521 meters. While drilling, we encountered significant oil shows and high pressure which limited penetration of only 160 meters of the Middle Triassic formation. Due to the high pressure, we decided to leave the drilling tool with the drill bit inside the wellbore at the depth of 2,910 meters, and start test production through the nozzles of the drill bit. The current production rate of the well, with a 14mm choke set at the wellhead, is 925 bpd.

During the quarter ended September 30, 2010, our average daily crude oil production dropped from 2,415 barrels per day to 2,174 barrels per day. This decrease in production was the result of several factors, including, natural decline rates, well maintenance downtime and curtailment of production required by maintenance and improvement works at the oil storage facility.

We incurred production declines due to downtime at some Kariman wells in preparation for and sidetrack drilling operations on such wells. We have also incurred natural production declines at wells on each of the Aksaz, Dolinnoe and Kariman fields. Most wells that have experienced production declines have been producing based upon primary depletion mechanism (gas lift mechanism). It is natural for oil production to decline as gas pressure is reduced due to oil and gas production in the pay zone. We have installed ESP pumps in some wells and have been required to conduct some maintenance on those pumps and workover on some wells. We plan to continue installing ESP pumps in the future, provided that the pumps installed are successful in restoring production rates near the higher levels realized during earlier periods.

Significant production declines in the second and third fiscal quarters have and will result from major renovation and refurbishment of the oil storage facility we lease conducted between August and November 2010. As a part of the maintenance and repair works, we revamped and improved the oil processing circuit designed to remove impurities, mainly salts and water, from crude oil. This will allow us to continue selling crude oil produced to the international markets at higher market prices. Maintenance and improvement works were completed in early November 2010. The oil processing circuit can process up to 1,200 cubic meters per day (7,550 bpd) with the capability to be increased as needed to accommodate higher production rates. During the three months of reconstruction utilization of the storage facility was limited. This required us to curtail production at some wells.

We expect the reduced production rates caused by the foregoing activities to be offset, in large measure, by the improvements that will be realized in the reconstructed oil storage facility and the production increases realized by the drilling activities commenced in the second fiscal quarter that have been or will be completed in the third fiscal quarter.

We have continued our preparatory work for eventual transition of a portion of existing assets to commercial production. Our gas utilization facility is fully functional, resulting in cessation of gas flaring on all of the producing fields, as required by the laws and regulations of the Republic of Kazakhstan of all holders of commercial production licenses. We have increased the capacity of our gas utilization facility to 150,000 cubic meters of gas (approximately 5.3 million cubic feet) per day during 2010. All of these actions will allow us to accommodate existing production and be well-prepared for transition to commercial production stage.

During the quarter we completed 3D seismic processing and interpretation of our Northwest Block and have identified potential structures to be further evaluated.

Results of Operations

Three months ended September 30, 2010, compared to the three months ended September 30, 2009.

Revenue and Production

The following table summarizes production volumes, average sales prices and operating revenue for our oil and natural gas operations for the three months ended September 30, 2010 and the three months ended September 30, 2009.

			Three months ended September 30, 2010 to the three months ended September 30, 2009
	For the three	For the three	$	%
	months ended	months ended
	September 30, 2010	September 30, 2009	Increase (Decrease)	Increase (Decrease)

Production volumes:
Natural gas (in thousand m 3 )	8,534	-	8,534	100%
Natural gas liquids (Bbls)	-	-	-	-
Oil and condensate (Bbls)	199,993	260,123	(60,130)	(23%)
Barrels of Oil equivalent (BOE) (3)	250,220	260,123	(9,903)	(4%)

Sales volumes:
Natural gas (in thousand m 3 )	7,183	-	7,183	100%
Natural gas liquids (Bbls)	-	-	-	-
Oil and condensate (Bbls)	193,641	282,889	(89,248)	(32%)
Barrels of Oil equivalent (BOE) (3)	235,918	282,889	(46,971)	(17%)

Average Sales Price (1)
Natural gas ($ per thousand m 3 )	$ 40.70	-	$ 40.70	100%
Natural gas liquids ($ per Bbl)	-	-	-	-
Oil and condensate ($ per Bbl)	$ 62.22	$ 56.82	$ 5.39	9%
Barrels of Oil equivalent ($ per BOE) (3)	$ 52.31	$ 56.82	$ (4.52)	(8%)

Operating Revenue:
Natural gas	$ 292,353	-	$ 292,353	100%
Natural gas liquids	-	-	-	-
Oil and condensate	$ 12,047,614	$ 16,074,217	$ (4,026,603)	(25%)
Gain on hedging and derivatives (2)	-	-	-	-

(1) At times we may produce more barrels than we sell in a given period. The average sales price is calculated based on the average sales price per barrel sold, not per barrel produced.
(2) We did not engage in hedging transactions, including derivatives, during the three months ended September 30, 2010 or the three months ended September 30, 2009.
(3) The coefficient for conversion of production and sales of gas from cubic meters to barrels equals: 1 thousand m 3 = 5.8857 barrels of oil equivalent.

Revenues . We generate revenue under our exploration contract from the sale of oil and natural gas recovered during test production. During the three months ended September 30, 2010 our oil production decreased 23% compared to the three months ended September 30, 2009, as a result of natural decline rates, well maintenance downtime and curtailment of production required by maintenance and improvement works at the oil storage facility, as discussed in more detail above.

During the three months ended September 30, 2010 we realized revenue from oil sales of $12,047,614 compared to $16,074,217 during the three months ended September 30, 2009. The significant contributing factors to the 25% decrease in revenue from oil sales was a 32% decrease in sales volume as a result of decreased production, as discussed above. During the three months ended September 30, 2010 and 2009 we exported 100% and 94% respectively, of our oil 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 97% of total revenue, respectively, during the three months ended September 30, 2010 and 2009. As discussed in more detail above, we expect the reduced production rates experienced during the second fiscal quarter to begin to be offset during the third fiscal quarter, in large measure, as a result of the improvements that will be realized in the reconstructed oil storage facility and the production increases realized by the drilling activities commenced in the second fiscal quarter that have been or will be completed in the third fiscal quarter.

During the first fiscal quarter 2010 we began to realize revenue from natural gas sales to the domestic market. During the three months ended September 30, 2010 we realized revenue from natural gas sales of $292,353. During the periods prior to first fiscal quarter of 2010 we did not realize revenue from natural gas sales, because the amount from natural gas sales was insignificant and thus were included in revenue from oil sales. Our natural gas production is largely a byproduct of oil production. We anticipate future natural gas production will continue to be determined by oil production.

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, 2010 and 2009:

	For the three months ended September 30, 2010	For the three months ended September 30, 2009
Expenses:
Rent export tax	$ 2,388,117	$ 2,446,476
Export duty	177,803	-
Oil and gas operating (1)	2,018,496	2,361,284
General and administrative	4,328,090	2,952,173
Depletion (2)	2,197,826	2,869,424
Interest expense	1,100,382	1,145,331
Accretion expenses	122,537	110,878
Depreciation of gas utilization facility	339,243	-
Amortization and depreciation	152,747	161,840
Total	$ 12,825,241	$ 12,047,406
Expenses ($ per BOE):
Oil and gas operating (1)	8.56	8.35
Depletion (2)	9.32	10.14

	(1)	Includes transportation cost, production cost and ad valorem taxes (excluding rent export tax and export duty).
	(2)	Represents depletion of oil and gas properties only.

Rent Export Tax . Rent export tax is calculated based on the export sales price and ranges from as low as 0% if the export sales price is less than $40 per barrel to as high as 32% if the price per barrel exceeds $190. During the three months ended September 30, 2010 rent export tax paid to the government was $2,388,117 compared to $2,446,476 during the three months ended September 30, 2009.

Export Duty. On April 18, 2008 the government introduced an export duty on several products (including crude oil.) We 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. In December 2008 the Government 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 issued a resolution which reenacted the export duty for several products (including crude oil.) We 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. As a result of the export duty being reenacted, the export duty during the three months ended September 30, 2010 amounted $177,803. We were not subject to export duty during the three months ended September 30, 2009. Export duty was not recorded as part of oil and gas operating expense and was not included in oil and gas operating expense per BOE calculation.

Oil and Gas Operating Expenses . During the three months ended September 30, 2010 we incurred $2,018,496 in oil and gas operating expenses compared to $2,361,284 during the three months ended September 30, 2009. This decrease is primarily the result of a 15% increase in transportation expense, which was more than offset by a 48% decrease in production expense and an 18% decrease of mineral extraction tax for the three months period ended September 30, 2010 compared to the three months ended September 30, 2009.

Oil and gas operating expenses for the three months ended September 30, 2010 and 2009 consisted of the following expenses:

	Three months ended September 30,
	2010		2009
	Total	Per BOE	Total	Per BOE
Oil and Gas Operating Expenses:
Production	$ 320,727	$ 1.36	$ 615,148	$ 2.17
Transportation	938,298	3.98	814,672	2.88
Mineral extraction tax	759,471	3.22	931,464	3.30

Total	$ 2,018,496	$ 8.56	$ 2,361,284	$ 8.35

Production expense decreased 48% during the three months ended September 30, 2010 compared to the quarter ended September 30, 2009. This decrease was partially the result of decreased production. Additionally, during the second fiscal quarter 2009 we purchased light crude oil for blending purposes from a third party in amount of $465,832. Because of decreased production during the second fiscal quarter 2010, we did not have similar purchases of light crude. The reduction in production expense was partially offset by an $83,727, or 56%, increase in payroll and related payments to production personnel during the three months ended September 30, 2010 compared to three months ended September 30, 2009.

Transportation expenses increased by $123,626 or 15%, as a result of materials used in maintenance and repair of oil storage facility, we lease, spare parts for oil trucks, increases in fuel consumption at the oil storage facility, increases in salary of transportation personnel and interest expense we incurred for leased trucks.

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 on production sold to the export market, and a 2.5% tax rate. During the three months ended September 30, 2010 mineral extraction tax paid was $759,471. During the quarter ended September 30, 2009 mineral extraction tax payments were $931,464.

We calculate oil and gas operating expense per BOE based on the volume of oil and gas 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 and gas we sell. During the three months ended September 30, 2009 we sold 282,889 barrels of oil, compared the three months ended September 30, 2010 we sold 235,918 barrels of oil and gas. The 32% decrease in sales of oil volume coupled with the 15% increase in transportation expenses as part of oil and gas operating expenses resulted in a $0.21, or 3%, increase in oil and gas operating expense per BOE.

General and Administrative Expenses . General and administrative expenses during the three months ended September 30, 2010 were $4,328,090 compared to $2,952,173 during the three months ended September 30, 2009. This represents a 47% increase. This increase in general and administrative expenses was the result of:

	●	a 282% increase in other taxes, which was mainly due to recognition of property tax expenses in the amount of $292,487 for roads built during the period from 2005 to 2009;
	●	a 155% increase in professional services resulting from increases in legal fees and consulting expenses incurred in our ongoing litigation;
	●	a 4% increase in business trips and accommodation expenses;
	●	a 29% increase in rent expenses; and
	●	a 15% increase in payroll expenses;

During the three months ended September 30, 2010 we recognized non-cash compensation expense of $420,375 resulting from restricted stock grants previously made to employees. By comparison, during the three months ended September 30, 2009 we recognized non-cash compensation expense in the amount of $342,557 for restricted stock grants previously made to employees and outside consultants.

Depletion . Depletion expense for the three months ended September 30, 2010 decreased by $671,598 compared to the three months ended September 30, 2009. The major reason for this decrease in depletion expense was a 32% decrease in sales volume during the three months ended September 30, 2010 compared to the three months ended September 30, 2009.

Amortization and Depreciation . Amortization and depreciation expense for the three months ended September 30, 2010 decreased by 6% compared to the three months ended September 30, 2009.

Loss/Income from Operations . During the three months ended September 30, 2010 we realized a loss from operations of $485,274 compared to income from operations of $4,026,811 during the three months ended September 30, 2009. This decrease in income from operations during the three months ended September 30, 2010 was the result of the 23% decrease in revenue coupled with a 6% increase in total costs and operating expenses.

Other Expense/Income . During the three months ended September 30, 2010 we recognized total other expense of $71,146 compared to total other income of $13,198 during the three months ended September 30, 2009. The 639% change from other income to other expense between the respective quarters is largely attributable to a $170,013 foreign exchange loss, which was offset by interest income of $107,199 during the quarter ended September 30, 2010.

Net Loss/Income . For the foregoing reasons, during the three months ended September 30, 2010 we realized net loss of $556,420 or $0.01 per share compared to net income of $4,040,009 or $0.08 per share for the three months ended September 30, 2009.

Six months ended September 30, 2010, compared to the six months ended September 30, 2009.

Revenue and Production

The following table summarizes production volumes, average sales prices and operating revenue for our oil and natural gas operations for the six months ended September 30, 2010 and the six months ended September 30, 2009.

			Six months ended September 30, 2010 to the six months ended September 30, 2009
	For the six	For the six	$	%
	months ended	months ended
	September 30, 2010	September 30, 2009	Increase (Decrease)	Increase (Decrease)

Production volumes:
Natural gas (in thousand m 3 )	15,885	-	15,885	100%
Natural gas liquids (Bbls)	-	-	-	-
Oil and condensate (Bbls)	419,747	484,810	(65,063)	(13%)
Barrels of Oil equivalent (BOE) (3)	513,243	484,810	28,433	6%

Sales volumes:
Natural gas (in thousand m 3 )	13,203	-	13,203	100%
Natural gas liquids (Bbls)	-	-	-	-
Oil and condensate (Bbls)	408,232	505,439	(97,207)	(19%)
Barrels of Oil equivalent (BOE) (3)	485,941	505,439	(19,498)	(4%)

Average Sales Price (1)
Natural gas ($ per thousand m 3 )	$ 40.76	-	$ 40.76	100%
Natural gas liquids ($ per Bbl)	-	-	-	-
Oil and condensate ($ per Bbl)	$ 60.23	$ 55.08	$ 5.15	9%
Barrels of Oil equivalent ($ per BOE) (3)	$ 51.71	$ 55.08	$ (3.37)	(6%)

Operating Revenue:
Natural gas	$ 538,146	-	$ 538,146	100%
Natural gas liquids	-	-	-	-
Oil and condensate	$ 24,589,667	$ 27,841,023	$ (3,251,356)	(12%)
Gain on hedging and derivatives (2)	-	-	-	-

(1) At times we may produce more barrels than we sell in a given period. The average sales price is calculated based on the average sales price per barrel sold, not per barrel produced.
(2) We did not engage in hedging transactions, including derivatives, during the six months ended September 30, 2010 or the six months ended September 30, 2009.
(3) The coefficient for conversion production and sales of gas from cubic meters to barrels equals: 1 thousand m 3 = 5.8857 barrels of oil equivalent.

Revenues . During the six months ended September 30, 2010 our oil production decreased 13% compared to the six months ended September 30, 2009, as a result of downtime of wells, natural decline of production and maintenance and improvement works at the oil storage facility.

During the six months ended September 30, 2010 we realized revenue from oil sales of $24,589,667 compared to $27,841,023 during the six months ended September 30, 2009.
The significant contributing factor to the 12% decrease in revenue from oil sales was a 19% decrease in sales volume as a result of decreased production. During the six months ended September 30, 2010 and 2009 we exported 100% and 89% 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 100% and 98% of total revenue, respectively, during the six months ended September 30, 2010 and 2009.

During the first quarter of 2010 we began realizing revenue from natural gas sales to the domestic market. During the six months ended September 30, 2010 we realized revenue from natural gas sales of $538,146. During the periods prior to first quarter of 2010 we did not realize revenue from natural gas sales, because the amounts realized from natural gas sales were insignificant and thus were included in revenue from oil sales.

Costs and Operating Expenses

The following table presents details of our costs and expenses for the six months ended September 30, 2010 and 2009:

	For the six months ended September 30, 2010	For the six months ended September 30, 2009
Expenses:
Rent export tax	$ 5,109,866	$ 3,979,913
Export duty	177,803	-
Oil and gas operating (1)	4,134,171	3,920,284
General and administrative	7,493,201	7,803,939
Depletion (2)	4,541,164	5,112,728
Interest expense	2,203,132	2,293,378
Accretion expenses	241,725	218,725
Depreciation of gas utilization facility	565,405	-
Amortization and depreciation	303,306	292,813
Total	$ 24,769,773	$ 23,621,780
Expenses ($ per BOE):
Oil and gas operating (1)	$ 8.51	$ 7.76
Depletion (2)	9.35	10.12

	(1)	Includes transportation cost, production cost and ad valorem taxes (excluding rent export tax and export duty).
	(2)	Represents depletion of oil and gas properties only.

Rent Export Tax . During the six months ended September 30, 2010 rent export tax paid to the government amounted to $5,109,866 compared to $3,979,913 during the six months ended September 30, 2009.

Export Duty. In July 2010 the government issued a resolution which reenacted the export duty for several products (including crude oil.) We became subject to the export duty in September 2010. As a result of the export duty being reenacted, the export duty during the six months ended September 30, 2010 amounted to $177,803. We were not subject to export duty during the six months ended September 30, 2009. Export duty was not recorded as part of oil and gas operating expense and was not included in oil and gas operating expense per BOE calculation.

Oil and Gas Operating Expenses . During the six months ended September 30, 2010 we incurred $4,134,171 in oil and gas operating expenses compared to $3,920,284 during the six months ended September 30, 2009. This increase is primarily the result of a 21% increase in transportation expense and 100% increase in expenses for gas production for the six months period ended September 30, 2010 compared to the six months ended September 30, 2009, which was partially offset by 22% decrease in production expense for the same period.

Oil and gas operating expenses for the six months ended September 30, 2010 and 2009 consist of the following expenses:

	Six months ended September 30,
	2010		2009
	Total	Per BOE	Total	Per BOE
Oil and Gas Operating Expenses:
Production	$ 610,503	$ 1.26	$ 779,241	$ 1.54
Transportation	1,920,167	3.95	1,582,536	3.13
Mineral extraction tax	1,603,501	3.30	1,558,507	3.08

Total	$ 4,134,171	$ 8.51	$ 3,920,284	$ 7.76

The 22% decrease in production expense during the six months ended September 30, 2010 compared to the six months ended September 30, 2009 was due to decreased oil production. Another contributing factor to this decrease was purchase of light crude oil for blending purposes from a third party in the amount of $465,832 during the six months ended September 30, 2009. Because of reductions in production during the six months ended September 30, 2010, we did not have a need to purchase light crude oil during that period.

Transportation expenses increased by $337,631, or 21%, as a result of materials used in maintenance and repair of oil storage facility, spare parts for oil trucks, increases in fuel consumption on oil storage facility, increases in salary of personnel related to transportation and interest expense we incurred for leased trucks.

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, 2010 mineral extraction tax paid to the government was $1,603,501. During the six months ended September 30, 2009, mineral extraction tax was $1,558,507.

Expense per BOE is a function of total expense divided by the number of barrels of oil and gas we sell. During the six months ended September 30, 2009 we sold 505,439 barrels of oil, by comparison, during the six months ended September 30, 2010 we sold 485,941 barrels of oil and gas. The 19% decrease in sales of oil volume coupled with a 21% increase in transportation expenses resulted in a $0.75, or 10%, increase in oil and gas operating expense per BOE.

General and Administrative Expenses . General and administrative expenses during the six months ended September 30, 2010 were $7,493,201 compared to $7,803,939 during the six months ended September 30, 2009. This represents a 4% decrease. This decrease in general and administrative expenses was the result of the following:

	•	a 68% decrease in environmental payments for flaring of unused natural gas as a result of decreased production. The amount of environmental payments totaled $51,175 and $158,211 during the six months ended September 30, 2010 and 2009, respectively;
	•	a 128% increase in other taxes;
	•	a 24% increase in business trips and accommodation expenses;
	•	a 76% increase in professional services resulting from increased legal fees incurred in our litigation;
	•	a 37% increase rent expenses; and
	•	a 16% increase in payroll expenses.

The main contributing factor for decrease in general and administrative expenses was a 70% decrease in non-cash compensation expense. During the six months ended September 30, 2010 we recognized non-cash compensation expense of $833,650 resulting from restricted stock grants previously made to employees. By comparison, during the six months ended September 30, 2009 we recognized non-cash compensation expense in the amount of $2,744,133 for restricted stock grants previously made to employees and outside consultants.

Depletion . Depletion expense for the six months ended September 30, 2010 decreased by $571,564 compared to the six months ended September 30, 2009. The principal reason for this decrease in depletion expense was a 19% decrease in sales volume of oil during the six months ended September 30, 2010 compared to the six months ended September 30, 2009.

Amortization and Depreciation . Amortization and depreciation expense for the six months ended September 30, 2010 increased 4% compared to the six months ended September 30, 2009. The increase resulted from purchases of fixed assets.

Income from Operations . During the six months ended September 30, 2010 we realized income from operations of $358,040 compared to income from operations of $4,219,243 during the six months ended September 30, 2009. This decrease in income from operations during the six months ended September 30, 2010 is the result of the 10% decrease in revenue coupled with a 5% increase in total costs and operating expenses.

Other Expense . During the six months ended September 30, 2010 we recognized total other expense of $42,592 compared to total other expense of $148,452 during the six months ended September 30, 2009. The change between other expenses between the respective periods is largely attributable to a $228,187 increase in foreign exchange loss.

Net Income . For the foregoing reasons, during the six months ended September 30, 2010 we realized net income of $315,448 or $0.01 per share compared to a net income of $4,070,491 or $0.09 per share for the six months ended September 30, 2009.

Liquidity and Capital Resources

For the period from inception on May 6, 2003 through September 30, 2010 we have incurred capital expenditures of $317,985,000 for exploration, development and acquisition activities. Funding for our activities has historically been provided by funds raised through the sale of our common stock and debt securities and revenue from oil sales. From inception to September 30, 2010 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, see Note 10 of the notes to the unaudited consolidated financial statements included in this Report.

The terms of the original indenture (the “Indenture”) governing the Notes provided for three put dates that allowed the Noteholders to redeem the Notes prior to their 2012 maturity date. The first two put dates passed unexercised. The third put date was July 13, 2010. Because we would have been unable to repay the Notes at July 13, 2010 had the Noteholders exercised their redemption right, we commenced negotiations with the Noteholders to restructure the Notes. In connection with those negotiations, we entered into Supplemental Indenture No. 1 in July 2010 and Supplemental Indenture No. 2 in September 2010 (jointly the “Supplemental Indentures”). The Supplemental Indentures amend and supplement the original Indenture. Supplemental Indenture No. 1 granted the Noteholders a fourth put option date extending their put right to any time between June 13, 2010 and September 13, 2010. Supplemental Indenture No. 2 granted Noteholders a fifth put option date, extending their put right to any time between September 13, 2010 and December 31, 2010. In exchange for the fifth put date, the Noteholders separately agreed they would not exercise their put option for the fourth put date or their fifth put option prior to October 15, 2010; provided, however, that under certain circumstances the Noteholders could exercise their put options before October 15, 2010.

Prior to entering into the Supplemental Indentures, we were in default of certain covenants contained in Article 9 of the Indenture requiring us to maintain a minimum net debt to equity ratio and to comply with certain notice, delivery and other provisions. In the context of the Indenture, the equity portion of the ratio is determined by reference to the market value of the Company’s common stock, not the Company’s book value. The market value of the Company’s stock has declined since the Notes were issued. In connection with Supplemental Indenture No. 2, the Noteholders separately agreed to waive the defaults until the earlier of: (i) October 15, 2010 or (ii) the fifth put date, except in certain circumstances that would allow the Noteholders to terminate the waiver early.

Supplemental Indenture No. 2 was entered into in conjunction with our having reached an agreement in principle with the Noteholders on a proposed restructure of the Notes, subject to confirmatory due diligence and the negotiation and execution of definitive agreements, including a revised Indenture governing the Notes.

The Note restructure contemplates that we will secure the Notes. The security will include: (i) a first priority pledge of the Company’s equity interest in its wholly-owned subsidiary, Emir Oil LLP (“Emir Oil”); (ii) a guarantee of payment of the Notes by Emir Oil and any future subsidiary of the Emir Oil or the Company; (iii) the guaranty obligation of Emir Oil to initially be secured by its exploration license(s); and (iv) a pledge of the production licenses for the Aksaz, Dolinnoe and Kariman fields once they become pledgable and the pledge over the exploration license ceases to be effective.

In addition to securing the Notes, we will agree to certain changes to the payment terms of the Notes. Upon consummation of the plan of restructure, we will make a $1,000,000 cash payment towards the principal balance of the Notes, which will result in an adjusted principal amount of $61,400,000 after giving effect to the payment. The cash payment and the increase in the principal amount reflect an adjustment based on the value of the unexercised third put option. The coupon rate of the Notes will increase from 5% to 9%, and will continue to be payable semi-annually. We also agreed to an additional coupon that will be payable if the product of the price of Brent and our production volumes exceeds certain threshold levels to be agreed upon. We will agree, beginning six months after the issue or restructuring date, to make quarterly principal amortization payments based on a percentage of excess cash flows, which is still being negotiated.

The parties intend to amend the maturity date and redemption and conversion provisions of the Notes and the existing Indenture. The new maturity date of the Notes will be July 13, 2013. The restructure contemplates the Noteholders will be granted a new put option, exercisable one year prior to the new maturity date. The conversion price of the Notes will be reduced to $2.00 per share, subject to certain adjustment events, including events included in the original Indenture and the minimum conversion price will be reduced to a floor of $1.00 per share. In the event of a change in control of the Company, the Noteholders will have an option to redeem their Notes at a price equal to 110% of the Notes or to convert their Notes to Company common stock. We will have the option to redeem the Notes in the event the closing market price for our common stock exceeds 200% of the then current conversion price.

It is contemplated that we will agree to certain other changes to the terms of the Indenture. Once definitive documents are executed, the Noteholders will have the right to appoint one board member to the Company’s board of directors, who will also sit on the compensation committee. The Noteholders will be granted certain registration, listing and tag along rights. We will agree to certain restrictions on incurring new indebtedness, uses of proceeds from any new debt or equity offerings, capital expenditures, dividends and other distributions, disposal of assets, investments and affiliate transactions and such other and customary covenants acceptable to the Noteholders. We will not adopt or amend any existing incentive plans or plan providing for payment in respect of severance, change in control or other extraordinary events or transactions until the Notes are repaid in full. We have agreed to maintain the NYSE Amex listing of our common stock.

The parties are working toward definitive documents to restructure the Notes upon the terms disclosed above, but such documents have not yet been completed.

As discussed above, in connection with the execution of Supplemental Indenture No. 2, the Noteholders separately agreed they would not exercise their put option right prior to October 15, 2010. They also separately agreed to waive existing defaults under the Indenture until the earlier of October 15, 2010 or the date they exercise their redemption right. As a result of the expiration of the abovementioned waiver, the Noteholders could, at any time prior to December 31, 2010 exercise their put option right or, at any time following compliance with the provisions of the Indenture seek to declare an event of default and accelerate the Notes. While the Noteholders have the right to do so, they have not done so as of the date of this Report and we continue to progress towards definitive agreements.

If the Noteholders were to exercise their put right or accelerate the Notes, we would have insufficient funds to repay the Notes. The outstanding balance of unpaid principal and interest under the Notes was $63,749,083 as of November 15, 2010. As we would have insufficient funds to repay the Notes, the Noteholders could seek any legal remedies available to them to obtain repayment of the Notes.

At September 30, 2010 our current liabilities exceeded our current assets by $1,456,285. Included in the current liabilities amount is $3,278,569 of accrued non-cash share based obligations. At September 30, 2010 we had cash and cash equivalents of $7,052,472. Through the first six months of our fiscal year net cash provided by operating activities was $14,647,343 and we had realized net income of $315,448. We believe that cash on hand and anticipated revenues from operations will be sufficient to fund our operations for the remainder of the current fiscal year unless the Noteholders exercise their redemption rights or accelerate the Notes.

Cash Flows

During the six months ended September 30, 2010 cash was primarily used to fund exploration expenditures. See below for additional discussion and analysis of cash flow.

	Six months ended September 30, 2010	Six months ended September 30, 2009

Net cash provided by operating activities	$ 14,647,343	$ 8,521,241
Net cash used in investing activities	$ (12,448,785)	$ (7,767,043)
Net cash provided by financing activities	$ (1,586,480)	$ (1,500,000)

NET CHANGE IN CASH AND CASH EQUIVALENTS	$ 612,078	$ (745,802)

Our principal source of liquidity during the six months ended September 30, 2010 was cash and cash equivalents. At March 31, 2010 cash and cash equivalents totaled approximately $6.4 million. At September 30, 2010 cash and cash equivalents had increased to approximately $7 million. During the six months ended September 30, 2010 we spent over $12 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, 2010, excluding current liabilities as listed on our consolidated balance sheet:

	Payments Due By Period
Contractual obligations	Total	Less than 1 year	2-3 years	4-5 years	After 5 years
Capital Expenditure Commitment (1)	$ 42,080,000	$ 13,620,000	$ 28,460,000	$ -	$ -
Due to the Government of the Republic of Kazakhstan (2)	16,106,108	100,000	960,848	2,925,467	12,119,793
Liquidation Fund	4,954,070	-	4,954,070	-	-
Convertible Notes with Interest (3)	68,823,785	1,500,000	67,323,785	-	-
Total	$ 131,963,963	$ 15,220,000	$ 101,698,703	$ 2,925,467	$ 12,119,793

(1)

Under the terms of our subsurface exploration contract we are required to spend a total of $42 million in exploration activities on our properties, including a minimum of $27.2 million by January 2012 and $14.8 million by January 2013. As of September 30, 2010, we have spent a total of $318 million in exploration activities. The rules of the Ministry of Oil and Gas provide a process whereby capital expenditures in excess of the minimum required expenditure in any period may be carried forward to meet the minimum obligations of future periods. Our capital expenditures in prior periods have exceeded our minimum required expenditures by more than $195 million.

(2)

In connection with our acquisition of the oil and gas contract covering the ADE Block, the Southeast Block and the Northwest Block, we are required to repay the ROK for historical costs incurred by it in undertaking geological and geophysical studies and infrastructure improvements. Our repayment obligation for the ADE Block is $5,994,200 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:

·	make additional payments to the liquidation fund, stipulated by the Contract;

·	make a one-time payment in the amount of $200,000 to the Astana Fund by the end of 2010; and

·	make annual payments to social projects of the Mangistau Oblast in the amount of $100,000 from 2010 to 2012.

(3)

On July 16, 2007 the Company completed the private placement of $60 million in principal amount of 5.0% Convertible Senior Notes due 2012 (“Notes”). The Notes carry a 5% coupon and have a yield to maturity of 6.25%. Interest will be paid at a rate of 5.0% per annum on the principal amount, payable semiannually. The Notes are callable and subject to early redemption at any time between September 13, 2010 and December 31, 2010. Unless previously redeemed, converted or purchased and cancelled, the Notes will be redeemed by the Company at a price equal to 107.2% of the principal amount thereof on July 13, 2012. The Notes constitute direct, unsubordinated and unsecured, interest bearing obligations of the Company. For additional details regarding the terms of the Notes, see Note 10 – Convertible Notes Payable to the notes to our Unaudited Consolidated Financial Statements.

Off-Balance Sheet Financing Arrangements

As of September 30, 2010, we had no 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, 2010, we sold 193,641 barrels of oil and condensate. We realized an average sales price per barrel of $62.22. For purposes of illustration, assuming the same sales volume but decreasing the average sales price we receive from oil sales by $5.00 and $10.00 respectively would change total revenue from oil sales as follows:

	Average Price Per Barrel	Barrels of Oil Sold	Approximate Revenue from Oil Sold (in thousands)	Reduction in Revenue (in thousands)
Actual sales for the three months ended September 30, 2010	$ 62.216	193,641	$ 12,048	$ -
Assuming a $5.00 per barrel reduction in average price per barrel	$ 57.216	193,641	$ 11,079	$ 969
Assuming a $10.00 per barrel reduction in average price per barrel	$ 52.216	193,641	$ 10,111	$ 1,937

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, 2010 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, 2010.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended September 30, 2010 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 19 “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 following risk factor, and other information set forth in this Report, you should carefully consider the risks discussed in our 2010 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.

If we are unsuccessful in restructuring the Notes, we do not have the funds, or the ability to raise the funds, necessary to repurchase the Notes if the Noteholders exercise their put right or declare an event of default and accelerate the Notes.

We have reached an agreement in principle with the holders of our $60 million in principal amount 5.0% Convertible Senior Notes due 2012 on a proposed restructure of the Notes subject to the negotiation and execution of definitive agreements, including a revised Indenture governing the Notes. For details regarding the proposed terms of the restructure of the Notes please see the Liquidity and Capital Resources section of Part I, Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Report (“ Liquidity and Capital Resources ”). We continue to work with the Noteholders toward definitive documents to restructure the Notes, but such documents have not yet been completed.

As discussed in more detail in Liquidity and Capital Resources , the agreements of the Noteholders to forbear from exercising their redemption right and their waiver of our defaults under the Notes executed in connection with Supplemental Indenture No. 2 expired on October 15, 2010. Therefore, the Noteholders currently have the right, until December 31, 2010, to require us to redeem their Notes or, because we are currently in default of certain provisions of the Indenture governing the Notes, they also have the right, following compliance with the provisions of the Indenture, to declare our default an event of default and accelerate repayment of the Notes. As of the date of this Report the Noteholders have not exercised either of these rights and we continue to progress towards definitive agreements to restructure the Notes.

If the Noteholders were to exercise their put right or declare an event of default and accelerate the Notes, we would have insufficient funds to repay the Notes. The outstanding balance of unpaid principal and interest under the Notes was $63,749,083 as of November 15, 2010. As we would have insufficient funds to repay the Notes, the Noteholders could seek any legal remedies available to them to obtain repayment of the Notes, including forcing us into bankruptcy, which would likely also result in Emir Oil being forced into bankruptcy. Pursuant to Kazakhstan law and the terms of our exploration license, the government of the Republic of Kazakhstan has the right to cancel our licenses to the ADE Block, the Southeast Block and the Northwest Block in the event Emir Oil becomes insolvent or enters into bankruptcy proceedings. If such were to happen, we would be left with limited assets, no operations and ability to generate revenue or otherwise repay the Notes.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

On July 20, 2010 we incurred an obligation to issue 3,947,538 shares of our common stock to Caspian Energy Consulting Ltd, an international business company organized under the laws of the British Virgin Islands, as the success fee for assisting Emir Oil to obtain an extension of its exploration territory. The shares have not yet been issued, as we are still awaiting applicable regulatory and other approvals for the issuance of the shares. The shares have been valued at $0.56 per share, which was the closing market price of our shares on the date we became obligate to issue them.

We offered and sold the shares to Caspian Energy Consulting, a non-U.S. person outside the United States, in accordance with Regulation S under the Securities Act.

Also on July 20, 2010 we incurred an obligation to issue 1,900,000 common shares to GeoSeismic Service LLP, a Kazakhstan LLP, in exchange for 3D seismic exploration service. The shares have not yet been issued as we are still awaiting applicable regulatory and other approvals of the issuance of the shares. The shares have been valued at $0.56 per share, which was the closing market price of our shares on July 20, 2010.

We offered and sold the shares to GeoSeismic Service LLP, a non-U.S. person outside the United States, in accordance with Regulation S under the Securities Act.

Item 3. Defaults Upon Senior Securities

As discussed in more detail in the Liquidity and Capital Resources section of Part I, Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Report, we are currently in default of the terms of our $60 million in principal amount 5.0% Convertible Senior Notes due 2012 (“Notes”). This default occurred when the agreement of the Noteholders to waive the defaults by the Company of certain covenants contained in Article 9 of the Indenture requiring us to maintain a minimum net debt to equity ratio and to comply with certain notice, delivery and other provisions expired on October 15, 2010. The outstanding balance of unpaid principal and interest under the Notes as of November 15, 2010 was $63,749,083. Despite the default, there has been no event of default declared by the Noteholders as we continue to work together to complete definitive agreements to restructure the Notes.

Item 6. Exhibits

	Exhibit No.		Description of Exhibit

	Exhibit 12.1		Computation of Earnings to Fixed Charges

	Exhibit 31.1		Certification of Principal Executive Officer Pursuant to
			Section 302 of the Sarbanes Oxley Act of 2002

	Exhibit 31.2		Certification of Principal Financial Officer Pursuant to
			Section 302 of the Sarbanes-Oxley Act of 2002

	Exhibit 32.1		Certification Pursuant to Section 906 of the Sarbanes-
			Oxley Act of 2002

	Exhibit 32.2		Certification Pursuant to Section 906 of the Sarbanes-
			Oxley Act of 2002

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.

		BMB MUNAI, INC.



Date:	November 15, 2010	/s/ Gamal Kulumbetov
		Gamal Kulumbetov Chief Executive Officer



Date:	November 15, 2010	/s/ Evgeniy Ler
		Evgeniy Ler Chief Financial Officer

TABLE OF CONTENTS

Part I - Financial Information Item 1 - Unaudited Consolidated Financial Statements Note 1 - Description Of Business Note 2 - Significant Accounting Policies Note 3 - Cash and Cash Equivalents Note 4 - Prepaid Expenses and Other Assets Note 5 - Oil and Gas Properties Note 6 Gas Utilization Facility Note 7 Inventories For Oil and Gas Projects Note 8 - Long Term Vat Recoverable Note 9 - Restricted Cash Note 10 - Convertible Notes Payable Note 11 - Liquidation Fund Note 12 Capital Lease Note 13 - Share and Additional Paid in Capital Note 14 Revenues Note 15 Export Duty Note 16 Income Taxes Note 17 - Earnings Per Share Information Note 18 - Related Party Transactions Note 19 - Commitments and Contingencies Note 20 - Financial Instruments Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Qualitative and Quantitative Disclosures About Market Risk Item 4. Controls and Procedures Part II - Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 6. Exhibits

Customer name	Ticker
Adams Resources & Energy, Inc.	AE
Devon Energy Corporation	DVN

FRHC 10-Q Quarter ended Sept. 30, 2010