Freedom Holding (FRHC) 10-Q/A 2007 Q3 Quarterly report (amended)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q/A-1

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

For the Quarterly Period Ended December 31, 2006

o 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 000-28638

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 (3272) 375-125

(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 any 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 x No o

Indicate by check mark whether the registrant is a large accelerated filed, an accelerated filer, or non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act: (Check one):

Large accelerated Filer o Accelerated Filer x Non-accelerated Filer o

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

Yes o No x

As of February 5, 2006, the registrant had 43,700,652 shares of common stock, par value $0.001, issued and outstanding.

BMB MUNAI, INC.

FORM 10-Q/A-1

TABLE OF CONTENTS

EXPLANATORY NOTE			3
PART I — FINANCIAL INFORMATION
	Item 1. Unaudited Consolidated Financial Statements
		Consolidated Balance Sheets as of December 31, 2006 and March 31, 2006	4
		Consolidated Statements of Loss for the Three and Nine Months Ended December 31, 2006 and 2005	5
		Consolidated Statements of Cash Flows for the Nine Months Ended
		December 31, 2006 and 2005	6
		Notes to Consolidated Financial Statements	7
	Item 2. Managements’ Discussion and Analysis of Financial Condition and Results
		of Operations	26
	Item 3. Quantitative and Qualitative Disclosures About Market Risk		43
	Item 4. Controls and Procedures		44
PART II — OTHER INFORMATION
	Item 1. Legal Proceedings		45
	Item 1A. Risk Factors		46
	Item 4. Submission of Matters to a Vote of Security Holders		46
	Item 6. Exhibits		47
	Signatures		47

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Explanatory Note to Amendment No. 1 to Quarterly Report on Form 10-Q

BMB Munai, Inc. (the “Company”) is filing this Amendment No. 1 on Form 10-Q/A-1 (the “Amendment”) to its Quarterly Report for the fiscal quarter ended December 31, 2006, which was originally filed with the Securities and Exchange Commission (“SEC”) on February 9, 2007 (the “Original Quarterly Report”) in response to certain comments raised by the staff of the SEC.

Part I, Item 1 “Financial Information” of the Original Quarterly Report is hereby amended. In connection with the preparation of the consolidated financial statements for the fiscal year ended March 31, 2007, we determined that the investments classified as “marketable securities” in the consolidated financial statements for the fiscal year ended March 31, 2006 and the fiscal quarter ended December 31, 2006 were, in fact, short-term highly liquid investments, readily convertible to cash, all of which had maturity dates of 90 days or less and therefore they should have properly been classified as cash and cash equivalents rather than marketable securities. In light of this determination, we reclassified “marketable securities” to “cash and cash equivalents” in the consolidated financial statements for the fiscal year ended March 31, 2006. We therefore have made appropriate revisions to the Consolidated Balance Sheets, the Consolidated Statements of Loss, the Consolidated Statements of Cash Flows and the Notes to the Consolidated Financial Statements to reflect the reclassification. The reclassification had no effect on net income. Revisions were also made to the Notes to the Consolidated Financial Statements to provide additional clarification as to our policy for recognition of revenue and costs, our accounting for share based compensation and reclassifications. Other footnote disclosures were revised in response to SEC comments.

Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Original Quarterly Report is also hereby amended to reflect the changes made to the Consolidated Financial Statements as discussed in the preceding paragraph to provide additional disclosure regarding the method we use to calculate our per unit costs and why they increased during the three and nine months ended December 31, 2006 and to explain fluctuations in depletion and depreciation and amortization increased during the three and nine months ended December 31, 2006.

.

In accordance with Rule 12b-15 under the Securities Exchange Act of 1934, this Amendment also includes currently dated certifications from the Company’s Chief Executive Officer and Chief Financial Officer as required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002. The certification exhibits and Item 6 have been revised accordingly.

This Amendment speaks only as of the filing date of the Original Quarterly Report and, except as discussed in this explanatory note, is unchanged from the Original Quarterly Report. This Amendment does not reflect events after the filing of the Original Quarterly Report or modify or update those disclosures affected by subsequent events. Therefore, you should read this Amendment together with our other reports that update and/or supersede the information contained in this Amendment.

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PART I - FINANCIAL INFORMATION

Item 1 - Unaudited Consolidated Financial Statements

BMB MUNAI, INC.

CONSOLIDATED BALANCE SHEETS

	Notes	December 31, 2006 (Unaudited)	March 31, 2006
ASSETS
CURRENT ASSETS
Cash and cash equivalents	3	$ 21,446,804	$ 51,141,732
Trade accounts receivable		1,034,802	1,675,202
Inventories	4	9,111,593	3,239,947
Prepayments for materials		2,078,151	712,526
Other prepaid expenses and other assets, net	5	1,999,260	566,920
Total current assets		35,670,610	57,336,327
LONG TERM ASSETS
Oil and gas properties, full cost method, net	6	95,096,803	66,683,297
Other fixed assets, net	7	1,434,437	1,020,951
Intangible assets, net		35,128	49,656
Construction in progress	8	3,347,529	-
Long term VAT recoverable	9	3,385,429	1,335,971
Restricted cash		303,697	156,454
Total long term assets		103,603,023	69,246,329
TOTAL ASSETS		$ 139,273,633	$ 126,582,656
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable		$ 7,142,293	$ 3,629,338
Due to reservoir consultants		-	500,000
Taxes payable		383,098	145,406
Accrued liabilities and other payables		132,185	349,231
Total current liabilities		7,657,576	4,623,975
LONG TERM LIABILITIES
Liquidation fund		2,112,545	924,592
Deferred income tax liabilities	10	7,270,530	6,405,285
Total long term liabilities		9,383,075	7,329,877
COMMITMENTS AND CONTINGENCIES	14	-	-
SHAREHOLDERS’ EQUITY
Share capital	11	43,701	42,224
Additional paid in capital	11	133,648,978	123,831,007
Accumulated deficit		(11,459,697)	(9,244,427)
Total shareholders’ equity		122,232,982	114,628,804
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$ 139,273,633	$ 126,582,656

See notes to the unaudited consolidated financial statements.

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BMB MUNAI, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Notes	Three months ended December 31, 2006 (unaudited)	Three months ended December 31, 2005 (unaudited)	Nine months ended December 31, 2006 (unaudited)	Nine months ended December 31, 2005 (unaudited)
REVENUES	12	$ 2,214,382	$ 2,058,792	$ 8,577,326	$ 4,106,765
EXPENSES
Oil and gas operating		360,905	242,582	1,351,478	509,289
General and administrative		1,705,166	1,497,515	9,028,108	7,379,267
Depletion		323,062	451,029	991,030	1,116,673
Amortization and depreciation		44,726	35,316	121,237	100,122
Accretion expenses		56,177	-	120,235	-
Total expenses		2,490,036	2,226,442	11,612,088	9,105,351
LOSS FROM OPERATIONS		(275,654)	(167,650)	(3,034,762)	(4,998,586)
OTHER INCOME (EXPENSE)
Realized gain on marketable securities		-	-	-	181,688
Unrealized gain on marketable securities		-	62,729	-	55,190
Foreign exchange (loss) / gain, net		(42,487)	58,450	(116,750)	(65,686)
Interest income, net		330,529	36,348	1,335,258	48,370
Other expense, net		(103,249)	(42,819)	(223,503)	(18,980)
Total other income		184,793	114,708	995,005	200,582
LOSS BEFORE INCOME TAXES		(90,861)	(52,942)	(2,039,757)	(4,798,004)
INCOME TAX EXPENSE	10	-	-	(175,513)	-
NET LOSS		$ (90,861)	$ (52,942)	$ (2,215,270)	$ (4,798,004)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING – BASIC AND DILUTED		43,693,985	33,426,080	43,422,404	32,676,428
LOSS PER COMMON SHARE - BASIC AND DILUTED		$            -	$            -	$         (0.05)	$          (0.15)

See notes to the unaudited consolidated financial statements.

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BMB MUNAI, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Notes	Nine months ended December 31, 2006 (unaudited)	Nine months ended December 31, 2005 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		$ (2,215,270)	$ (4,798,004)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion	6	991,030	1,116,673
Depreciation and amortization		121,237	100,122
Accretion expenses		120,235	-
Stock based compensation expense	11	3,605,946	3,876,658
Stock issued for services	11	455,000	172,682
Loss on disposal of fixed assets		14,953	-
Income taxes	10	175,513	-
Unrealized gain on marketable securities		-	(55,190)
Changes in operating assets and liabilities
Decrease in marketable securities		-	173,206
Decrease / (increase) in trade accounts receivable		640,400	(668,184)
Increase in inventories		(5,871,646)	(93,644)
(Increase) / decrease in prepaid expenses and other assets		(4,847,423)	249,582
Tax benefit realized from share based compensation		(904,399)	-
Increase /(decrease) in liabilities		2,909,399	(2,966,193)
Net cash used in operating activities		(4,805,025)	(2,892,292)
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisition of oil and gas properties	6	(27,412,450)	(12,016,813)
Acquisition of other fixed assets	7	(640,917)	(445,607)
Acquisition of intangible assets		(4,665)	(58,688)
Increase in construction in progress	8	(3,347,529)	-
Increase in restricted cash		(147,243)	(95,000)
Net cash used in investing activities		(31,552,804)	(12,616,108)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock		-	57,410,892
Proceeds from exercise of common stock options and warrants	11	5,758,502	2,401,750
Tax benefit realized from share based compensation		904,399	-
Net cash provided by financing activities		6,662,901	59,812,642
NET CHANGE IN CASH AND CASH EQUIVALENTS		(29,694,928)	44,304,242
CASH AND CASH EQUIVALENTS at beginning of period		51,141,732	9,989,632
CASH AND CASH EQUIVALENTS at end of period		$ 21,446,804	$ 54,293,874

See notes to the unaudited consolidated financial statements.

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BMB MUNAI, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF BUSINESS

BMB Munai, Inc. (the “Company” or “BMB Munai”) was incorporated in Utah in July 1981. The Company later changed its domicile to Delaware on February 7, 1994. Prior to November 26, 2003, the Company existed under the name InterUnion Financial Corporation (“InterUnion”). The Company changed its domicile from Delaware to Nevada in December 2004.

On November 26, 2003, InterUnion executed an Agreement and Plan of Merger (the “Agreement”) with BMB Holding, Inc (“BMB”), a private Delaware corporation, formed for the purpose of acquiring and developing oil and gas fields in the Republic of Kazakhstan. As a result of the merger, the shareholders of BMB obtained control of the Company. BMB 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, Inc.

The Company’s consolidated financial statements presented are a continuation of BMB, 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. From January 1, 2006 the Company started to generate significant revenues and is no longer in the development stage.

If we are unable to drill and complete a sufficient number of wells in each of our identified structures to support our claim of commercially producible reserves before the end of the term of our exploration contract, as extended, we may not be granted a commercial production contract for each of our structures.

In order to obtain a commercial production license for the structures contained within our licensed territory, we must engage in sufficient exploration, drilling and testing activities to gather adequate data to support our claims that we have discovered commercial producible reserves within our contract territory. These activities must be completed during the term of our exploration license. It is generally accepted that one exploratory and two appraisal wells are sufficient to determine whether a license holder has discovered a commercially producible reserve, although in some instances, license holders are able to establish commercially producible reserves with fewer than three wells.

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As of December 31, 2006, we have spent approximately $77.5 million in exploration and development activities to drill nine wells, with an additional well underway. As of December 31, 2006 we had $21.4 million in cash and cash equivalents to fund our operations, including drilling and exploration activities. At current production rates, we expect that we will need to seek additional equity or debt financing if we are to drill the additional wells we need to support our claims of commercially producible reserves in each of our identified structures by the end of the term of our exploration contract. At this time, we have no firm commitments from any party to provide us additional financing, and there is no guarantee that we will be able to secure additional funding on acceptable terms, or at all.

2. SIGNIFICANT ACCOUNTING POLICIES

The consolidated financial information included herein is unaudited, except for the balance sheet as of March 31, 2006, which is derived from the Company’s audited consolidated financial statements for the year ended March 31, 2006. However, such information includes all adjustments (consisting solely of normal recurring adjustments), which are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods. The consolidated results of operations for the interim period are not necessarily indicative of the consolidated results to be expected for an entire year.

Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted in this Form 10-Q Report pursuant to certain rules and regulations of the Securities and Exchange Commission. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes included in our March 31, 2006 Form 10-KSB Report.

The accounting principles applied are consistent with those as set out in the Company’s annual Consolidated Financial Statements for the year ended March 31, 2006.

Basis of consolidation

The Company’s consolidated financial statements present the consolidated results of BMB Munai, Inc., and its wholly owned subsidiary, Emir Oil LLP (hereinafter collectively referred to as the “Company”). All significant inter-company balances and transactions have been eliminated from the Consolidated Financial Statements.

Use of estimates

The preparation of Consolidated Financial Statements in conformity with US GAAP requires management to make estimates and assumptions that affect certain reported amounts of assets and liabilities and the

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disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements and revenues and expenses during the reporting period. Accordingly, actual results could differ from those estimates and affect the results reported in these Consolidated Financial Statements.

Licenses and contracts

Emir Oil LLP is the operator of the Aksaz, Dolinnoe and Emir oil and gas fields in western Kazakhstan (the “ADE Block”, the “ADE Fields”). The Government of the Republic of Kazakhstan (the “Government”) initially issued the license to Zhanaozen Repair and Mechanical Plant on April 30, 1999. 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 December 7, 2004 the Government assigned to Emir Oil LLP exclusive right to explore the additional territory during the remaining term of the License. To move from the exploration and development stage to the commercial production stage, the Company must apply for and be granted a commercial production contract. The Company has an exclusive right to negotiate for commercial production and the Government is obligated to conduct these negotiations under the Law of Petroleum in Kazakhstan. If the Company does not move from the exploration and development 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, which may be extended for an additional two-year term.

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 U.S. dollars at the rates of exchange prevailing at the balance sheet dates. Any gains or losses arising from a change in exchange rates subsequent to the date of the transaction are included as an exchange gain or loss in the Consolidated Statements of Operations.

Share-based compensation

The Company accounts for options granted to non-employees at their fair value in accordance with SFAS No. 123R, Share Based Payment and EITF Abstracts Issue 96-18, Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services. Under SFAS No. 123R, share-based compensation is determined as the fair value of the equity instruments

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issued. The measurement date for these issuances is the earlier of the date at which a commitment for performance by the recipient to earn the equity instruments is reached or the date at which the recipient’s performance is complete. Stock options granted to the “selling agents” in the private equity placement transactions have been offset to the proceeds as a cost of capital. Stock options and stocks granted to other non-employees are recognized in the Consolidated Statements of Operations.

The Company has a stock option plan as described in Note 11. Compensation expense for options and stocks 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.

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. However, management believes that over the life of the project, transportation options will improve as additional pipelines and rail-related infrastructure is built that will increase transportation capacity to the world markets.

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, collectibility is reasonably assured, delivery of oil has occurred or when ownership title transferred. Produced but unsold products are recorded as inventory until sold.

Income taxes

The Company accounts for income taxes using the liability method. Under the liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under the liability method, the effect on previously recorded deferred tax assets and liabilities resulting from a change in tax rates is recognized in earnings in the period in which the change is enacted.

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Cash and cash equivalents

The Company considers all demand deposits and money market accounts 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.

Trade accounts receivable and prepaid expenses

Accounts receivable and prepaid expenses are stated at their net realizable values after deducting provisions for uncollectable amounts. Such provisions reflect either specific cases or estimates based on evidence of collectability. The fair value of accounts receivable and prepaid expense accounts approximates their carrying amounts due to their short-term maturity.

Inventories

Inventories of equipment for development activities, tangible drilling materials required for drilling operations, spare parts, diesel fuel, and various materials for use in oil field operations are recorded at the lower of cost and net realizable value. Under the full cost method, inventory is transferred to oil and gas properties when used in exploration, drilling and development operations in oilfields.

Inventories of crude oil are recorded at the lower of cost or net realizable value. Cost comprises direct materials and, where applicable, direct labor costs and overhead, which has been incurred in bringing the inventories to their present location and condition. Cost is calculated using the weighted average method. Net realizable value represents the estimated selling price less all estimated costs to completion and costs to be incurred in marketing, selling and distribution.

The Company periodically assesses its inventories for obsolete or slow moving stock and records an appropriate provision, if there is any.

Oil and gas properties

The Company follows the full cost method of accounting for its costs of acquisition, exploration and development of oil and gas properties.

Under full cost accounting rules, the net capitalized costs of evaluated oil and gas properties shall not exceed an amount equal to the present value of future net cash flows from estimated production of proved oil and gas reserves, based on current economic and operating conditions, including the use of oil and gas prices as of the end of the period.

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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 ADE Block, have been capitalized as part of the oil and gas properties.

The Company’s oil and gas properties primarily include the value of the license and other capitalized costs.

Depletion of producing properties is computed using the unit-of-production method based on estimated proved reserves.

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. 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:

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Buildings and improvements	7-10 years
Machinery and equipment	6-10 years
Vehicles	3-5 years
Office equipment	3-5 years
Other	2-7 years

Maintenance and repairs are charged to expense as incurred. Renewals and betterments are capitalized.

Other fixed assets of the Company are evaluated 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.

Intangible assets

Intangible assets include accounting and other software. Amortization of intangible assets is calculated using straight-line method upon estimated useful life ranging from 3 to 4 years.

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.

Reclassifications

Certain reclassifications have been made in the financial statements for the nine months ended December 31, 2006 to conform to the March 31, 2006 presentation. The reclassifications had no effect on net income.

In Consolidated Balance Sheet as of March 31, 2006 marketable securities in the amount of $33,095,609 were reclassified to cash equivalents. The reclassification had no effect on net income.

Recent accounting pronouncements

In September 2006, the FASB issued Statement No. 157, “Fair Value Measurements” This Statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements, the Board having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. This Statement is effective for financial statements issued for the fiscal years beginning after November 15, 2007. Management does not anticipate this Statement will impact the Company’s consolidated financial position or consolidated results of operations and cash flows.

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In September 2006, the FASB issued Statement No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”, an amendment of FASB Statements No. 87, 88, 106, and 132(R). This Statement improves financial reporting by requiring an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization. This Statement is effective for employers with publicly traded equity securities is required to initially recognize the funded status of a defined benefit postretirement plan and to provide the required disclosures as of the end of the fiscal year ending after December 15, 2006. Management does not anticipate this Statement will impact the Company’s consolidated financial position or consolidated results of operations and cash flows.

In September 2006, the SEC staff issued Staff Accounting Bulletin (SAB) Topic 1N, “Financial Statements - Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” ( SAB 108). The SEC staff is providing guidance on how prior year misstatements should be taken into consideration when quantifying misstatements in current year financial statements for purposes of determining whether the current year’s financial statements are materially misstated and should be restated. SAB 108 is effective for fiscal years ending after November 15, 2006. The company does not believe SAB 108 will have a material impact on its results of operations, financial condition and cash flows.

In September 2006, the EITF issued EITF Abstracts Issue No. 06-3 (EITF 06-3). The EITF is providing guidance on how taxes collected from customers and remitted to Governmental Authorities should be presented in the income statements. EITF 06-3 is effective for interim and annual periods beginning after December 15, 2006. The company does not anticipate EITF 06-3 will have a material impact on its results of operations, financial condition and cash flows.

In June 2006, the FASB issued FASB Interpretation No. 48 “Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109”. This interpretation clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB No. 109 “Accounting for Income taxes”. This interpretation is effective for the fiscal years beginning after December 15, 2006. Management does not anticipate this Statement will impact the Company’s consolidated financial position or consolidated results of operations and cash flows.

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3. CASH AND CASH EQUIVALENTS

As of December 31, 2006 and March 31, 2006 cash and cash equivalents included:

	December 31, 2006	March 31, 2006
US Dollars	$ 21,221,951	$ 50,959,064
Foreign currency	224,853	182,668
	$ 21,446,804	$ 51,141,732

As of December 31, 2006 cash and cash equivalents included the amount of $20,280,260 placed in money market funds having a 30 day simple yield of 5.00%.

As of March 31, 2006 cash and cash equivalents included the amount of $11,100,262 placed in money market funds having a 30 day simple yield of 4.28%.

As of December 31, 2006 and March 31, 2006 cash and cash equivalents included the amounts of $293,319 and $324,621 presented by letters of credit opened for the purpose of purchasing production equipment.

4. INVENTORIES

Inventories as of December 31, 2006 and March 31, 2006 were as follows:

	December 31, 2006	March 31, 2006
Construction material	$ 8,790,318	$ 3,069,144
Spare parts	36,430	13,486
Crude oil produced	2,386	8,840
Other	282,459	148,477
	$ 9,111,593	$ 3,239,947

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5. OTHER PREPAID EXPENSES AND OTHER ASSETS, NET

Other prepaid expenses and other assets, net, as of December 31, 2006 and March 31, 2006 were as follows:

	December 31, 2006	March 31, 2006
Advances for services	$ 2,099,829	$ 452,839
Other	110,906	309,533
Reserves against uncollectible advances and prepayments	(211,475)	(195,452)
	$ 1,999,260	$566,920

6. OIL AND GAS PROPERTIES, FULL COST METHOD, NET

Oil and gas properties, full cost method, net, as of December 31, 2006 and March 31, 2006 were as follows:

	December 31, 2006	March 31, 2006
Cost of drilling wells	$ 29,584,916	$ 14,895,604
Subsoil use rights	20,788,119	20,788,119
Professional services received in exploration and development activities	14,609,266	10,600,327
Material and fuel used in exploration and development activities	12,472,979	6,840,976
Deferred tax	7,219,219	6,405,285
Geological and geophysical	2,475,763	1,432,418
Infrastructure development costs	1,535,004	1,412,999
Other capitalized costs	8,799,208	5,704,210
Accumulated depletion	(2,387,671)	(1,396,641)
	$ 95,096,803	$ 66,683,297

In nontaxable business combination, deferred taxes were provided for the basis difference related to oil and gas properties. Since goodwill was not recognized in subsidiary’s acquisition involving oil and gas properties, recognition of a deferred tax liability increased the financial reporting basis of the oil and gas properties.

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7. OTHER FIXED ASSETS, NET

	Construction	Machinery and equipment	Vehicles	Office equipment	Other	Total
Cost
at March 31, 2006	$ 149,272	$ 372,427	$ 432,121	$ 206,890	$ 148,645	$ 1,309,355
Additions	96,604	203,546	216,151	47,903	76,713	640,917
Disposals	-	-	-	(3,498)	(15,248)	(18,746)
at December 31, 2006	245,876	575,973	648,272	251,295	210,110	1,931,526
Accumulated depreciation
at March 31, 2006	24,922	26,187	152,719	51,650	32,926	288,404
Charge for the period	16,778	21,400	104,308	48,375	21,617	212,478
Disposals	-	-	-	(788)	(3,005)	(3,793)
at December 31, 2006	41,700	47,587	257,027	99,237	51,538	497,089
Net book value at March 31, 2006	$ 124,350	$ 346,240	$ 279,402	$ 155,240	$ 115,719	$ 1,020,951
Net book value at December 31, 2006	$ 204,176	$ 528,386	$ 391,245	$ 152,058	$ 158,572	$ 1,434,437

In accordance with SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, depreciation related to support equipment and facilities used in exploration and development activities in the amount of $110,434 was capitalized to oil and gas properties for the nine month ended December 31, 2006.

8. CONSTRUCTION IN PROGRESS

On April 13, 2006 the Company entered into Agreement on Joint Business (the “Agreement”) with Ecotechnic Chemicals AG incorporated in Switzerland (the “Ecotechnic”) for construction of facility on utilization of associated gas on Company’s fields (the “Facility”). After completion of the Facility construction the Company and Ecotechnic will sign the agreement on formation of joint venture company, which will operate the Facility.

In accordance with terms of the Agreement the Company has made payments of USD $3,347,529 for development of project documentation, purchase of equipment, transportation and customs and construction of gas pipe-line.

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9. LONG TERM VAT RECOVERABLE 

As of December 31, 2006 and March 31, 2006 the Company had long term VAT recoverable in amount of $3,385,429 and $1,335,971, respectively. The management believes that this asset will not be realized in the current year because to return funds or offset this tax with other taxes the tax examination should be performed by tax authorities.

10. INCOME TAXES

The income tax charge in the Consolidated Statements of Operations comprised:

	Three months ended December 31, 2006	Three months ended December 31, 2005	Nine months ended December 31, 2006	Nine months ended December 31, 2005
Current tax expense	$           -	$           -	$           -	$           -
Deferred tax expense	-	-	175,513	-
	$           -	$           -	$ 175,513	$             -

Relationship between tax expenses and accounting income for the three and nine months ended December 31, 2006 and 2005 is explained as follows:

	Three months ended December 31, 2006	Three months ended December 31, 2005	Nine months ended December 31, 2006	Nine months ended December 31, 2005
Loss before income taxes	$ (90,861)	$ (52,942)	$(2,039,757)	$(4,798,004)
Expected tax provision	(27,258)	(15,883)	(611,927)	(1,439,401)
Add tax effect of:
Permanent differences	27,258	15,883	787,440	1,439,401
	$           -	$           -	$ 175,513	$           -

Deferred taxes reflect the estimated tax effect of temporary differences between assets and liabilities for financial reporting purposes and those measured by tax laws and regulations. The components of deferred tax assets and deferred tax liabilities are as follows:

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	December 31, 2006	March 31, 2006
Deferred tax assets:
Stock based compensation	$904,399	$           -
Tax losses carried forward	2,960,306	593,122
	3,864,705	593,122
Deferred tax liabilities:
Oil and gas properties	9,935,723	6,636,522
Accrued interest income	799,229	361,885
	10,734,952	6,998,407
Valuation allowance	(400,283)	-
Net deferred tax liability	$ 7,270,530	$ 6,405,285

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

	December 31, 2006		March 31, 2006
	US tax jurisdiction	Kazakstan tax jurisdiction	US tax jurisdiction	Kazakstan tax jurisdiction
Deferred tax assets:
Stock based compensation	$ 904,399	$           -	$           -	$           -
Tax losses carried forward	2,950,513	9,793	583,329	9,793
	3,854,912	9,793	583,329	9,793
Deferred tax liabilities:
Oil and gas properties	7,219,219	2,716,504	6,369,899	266,623
Accrued interest income	799,229	-	361,885	-
	8,018,448	2,716,504	6,731,784	266,623
Valuation allowance	(400,283)	-	-	-
Net deferred tax liability	$ 4,563,819	$ 2,706,711	$ 6,148,455	$ 256,830

Deferred tax liability from oil and gas properties for US tax jurisdiction, also described in Note 6, resulted from temporary difference related to oil and gas basis from non-taxable business combination.

11. SHARE AND ADDITIONAL PAID IN CAPITAL

Common and preferred stock as of December 31, 2006 and March 31, 2006 were as follows:

	December 31, 2006	March 31, 2006
Preferred stock, $0.001 par value
Authorized	20,000,000	20,000,000
Issued and outstanding	-	-
Common stock, $0.001 par value
Authorized	500,000,000	100,000,000
Issued and outstanding	43,700,652	42,223,685

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On June 21, 2006 the Company filed Certificate of Amendment to BMB Munai, Inc. Articles of Incorporation with the Nevada Secretary of State to increase the Company’s authorized common stock from 100,000,000 to 500,000,000 shares. Authorized preferred stock remained unchanged.

Share-Based Compensation

During the fiscal year ended March 31, 2005 the shareholders of the Company approved an incentive stock option plan (the “Plan”) under which directors, officers and key personnel may be granted options to purchase common shares of the Company, as well as other stock based awards. 5,000,000 common shares were reserved for issuance under the Plan. The Board determines the terms of options and other awards made under the Plan. Under the terms of the Plan, no incentive stock options shall be granted with an exercise price at a discount to the market.

Common Stock

On June 20, 2006 the Company granted common stock to officers and directors and certain employees and consultants of the Company under the Plan. The total number of restricted common shares granted was 495,000. The restricted stock grants were valued at $7.00 per share. All of the restricted stock grants vested immediately upon grant. Compensation expense in the amount of $3,465,000 was recognized in the Consolidated Statements of Operations and Consolidated Balance Sheet.

On July 18, 2005, the Company granted 90,000 restricted common shares to three Company employees. Each employee’s stock grants vest in three equal tranches of 10,000 shares on the first, second and third anniversaries of their employment with the Company. We record the fluctuations in the fair value of certain unvested stock grants as a deferred compensation asset (reported as a reduction of shareholders’ equity on the balance sheet). This asset is amortized upon vesting of related stock grants as non-cash compensation expense. Compensation expense for vested stock grants in the amount of $50,600 has been recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the quarter ended December 31, 2006.

As of December 31, 2006 there was $190,000 of total unrecognized compensation expense related to non-vested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 0.6 years.

Stock Options

On June 20, 2006 the Company granted stock options to directors of the Company under the Plan. The total number of options was 200,000. The options are exercisable at a price of $7.00 per share. The options will expire three years from the grant date. All of the options vested immediately upon grant. Compensation

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expense for options granted is determined based on their fair values at the time of grant, the cost of which in the amount of $545,346 was recognized in the Consolidated Statements of Operations and Consolidated Balance Sheet.

On November 12, 2004 the Company granted stock options to its former corporate secretary for past services rendered. These options grant the employee the right to purchase up to 60,000 shares of the Company’s common stock at an exercise price of $4.00 per share. The options vested immediately and expire five years from the date of grant. In April 2006, options to acquire 7,200 common shares were exercised.

Stock options outstanding and exercisable as of December 31, 2006 were as follows:

	Number of Shares	Weighted Average Exercise Price
As of March 31, 2006	980,783	$ 4.97
Granted	200,000	7.00
Exercised	(7,200)	4.00
Expired	-	-
As of December 31, 2006	1,173,583	$ 5.33

Additional information regarding outstanding options as of December 31, 2006 was 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
$ 4.00 – $ 7.40	1,173,583	$ 5.33	4.15	1,173,583	$ 5.33

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

	Nine months ended December 31, 2006	Year ended March 31, 2006
Risk-free interest rate	5.23%	4.01% - 4.51%
Expected option life	2 years	2 – 4 year
Expected volatility in the price of the Company’s common shares	65%	65% - 74%
Expected dividends	0%	0%
Weighted average fair value of options and warrants granted
during the period	$2.73	$2.01 - $3.92

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Warrants

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

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

Warrants outstanding and exercisable as of December 31, 2006 were as follows:

	Number of Shares	Weighted Average Exercise Price
As of March 31, 2006	1,109,624	$ 5.63
Granted	-	-
Exercised	(966,767)	5.95
Expired	-	-
As of December 31, 2006	142,857	$ 3.50

Additional information regarding warrants outstanding as of December 31, 2006 is as follows:

Warrants Outstanding				Warrants Exercisable
Range of Exercise Price	Warrants	Weighted Average Exercise Price	Weighted Average Contractual Life (years)	Warrants	Weighted Average Exercise Price
$ 3.50	142,857	$3.50	5.01	142,857	$3.50

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12. REVENUES

	Three months ended December 31, 2006	Three months ended December 31, 2005	Nine months ended December 31, 2006	Nine months ended December 31, 2005
Export sales	$ 2,214,382	$           -	$ 8,577,326	$           -
Domestic sales	-	2,058,792	-	4,106,765
	$ 2,214,382	$ 2,058,792	$ 8,577,326	$ 4,106,765

13. 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 three months ended December 31, 2006 and 2005, totaled to $41,347 and $109,913, respectively. Also the Company had accounts payable to Term Oil LLC in amount of $57,232 and $76,004 as of December 31, 2006 and March 31, 2006, respectively. One of our shareholders is an owner of Term Oil LLC.

14. 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 in total amount of $5,994,200 in relation to ADE Block and $5,350,680 in relation to the Extended Territory. When the Company applies for and is granted commercial production rights for the ADE Block and Extended Territory, the Company will be required to begin repaying these historical investments to the Government of the Republic of Kazakhstan. The terms of repayment will be negotiated at the time the Company applies for commercial production rights.

Capital Commitments

Under the terms of its subsurface exploration contract, Emir Oil LLP is required to spend a total of $32 million in exploration and development activities on the ADE Block. To retain its rights under the contract, the Company must spend a minimum of $4.5 million in 2007. The Company must also comply with the terms of the work program associated with the contract, which includes the drilling of at least nine additional new wells by July 9, 2007. Under the terms of its contract, the Company can apply for a two-year extension of time to complete its work program. The Company recently applied to extend the subsurface exploration contract to July 2009 and is awaiting approval of the extension. 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.

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Litigation

In December 2003, Brian Savage, Thomas Sinclair and Sokol Holdings, Inc., filed a lawsuit in Florida naming the Company and some of its former officers and directors as defendants. The plaintiffs in the case alleged breach of contract, unjust enrichment, breach of fiduciary duty, conversion and violation of a Florida trade secret statute in connection with a business plan for the development of the Aksaz, Dolinnoe and Emir oil and gas fields owned by Emir Oil LLP. The plaintiffs seek unspecified compensatory and exemplary damages. The parties have mutually agreed to dismiss this lawsuit without prejudice.

In April 2005, Sokol Holdings, Inc., filed a complaint in United States District Court, Southern District of New York alleging that the Company, and others, wrongfully induced Mr. Tolmakov, Director of Emir Oil, to breach a contract under which Mr. Tolmakov had agreed to sell to Sokol 70% of his 90% interest in Emir Oil LLP. Sokol Holdings, Inc. seeks damages in an unspecified amount exceeding $75,000 to be determined at trial, punitive damages, specific performance in the form of an order compelling BMB to relinquish its interest in Emir and the underlying interest in the ADE fields to Sokol Holdings, Inc. and such other relief as the court finds just and reasonable.

In October 2005, Sokol Holdings amended its complaint in New York to add Brian Savage and Thomas Sinclair as plaintiffs and adding Credifinance Capital, Inc., and Credifinance Securities, Ltd., (collectively “Credifinance”) as defendants in the matter. The amended complaint alleges tortious interference with contract, specific performance, breach of contract, unjust enrichment, breach of fiduciary duty, conversion, misappropriation of trade secrets, tortuous interference with fiduciary duty and aiding and abetting breach of fiduciary duty in connection with a business plan for the development of the Aksaz, Dolinnoe and Emir oil and gas fields owned by Emir Oil, LLP. The plaintiffs seek damages in an amount to be determined at trial, punitive damages, specific performance and such other relief as the Court finds just and reasonable.

The Company is confident that the matters shall be resolved in the Company’s favor. The Company has retained legal counsel to protect its interests. In the opinion of the Company’s management and legal counsel, the resolution of those lawsuits will not have a material adverse effect on Company’s financial condition, results of operations or cash flows.

Other than the foregoing, to the knowledge of management, there is no other material litigation or governmental agency proceeding pending or threatened against the Company or management.

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15. FINANCIAL INSTRUMENTS

As of December 31, 2006 and March 31, 2006 cash and cash equivalents included marketable securities of $0 and $33,095,609, respectively, consisted of discount bonds issued by General Electric Corporation and discount notes issued by Fannie Mae.

As of December 31, 2006 and March 31, 2006 cash and cash equivalents included deposits in Kazakhstan banks in the amount $1,024,804 and $3,881,255, respectively and deposits in U.S. banks in the amount of $20,422,000 and $14,164,868, 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 December 31, 2006 and March 31, 2006. Our deposits in the U.S. banks are also in non-FDIC insured accounts which means they too are not insured to the $100,000 FDIC insurance limit. To mitigate this risk, we have placed all of our U.S. deposits in a money market account that invests in U.S. government backed securities. As of December 31, 2006 and March 31, 2006 the Company made advance payments to Kazakhstan companies and government bodies in the amount $7,396,591 and $2,473,985, respectively. As of December 31, 2006 and March 31, 2006 restricted cash reflected in the long-term assets consisted of $303,697 and $156,454, respectively, deposited in a Kazakhstan bank and restricted to meet possible environmental obligations according to the regulations of Kazakhstan. Furthermore, the primary asset of the Company is Emir Oil LLP; an entity formed under the laws of the Republic Kazakhstan.

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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 amended 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-KSB of the Company, as amended, for the year ended March 31, 2006.

Statements in this discussion may be forward-looking. These forward-looking statements involve risks and uncertainties, including those discussed below, which could cause actual results to differ from those expressed.

Forward Looking Statements

Certain of the statements contained in all parts of this document including, but not limited to, those relating to our drilling plans, future expenses, changes in wells operated and reserves, future growth and expansion, future exploration, future seismic data, expansion of operations, our ability to generate new prospects, our ability to obtain a production license, review of outside generated prospects and acquisitions, additional reserves and reserve increases, managing our asset base, expansion and improvement of capabilities, integration of new technology into operations, credit facilities, new prospects and drilling locations, future capital expenditures and working capital, sufficiency of future working capital, borrowings and capital resources and liquidity, projected cash flows from operations, future commodity price environment, expectations of timing, the outcome of legal proceedings, satisfaction of contingencies, the impact of any change in accounting policies on our consolidated financial statements, the number, timing or results of any wells, the plans for timing, interpretation and results of new or existing seismic surveys or seismic data, future production or reserves, future acquisitions of leases, lease options or other land rights, management’s assessment of internal control over financial reporting, financial results, opportunities, growth, business plans and strategy and other statements that are not historical facts contained in this report are forward-looking statements. When used in this document, words like “expect,” “project,” “estimate,” “believe,” “anticipate,” “intend,” “budget,” “plan,” “forecast,” “predict,” “may,” “should,” “could,” “will” and similar expressions are also intended to identify forward-looking statements. Such statements involve risks and uncertainties, including, but not limited to, market factors, market prices (including regional basis differentials) of crude oil and natural gas, results of future drilling and marketing activity, future production and costs and other factors detailed herein and in our other Securities and Exchange Commission filings. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. These forward-looking statements speak only as of their dates and should not be unduly relied upon. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.

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Overview

BMB Munai, Inc. is an independent oil and natural gas company engaged in the exploration, development, acquisition and production of crude oil and natural gas properties in the Republic of Kazakhstan (sometimes also referred to herein as the “ROK” or “Kazakhstan”). We hold a contract that allows us to explore and develop approximately 460 square kilometers in western Kazakhstan. Our contract grants us the right to explore and develop the Aksaz, Dolinnoe and Emir oil and gas fields, referred to herein as “the ADE Block” and an area adjacent to the ADE Block referred to herein as “the Extended Territory”, which includes the Kariman, Borly and Yessen oil and gas fields. The ADE Block and Extended Territory are collectively referred to herein as “our properties.”

Exploration Stage Activities

Under the statutory scheme in the Republic of Kazakhstan prospective oil fields are developed in two stages. The first stage is an exploration and appraisal stage during which a private contractor, such as BMB, is given a license to explore for oil and gas on a territory for a set term of years. During this stage the primary focus is on the search for a commercial discovery, i.e., a discovery of a sufficient quantity of oil and gas to make it commercially feasible to pursue execution of, or transition to, a production contract with the government.

In order to be assured that adequate exploration activities are undertaken by the contractor, the Ministry of Energy and Mineral Resources, (“MEMR”) establishes an annual mandatory work program to be accomplished in each year of an exploration contract. The minimum work program is comprised of two parts. The first part sets a minimum dollar amount to be invested in exploration activities on the contract territory that may include geophysical studies, construction of field infrastructure or drilling activities. The second factor is to establish a minimum number of wells to be drilled in the contract territory during the term of an exploration contract. Failure to complete the minimum work program during the term of an exploration contract would preclude a contractor from entitlement to a longer-term production contract, regardless the success of the contractor in proving commercial reserves during the partial fulfillment of the minimum work program. Therefore, completion of the exploration contract’s minimum work program is essential to the success of any oil company working in Kazakhstan.

The contract we hold follows the above format. Our contract was granted for an initial term that expired in 2005. The contract also provided for two extensions of two years each. The current contract extension will run through July 2007. Following this extension, we have the right to request a second extension to run through July 2009. Application for this second extension has been submitted to the MEMR and we are awaiting approval of the request for the extension.

The contract sets the minimum dollar amount to be expended by the Company through July 2007 as follows:

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Amount of Expenditure	Prior to July 2005	July 2005 to July 2006	July 2006 to July 2007	Total
Mandated by Contract	$21,500,000	$6,000,000	$4,500,000	$32,000,000
Actually Made	$38,400,000	$12,700,000	$26,370,000*	$77,470,000

* Investment as of December 31, 2006

Under the rules of the MEMR there is an option for our expenditures above the minimum requirements in one period to be carried over to meet minimum obligations in future periods. As the above chart shows we have exceeded the minimum expenditure requirement in each period of the contract. We have applied for a second extension of our exploration contract. We anticipate that if this extension is granted, the MEMR will require an additional investment consistent with the amount imposed on the extension covering the 2006-2007 period. However, we expect our scheduled drilling activities to exceed any new amounts added to our minimum work program.

As noted above, from July 2006 through December 31, 2006, we invested approximately $26.4 million in the exploration and development of our properties. During the quarter ended December 31, 2006, we incurred and capitalized expenses of approximately $10.5 million attributable to the drilling activities at the Kariman-2, Dolinnoe-6 and Emir-6 wells during the quarter, as discussed in more detail below. We also incurred and capitalized approximately $1.1 million in well workover expenses and almost $2.3 million in other infrastructure development. Such capitalized costs are recorded as oil and gas properties on our balance sheet as at December 31, 2006. See Note 7 to Consolidated Financial Statements.

The second aspect of the mandatory minimum work program is the requirement that we drill a sufficient number of wells on each structure within our contract territory to support our claim to the government that we have made a commercial discovery within the contract territory, before we are permitted to transition to commercial production. Typically, one exploratory well and two appraisal wells are considered sufficient to support such a claim. The number of wells to be drilled is generally determined by the number of structures identified by the seismic studies done on a territory. The 3D seismic studies of our contract territory, as extended, have identified six potential structures. Therefore, we anticipate the need to drill up to 18 wells during the exploration phase of our contract as reflected on the top half of the following chart:

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Structures	Aksaz	Dolinnoe	Emir	Kariman	Borly	Yessen
Exploratory Wells	1	1	1	1	1	1
Appraisal Wells	2	2	2	2	2	2
Existing Wells	2	4	1	2	0	0
Wells in Progress	0	0	1	0	0	0
Remaining Wells to Drill by 2009	1	0	1	1	3	3

The bottom half of the above chart shows our current progress on drilling of exploratory and appraisal wells, the second aspect of our mandatory minimum work program. As the chart shows, for purposes of meeting the minimum work program requirements, we have nine wells completed and one well currently in progress. Of the four wells in the Dolinnoe structure, only three will count toward our total minimum number of wells.

To date we have been conservative in our approach to exploration. It has been our practice to drill our first few wells serially. Our first well was the Dolinnoe-2 well drilled in 2004. This was followed by the Dolinnoe-3 well, and then the Aksaz-4 and Kariman-1 wells. We have verified the presence of oil and gas in all our wells thus far. And we have expended substantial time and money to study our wells very closely.

It is important to remember that the purpose of the exploration phase is to study the geology and geophysical characteristics of each field and individual wells, with a view to qualifying for a longer-term production contract. Once drilling of a well is completed, our emphasis focuses on an extended period of testing a well’s production characteristics and capacities to determine the best method for producing oil from a well and to gain insight into the further development of the entire field. During this stage of exploration, oil production is subject to wide fluctuations caused by varying pressures commonly experienced by new wells and by significant periods of well closure to accommodate various mandatory testing. Maximizing oil production only becomes the central focus during the post-exploration phase when exploiting the commercial discovery commences under a production contract.

In addition to the wells currently in progress, we anticipate the need to complete up to nine additional wells by the end of the term of our exploration contract, as extended, in order to qualify for a commercial production license on each of our structures. This will require that we continue to accelerate our drilling activities during the next two and a half years.

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Drilling Operations

During the fourth fiscal quarter of last year we took steps to secure drilling rigs that would allow us to accelerate our drilling activities over previous years. In January 2006 we signed one-year contracts with Great Wall, a Chinese drilling company, and Oil and Gas Exploration Krakow, a Polish drilling company, to furnish heavy rigs of sufficient size to drill wells to the depth of 4,000 meters, which is generally our target depth in Triassic period carbonate structures. We also signed a turnkey contract with KandyagashBurService, LLP, a Kazakhstani drilling company, for drilling of new wells on the Emir oil field. In addition, we hired Great Wall to provide the lighter rigs we use for workover and testing activities on completed wells.

By the summer of 2006 all of our contracted rigs had arrived on-site and we were able to expand our drilling activities on new wells. As discussed below, we currently have three new wells in various stages of progress. We anticipate that our testing activities will be completed near our current fiscal year end and we should be able to realize stable production from these wells commencing in the spring of 2007.

Drilling of the Kariman-2 well was finished on December 25, 2006 by Oil and Gas Exploration Crakow. Drilling operations were concluded at a depth of 3,535 meters, upon reaching the end of the targeted Middle Triassic horizons. The well was spudded on August 15^th, 2006 and is the first new well we have drilled on the Kariman oil field.

Well completion activities were preformed at the Kariman-2 well utilizing a drilling rig specifically employed for workover and completion operations. Initial perforation of casing in the production zone has been made and resulted in oil inflow. Immediately following completion activities we have embarked on an extensive period of production testing and evaluation to study the well characteristics and formulate a model of the long-term stable production potential of the well.

Following completion of drilling at the Kariman-2 well, Oil and Gas Exploration Crakow relocated the rig to the Kariman-1 well where it will be used to clean the wellbore, case the well and run liner. We will then perforate the Upper Triassic formation penetrated during drill-in completed during the summer of 2006 and resume test production.

In August 2006, Great Wall LLP spudded the Dolinnoe-6 well, our third new well drilled on the Dolinnoe field. Drilling continued beyond the initial target depth to drill through the full Middle Triassic layer, which extended beyond earlier estimates made by the Company. This extended the drilling time beyond our initial drilling schedule. The well, which was completed on January 24, 2006, was drilled to a total depth of 3,883 meters.

Well completion activities have been subcontracted to Burgylau LLP, and we are in the process of moving the completion rig to this Dolinnoe-6 well site. We expect well completion to conclude by mid-February. The well will then be tested for a period of up to three months, during which time some test oil production should be realized. However, stable production estimates will not be available until conclusion of the testing period.

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KandyagashBurService, LLP, a Kazakhstani drilling company, spudded the Emir-6 well, our first new well on Emir field, on October 2, 2006. We signed a turnkey contract for drilling of Emir-6 well. Target depth of the well is 3,100 meters. Currently drilling on the Emir-6 well is underway.

Well Performance

Following is a brief description of the production status and performance of each of our seven completed wells.

Aksaz-1

This well is currently under workover and is not producing. Prior to workover, four producing intervals were tested. The single interval test production rates in Aksaz-1 using a 10 mm diameter choke was 140 bpd.

Aksaz-4

Drilling of this well was completed in August 2005. Two producing intervals have been tested. Current production rates from single interval testing using a 6 mm diameter choke ranges from 50 to 125 bpd.

Dolinnoe-1

Currently this well is under workover and is not producing. Prior to workover production rates from single interval testing using a 6 mm diameter choke ranges 60 to 100 bpd.

Dolinnoe-2

This well is also producing. Current production rates from single interval testing using an 8 mm diameter choke ranges from 60 to 100 bpd.

Dolinnoe-3

This well was initially completed to a depth of 3,800 meters in September 2005. During initial testing, we were able to perforate only 17 of 24 meters of the producing interval because of intensive oil and gas shows. Subsequent, perforation of the remaining 7 meters of the interval was disrupted when tubing was impacted by the heavy drilling mud components, and the blowout preventer was damaged, which required us to kill the well. Although we were able to restore limited oil production from the well, the production was substantially lower than the well’s initial test production performance. We have conducted numerous tests during the past nine

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months in an effort to increase daily production rates to levels consistent with management expectations. In August 2006 we completed the acid treatment of the Dolinnoe-3 well. During the ten days following completion of the acid treatment the well produced between 460 and 630 bpd while being tested using chokes between 6mm and 10mm in size. Currently production rate from single interval testing using an 8 mm choke ranges from 280 to 350 bpd.

Emir-1

This well is currently producing. Current production rates from single interval testing using a 8 mm diameter choke ranges from 3 to 20 bpd.

Kariman-1

We began our current fiscal year continuing the re-entry of Kariman-1 well, our first project within the Extended Territory. The re-entry was completed on June 30, 2006 and well completion was undertaken and completed between July 7, 2006 and July 17, 2006 to the upper Triassic formation. Despite the fact that the flows from this horizon are partially blocked by drilling fluid, preliminary testing conducted during the first month of testing using chokes ranging from 20 mm to 30 mm yielded results ranging from 250 to 530 barrels per day. The well was then put into a pressure-build up test to better understand the source of the high pressures located during earlier re-entry operations at the upper four meters of Middle Triassic formation at the Karamin-1 well. We have obtained a specialized low diameter casing which will be run down the well by the Oil and Gas Exploration Cracow contractor. During the latter part of February, we plan to complete the well and commence extensive testing of the Upper Triassic formations penetrated during summer re-entry operations.

Results of Operations

Three months ended December 31, 2006, compared to the three months ended December 31, 2005.

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 December 31, 2006 and the three months ended December 31, 2005.

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				Three months ended December 31, 2006 to the three months ended December 31, 2005
	For the three	For the three	$		%
	months ended	months ended	Increase		Increase
	December 31, 2006	December 31, 2005		(Decrease)	(Decrease)
Production volumes:
Natural gas (Mcf)	-	-	-		-
Natural gas liquids (Bbls)	-	-	-		-
Oil and condensate (Bbls)	53,456	92,342	(38,886)		(42%)
Barrels of Oil equivalent (BOE)	53,456	92,342	(38,886)		(42%)
Sales volumes:
Natural gas (Mcf)	-	-	-		-
Natural gas liquids (Bbls)	-	-	-		-
Oil and condensate (Bbls)	52,019	93,224	(41,205)		(44%)
Barrels of Oil equivalent (BOE)	52,019	93,224	(41,205)		(44%)
Average Sales Price (1)
Natural gas ($ per Mcf)	-	-	-		-
Natural gas liquids ($ per Bbl)	-	-	-		-
Oil and condensate ($ per Bbl)	$ 42.57	$ 22.08	$ 20.49		93%
Barrels of Oil equivalent ($ per BOE)	$ 42.57	$ 22.08	$ 20.49		93%
Operating Revenue:
Natural gas	-	-	-		-
Natural gas liquids	-	-	-		-
Oil and condensate	$ 2,214,382	$ 2,058,792	$ 155,590		7%
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 December 31, 2006, or the three months ended December 31, 2005.

Revenues. We generate revenue under our contract from the sale of oil recovered during test production. During the three months ended December 31, 2006 our oil production decreased 42% compared to the three months ended December 31, 2005. This significant decrease in production is primarily attributable to production decreases on the Dolinnoe field. Following workover operations and well flow stimulation during July 2006, production rates at the Dolinnoe-3 well stabilized between 280 and 350 barrels per day, a 53% decrease from production rates experienced at the well during the three months ended December 31, 2005. During November and December 2006, we also undertook workover activities at the Dolinnoe-1 well. The well continued to produce during workover, albeit at a much reduced rate.

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Despite this significant decrease in production we realized revenue from oil sales of $2,214,382 during the quarter ended December 31, 2006 compared to $2,058,792 during the quarter ended December 31, 2005. The largest contributing factor to the 7% increase in revenue was a 93% increase in the price per barrel we received for oil sales during the quarter ended December 31, 2006 compared to the fiscal quarter ended December 31, 2005. During the fiscal quarter ended December 31, 2006 we exported our oil to the world markets and realized the world market price for those sales. By comparison, during the fiscal quarter ended December 31, 2005 all oil sales were to the domestic market in Kazakhstan, where the price per barrel of oil is significantly lower than the world market price. We anticipate production to increase in upcoming years as we complete more wells. We plan to continue our drilling activities. We also hope to continue to be granted export quotas, which allow us to realize world market prices. This should continue to lead to increased revenue from oil sales.

As discussed above, our revenue is sensitive to changes in prices received for our oil. Our production is currently being sold at the prevailing world market price, which fluctuates in response to many factors that are outside our control. Imbalances in the supply and demand for oil can have a dramatic effect on the prices we receive for our production. Similarly, if we were denied an export quota and were forced to sell our production to the domestic market in Kazakhstan, we anticipate the price we would receive per barrel of oil would be much lower than the price we currently realize. Political instability, the economy, weather and other factors outside our control could have an impact on both supply and demand.

Costs and Operating Expenses

The following table presents details of our expenses for the three months ended December 31, 2006 and 2005:

	For the three months ended December 31, 2006	For the three months ended December 31, 2005
Expenses:
Oil and gas operating(1)	$ 360,905	$ 242,582
General and administrative	1,705,166	1,497,515
Depletion	323,062	451,029
Accretion expenses	56,177	-
Amortization and depreciation	44,726	35,316
Total	$ 2,490,036	$ 2,226,442
Expenses ($ per BOE):
Oil and gas operating(1)	6.94	2.60
Depletion (2)	6.21	4.84

(1) Includes transportation cost, production cost and ad valorem taxes.

(2) Represents depletion of oil and gas properties only.

Oil and Gas Operating Expenses. During the three months ended December 31, 2006 we incurred $360,905 in oil and gas operating expenses compared to $242,582 during the three months ended December 31, 2005. This significant increase is primarily the result of several factors. During the three months ended December

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31, 2006 we experienced salary and transportation expenses of $23,970 and $86,712, respectively. Salary and transportation expenses increased primarily because we had two additional wells in testing or test production during the current fiscal quarter as compared to the fiscal quarter ended December 31, 2005. This required us to retain additional production and maintenance personnel and oil tankers. Also during the quarter ended December 31, 2006, despite a production volume decrease of 42%, royalty paid to the Government increased $7,641 to $49,213. During the quarter ended December 31, 2006 we realized greater revenue because all sales were to the world market and realized the world market price. By comparison, during the fiscal quarter ended December 31, 2005 all oil sales were to the domestic market in Kazakhstan, where the price per barrel of oil is significantly lower than the world market price. As a result, because of the increase in revenue from oil sales in the current year, we recognized a corresponding increase in our royalty payment. We expect oil and gas operating expenses to continue to increase in upcoming fiscal quarters as the number of wells we have in testing and test production continues to increase.

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

Oil and gas operating expenses increased 49% during current fiscal quarter compared to quarter ended December 31, 2005, so expense per BOE increased from $2.60 per BOE in quarter ended December 31, 2005 to $6.94 in current fiscal quarter.

General and Administrative Expenses. General and administrative expenses during the three months ended December 31, 2006 were $1,705,166 compared to $1,497,515 during the three months ended December 31, 2005. This represents a 14% increase in general and administrative expenses. This increase resulted from increased payroll expenses of $61,825 resulting from the hiring of additional administrative personnel as our business has grown, increased tax expenses of $66,163 resulting from environmental payments and increased transportation expenses of $27,292 resulting from increased business travel by our administrative personnel. These increases were only partially offset by a decrease in professional services of $187,415, as litigation-related expenses were lower during the quarter ended December 31, 2006. We anticipate general and administrative expenses in upcoming fiscal quarters will remain fairly consistent with the expenses incurred during the three months ended December 31, 2006.

Depletion. Depletion expenses for the current fiscal quarter decreased by $127,967 compared to depletion expenses for the quarter ended December 31, 2005. The major reason for this decrease in depletion expense is due to sales volumes decreasing by 44% in current fiscal quarter compared to the quarter ended December 31, 2005.

Depreciation and Amortization. Depreciation and amortization expenses for the current fiscal quarter increased 27% compared to the quarter ended December 31, 2005. The increase resulted from purchases of fixed assets during the quarter.

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Loss from Operations. As a result of a 49% increase in oil and gas operating expenses and a 14% increase in general and administrative expenses during the fiscal quarter ended December 31, 2006 we realized a loss from operations of $275,654 compared to a loss from operations of $167,650 during the fiscal quarter ended December 31, 2005. This represents a 64% increase in loss from operations during the fiscal quarter ended December 31, 2006 compared to the fiscal quarter ended December 31, 2005. In future periods, we believe production rates and oil prices will be such that we will be able to generate sufficient revenue from oil sales to offset our expenses. If, however, production levels or oil prices were to decrease, we may be unable to offset our operating expenses with revenue from production and could continue to experience losses from operations.

Other Income. During the fiscal quarter ended December 31, 2006 we realized total other income of $184,793 compared to $114,708 during the fiscal quarter ended December 31, 2005. This 61% increase is largely attributable to $294,181 increase in interest income we realized from funds we received from a private placement we completed in December 2005. This income is partially offset by a $100,937 increase in exchange loss resulting from fluctuations of foreign currency rates against the U.S. Dollar, a $62,729 decrease in unrealized gain on marketable securities and $60,430 increase in other expenses. We anticipate the funds held in deposits and marketable securities will be used to fund our operations and therefore expect interest income and gains from marketable securities, both realized and unrealized, to decrease in upcoming quarters.

Net Loss. During the fiscal quarter ended December 31, 2006 we realized a net loss of $90,861 compared to a net loss of $52,942 during the fiscal quarter ended December 31, 2005. The net loss for the quarter is largely attributable to the factors discussed above. As we complete and begin to engage in test production at the Kariman-1, Dolinnoe-6 and Emir-6 wells, we anticipate that we will realize an increase in production and revenue. Based on these expectations, we anticipate having the ability to produce sufficient oil and gas to offset our expenses.

Results of Operations

Nine months ended December 31, 2006, compared to the nine months ended December 31, 2005

Revenue and Production

The following table summarizes production volumes, average sales prices and operating revenue for our oil and natural gas operations for the nine months ended December 31, 2006 and the nine months ended December 31, 2005.

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				Nine months ended December 31, 2006 to the nine months ended December 31, 2005
	For the nine	For the nine	$		%
	months ended	months ended	Increase		Increase
	December 31, 2006	December 31, 2005		(Decrease)	(Decrease)
Production volumes:
Natural gas (Mcf)	-	-	-		-
Natural gas liquids (Bbls)	-	-	-		-
Oil and condensate (Bbls)	179,487	204,163	(24,676)		(12%)
Barrels of Oil equivalent (BOE)	179,487	204,163	(24,676)		(12%)
Sales volumes:
Natural gas (Mcf)	-	-	-		-
Natural gas liquids (Bbls)	-	-	-		-
Oil and condensate (Bbls)	171,897	192,722	(20,825)		(11%)
Barrels of Oil equivalent (BOE)	171,897	192,722	(20,825)		(11%)
Average Sales Price (1)
Natural gas ($ per Mcf)	-	-	-		-
Natural gas liquids ($ per Bbl)	-	-	-		-
Oil and condensate ($ per Bbl)	$ 49.90	$ 21.31	$ 28.59		134%
Barrels of Oil equivalent ($ per BOE)	$ 49.90	$ 21.31	$ 28.59		134%
Operating Revenue:
Natural gas	-	-	-		-
Natural gas liquids	-	-	-		-
Oil and condensate	$ 8,577,326	$ 4,106,765	$ 4,470,561		109%
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 nine months ended December 31, 2006, or the nine months ended December 31, 2005.

Revenues. As mentioned above, we generate revenue under our contract from the sale of oil recovered during test production. During the nine months ended December 31, 2006, our overall production volume decreased 12% compared to the nine months ended December 31, 2005. The major reason for this overall production decrease was a 23% decrease in production from the Dolinnoe field wells, as discussed in more detail above. This decrease in production from the Dolinnoe field wells was only partially offset by production from two additional wells that were not in test production during the nine months ended December 31, 2005.

While overall production dropped 12%, during the nine months ended December 31, 2006, we still realized a 109% increase in revenue from oil sales, as sales grew to $8,577,326. The largest contributing factor to the increase in revenue was a 134% increase in the price per barrel we received for oil sales during the nine

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month period ended December 31, 2006 compared to the nine month period ended December 31, 2005. During the nine months ended December 31, 2006 we exported our oil to the world market and realized the world market price for those sales. By comparison, during the nine months ended December 31, 2005 all oil sales were to the domestic market in Kazakhstan, where the price per barrel of oil is significantly lower than the world market price.

We plan to continue drilling activities in the upcoming periods, which we believe will result in increases in production. We hope to continue to be granted export quotas, which allow us to realize world market prices for our oil. If we continue to be granted export quotas, we should continue to realize world market price for our oil sales, which results in higher revenues compared to our prior fiscal years because of the increased price per barrel we realize.

Costs and Operating Expenses

The following table presents details of our expenses for the nine months ended December 31, 2006 and 2005:

	For the nine months ended December 31, 2006	For the nine months ended December 31, 2005
Expenses:
Oil and gas operating(1)	$ 1,351,478	$ 509,289
General and administrative	9,028,108	7,379,267
Depletion	991,030	1,116,673
Accretion expenses	120,235	-
Amortization and depreciation	121,237	100,122
Total	$ 11,612,088	$ 9,105,351
Expenses ($ per BOE):
Oil and gas operating(1)	7.86	2.64
Depletion (2)	5.77	5.79

(1) Includes transportation cost, production cost and ad valorem taxes.

(2) Represents depletion of oil and gas properties only.

Oil and Gas Operating Expenses. During the nine months ended December 31, 2006 we incurred $1,351,478 in oil and gas operating expenses compared to $509,289 during the nine months ended December 31, 2005. This significant increase is the result of several factors. During the nine months ended December 31, 2006 royalties paid to the government increased 80% or $64,097. This increase resulted from the fact that all oil sales in current nine-month period were to the world markets and we realized the world market price for those sales. By comparison, during the nine-month period ended December 31, 2005 all oil sales were to the domestic market in Kazakhstan, where the price per barrel of oil is significantly lower than the world market price. Another reason for increase in oil and gas operating expenses is increase in salary expenses and transportation expenses for

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$347,094 and $430,998, respectively. These expenses increased primarily because during the nine months ended December 31, 2006 we had two additional wells in testing or test production as compared to the nine months ended December 31, 2006. This required us to hire more production and maintenance personnel and additional oil tankers. We expect oil and gas operating expenses to continue to increase in the upcoming fiscal year as revenue continues to increase.

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

Oil and gas operating expenses increased 165% during nine months ended December 31, 2006 compared to same prior period, so expense per BOE increased from $2.64 per BOE in nine months ended December 31, 2005 to $7.86 in nine month ended December 31, 2006.

General and Administrative Expenses. General and administrative expenses during the nine months ended December 31, 2006 were $9,028,108 compared to $7,379,267 during the nine months ended December 31, 2005. This represents a 22% increase in general and administrative expenses. This increase is attributable to a 13% increase in payroll and other compensation, during the nine months ended December 31, 2006 because we hired more administrative personnel to operate our business. During the nine-month period ended December 31, 2006 we granted restricted stock and stock options to our directors, officers and key employees. The fair value of these stock and stock option grants was recognized in our consolidated financial statements as compensation expense. The total amount of compensation expense recognized as a result of the stock and option grants was $4,060,946. During the nine-month period ended December 31, 2005 we also granted restricted stock and stock options to our directors, officers and key employees. The total amount of compensation expense recognized as a result of the stock and option grants was $4,049,340. Other factors contributing to the increase in general and administrative expense were a 6% increase in rent expense, a 114% increase in taxes resulting from increased environmental payments and a 172% increase in travel and related expenses resulting from increased business travel. We anticipate general and administrative expenses will continue to increase in upcoming quarters.

Depletion. Depletion expenses for the nine months ended December 31, 2006 decreased by $125,643 compared to depletion expenses for the nine month ended December 31, 2005. The major reason for this decrease in depletion expense is due to sales volumes decreasing by 11% in current nine month period compared to nine month period ended December 31, 2005.

Depreciation and Amortization. Depreciation and amortization expenses for the nine months ended December 31, 2006 increased 21% compared to nine months ended September 30, 2005. The increase resulted from purchases of fixed assets during the current six month period.

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Loss from Operations. During the nine months ended December 31, 2006 we realized a loss from operations of $3,034,762 compared to a loss from operations of $4,998,586 during the nine months ended December 31, 2005. This 39% decrease in loss from operations is a result of our realizing a 109% increase in revenue during the nine month period ended December 31, 2006 compared to the comparable period 2005, this increase was partially offset by a 165% increase in oil and gas operating expenses and a 22% increase in general and administrative expenses. In future periods, we believe production rates and oil prices will be such that we will be able to generate sufficient revenue from oil sales to offset our expenses. If, however, production levels or oil prices were to decrease or we were to lose or experience a significant decrease in our export quota we may be unable to offset our operating expenses with revenue from production and could continue to experience losses from operations.

Other Income. During the nine-month period ended December 31, 2006 we realized total other income of $995,005 compared to $200,582 during the fiscal quarter ended December 31, 2005. This 396% change is largely attributable to $1,286,888 increase in interest income. This income was partially offset by a $51,064 increase in exchange loss resulting from fluctuations of foreign currency rates against the U.S. Dollar, $181,688 decrease in realized gain on marketable securities and $55,190 decrease in unrealized gains on marketable securities and a $204,523 increase in other expenses. We anticipate the funds held in deposits and marketable securities will be used to fund our operations and therefore expect interest income and gains from marketable securities, both realized and unrealized, to decrease in upcoming quarters.

Net Loss. For the reasons detailed above, during the nine-month period ended December 31, 2006 we realized a net loss of $2,215,270 compared to a net loss of $4,798,004 during the comparable period of 2005. We anticipate that we will continue to realize increases in revenue as our production levels continue to increase. Based on these expectations, we anticipate net losses in upcoming quarters will continue to decrease.

Liquidity and Capital Resources

Funding for our activities has historically been provided by funds raised through the sale of our common stock. From inception on May 6, 2003 through December 31, 2006 we have raised $94,626,926 through the sale of our common stock. As of December 31, 2006 we had cash and cash equivalents on hand of $21,446,804. We anticipate our capital resources in the upcoming three months will consist primarily of revenue from the sale of oil recovered and cash and cash equivalents on hand.

Our need for capital is primarily to fund our ongoing operations to meet the drilling requirements of our minimum work program. For the period from inception on May 6, 2003 through December 31, 2006, we have incurred capital expenditures of $95,096,803 for exploration, development and acquisition activities.

We continually evaluate our capital needs and compare them to our capital resources. At the beginning of the current fiscal year we had budgeted capital expenditures of about $60 million to $70 million for exploration,

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development, production and acquisitions. At the time the budget was prepared, we believed our production would be sufficient to allow us to generate enough revenue from oil sales to finance the gap of $10 million to $20 million required for our planned exploration, development, production and acquisitions. However, the drilling schedules we initially anticipated have been delayed and production has developed more slowly than expected.

One of the challenging tasks we have faced is how to make accurate production forecasts during the exploration stage. There are many factors that contribute to the complexity of reliable forecasting by an exploration stage company. Our first challenge has been to secure qualified drilling subcontractors and to obtain timely performance. The current energy boom in Kazakhstan has created considerable competition for good rigs and qualified labor. In the case of the heavy rig of Great Wall, the original estimate scheduled a new heavy rig in place in March 2006. It was July 2006 before the rig was in place and ready to begin drilling the Dolinnoe-6 well. The delay was not the fault of the driller, but arose from delay at the China-Kazakhstan border.

Second, we are in continuous test production on each well. We are required by law to test each interval using different choke sizes. The minimum testing periods usually extend over a period of months. There is considerable down time while equipment is being put in place and removed during this process. In addition, we have experimented with various reworking methodologies attempting to determine the best methods to suit the characteristics of the oil, gas and pressure variations encountered in each structure.

Our monthly production figures have remained steadily within a range below our expectations, and at our current levels of oil production we are operating below the break-even point, exclusive of our drilling program expenditures. If our operations are to generate a significant portion of the future capital needed to complete our exploration contract, then our monthly production will have to increase significantly. In addition to our efforts to increase revenue from oil sales to help fund our drilling program expenditures, we are also negotiating with interested banks to secure a credit facility that will allow us to continue our exploration contract drilling obligations without delay.

Cash Flows

During the nine months ended December 31, 2006 cash was primarily used to fund exploration and development expenditures. See below for additional discussion and analysis of cash flow.

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	Nine months ended December 31, 2006	Nine months ended December 31, 2005
Net cash used in operating activities	$ (4,805,025)	$ (2,892,292)
Net cash used in investing activities	$ (31,552,804)	$ (12,616,108)
Net cash provided by financing activities	$   6,662,901	$  59,812,642
NET CHANGE IN CASH AND CASH   EQUIVALENTS	$ (29,694,928)	$ 44,304,242

Our principal source of liquidity during the third quarter and the nine months ended December 31, 2006 was cash and cash equivalents. At March 31, 2006 cash and cash equivalents totaled approximately $51 million. At December 31, 2006 cash and cash equivalents had decreased approximately $29.7 million. As discussed above, during the three months ended December 31, 2006 we spent approximately $14 million to fund the most active period of drilling and development activities in our history. During the nine months ended December 31, 2006, we have spent approximately $26 million in exploration, development and production

While we anticipate revenue to increase in upcoming quarters as these new wells are completed and are put into test production, at this time we cannot predict how much our production, and correspondingly, our revenue might increase. At current production rates, we expect that we will need to seek additional equity or debt financing if we are to drill the additional wells we need to support our claims of commercially producible reserves by the end of the term of our exploration contract. At this time, we have no firm commitments from any party to provide us additional financing, and there is no guarantee that we will be able to secure additional funding on acceptable terms, or at all.

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 December 31, 2006, excluding current liabilities as listed on our consolidated balance sheet:

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	Payments Due By Period
Contractual obligations	Total	Less than 1 year	1-3 years	4-5 years	After 5 years
Capital Expenditure Commitment(1)	$ 4,500,000	$4,500,000	$              -	-	-
Due to the Government of the Republic of Kazakhstan(2)	11,344,880	11,344,880	-	-	-
Liquidation Fund	2,112,545	-	2,112,545	-	-
Total	$ 17,957,425	$15,844,880	$2,112,545	-	-

(1)   Under the terms of our contract with the ROK, we are required to spend a total of at least $10.5 million dollars in exploration, development and improvements within the ADE Block and Extended Territory during the term of the license, including $6 million in the 2006 calendar year and $4.5 million in the 2007 calendar year. If we fail to do so, we may be subject to the loss of our exploration license.

(2)   In connection with our acquisition of the oil and gas contract covering the ADE Block and the Extended Territory, we are required to repay the ROK for historical costs incurred by it in undertaking geological and geophysical studies and infrastructure improvements. The repayment terms of this obligation will not be determined until such time as we apply for and are granted commercial production rights by the ROK. Under our contract, if we wish to commence commercial production, we must apply for such right prior to the expiration of our exploration and development rights in July 2007 or we must apply for a two-year extension of our exploration license. We are legally entitled to the two-year extension. We have the exclusive right to negotiate for commercial production rights with the ROK, and the ROK is required to conduct the negotiations under the Law of Petroleum in Kazakhstan. Although we can apply for commercial production rights at any time, we enjoy certain benefits under our contract that currently make it more economically advantageous for us to continue exploration and development activities at this time. At this time, we anticipate that we will apply for a two-year extension of our exploration license during the first half of the 2007 calendar year. This would give us an additional two years to explore and prove up our properties before we apply for commercial production rights. Should we decide not to pursue a commercial production contract, we can relinquish the ADE Block and Extended Territory to the ROK in satisfaction of this obligation. Our repayment obligation for the ADE Block is $5,994,200. Our repayment obligation for the Extended Territory is $5,350,680.

Off-Balance Sheet Financing Arrangements

As of December 31, 2006, 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

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our production either through export to international markets or within Kazakhstan. Our third quarter 2006 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.

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.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our principal executive officers and our principal financial officer (the “Certifying Officers”) are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e). Such officers have concluded (based upon their evaluations of these controls and procedures as of the end of the period covered by this report) that our disclosure controls and procedures are effective to ensure that information required to be disclosed by it in this report is accumulated and communicated to management, including the Certifying Officers as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, our Certifying Officers have concluded that our disclosure controls and procedures are effective as of December 31, 2006.

Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting during the quarter ended December 31, 2006 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II - OTHER INFORMATION

Item 1. Legal Proceedings

In December 2003, a complaint was filed in the 15th Judicial Court in and for Palm Beach County, Florida, naming, among others, the Company and former directors, Georges Benarroch and Alexandre Agaian, as defendants. The plaintiffs, Brian Savage, Thomas Sinclair and Sokol Holdings, Inc., allege claims of breach of contract, unjust enrichment, breach of fiduciary duty, conversion and violation of a Florida trade secret statute in connection with a business plan for the development Aksaz, Dolinnoe and Emir oil and gas fields owned by Emir Oil, LLP. The parties mutually agreed to dismiss this lawsuit without prejudice.

In April 2005, Sokol Holdings, Inc., also filed a complaint in United States District Court, Southern District of New York alleging that BMB Munai, Inc., Boris Cherdabayev, and former BMB directors Alexandre Agaian, Bakhytbek Baiseitov, Mirgali Kunayev and Georges Benarroch wrongfully induced Toleush Tolmakov to breach a contract under which Mr. Tolmakov had agreed to sell to Sokol 70% of his 90% interest in Emir Oil LLP.

In October 2005, Sokol Holdings amended its complaint in the U.S. District Court in New York to add Brian Savage and Thomas Sinclair as plaintiffs and to add Credifinance Capital, Inc., and Credifinance Securities, Ltd., (collectively “Credifinance”) as defendants in the matter. The amended complaint alleges tortious interference with contract, specific performance, breach of contract, unjust enrichment and breach of fiduciary duty by Georges Benarroch, Alexandre Agaian and Credifinance, conversion, breach of fiduciary duty by Boris Cherdabayev, Mirgali Kunayev and Bakhytbek Baiseitov, misappropriation of trade secrets and tortuous interference with fiduciary duty by Mr. Agaian, Mr. Benarroch and Credifinance and aiding and abetting breach of fiduciary duty by Mr. Benarroch, Mr. Agaian and Credifinance in connection with a business plan for the development of the Aksaz, Dolinnoe and Emir oil and gas fields owned by Emir Oil, LLP. The plaintiffs have not named Toleush Tolmakov as defendant in the action nor have the plaintiffs ever brought claims against Mr. Tolmakov to establish the existence or breach of any legally binding agreement between the plaintiffs and Mr. Tolmakov. The plaintiffs seek damages in an amount to be determined at trial, punitive damages, specific performance and such other relief as the Court finds just and reasonable.

We have retained the law firm of Bracewell & Giuliani LLP in New York, New York to represent us in the lawsuit. We moved for dismissal of the amended complaint or for a stay pending arbitration in Kazakhstan. That motion was denied, without prejudice to renewing it, to enable defendants to produce documents to plaintiffs relating to the issues raised in the motion. Following completion of document production, the motion has been renewed. Briefing on the motion was completed on August 24, 2006, and the motion is awaiting decision.

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In the opinion of management, the resolution of this lawsuit will not have a material adverse effect on our financial condition, results of operations or cash flows.

Other than the foregoing, to the knowledge of management, there is no other material litigation or governmental agency proceeding pending or threatened against the Company or our management.

Item 1A. Risk Factors

If we may be unable to drill and complete a sufficient number of wells in each of our identified structures to support our claim of commercially producible reserves before the end of the term of our exploration contract, as extended, we may not be granted a commercial production contract for each of our structures.

As discussed in “Management’s Discussion and Analysis” in order to obtain a commercial production license for the structures contained within our licensed territory, we must engage in sufficient exploration, drilling and testing activities to gather adequate data to support our claims that we have discovered commercially producible reserves within our contract territory. These activities must be completed during the term of our exploration license. It is generally accepted that one exploratory and two appraisal wells are sufficient to determine whether a license holder has discovered a commercially producible reserve, although in some instances, license holders are able to establish commercially producible reserves with fewer than three wells.

As of December 31, 2006, we have spent approximately $77.5 million in exploration and development activities to drill nine wells, with an additional well underway. As of December 31, 2006 we had $21.4 million in cash and cash equivalents to fund our operations, including drilling and exploration activities. At current production rates, we expect that we will need to seek additional equity or debt financing if we are to drill the additional wells we need to support our claims of commercially producible reserves in each of our identified structures by the end of the term of our exploration contract. At this time, we have no firm commitments from any party to provide us additional financing, and there is no guarantee that we will be able to secure additional funding on acceptable terms, or at all.

Other than the foregoing, there have been no material changes in the risk factors previously described in Items 1 and 2 to Part I of our Form 10-KSB filed on June 29, 2006.

Item 4. Results of Votes of Security Holders

We held our Annual Meeting of Shareholders on October 5, 2006. We previously report on the matters voted upon and the votes case with respect to each matter in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2006.

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Item 6. Exhibits

Exhibits. The following exhibits are included as part of this report:

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 of Principal Executive Officer Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2 Certification of Principal Financial Officer 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:	January 4, 2008		/s/ Gamal Kulumbetov
		Gamal Kulumbetov
		Chief Executive Officer

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