k033111.htm

10-K 1 k033111.htm FORM 10-K YEAR ENDED MARCH 31, 2011 k033111.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

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

For the fiscal year ended March 31, 2011

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

For the transition period from ________ to _________

Commission File Number 001-33034

BMB MUNAI, INC.

(Exact name of registrant as specified in its charter)

Nevada		30-0233726
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

202 Dostyk Ave, 4th Floor
Almaty, Kazakhstan		050051
(Address of principal executive offices)		(Zip Code)

+7 (727) 237-51-25

(Registrant’s telephone number, including area code)

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

Title of Each Class		Name of Exchange on Which Registered

Common - $0.001		NYSE Amex

Securities registered under Section 12(g) of the Exchange Act: None

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

¨ Yes þ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.

¨ Yes þ No

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

þ Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)

o Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

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

Large accelerated Filer ¨ Accelerated filer ¨

Non-accelerated Filer ¨ (Do not check if smaller reporting company) Smaller reporting company þ

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

¨ Yes þ No

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter was $22,144,769.

As of June 11, 2011, the registrant had 55,787,554 shares of common stock, par value $0.001, issued and outstanding.

Documents Incorporated by Reference: None

Table of Contents

	PART I
		Page

Item 1.	Business	5

Item 1A.	Risk Factors	11

Item 1B.	Unresolved Staff Comments	22

Item 2.	Properties	23

Item 3.	Legal Proceedings	34

Item 4.	[Removed and Reserved]	34

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34

Item 6.	Selected Financial Data	35

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	49

Item 8.	Financial Statements and Supplementary Data	49

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	49

Item 9A.	Controls and Procedures	49

Item 9B.	Other Information	50

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	51

Item 11.	Executive Compensation	59

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	65

Item 13.	Certain Relationships and Related Transactions, and Director Independence	67

Item 14.	Principal Accountant Fees and Services	69

	PART IV

Item 15.	Exhibits and Financial Statement Schedules	71

	SIGNATURES	74

Forward-Looking Information

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

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

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

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

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

PART I

Item 1. Business

Overview

BMB Munai, Inc. is a Nevada corporation that originally incorporated in the State of Utah in 1981. Since 2003, our business activities have focused on oil and natural gas exploration and production in the Republic of Kazakhstan (also referred to herein as the “ROK” or “Kazakhstan”) through our wholly-owned operating subsidiary Emir Oil LLP, (“Emir Oil”). Emir Oil holds an exploration contract that allows us to conduct exploration drilling and oil production in the Mangistau Province in the southwestern region of Kazakhstan until January 2013. The exploration territory of our contract area is approximately 850 square kilometers and is comprised of three areas, referred to herein as the ADE Block, the Southeast Block and the Northwest Block. The ADE Block, the Southeast Block and the Northwest Block are collectively referred to herein as “our properties.” For additional information regarding the contract and license to our properties please see Item 2. Properties of this report.

Recent Developments

Sale of Emir Oil LLP

On February 14, 2011, we entered into a Participation Interest Purchase Agreement (the “Purchase Agreement”) with MIE Holdings Corporation, a company with limited liability organized under the laws of the Cayman Islands (“MIE”), and its subsidiary, Palaeontol B.V., a company organized under the laws of the Netherlands (“Palaeontol”), pursuant to which we agreed to sell (i) all of our interest in Emir Oil to Palaeontol, and (ii) certain intercompany loans we made to Emir Oil (the “Sale.”) The initial purchase price is $170 million and is subject to various closing adjustments and the deposit of $36 million in escrow to be held for a period of twelve months following the closing for indemnification purposes. Upon consummation of the Sale, we will use a portion of the proceeds to repay the Company’s outstanding Senior Notes (as defined herein) and to pay transaction costs and expenses. We also intend to make an initial cash distribution from the Sale proceeds to our stockholders in the estimated range of $1.04 to $1.10 per share upon the closing, after giving effect to the estimated closing adjustments and escrow holdback amount, the repayment of the convertible senior notes and providing for the payment or reserve of other projected liabilities and transaction costs. We intend to make a second distribution to our stockholders that could range up to approximately $0.30 per share following termination of the escrow, subject to the availability of funds to be released from the escrow, actual costs incurred and other factors.

Pursuant to the Purchase Agreement, the closing of the Sale is subject to the satisfaction or waiver of a number of conditions, including regulatory approvals, other customary closing conditions and the following:

·	approval by our stockholders and the stockholders of MIE;

·	approval of the holders of Senior Notes (as defined herein) of the Company;

·	consent of the Ministry of Oil and Gas on behalf of the Republic of Kazakhstan (the “MOG”);

·	waiver of Kazakhstan’s priority right to purchase interests in the assets in accordance with Kazakhstan’s Subsoil Use Law;

·	approval by the Hong Kong Stock Exchange;

·	satisfaction of Kazakhstan legal requirements with respect to the Company’s existing exploration contract in Kazakhstan;

·	Emir Oil’s entry into a duly registered production contract for production of petroleum at each of the Kariman, Dolinnoe and Aksaz locations; and

·	Palaeontol’s receipt of a valid work permit from the Kazakhstan Ministry of Labor and Social Protection for the appointment of a new general manager of Emir.

At a special meeting of our stockholders held on June 2, 2011, our stockholders voted on and approved the Sale. The parties are currently working to satisfy the other closing conditions.

The Purchase Agreement requires us to continue to conduct the business of Emir Oil in the ordinary course until the consummation of the Sale, which we are doing. Consistent with generally accepted accounting principles in the United States, however, because of the pending Sale, the assets, liabilities and operations of Emir Oil have been classified as discontinued operations for reporting purposes.

Restructure of Convertible Senior Notes

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

	•	increased the coupon rate of the Original Notes from 9.0% to 10.75%;
	•	made a $1.0 million cash payment to holders of the Original Notes;
	•	increased the aggregate principal amount of the Original Notes from $60.0 million to $61.4 million;
	•	extended the maturity date of the Original Notes from July 13, 2012 to July 13, 2013;
	•	granted the holders of the Original Notes a new put option, exercisable one year prior to the new maturity date;
	•	agreed to additional covenant restrictions, including a limitation on indebtedness that we may incur, a restriction on the capital expenditures we may make, a prohibition on paying dividends on shares of our common stock and a limitation on the investments we may make;
	•	agreed to semi-annual principal amortization payments of 30% of our excess cash flow, if any;
	•	granted the holders of the Original Notes director nominee rights with respect to the Company and Emir Oil;

	•	agreed, subject to approval of our common stockholders and to receipt of any necessary regulatory approvals, to reduce the conversion price of the Original Notes from $7.2904 per share to $2.00 per share with a corresponding reduction in the minimum conversion price from $6.95 per share to $1.00 per share (the “Conversion Price Reduction”); and
	•	entered into various agreements including an amended and restated indenture (the “Amended Indenture”) reflecting the changes discussed herein and the Original Notes were delivered to the Trustee for cancellation and in substitution the Company issued $61.4 million in principal amount of 10.75% Convertible Senior Notes due 2013 (the “Senior Notes”).

In connection with the Note Restructure, the Noteholders approved the Sale pursuant to the Purchase Agreement. Upon consummation of the Sale, we are required to redeem each Senior Note for 100% of such Senior Note’s outstanding principal amount, together with interest accrued to such date, out of the proceeds of the Sale.

On June 2, 2011, at a special meeting of our stockholders, our stockholders voted on and approved the Conversion Price Reduction. The Conversion Price Reduction may also be subject to approval of the MOG. We have agreed with the Noteholders that we will seek clarification from the MOG as to whether MOG approval of the Conversion Price Reduction is necessary. We are not, however, obligated to seek such clarification until we have received the approval of the MOG of the Sale, and if approval of the Sale has been obtained, we may delay seeking such clarification to the extent we believe in good faith that it would adversely affect the approval of the MOG granted for the Sale. If the MOG confirms that approval is not necessary, we will execute a supplemental indenture to effect the Conversion Price Reduction upon receipt of confirmation that the approval of the MOG is not required for the Conversion Price Reduction. If the MOG confirms that its approval is required, we are required to promptly seek that approval, and to cause the Conversion Price Reduction to become effective by the earlier of (a) the date that is 10 business days after approval of the MOG has been obtained or the date on which it is determined that such approval is not required, or (b) December 30, 2011.

If we do not complete the Sale, we anticipate that we will lack sufficient funds to retire the restructured Senior Notes when they become due.

Our Business

Principal Products or Services

Since 2003 our primary operating asset has been Emir Oil. Since 2004 we have been actively drilling wells in each field on the ADE Block and since 2005 we have been drilling in the Kariman field in the Southeast Block.

Our drilling activities have consisted of drilling an array of exploratory wells to delineate reservoir structures and developmental wells intended to provide income to the Company. Our operational focus during the last fiscal year has been to work on improving and stabilizing production from our existing wellstock. Because of limited available funds for drilling activities during fiscal 2011, we attempted to increase production through drilling directional sidetracks at existing wells, which is less expensive than drilling new vertical wells. Although these efforts were successful with certain wells, overall production remained stable, due to a decline in production from existing wells, which were not drilled directionally. Currently, we have 1,160 gross (1,160 net) proved developed producing acres, 360 gross (360 net) proved developed non-producing acres, 220 gross (220 net) probable developed acres plus 240 gross (240 net) proved undeveloped acres. We also hold approximately 111,690 gross (111,690 net) unproved, undeveloped acres in the ADEK Block and approximately 96,370 gross (96,370 net) unproved, undeveloped acres in the Northwest Block. For additional information regarding our oil and natural gas reserves, operations, licenses and concessions please see Item 2. Properties of this report.

Oil and Natural Gas Reserves

Please see Item 2. Properties of this report for a description of our oil and gas reserves and related information.

Industry and Economic Factors

The oil and gas exploration and production business is subject to many factors beyond our control. One such factor is the fluctuation of oil and gas prices. Historically, oil and gas markets have been cyclical and volatile. During fiscal year 2011 we experienced wide fluctuation in the world price for oil. We expect prices to continue to be difficult to predict.

While our revenues are a function of both production and prices, wide swings in commodity prices have significantly impacted our results of operations. We have not engaged in hedging transactions because we believe that at current production levels it is not economically viable.

Our operations entail significant complexities due to the depth and geological makeup of the structures we are entering. Advanced technologies requiring highly trained personnel are utilized in both exploration and development. Even when the technology is properly used we still may not know conclusively whether hydrocarbons will be present or the rate at which they may be produced when wells are completed. Despite our best efforts to limit our risks, exploration drilling is a high-risk activity that may not yield commercial production or reserves.

Marketing and Sales to Major Customers

There are a variety of factors that affect the market for oil and natural gas, including the extent of domestic production and imports, the availability, proximity and capacity of pipelines and other transportation facilities, demand, the marketing of competitive fuels and the effects of state and federal regulations on oil and natural gas production and sales.

In the oil and natural gas exploration, development and production business, production is normally sold to relatively few customers. We currently export nearly all of our test production for sale in the world market. Currently, 99% of our production is being sold to one client, Titan Oil (formerly Euro-Asian Oil AG). Revenue from oil sold to Titan Oil made up 97% of our total revenue. The loss of Titan Oil may have a material adverse effect on our operations in the short-term. Based on current demand for crude oil and the fact that alternate purchasers are readily available, we believe the loss of Titan Oil would not materially adversely affect our operations long-term.

Distribution Method

Our crude oil exports are transported via the Aktau seaport to world markets. Pursuant to our agreement with Titan Oil, delivery is FCA (Incoterms 2000) at the railway station in Mangishlak. The oil is shipped via railway cars provided by Titan Oil. The volume and sales price are determined on a monthly basis, with all payments being covered by an irrevocable standby letter of credit opened through a first-class international bank. Sales price is based on the average quoted Brent crude oil price from Platt's Crude Oil Marketwire for the three days following the bill of lading date, less a discount for transportation expenses, freight charges and other expenses. The quality of crude oil supplied must meet minimum quality specifications.

Competition

Competition in Kazakhstan and Central Asia includes other junior hydrocarbons exploration companies, mid-size producers and major exploration and production companies. We compete for additional exploration and production properties with these companies, which in many cases have greater financial resources and larger technical staffs than we do.

We face significant competition for capital from other exploration and production companies and industry sectors. At times, other industry sectors may be more in favor with investors, limiting our ability to obtain necessary capital.

We believe we have a competitive advantage in Kazakhstan in that our management team is comprised of Kazakh nationals who have developed trusted relationships with many of the departments and ministries within the government of Kazakhstan.

Government Regulation

Our operations are subject to various levels of government controls and regulations in both the United States and Kazakhstan. We focus on compliance with all legal requirements in the conduct of our operations and employ business practices that we consider to be prudent under the circumstances in which we operate. It is not possible for us to separately calculate the costs of compliance with environmental and other governmental regulations as such costs are an integral part of our operations.

In Kazakhstan, legislation affecting the oil and gas industry is under constant review for amendment or expansion. Pursuant to such legislation, various governmental departments and agencies have issued extensive rules and regulations which affect the oil and gas industry, some of which carry substantial penalties for failure to comply. These laws and regulations can have a significant impact that can adversely affect our profitability by increasing the cost of doing business and by imposition of new taxes and duties, tax and duty rates and tax and duty schemes. Inasmuch as new legislation affecting the industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations.

In Kazakhstan, among the main laws on government controls and regulations applicable to the Company are: (1) Law “On subsoil and subsoil use” dated June 24, 2010, which governs subsoil use; (2) Law “On private entrepreneurship” dated January 31, 2006; and (3) Law “On state control and supervision in the Republic of Kazakhstan” dated January 6, 2011, which governs laws on state controls.

Governmental regulation is performed at both the central and local levels with scheduled and unscheduled inspections conducted by regulators. Most of Emir Oil’s in-person interaction with government regulators occurs with local state authorities because they have local departments in the region where Emir Oil is located. Central state authorities usually require only information and reports on compliance with legal requirements by Emir Oil.

Environmental Matters

Oil and gas operations are subject to numerous laws and regulations controlling the generation, use, storage and discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may:

•

require the acquisition of a permit or other authorization before construction or drilling commences;

•

restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, production, and natural gas processing activities;

•

suspend, limit or prohibit construction, drilling and other activities in certain lands lying within wilderness, wetlands, areas inhabited by threatened or endangered species and other protected areas;

•

require remedial measures to mitigate pollution from historical and on-going operations such as the use of pits and plugging of abandoned wells;

•

restrict injection of liquids into subsurface strata that may contaminate groundwater; and

•

impose substantial liabilities for pollution resulting from our operations.

Environmental permits that the operators of properties are required to possess may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations and permits, and violations are subject to injunction, civil fines and criminal penalties. Our management believes that we are in substantial compliance with current environmental laws and regulations, and that we will not be required to make material capital expenditures to comply with existing laws. Nevertheless, changes in existing environmental laws and regulations or interpretations thereof could have a significant impact on our operations as well as the oil and gas industry in general, and thus we are unable to predict the ultimate cost and effects of future changes in environmental laws and regulations.

Emir Oil is subject to a number of laws and regulations on environmental matters. Among them are the Ecology Code, Water Code, Land Code, Law on subsoil and subsoil use, Tax Code and others.

We are not currently involved in any administrative, judicial or legal proceedings arising under environmental protection laws and regulations, which would have a material adverse effect on our respective financial positions or results of operations. We do not maintain insurance against the costs of clean-up operations and we are not fully insured against all such risks. A serious incident of pollution may result in the suspension or cessation of operations in the affected area.

Employees

We have approximately 415 total employees, including approximately 382 full-time employees. From time to time we utilize the services of independent consultants and contractors to perform various professional services. Field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testing are generally provided by independent contractors.

Reports to Security Holders

We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and other items with the Securities and Exchange Commission (the “Commission”). We provide free access to all of these Commission filings, as soon as reasonably practicable after filing, on our Internet web site located at www.bmbmunai.com. In addition, the public may read and copy any documents we file with the Commission at its Public Reference Room at 100 F Street N.E., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the Commission at 1-800-SEC-0330. The Commission maintains its Internet web site at www.sec.gov, which contains reports, proxy and information statements and other information regarding issuers like BMB Munai.

Item 1A. Risk Factors

We operate in a challenging and highly competitive market. Listed below are some of the more critical or unique risk factors that we have identified as affecting or potentially affecting the Company and our business. You should consider these risks and the risks identified elsewhere in this annual report on Form 10-K and in the Notes to the Consolidated Financial Statements included in this report when evaluating our forward-looking statements and our Company. The effect of any one risk factor or a combination of several risk factors could materially affect our results of operations, financial condition and cash flows and the accuracy of any forward-looking statement made in this annual report on Form 10-K.

We will have limited continuing operations following the Sale.

We are a holding company and our primary operating asset is Emir Oil. Upon the closing of the Sale, we will no longer have substantial operations or assets. Following the closing, our existence will continue to (i) address existing Company liabilities, (ii) respond to indemnification claims made by Palaeontol in connection with the Purchase Agreement, and (iii) pay out the second distribution, if any, to our stockholders. Because of the limited continuing operations of the Company and limited capital, we may be unable to continue as a going concern, which will adversely impact our stockholders.

If the Sale is not consummated, we will have insufficient capital to run our business.

If the Sale is not consummated, we will continue to face significant operating and financial challenges, which include the insufficiency of capital to run our business. Our inability to raise the funding or to otherwise finance our capital needs will adversely affect our financial condition and our results of operations, and could prevent us from continuing our business. Given current equity and credit markets and our own financial condition, we have been unable to raise additional capital and we do not expect this to change. However, if we attempt to raise capital in the future through public and private equity offerings, debt financing or collaboration, or strategic alliances, such financing may not be available on terms that are favorable to us and/or our stockholders. In addition, if we raise additional capital through the sale of our common stock, stockholders’ ownership interests in the Company may be significantly diluted and the terms of the financing may adversely affect stockholders’ rights.

If the Sale is not consummated, we will be unable to pay off the Senior Notes.

If we do not complete the Sale, we will lack sufficient funds to retire the restructured Senior Notes when they become due. In this event, we would likely be required to consider liquidation alternatives, including the liquidation of our business under bankruptcy protection.

Certain conditions to completing the Sale are beyond our control.

There are certain conditions to closing that must be fulfilled before we can complete the Sale of Emir Oil that are beyond our control, such as timing and receipt of commercial production contracts on the Kariman, Dolinnoe and Aksaz fields, or receipt by Palaeontol of a valid work permit from the Kazakhstan Ministry of Labor and Social Protection. If these conditions to closing are not met or waived, we will be unable to complete the Sale and will be subject to all the risks discussed herein in the event the Sale is not consummated.

We will incur significant expenses in connection with the Sale and could be required to make significant payments if the Purchase Agreement is terminated under certain conditions.

We could be obligated to pay the Buyer a $17 million termination fee and/or to reimburse the Buyer up to $3.5 million for expenses if the Purchase Agreement is terminated under certain circumstances. In addition, we expect to pay legal and accounting fees whether the Sale closes or not. Any significant expenses or payment obligations incurred by us in connection with the Sale could adversely affect our financial condition and cash position.

We will not realize the benefits of the reserves being sold through Emir Oil.

We have expended considerable resources conducting exploratory drilling and testing to establish the existence of commercially producible reserves in four of the ten identified structures within the Contract Area, as required under our existing exploration contract. If the Sale is consummated, we will not realize the financial benefits from any commercially producible reserves existing in any of the six remaining structures. In addition, Palaeontol will realize all benefits attributable to our previous drilling and testing of the four established fields.

The amount of the second distribution is an estimate and the second distribution, if any, may be much lower than anticipated.

The amount of the anticipated second distribution to our stockholders is an estimate that remains subject to various adjustments, including, but not limited to, (i) fees and expenses incurred in connection with the consummation of the Sale and transactions in furtherance thereof, (ii) payment of our other debts, obligations and liabilities, (iii) payments to Messrs. Tolmakov and Cherdabayev of their deferred distribution amounts and payment to Mr. Cherdabayev of his extraordinary event payment, (iv) the repayment of the Senior Notes, and (v) the availability of funds to be released from the escrow, which is subject to certain indemnification claims for a minimum twelve-month period. Because of the uncertainty of these adjustments, stockholders may not receive a second distribution, or the second distribution may be considerably lower than estimated.

If the Sale is not consummated, our ability to obtain additional financing or use our operating cash flow to fund operations may be adversely affected by our level of indebtedness.

If the Sale is not consummated, our level of indebtedness could have negative consequences, which include, but are not limited to, the following:

	•	our ability to obtain additional financing to fund capital expenditures, acquisitions, working capital, repay debts or for other purposes may be impaired;
	•	our ability to use operating cash flow in other areas of our business may be limited because we must dedicate a substantial portion of these funds to repay debt obligations;
	•	we may be unable to compete with others who may not be as highly leveraged; and
	•	our debt may limit our flexibility to adjust to changing market conditions, changes in our industry and economic downturns.

The financial crisis and economic conditions have and may continue to have a material adverse impact on our business and financial condition.

The global financial markets have experienced a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in prices of securities, diminished liquidity and credit availability, inability to access capital, bankruptcy, failure, collapse or sale of financial institutions and an unprecedented level of intervention from the U.S. federal government and other governments. In particular, the cost of raising money in the debt and equity capital markets has increased while the availability of funds from those markets generally has diminished. As a result of the concerns about the stability of financial markets generally and the solvency of existing debtors specifically, the cost of obtaining money from credit markets has increased. Many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity and have either reduced or, in many cases, ceased to provide any new funding.

If we are unable to complete the Sale, current economic conditions could materially adversely affect our business in, among other, the following ways:

		•	our ability to obtain credit and access the capital markets may continue to be restricted adversely affecting our financial position and our ability to continuing exploration and drilling activities on our territory;
		•	the values we are able to realize in transactions we engage in to raise capital may be reduced, thus making these transactions more difficult to consummate and more dilutive to our shareholders; and
		•	the demand for oil and natural gas may decline due to weak international economic conditions.

We may not be able to replace our reserves or generate cash flows if we are unable to raise capital.

If we do not consummate the Sale, and continue our oil and gas operations, we will need to make substantial capital expenditures for the exploration, development, production and acquisition of oil and gas reserves and the construction of additional facilities. These capital expenditures may include capital expenditures associated with drilling and completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved properties or our proved reserves to the extent such additions maintain our asset base. These expenditures could increase as a result of:

	•	changes in our reserves;
	•	changes in oil and gas prices;
	•	changes in labor and drilling costs;
	•	our ability to acquire, locate and produce reserves;
	•	changes in license acquisition costs; and
	•	government regulations relating to safety and the environment.

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

	•	our proved reserves;
	•	the success or our drilling efforts;
	•	the level of oil and gas we are able to produce from existing wells;
	•	the prices at which our oil and gas is sold; and
	•	our ability to acquire, locate and produce new reserves.

Historically, we have financed these expenditures primarily with cash raised through the sale of our equity and debt securities and revenue generated by operations. If our revenues or borrowing base decreases, which is expected, as a result of higher than anticipated decline curves, lower production, lower oil and natural gas prices, operating difficulties or declines in reserves, we may have limited ability to expend the capital necessary to undertake or complete future drilling programs. Additional debt or equity financing or cash generated by operations may not be available to meet these requirements. We anticipate that if we do not consummate the Sale we will not have enough capital available during the upcoming fiscal year to make substantial capital expenditures.

Oil and gas prices are characteristically volatile, and if they remain low for a prolonged period, our revenues, profitability and cash flows will decline. A sustained period of low oil and natural gas prices would adversely affect our business operations, our asset values and our financial condition and ability to meet our financial commitments.

The price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth. The prices we receive for our production, and the levels of our production, depend on a variety of factors that are beyond our control, such as:

	•	the domestic and foreign supply of and demand for oil and natural gas;
	•	the price and level of foreign imports of oil and natural gas;
	•	the level of consumer product demand;
	•	weather conditions;
	•	overall domestic and global economic conditions;
	•	political and economic conditions in oil and gas producing countries, including embargoes and continued hostilities in the Middle East and other sustained military campaigns, acts of terrorism or sabotage;
	•	actions of the Organization of Petroleum Exporting Countries and other state-controlled oil companies relating to oil price and production controls;
	•	the impact of the U.S. dollar exchange rates on oil and gas prices;
	•	technological advances affecting energy consumption;
	•	domestic and foreign governmental regulations and taxation;
	•	the impact of energy conservation efforts;
	•	the costs, proximity and capacity of gas pipelines and other transportation facilities; and
	•	the price and availability of alternative fuels.

Our revenue, profitability and cash flow depend upon the prices and demand for oil and gas, and a drop in prices can significantly affect our financial results and impede our growth. In particular, price declines or sustained low prices for oil and gas will:

	•	negatively impact the value of our reserves because declines in oil and natural gas prices would reduce the amount of oil and natural gas we can produce economically;
	•	reduce the amount of cash flow available for capital expenditures; and
	•	limit our ability to borrow money or raise additional capital.

Future price declines may result in a write-down of our asset carrying values.

Lower oil and natural gas prices may not only decrease our revenues, profitability and cash flows, but also reduce the amount of oil and gas that we can produce economically. This may result in downward adjustments to our estimated proved reserves. Substantial decreases in oil and gas prices could render future exploration and development projects uneconomical. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our properties for impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and may, therefore, require a write-down of such carrying value. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred and on our ability to borrow funds under our credit agreements.

Unless we replace our oil and natural gas reserves, our reserves and future production will decline, which would adversely affect our cash flows and income.

Unless we conduct successful development, exploration and exploitation activities, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our oil and natural gas reserves and production, and, therefore our cash flow and income, are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves.

Drilling for and producing oil and gas is a costly and high-risk activity with many uncertainties that could adversely affect our financial condition or results of operations.

Our drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. The cost of drilling, completing and operating a well is often uncertain, and cost factors, as well as the market price of oil and natural gas, can adversely affect the economics of a well. Furthermore, our drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

	•	high costs, shortages or delivery delays of drilling rigs, equipment, labor or other services;
	•	adverse weather conditions;
	•	equipment failures or accidents;
	•	pipe or cement failures or casing collapses;
	•	compliance with environmental and other governmental requirements;
	•	environmental hazards, such as gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;
	•	lost or damaged oilfield drilling and service tools;
	•	loss of drilling fluid circulation;
	•	unexpected operational events and drilling conditions;
	•	unusual or unexpected or difficult geological formations;
	•	natural disasters, such as fires;
	•	blowouts, surface cratering and explosions; and
	•	uncontrollable flows of oil, gas or well fluids.

A productive well may become uneconomical in the event deleterious substances are encountered which impair or prevent the production of oil or gas from the well. In addition, production from any well may be unmarketable if it is contaminated with water or other substances. We may drill wells that are unproductive or, although productive, do not produce oil or gas in economic quantities. Unsuccessful drilling activities could result in higher costs without any corresponding revenues. Furthermore, the successful completion of a well does not ensure a profitable return on the investment.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the size and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves shown in this report.

In order to prepare estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this report. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our proved reserves referred to in this report is the current market value of our estimated oil and natural gas reserves. In accordance with Commission requirements, we generally base the estimated discounted future net cash flows from our proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. If future values decline or costs increase, it could have a negative impact on our ability to finance operations; individual properties could cease being commercially viable; affecting our decision to continue operations on producing properties or to attempt to develop properties. All of these factors would have a negative impact on earnings and net income, and most likely the trading price of our securities.

If we do not complete the Sale, we will be unable to produce up to 83% of our proved reserves if we are not able to obtain a commercial production contract or extend our current exploration contract, which would likely require us to terminate our operations.

Under our exploration contract on our properties we have the rights to produce oil and gas only until January 2013, yet 83% of our proved reserves are scheduled to be produced after January 2013. We have the exclusive right to negotiate a commercial production contract as per the terms of our exploration contract. If we do not complete the Sale and are not granted commercial production rights prior to the expiration of our exploration contract, we may lose our right to produce the reserves on our current properties. If we are unable to produce those reserves, we will be unable to realize revenues and earnings and to fund operations and we would most likely be unable to continue as a going concern.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

	•	environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;
	•	abnormally pressured formations;
	•	mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
	•	fires and explosions;
	•	personal injuries and death; and
	•	natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses. In instances when we believe that the cost of available insurance is excessive relative to the risks presented we may elect not to obtain insurance. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs that is not fully covered by insurance, it could adversely affect us.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and natural gas are subject to extensive governmental regulation. We may be required to make large expenditures to comply with these regulations. Matters subject to regulation include:

	•	discharge permits for drilling operations;
	•	reports concerning operations;
	•	the spacing of wells;
	•	unitization and pooling of properties; and
	•	taxation.

Under these laws, we could be liable for personal injuries, property damage and other damages. Failure to comply with these laws may also result in the suspension or termination of our licenses or operations and could subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations. We believe that there is political and legal risk doing business in Kazakhstan, as the country is still in the process of developing stable and predictable laws required to underpin a free market economy and foster private enterprise.

We may incur substantial liabilities to comply with environmental laws and regulations.

Our oil and natural gas operations are subject to governmental laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of permits before drilling commences, restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities and impose substantial liabilities for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of investigatory or remedial obligations or even injunctive relief. Changes in environmental laws and regulations occur frequently. Any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to maintain compliance, and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition as well as on the industry in general. Under these environmental laws and regulations, we could be held strictly liable for the removal or remediation of previously released materials or property contamination regardless of whether we were responsible for the release or whether our operations were standard in the industry at the time they were performed.

Because of our lack of asset and geographic diversification, adverse developments in our operating area would adversely affect our results of operations.

Substantially all of our assets are located in southwestern Kazakhstan. As a result, our business is disproportionately exposed to adverse developments affecting this region. These potential adverse developments could result from, among other things, changes in governmental regulation, capacity constraints with respect to storage facilities, transportation systems and pipelines, curtailment of production, natural disasters or adverse weather conditions in or affecting these regions. Due to our lack of diversification in asset type and location, an adverse development in our business or the area in which we operate would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

The unavailability or high price of transportation systems could adversely affect our ability to deliver our oil on terms that would allow us to operate profitably, or at all.

Because of the location of our properties, the crude oil we produce must be transported by truck or by rail. In the future it will likely also be transported by pipelines. These railways and pipelines are operated by state-owned entities or other third-parties, and there can be no assurance that these transportation systems will always be functioning and available, or that the transportation costs will not become cost prohibitive. In addition, any increase in the cost of transportation or reduction in its availability to us could have a material adverse effect on our results of operations. There is no assurance that we will be able to procure sufficient transportation capacity on economical terms, if at all.

We depend on one customer for sales of crude oil. A reduction by this customer in the volumes of oil it purchases could result in a substantial decline in our revenues and net income.

During the year ended March 31, 2011, we sold approximately 99% of our crude oil production to Titan Oil. Revenue from oil sold to Titan Oil made up 97% of our revenue during the year ended March 31, 2011. The loss of Titan Oil may have a material adverse effect on our operations in the short-term. Based on current demand for crude oil and the fact that alternate purchasers are readily available, we believe the loss of Titan Oil would not materially adversely affect our operations long-term.

If you purchase shares of our stock, your investment will be subject to the same risks inherent in international operations, including, but not limited to, adverse governmental actions, political risks, and expropriation of assets, loss of revenues and the risk of civil unrest or war.

While we have significant experience working in Kazakhstan, and feel we have good relationships with government agencies at many levels, we remain subject to all the risks inherent in international operations, including adverse governmental actions, uncertain legal and political systems, and expropriation of assets, loss of revenues and the risk of civil unrest or war. Our primary oil and gas properties are located in Kazakhstan, which until 1990 was part of the Soviet Union. Kazakhstan retains many of the laws and customs of the former Soviet Union, but has and is continuing to develop its own legal, regulatory and financial systems. As the political and regulatory environment changes, we may face uncertainty about the interpretation of our agreements; in the event of dispute, we may have limited recourse within the legal and political system.

Prior to the expiration of our exploration rights, we must make application for commercial production rights to the extent we have established commercially producible reserves on our properties. We have the exclusive right to negotiate a commercial production contract for the ADE Block, the Southeast Block and the Northwest Block and the government is required to conduct these negotiations under the “Law of Petroleum” in Kazakhstan. The terms of the commercial production contract will establish the Mineral Extraction Tax, Rent Export Tax and other payments due to the government in connection with commercial production. At the time the commercial production contract is issued, we will be required to begin repaying the government its historical investment costs of exploration and development of the ADE Block, the Southeast Block and the Northwest Block, as well as a Commercial Discovery Bonus. The historical investment costs associated with the ADE Block, the Southeast Block and the Northwest Block are approximately $6 million, $5.3 million and $5.4 million, respectively. We currently do not know the amount of any required Commercial Discovery Bonus, but anticipate it could be as high as $10 million. If satisfactory terms for commercial production rights cannot be negotiated, it could have a material adverse effect on our financial position.

Risks Relating to Our Common Stock

Our common stock price will decline.

Since the announcement of the pending Sale, the price of our common stock has been, and is likely to continue to be, volatile, which means that it could decline substantially within a short period of time. If the Sale closes, because of our limited continuing operations thereafter, an active and liquid market for our common stock will not be sustained, which will depress the trading price of our common stock. A significant decline in our common stock price may result in substantial losses for individual stockholders if they trade prior to closing of the Sale transaction, and may lead to securities litigation against the Company, which could result in substantial costs to the Company.

The NYSE Amex will likely determine that we are operating as a “public shell” and delist us.

While the NYSE Amex has no bright-line test for determining whether a particular company is a “public shell,” the exchange has expressed the opinion that the securities of companies operating as “public shells” may be subject to market abuses or other violative conduct that is detrimental to the interests of the investing public. The Commission has defined a public shell as a company with no or nominal operations and either no or nominal assets, assets consisting solely of cash and cash equivalents, or assets consisting of any amount of cash and cash equivalents and nominal other assets. The NYSE Amex may perform a facts and circumstances analysis to determine whether they believe that we are a “public shell.” Listed companies determined to be public shells by the NYSE Amex may be subject to delisting proceedings or additional and more stringent continued listing criteria. Listed companies determined to be public shells by the Commission will be subject to more stringent regulation and disclosure requirements and shares of common stock of such companies will be more difficult to sell.

If our common stock is subject to the Commission’s penny stock rules, broker-dealers may experience difficulty in completing customer transactions and trading activity in our securities may be adversely affected.

If at any time we have net tangible assets of $5.0 million or less and our common stock has a market price per share of less than $5.00, transactions in our common stock may be subject to the “penny stock” rules promulgated under the Exchange Act. Under these rules, broker-dealers who recommend such securities to persons other than institutional accredited investors must:

	•	make a special written suitability determination for the purchaser;
	•	receive the purchaser’s written agreement to a transaction prior to sale;
	•	provide the purchaser with risk disclosure documents that identify certain risks associated with investing in “penny stocks” and that describe the market for the “penny stocks,” as we as a purchaser’s legal remedies: and
	•	obtain a signed and dated acknowledgement from the purchaser demonstrating that the purchase has actually received the required risk disclosure document before a transaction in a “penny stock” can be completed.

If our common stock is subject to these rules, broker-dealers may find it difficult to effect customer transactions and trading activity in our securities may be adversely affected. As a result, the market price of our securities may be depressed, and you may find it more difficult to sell our securities.

Item 1B. Unresolved Staff Comments

As a Smaller Reporting Company as defined by Rule 12b-2 of the Exchange Act and in Item 10(f)(1) of Regulation S-K, we are electing scaled disclosure reporting obligations and therefore are not required to provide the information requested by this Item.

Item 2. Properties

Our properties comprise an 850 contiguous square kilometer area in the Mangistau Region of southwestern Kazakhstan.

Exploratory and Developmental Acreage

The following table summarizes our gross and net developed and undeveloped mineral acreage by block at March 31, 2011.

	Developed		Undeveloped		Total
	Gross	Net	Gross	Net	Gross	Net
ADE Block	990	990	46,765	46,765	47,755	47,755
Southeast Block	750	750	65,165	65,165	65,915	65,915
Northwest Block	-	-	96,370	96,370	96,370	96,370

Development of Oil and Gas Properties in Kazakhstan

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

Emir Oil holds a 100% interest in both a license to use subsurface mineral resources and a hydrocarbon exploration contract issued by the ROK in 1999 and 2000, respectively (collectively referred to herein as the “license” or the “exploration contract”). The exploration and development stage of our exploration contract expires in January 2013.

This exploration contract originally granted us the right to engage in exploration and development activities in an area of approximately 200 square kilometers referred to herein as the ADE Block. The ADE Block is comprised of three fields, the Aksaz, Dolinnoe and Emir fields. During our 2006 fiscal year our exploration contract was expanded to include an additional 260 square kilometers of land adjacent to the ADE Block, which we refer to herein as the Southeast Block, which includes the Kariman oil and gas field and the Borly and Yessen structures. In October 2008 the MEMR (as defined herein) granted us an additional 390 square kilometer area, referred to herein as the Northwest Block bringing our total contract area to 850 square kilometers (approximately 210,000 acres). The Northwest Block extends north and west from the ADE Block toward the Caspian Sea. The Southeast Block and the Northwest Block are governed by the terms of our exploration contract.

In order to be assured that adequate exploration activities are undertaken during exploration stage, the MOG establishes an annual mandatory minimum work program to be accomplished in each year of the exploration contract. Under the minimum work program the contractor is required to invest a minimum dollar amount in exploration activities within the contract territory, which may include geophysical studies, construction of field infrastructure or drilling activities. During the exploration stage, the contractor is also required to drill sufficient wells in each field to establish the existence of commercially producible reserves in any field for which it seeks a commercial production license. Failure to complete the minimum work program requirements for any particular field during the term of the exploration contract could preclude the contractor from receiving a longer-term production contract for such field and result in relinquishment of the field back to the ROK, regardless of the success of the contractor in proving commercial reserves during the partial fulfillment of the minimum work program.

The contract we hold follows the above format. The contract sets the minimum dollar amount we must expend during each year of our work program. Our work program year ends on January 9 of each year through January 9, 2013. Therefore our work program year does not coincide with our fiscal year. As a result of these timing differences, the amounts reflected in the table below as “Actually Made” may differ from amounts disclosed in this report in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations or the consolidated financial statements included in this report, which present figures based on our fiscal year rather than our work program year.

Amount of Expenditure	Mandated by Contract	Actually Made
Prior to January 2010	$ 59,090,000	$280,660,000
January 2010 to January 2011	$ 21,540,000	$ 56,650,000
January 2011 to January 2012	$ 27,240,000	$ 14,530,000*
January 2012 to January 2013	$ 14,840,000	$ -
Total	$ 122,710,000	$ 351,840,000

* Investment as of March 31, 2011.

Under the rules of the MOG there is a process whereby expenditures above the minimum requirements in one period may be carried over to meet minimum obligations in future periods. As the above chart shows we have significantly exceeded the minimum expenditure requirement in each period of the contract and have more than doubled the total minimum capital expenditure requirement during the exploration stage.

In addition to mandatory minimum capital expenditures in each year, exploration contracts typically require the contract holder to drill a certain number of wells in each structure for which it plans to seek commercial production rights.

Typically, one exploratory well and two appraisal wells are sufficient to support a claim of commercially producible reserves in a particular field, although in some cases, commercial reserves have been demonstrated with fewer wells. The total number of wells the MOG requires during exploration stage is generally determined by the number of fields or structures identified by the seismic studies done on a territory. Three dimensional ("3D") seismic studies completed on the ADE Block and the Southeast Block, have identified six potential fields or structures.

Chapman Petroleum (as defined herein) has identified four potential structures in the Northwest Block territory based principally on interpretation of recently completed 3D seismic studies in the Northwest Block territory.

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

Structures	Aksaz	Dolinnoe	Emir	Kariman	Borly	Yessen	Northwest Block(1)
Exploratory Wells	1	1	1	1	1	1	4
Appraisal Wells	2	2	2	2	2	2	8

Existing Wells	5	6	3	10	0	0	0
Wells in Progress	0	0	0	0	0	0	0
Remaining Wells to Drill by 2013	0	0	0	0	3	3	12

(1) Addendum No. 6 to our exploratory contract requires the drilling of three exploratory wells. Based on our experience, however, we assume we will need to drill a minimum of one exploratory well and two appraisal wells in each of the four potential structures identified in the Northwest Block by Chapman Petroleum Engineering to determine whether commercially producible reserves exist in any of the potential structures.

The bottom half of the above chart shows current progress on drilling of exploratory and appraisal wells.

Pursuant to the terms of the extensions of our exploration contract, we are required to drill not less than nine new wells by January 9, 2013. With the identification of four potential structures in the Northwest Block, we anticipate that well drilling requirement will increase significantly if we are to determine the existence of commercially producible reserves in any of the possible structures in the Northwest Block. Due to the difficult financial situation we have faced the past fiscal year, we were unable to drill any new wells. We do not expect our financial situation to improve sufficiently to allow us to complete our exploration obligations prior to January 2013. In addition to these drilling obligations, once a contractor moves to commercial production, it becomes subject to a new work program designed to maximize production. This new work program imposes additional drilling and development obligations. Given our financial situation, we do not anticipate being able to satisfy the drilling requirements of a commercial production work program, which likely would result in the loss of any commercial production contract we would have been awarded. These factors contributed to our decision to sell our interest in Emir Oil.

Drilling Operations

Over the past fiscal year we have concentrated our operational efforts on stabilizing and maintaining production through work with our existing wellstock, including sidetracking operations. We have utilized services of XIBU Drilling services and Frac Jet Drilling and Workover Company for these purposes.

During the fourth fiscal quarter, in January 2011 we commenced sidetracking at the Dolinnoe 6 well location. The kick off point for the sidetrack was at the depth of 3,140-3,142 m. The sidetrack was drilled to 3,932 m. We have experienced high gas readings while drilling and at the bottom of the well (gas was 100%, methane 40%). The well was completed in April 2011.

Subsequent to the end of the fourth fiscal quarter, in April 2011 we commenced the sidetrack for the Dolinnoe 2 well. The window was milled at the depth of 3,411-3,440 m. The sidetrack was successfully completed to a depth of 3,736m in April 2011.

In February 2011 Frac Jet Drilling and Workover Company commenced a sidetrack on the Kariman 11 well. The window was milled at the depth of 3,309-3,314.8m. We experienced a number of technical difficulties while drilling this section which forced us to re-mill a new window at the depth of 3,299.96m. Drilling of this well was completed successfully in April 2011.

We have also made much progress in eventual transition of a portion of our existing assets to commercial production. Transition of the Aksaz, Dolinnoe and Kariman wells to commercial production is one of the conditions to closing the Sale. We have successfully proved reserves related to the above-mentioned three fields with the Geological Committee of the MOG. Subsequently the technical scheme was developed by our design institute and was also successfully approved by the Government. Currently we are awaiting approval on the working program and feasibility study by the MOG which has to be subsequently reviewed and approved by various ministries and agencies in Kazakhstan before commercial production for Aksaz, Dolinnoe and Kariman can be signed. We expect this process to be completed in the third calendar quarter 2011.

Chapman Petroleum, our independent reserve engineers, has confirmed the presence and identification of at least four structures on the territory of the Northwest block. Our further activities related to the Northwest block will depend on the results of the pending Sale. If the Sale does not close for whatever reason we anticipate we will use internally generated cash flow or will seek alternative funding to commence exploration drilling in the Northwest block.

Well Performance and Production

The following table sets forth our gross and net working interests in exploratory and development wells drilled during the three years ended March 31, 2011, 2010 and 2009:

	2009		2010		2011
	Gross	Net	Gross	Net	Gross	Net
Exploratory
Productive
Oil	18	18	24	24	24	24
Gas	-	-	-	-	-	-
Dry wells	-	-	-	-	-	-
Total	18	18	24	24	24	24
Development
Productive
Oil	-	-	-	-	-	-
Gas	-	-	-	-	-	-
Dry wells	-	-	-	-	-	-
Total	-	-	-	-	-	-

As of the fiscal year ended March 31, 2011, each of the 24 wells identified above was in test production, testing or under or awaiting workover. Each of the above listed wells is Company operated.

According to the laws of the Republic of Kazakhstan, we are required to test every prospective target on our properties separately; this includes the completion of well surveys on different modes with various choke sizes on each horizon.

In the course of well testing, when the transfer from target to target occurs, the well must be shut in; oil production ceases for the period of mobilization/demobilization of the workover rig, pull out of the hole, run in the hole, perforation, packer installation time, etc. This has the effect of artificially diminishing production rates averaged over a set period of time.

During our fourth fiscal quarter 2011, our average daily crude oil production was 2,381 barrels per day. Following is a brief description of the production rates of each of our 24 wells during the fiscal year ended March 31, 2011.

Well	Single Interval Production Rate for the year ended March 31, 2011	Average Daily Production Rate for the quarter ended March 31, 2011	Diameter Choke Size

Aksaz -1	5 - 63 bpd	25 - 31 bpd	5 mm
Aksaz -2	0 - 6 bpd	0 bpd	4 mm
Aksaz-3	31 - 465 bpd(1)	277 - 327 bpd(1)	7 mm
Aksaz -4	9 - 126 bpd(1)	50 - 57 bpd(1)	8 mm
Aksaz -6	4 - 31 bpd	13 - 25 bpd	5 mm
Dolinnoe -1	0 - 220 bpd(2)	75 - 157 bpd(2)	6 mm
Dolinnoe -2	8 - 176 bpd	63 - 82 bpd	15 mm
Dolinnoe -3	0 - 415 bpd(1)	0 - 415 bpd(1)	12 mm
Dolinnoe -5	0 bpd	0 bpd	0 mm
Dolinnoe -6	0 - 69 bpd(2)	0 bpd(2)	16 mm
Dolinnoe -7	44 - 233 bpd	88 - 94 bpd	8 mm
Emir -1	0 bpd(3)	0 bpd(3)	0 mm
Emir - 2	0 bpd(3)	0 bpd(3)	0 mm
Emir -6	0 bpd(3)	0 bpd(3)	0 mm
Kariman -1	0 - 1,396 bpd(4)	138 - 509 bpd(4)	9 mm
Kariman -2	90 - 579 bpd(4)	377 - 579 bpd(4)	16 mm
Kariman -3	0 - 220 bpd(1)	88 - 170 bpd(1)	5 mm
Kariman -4	6 - 1,214 bpd(4)	38 - 1,214 bpd(4)	14 mm
Kariman -5	0 - 176 bpd(2)	19 - 176 bpd(2)	5 mm
Kariman -6	0 - 82 bpd(4)	0 bpd(4)	2 mm
Kariman -7	0 - 333 bpd(1)	0 - 270 bpd(1)	9 mm
Kariman -8	40 - 384 bpd(4)	75 - 208 bpd(4)	22 mm
Kariman -10	13 - 270 bpd(4)	13 - 270 bpd(4)	13 mm
Kariman-11	13 - 270 bpd(2)	13 - 270 bpd(2)	9 mm

(1)	We have performed acid treatment at these wells.
(2)	We have performed workover at these wells and moved to new horizons.
(3)	Emir wells are on temporary abandonment as the Company is planning for submission of an application for pilot development project for this field.
(4)	We have installed centrifugal submersible pumps at these wells. After a brief period of testing and fine tuning, production from this well stabilized. Stabilized production rates are included in the table above.

Proved Reserves Disclosures

Recent Commission Rule-Making Activity. In December 2008, the Commission announced that it had approved revisions to modernize the oil and gas reserve reporting disclosures. The new disclosure requirements include provisions that:

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

·	Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices.

·	Permit companies to disclose their probable and possible reserves on a voluntary basis. In the past, proved reserves were the only reserves allowed in the disclosures. We have chosen not to make disclosure under these categories.

·	Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.

·	Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

·	Replace the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test.

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures regarding internal controls over reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.

We adopted the rules effective March 31, 2011.

The new rule does not allow for prior-year reserve information to be restated, so all information related to periods prior to 2011 is presented consistent with prior Commission rules for the estimation of proved reserves.

Oil and Natural Gas Reserves

The following table sets forth our estimated net proved oil and natural gas reserves and the standardized measure of discounted future net cash flows related to such reserves as of March 31, 2011. The standardized measure of discounted future net cash flows is not intended to represent the current market value of our estimated oil and natural gas reserves. The oil and natural gas reserve data included in, or incorporated by reference in this document, are only estimates and may prove to be inaccurate.

	Proved reserves to be recovered by January 9, 2013(1)		Proved reserves to be recovered after January 9, 2013(1)
	Developed(2)	Undeveloped(3)	Developed(2)	Undeveloped(3)	Total
Oil and condensate (MBbls)(4)	4,025	8	16,893	2,582	23,508
Natural gas (MMcf)	5,223	19	18,218	3,954	27,414
Total MBOE(5)	4,896	11	19,929	3,241	28,077

Standardized Measure of discounted future net cash flows(6) (in thousands of U.S. Dollars)					$ 392,437

(1)

Under our exploration contract we have the right to sell the oil and natural gas we produce while we undertake exploration stage activities within our licensed territory. As discussed in more detail in “Risk Factors” and “Properties” we have the right to engage in exploration stage activities until January 9, 2013. To retain our rights to produce and sell oil and natural gas after that date, we must apply for and be granted commercial production rights by no later than January 2013 or obtain a further extension of our exploration contract. If we are not granted commercial production rights or another extension by that time, we would expect to lose our rights to the licensed territory and would expect to be unable to produce reserves after January 2013.

(2)	Proved developed reserves are proved reserves that are expected to be recovered from existing wells with existing equipment and operating methods.

(3)	Proved undeveloped reserves are proved reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

(4)	Includes natural gas liquids.

(5)	The coefficient for conversion of production and sales of gas from cubic meters to barrels equals: 1 thousand m3 = 5.8857 barrels of oil equivalent.

(6)	The standardized measure of discounted future net cash flows represents the present value of future net cash flow net of all taxes.

As of March 31, 2011 our estimated proved reserves had a pre-tax PV10 value of approximately $545.6 million and a standardized measure of discounted future cash flows of approximately $392.4 million.

The following table summarizes our total net proved reserves, pre-tax PV10 value and Standardized Measure of Discounted Future Net Cash Flows as of March 31, 2011.

	Oil (Bbl)	Pre-Tax PV10 Value	Standardized Measure of Discounted Future Net Cash Flows
Oil and condensate (MBbls)(4)	23,508	$ 531,429	$ 382,234
Natural gas (MMcf)	27,414	$ 14,165	$ 10,203
Total MBOE	28,077	$ 545,594	$ 392,437

Proved Undeveloped Reserves

Our reserve estimates as of March 31, 2011 and 2010 include 3.2 million and 2.6 million BOE of proved undeveloped reserves, respectively. The change in proved undeveloped reserves during the year ended March 31, 2011 was due to the increase of proved undeveloped reserves of oil in the amount of 81,000 BOE and an increase in proved undeveloped reserves of gas in the amount of 601,000 BOE. We did not incur capital expenditures for conversion of proved undeveloped reserves to proved developed reserves as of year ended March 31, 2011.

Internal Controls Over Reserves Estimates.

We engaged Chapman Petroleum Engineering, Ltd. (“Chapman Petroleum”), to estimate our net proved reserves, projected future production and the standardized measure of discounted future net cash flows as of March 31, 2011. Chapman Petroleum’s estimates are based upon a review of production histories and other geologic, economic, ownership and engineering data provided by us. Chapman Petroleum has independently evaluated our reserves for the past several years. In estimating the reserve quantities that are economically recoverable, Chapman Petroleum used oil and natural gas prices in effect as of March 31, 2011 without giving effect to hedging activities. In accordance with requirements of Commission regulations, no price or cost escalation or reduction was considered by Chapman Petroleum. Our reserves estimates are reviewed and approved by our Chief Executive Officer and our President. Our Chief Financial Officer reviews the reserves estimates to assure compliance with Commission reporting requirements. A letter which identifies the professional qualifications of the individual who was responsible for overseeing the preparation of our reserve estimates as of March 31, 2011 has been filed as Exhibit 99.1 to this report.

Cost Information

Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves

The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped or proved developed non-producing to proved developed, as well as the estimated costs per year involved in such development.

Year	Total BOE	Estimated Development Costs
2012	12,804,000	8,100,000
2013	105,000	800,000
2014	3,172,000	25,500,000
2015	-	-
2016	-	-

The reserve data set forth herein represents estimates only. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimates, and such revisions may be material. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Furthermore, the estimated future net revenue from proved reserves and the present value thereof are based upon certain assumptions, including current prices, production levels and costs that may vary from what is actually incurred or realized.

No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Commission.

In accordance with Commission regulations, the Chapman Petroleum Report used oil and natural gas average prices in effect during the year ended March 31, 2011. The prices used in calculating the standardized measure of discounted future net cash flows attributable to proved reserves do not necessarily reflect market prices for oil and natural gas production subsequent to March 31, 2011. There can be no assurance that all of the proved reserves will be produced and sold within the periods indicated, that the assumed prices will actually be realized for such production or that existing contracts will be honored or judicially enforced.

Capitalized Costs

Capitalized costs and accumulated depletion, depreciation and amortization relating to our oil and natural gas producing activities, all of which are conducted in the Republic of Kazakhstan, are summarized below:

	As of March 31, 2011	As of March 31, 2010

Developed oil and natural gas properties	$ 281,183,314	$ 246,979,803
Unevaluated oil and natural gas properties	26,402,637	25,924,087
Accumulated depletion, depreciation and amortization	(44,634,163)	(34,302,048)
Net capitalized cost	$ 262,951,788	$ 238,601,842

Exploration, Development and Acquisition Capital Expenditures

The following table sets forth certain information regarding the total costs incurred associated with exploration, development and acquisition activities.

	For the year ended March 31, 2011	For the year ended March 31, 2010	For the year ended March 31, 2009

Acquisition costs:
Unproved properties	$ -	$ -	$ -
Proved properties	-	-	-
Exploration costs	7,079,146	-	2,275,021
Development costs	27,602,916	10,949,019	63,727,311
Subtotal	34,682,062	10,949,019	66,002,332
Asset retirement costs	-	-	86,438
Total costs incurred	$ 34,682,062	$ 10,949,019	$ 66,088,770

Oil and Natural Gas Volumes, Prices and Operating Expense

The following table sets forth certain information regarding production volumes, average sales price and average operating expense associated with our sale of oil and natural gas for the periods indicated.

	For the Year Ended March 31, 2011	For the Year Ended March 31, 2010	For the Year Ended March 31, 2009
Production:
Oil and condensate (Bbls)	869,208	1,016,221	1,080,895
Natural gas liquids (Bbls)	-	-	-
Natural gas (thousand m3)	39,048	-	-
Barrels of oil equivalent (BOE)	1,099,030	1,016,221	1,080,895

Sales(1)(3):
Oil and condensate (Bbls)	853,956	1,036,070	1,073,754
Natural gas liquids (Bbls)	-	-	-
Natural gas (thousand m3)	33,856	-	-
Barrels of oil equivalent (BOE)	1,053,223	1,036,070	1,073,754

Average Sales Price(1):
Oil and condensate ($ per Bbl)	$ 73.82	$ 55.28	$ 64.84
Natural gas liquids ($ per Bbl)	$ -	$ -	$ -
Natural gas ($ per thousand m3)	$ 40.83	$ -	$ -
Barrels of Oil equivalent ($ per BOE)	$ 61.16	$ 55.28	$ 64.84

Average oil and natural gas operating expenses including production and ad valorem taxes ($ per BOE)(2)(3)	$ 9.05	$ 8.27	$ 7.01

(1)	During the years ended March 31, 2011, 2010 and 2009, the Company has not engaged in any hedging activities, including derivatives.
(2)	Includes transportation cost, production cost and ad valorem taxes (except for rent export tax and export duty).
(3)	We use sales volume rather than production volume for calculation of per unit cost because not all volume produced is sold during the period. The related production costs were expensed only for the units sold, not produced based on a matching principle of accounting. Therefore, oil and gas operating expense per BOE was calculated by dividing oil and gas operating expenses for the year by the volume of oil sold during the year.
(4)	The coefficient for conversion of production and sales of gas from cubic meters to barrels equals: 1 thousand m3 = 5.8857 barrels of oil equivalent.

Office Facilities

Our principal executive and corporate offices are located in an office building located at 202 Dostyk Avenue, in Almaty, Kazakhstan. We lease this space and believe it is sufficient to meet our needs for the foreseeable future.

We also maintain an administrative office in Salt Lake City, Utah. The address is 324 South 400 West, Suite 255, Salt Lake City, Utah 84101, USA.

Item 3. Legal Proceedings

See Note 12 “Commitments and Contingencies” of the Notes to our Consolidated Financial Statements accompanying this report.

Item 4. [Removed and Reserved]

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is traded on the NYSE Amex under the symbol “KAZ.” Our shares are also traded on XETRA, the Deutsche Borse electronic trading system under SE code DL-,001 DMW US09656A1051.

The following table presents the high and low sales price for the fiscal year ended March 31, 2011 and March 31, 2010, as reported by the NYSE Amex.

Fiscal year ended March 31, 2011	High	Low

Fourth quarter	$ 1.18	$ 0.86
Third quarter	$ 0.99	$ 0.57
Second quarter	$ 0.62	$ 0.52
First quarter	$ 1.06	$ 0.61

Fiscal year ended March 31, 2010

Fourth quarter	$ 1.45	$ 0.94
Third quarter	$ 1.31	$ 0.88
Second quarter	$ 1.14	$ 0.78
First quarter	$ 1.79	$ 0.56

Holders

As of June 11, 2011, we had approximately 362 shareholders of record holding 55,787,554 shares of our common stock. The number of record holders was determined from the records of our stock transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various securities brokers, dealers, and registered clearing agencies.

Dividends

We have not declared or paid a cash dividend on our common stock during the past two fiscal years. Our ability to pay dividends is subject to limitations imposed by Nevada law. Under Nevada law, dividends may be paid to the extent that a corporation’s assets exceed it liabilities and it is able to pay its debts as they become due in the usual course of business.

If the Sale is consummated, we intend to make an initial cash distribution to our stockholders in the estimated range of $1.04 to $1.10 per share upon the closing from the Sale proceeds after giving effect to the estimated closing adjustments and escrow holdback amount, the repayment of the Senior Notes, and after providing for payment or reserve for other projected liabilities and transaction costs. We also intend to make a second distribution to our stockholders that could range up to $0.30 per share following termination of the escrow, subject to the availability of funds to be released from escrow, actual costs incurred and other factors.

Securities Authorized for Issuance Under Equity Compensation Plans

See Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” of this report.

Performance Graph

Recent Sales of Unregistered Securities

We did not sell any unregistered equity securities during the quarter ended March 31, 2011.

Issuer Purchases of Equity Securities

We did not repurchase any equity securities of the Company during the quarter ended March 31, 2011.

Item 6. Selected Financial Data

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

As more fully discussed in this report in Item 1. “Business,” and Note 6 – “Discontinued Operations” of the Notes to our Consolidated Financial Statements accompanying this report, we are in the process of selling our interest in Emir Oil. Our stockholders approved the Sale at a special meeting of stockholders held on June 2, 2011 and the parties are working to complete the remaining conditions to closing. If we are successful in consummating the Sale, we will no longer have substantial operations or assets. Following the closing, the existence of BMB will continue to: (i) address existing liabilities; (ii) respond to indemnification claims made by Palaeontol in connection with the Purchase Agreement; and (iii) pay out the second distribution, if any, to our stockholders. Because of the limited continuing operations of BMB and limited capital, there is substantial doubt as to our ability to continue to operate as a going concern.

In accordance with generally accepted accounting principle in the United States, because of the pending Sale, the results of operations and the financial position of Emir Oil have been classified in the Consolidated Financial Statements accompanying this report as discontinued operations. Historically, the assets and operations of Emir Oil have represented the major portion of our consolidated total assets and results of operations. The results of our operations, that are solely operations of BMB Munai, excluding the operations of Emir Oil, will be reported and further discussed as results of continuing operations. This discussion and analysis of financial condition and results of operations has been retroactively reclassified and subdivided to results from continuing operations and results from discontinued operations.

This discussion summarizes the significant factors affecting our continuing and discontinued operating results, financial condition, liquidity and capital resources during the fiscal years ended March 31, 2011 and 2010. This discussion should be read in conjunction with the Consolidated Financial Statements and Notes to the Consolidated Financial Statements accompanying this report.

Results of Continuing Operations

Year ended March 31, 2011 compared to the year ended March 31, 2010.

Revenue

We did not generate any revenue during the fiscal years ended March 31, 2011 and 2010 except from oil and gas sales through Emir Oil.

Expenses

The following table presents details of our expenses for the years ended March 31, 2011 and 2010:

	For the year ended March 31, 2011	For the year ended March 31, 2010
Costs and Operating Expenses:
General and administrative	10,037,072	9,307,412
Interest expense	5,977,640	4,604,446
Amortization and depreciation	89,575	123,541
Total	$ 16,104,287	$ 14,035,399

General and Administrative Expenses. General and administrative expenses from continuing operations during the year ended March 31, 2011 were $10,037,072 compared to $9,307,412 during the year ended March 31, 2010. This represents an 8% increase. This increase was the result of increased legal fees in connection with the Note Restructure and Sale discussed in more detail in this report in Note 1. Business.

During the year ended March 31, 2011 we recognized non-cash compensation expense in the amount of $1,254,025 resulting from restricted stock grants previously made to our executive officers, directors, employees and outside consultants. By comparison, during the year ended March 31, 2010 we recognized non-cash compensation expense in the amount of $3,171,633 for restricted stock grants previously made to employees and outside consultants.

Amortization and Depreciation. Amortization and depreciation expense from continuing operations for the year ended March 31, 2011 decreased by $33,966 or 27% compared to the year ended March 31, 2010. The decrease resulted from the sale of fixed assets during the 2011 fiscal year.

Interest Expense. During the year ended March 31, 2011 we incurred interest expense from continuing operations of $5,977,640 compared to interest expense of $4,604,446 during the same period of 2010. We have not drilled any new wells since the end of the 2010 calendar year; therefore, all interest expense incurred in connection with our convertible notes since that time has been expensed.

Loss from Operations. During the year ended March 31, 2011 we recognized a loss from continuing operations of $16,104,287 compared to loss from continuing operations of $14,035,399 during the year ended March 31, 2010. This increase in loss from continuing operations during fiscal 2011 is the result of the 30% increase in interest expense during fiscal 2011, coupled with 8% increase in general administrative expenses.

Total Other Expense/Income. During the fiscal year ended March 31, 2011 we recognized total other expense from continuing operations of $396,441 compared to total other income of $45,075 during the fiscal year ended March 31, 2009. The 980% change from other income in fiscal year 2010 to other expense in fiscal year 2011 was mainly due to a foreign exchange loss of $415,803 incurred during the fiscal year 2011.

Income Tax Benefit. During fiscal 2011 we realized an income tax benefit from continuing operations of $1,366,631 compared to an income tax benefit of $3,260,619 during fiscal 2010. The income tax benefit for the periods ended March 31, 2010 and 2011 was mainly attributable to a decrease in deferred tax expense to account for a reduction of the rate to the intercompany note receivable and an increase in deferred tax benefit to account for the increased net operating loss (NOL) in large part attributable to higher general & administrative expenses and note interest expense.

Loss from Continuing Operations. During the fiscal year ended March 31, 2011 we realized a loss from continuing operations of $15,134,097 compared to $10,729,705 during the fiscal year ended March 31, 2010. This 41% increase in loss from continuing operations was primarily attributable to increased general and administrative and interest expense and the foreign exchange loss discussed above.

Income from Discontinued Operations. During the fiscal year ended March 31, 2011 we realized income from discontinued operations of $20,015,870 compared to $19,723,178 during the fiscal year ended March 31, 2010.

Net Income. For all of the foregoing reasons, during the year ended March 31, 2011 we realized net income of $4,881,773 or $0.09 basic and diluted income per share compared to a net income of $8,993,473 or $0.18 basic and diluted income per share for the year ended March 31, 2010.

Results of Discontinued Operations

The following table sets forth selected operating data from discontinued operations for the fiscal years ended March 31, 2011 and 2010:

	For the year ended March 31, 2011	For the year ended March 31, 2010
Revenues:
Oil and gas sales	$ 64,417,933	$ 57,274,526

Expenses:
Rent export tax	13,338,869	10,032,857
Export duty	1,951,794	-
Oil and gas operating(1)	9,534,217	8,568,453
Depletion	10,332,115	11,075,590
Depreciation and amortization	495,537	490,412
Accretion	495,497	448,351
Depreciation of gas utilization Facility	1,243,891	-
General and administrative	6,227,597	4,735,165

Net Production Data:
Oil (Bbls)	869,208	1,016,221
Natural gas (in thousand m3)(4)	39,048	-
Barrels of Oil equivalent (BOE)	1,099,030	1,016,221

Net Sales Data(3):
Oil (per Bbl)	853,956	1,036,070
Natural gas (in thousand m3) (4)	33,856	-
Barrels of Oil equivalent	1,053,223	1,036,070

Average Sales Price:
Oil (per Bbl)	73.82	55.28
Natural gas (in thousand m3) (4)	40.83	-
Equivalent price (per BOE)	61.16	55.28

Expenses ($ per BOE) (3):
Oil and gas operating(1)	9.05	8.27
Depletion(2)	9.81	10.69

(1)	Includes transportation cost, production cost and ad valorem taxes (excluding rent export tax).
(2)	Represents depletion of oil and gas properties only.
(3)	We use sales volume rather than production volume for calculation of per unit cost because not all volume produced is sold during the period. The related production costs are expensed only for the units sold, not produced, based on a matching principle of accounting. Oil and gas operating expense per BOE is calculated by dividing oil and gas operating expenses for the year by the volume of oil sold during the year.
(4)	The coefficient for conversion production and sales of gas from cubic meters to barrels equals: 1 thousand m3 = 5.8857 barrels of oil equivalent.

Revenue and Production

The following table summarizes production volumes, average sales prices and operating revenue for our oil and natural gas operations for the year ended March 31, 2011 and the year ended March 31, 2010.

			Year ended March 31, 2011 to the year ended March 31, 2010
	For the year	For the year	$	%
	Ended	ended	Increase	Increase
	March 31, 2011	March 31, 2010	(Decrease)	(Decrease)

Production volumes:
Natural gas (in thousand m3)	39,048	-	39,048	100%
Natural gas liquids (Bbls)	-	-	-	-
Oil and condensate (Bbls)	869,208	1,016,221	(147,013)	(14%)
Barrels of Oil equivalent (BOE) (3)	1,099,030	1,016,221	82,809	8%

Sales volumes:
Natural gas (in thousand m3)	33,856	-	33,856	100%
Natural gas liquids (Bbls)	-	-	-	-
Oil and condensate (Bbls)	853,956	1,036,070	(182,114)	(18%)
Barrels of Oil equivalent (BOE) (3)	1,053,223	1,036,070	17,153	2%

Average Sales Price (1)
Natural gas ($ per thousand m3)	$ 40.83	-	$ 40.83	100%
Natural gas liquids ($ per Bbl)	-	-	-	-
Oil and condensate ($ per Bbl)	$ 73.82	$ 55.28	$ 18.54	34%
Barrels of Oil equivalent ($ per BOE) (3)	$ 61.16	$ 55.28	$ 5.88	11%

Operating Revenue:
Natural gas	$ 1,382,172	-	$ 1,382,172	100%
Natural gas liquids	-	-	-	-
Oil and condensate	$ 63,035,761	$ 57,274,526	$ 5,761,235	10%
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 year ended March 31, 2011 or the year ended March 31, 2010.

(3)	The coefficient for conversion of production and sales of gas from cubic meters to barrels equals: 1 thousand m3 = 5.8857 barrels of oil equivalent.

Revenue. We generated revenue from discontinued operations under our exploration contract from the sale of oil recovered during test production. During the year ended March 31, 2011 our oil production decreased 14% compared to the year ended March 31, 2010, as a result of natural decline rates of production, well downtime, and maintenance and improvement works at the oil storage facility.

During the year ended March 31, 2011 we realized revenue from discontinued operations from oil sales of $63,035,761 compared to $57,274,526 during the year ended March 31, 2010. The largest contributing factor to the 10% increase in revenue was a 34% increase in the price per barrel we received for oil sales during the year ended March 31, 2011 compared to the fiscal year ended March 31, 2010. During the fiscal years ended March 31, 2011 and 2010 we exported 99% and 95% of our oil, respectively, to the world markets and realized the world market price for those sales. Revenue from oil sold to the world markets made up 97% and 98% of total revenue during each of the years ended March 31, 2011 and 2010.

We began realizing revenue from natural gas sales to the domestic market in May 2010. During the year ended March 31, 2011 we realized revenue from natural gas sales of $1,382,172. Prior to May 2010 we did not realize revenue from natural gas sales, because the amounts realized from natural gas sales were insignificant and thus were included in revenue from oil sales.

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

Expenses

The following table presents details of our expenses from discontinued operations for the years ended March 31, 2011 and 2010:

	For the year ended March 31, 2011	For the year ended March 31, 2010
Expenses:
Rent export tax	$ 13,338,869	$ 10,032,857
Export duty	1,951,794	-
Oil and gas operating(1)	9,534,217	8,568,453
General and administrative	6,227,597	4,735,165
Depletion	10,332,115	11,075,590
Depreciation of gas utilization Facility	1,243,891	-
Accretion expenses	495,497	448,351
Amortization and depreciation	495,537	490,412
Total	$ 43,619,517	$ 35,350,828
Expenses ($ per BOE):
Oil and gas operating(1)	$ 9.05	$ 8.27
Depletion (2)	$ 9.81	$ 10.69

(1) Includes transportation cost, production cost and ad valorem taxes (excluding rent export tax and export duty).

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

Rent export tax. Rent export tax is calculated based on the export sales price and ranges from as low as 0% if the export sales price is less than $40 per barrel to as high as 32% if the price per barrel exceeds $190. During the year ended March 31, 2011 rent export tax paid to the government amounted to $13,338,869 compared to $10,032,857 for the year ended March 31, 2010. This increase was mainly due to increased world price for oil during the fiscal year ended 2011.

Export Duty. In July 2010 the government issued a resolution that reenacted the export duty for several products, including crude oil. We became subject to the export duty in September 2010. As a result, we incurred export duty during the fiscal year ended March 31, 2011 of $1,951,794. We were not subject to export duty during the fiscal year ended March 31, 2010. Export duty was not recorded as part of oil and gas operating expense and was not included in oil and gas operating expense per BOE calculation.

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

Oil and Gas Operating Expenses. During the year ended March 31, 2011 we incurred $9,534,217 in oil and gas operating expenses compared to $8,568,453 during the year ended March 31, 2010. This increase was primarily the result of increased transportation expense.

Oil and gas operating expenses from discontinued operations for the year ended March 31, 2011 and 2010 consist of the following expenses:

	For the year ended March 31,
	2011		2010
	Total	Per BOE	Total	Per BOE
Oil and Gas Operating Expenses:
Production	$ 1,420,275	$ 1.35	$ 1,635,039	$ 1.58
Transportation	4,345,700	4.12	3,423,803	3.30
Mineral extraction tax	3,768,242	3.58	3,509,611	3.39
Total	$ 9,534,217	$ 9.05	$ 8,568,453	$ 8.27

The 13% decrease in production expense during the year ended March 31, 2011 was due to a decrease in oil production.

Transportation expenses increased by $921,897 or 27% as a result of an increase of $414,482 or 118%, in salary and related payments. The increase in salary and related payments is reflected in bonus and overtime salary of personnel related to transportation, which increased $186,120 or 95%. We also realized increases in (i) expensed materials used during the renovation and refurbishment of the oil storage facility we lease from Term Oil conducted between August and November 2010, (ii) fuel expenses of $144,500 or 37%, (iii) depreciation expense of fixed assets due to the depreciation expense recognized for leased oil trucks of $76,155, or 49%, and (iv) interest expense on oil truck leases of $62,773 or 272%, which was higher in fiscal 2011 because we paid interest for the full fiscal year. In contrast we paid interest on oil truck leases during only one quarter of fiscal 2010.

The amount of the mineral extraction tax depends on annual production output. The new code currently provides for a 5% mineral extraction tax rate (6% starting from 2013 and 7% starting from 2014) on production sold to the export market, and a 2.5% tax rate (3% in 2013 and 3.5% starting from 2014) on production sold to the domestic market. The mineral extraction tax expense is reported as part of oil and gas operating expense.

During the year ended March 31, 2011 mineral extraction tax paid to the government amounted to $3,768,242, which represents an increase of 7% compared to $3,509,611 paid during the fiscal year ended March 31, 2010. This increase was due to the increase in world oil prices during year ended March 31, 2011.

We calculate oil and gas operating expense per BOE based on the volume of oil and gas actually sold rather than production volume because not all volume produced during the period is sold during the period. The related production costs are expensed only for the units sold, not produced. Expense per BOE is a function of total expense divided by the number of barrels of oil we sell. During the year ended March 31, 2010 we sold 1,036,070 BOE of oil. During the year ended March 31, 2011 we sold 1,053,223 BOE of oil and gas. The 2% increase in sales volume of oil and gas coupled with the 11% increase in oil and gas operating expenses resulted in a $0.78, or 9%, increase in oil and gas operating expense per BOE.

General and Administrative Expenses. General and administrative expenses from discontinued operations during the year ended March 31, 2011 were $6,227,597 compared to $4,735,165 during the year ended March 31, 2010. This represents a 32% increase. This increase in general and administrative expenses from discontinued operations was the result of:

	•	a 36% increase in payroll and related expenses, which were due to increased salary and bonuses paid to employees;
	•	a 550% increase in other taxes, due to incurred property taxes for 2010;

Depletion. Depletion expense for the year ended March 31, 2011 decreased by $743,475 or 7% compared to the year ended March 31, 2010. The decrease in depletion expense was mainly attributable to the increase in proved reserves of oil and gas.

Amortization and Depreciation. Amortization and depreciation expense from discontinued operations for the year ended March 31, 2011 increased 1% compared to the year ended March 31, 2010. The increase resulted from purchases of fixed assets during the 2011 fiscal year.

Income from Operations of Emir Oil. During the year ended March 31, 2011 we realized income from discontinued operations of $20,798,416 compared to income from discontinued operations of $21,923,698 during the year ended March 31, 2010. This decrease in income from discontinued operations during fiscal 2011 is primarily the result of the 23% increase in operating expenses recognized during fiscal 2011, which was only partially offset by the 12% increase in our revenue.

Other Expense. During the fiscal year ended March 31, 2011 we realized total other income from discontinued operations of $354,550 compared to total other expense of $491,963 during the fiscal year ended March 31, 2010. This change from income to expense is largely attributable to:

	•	a $108,261 foreign exchange gain realized during the year ended March 31, 2011 compared with the foreign exchange loss in the amount $396,328 incurred in year ended March 31, 2010;
	•	a $67,691 increase in interest income; and
	•	a $274,233 decrease in other expense during the fiscal year ended March 31, 2011 compared the fiscal year ended March 31, 2010.

Income from Discontinued Operations. For the foregoing reasons, during the year ended March 31, 2011 we realized income from discontinued operations of $20,015,870 or $0.38 per share compared to income from discontinued operations of $19,723,178 or $0.39 basic and diluted income per share for the fiscal year ended March 31, 2010.

Liquidity and Capital Resources

For the period from inception on May 6, 2003 through March 31, 2011, we have incurred capital expenditures of approximately $351,840,000 for exploration, development and acquisition activities. Funding for our activities has historically been provided by funds raised through the sale of our common stock and debt securities and revenue from oil sales. From inception to March 31, 2011 we raised approximately $94.6 million through the sale of our common stock and $60 million from the sale of convertible senior notes.

As discussed in more detail in this report in Item 2. Properties, the term of our exploration contract expires in January 2013. We must transition any fields we wish to retain to commercial production by January 2013. Any fields not transitioned to commercial production by that time will be subject to forfeiture to Kazakhstan. To transition to commercial production, we must establish the existence of commercially producible reserves in each field we intend to transition. To do so, we must drill and test a sufficient number of wells in each field to establish the existence of commercially producible reserves. We have identified ten structures (potential fields) within our Contract Area. We have conducted sufficient drilling and testing to establish the existence of four fields. Given our current financial condition and outlook, we do not anticipate having the funds available to engage in exploratory drilling in any of the remaining six fields prior to January 2013. Pursuant to the terms of the Purchase Agreement, we are working to transition the Kariman, Dolinnoe and Aksaz fields to commercial production.

At the time a field is transitioned to commercial production, a commercial production bonus is paid to Kazakhstan. We anticipate we will be required to pay a commercial production bonus up to $10 million to transition our established fields to commercial production. Given current production rates and decline curves, anticipated revenue from production and anticipated expenses, we are uncertain whether we will have adequate funds to pay the commercial production bonus at the time we apply for commercial production rights on our four established fields.

In connection with the application for commercial production, we will be required to submit to the MOG a field development plan prepared by a third-party design institute. Among other things, the development plan establishes a drilling plan to maximize commercial production. We must commit to fulfill the development plan before a commercial production license will be granted. The failure to satisfy the development plan could result in the loss of the commercial production license and forfeiture of the fields to Kazakhstan. Given our current financial condition, lack of available additional funding and anticipated future revenue from production, we do not expect to have adequate funding to satisfy a field development plan on our existing fields.

In addition to our obligations under our exploration contract, we also owe $61.4 million in principle amount, plus interest, to the holders of our Senior Notes, as discussed in more detail in the report in Item 1. Business and Note 8 – Convertible Notes Payable to the Notes to our Consolidated Financial Statements accompanying this report.

Despite our efforts to increase revenue, control costs and explore financing arrangements, we do not believe we will have sufficient funds to meet our obligations under our exploration contract or under the Senior Notes without a significant infusion of capital. If we do not complete the Sale, we anticipate we will lack sufficient funds to retire the restructured Senior Notes when they become due. If we fail to attain commercial production rights we will be unable to complete the Sale. There is substantial doubt that we will be able to continue as a going concern if we do not complete the Sale and we would likely be required to consider other liquidation alternatives, including a liquidation of our business under bankruptcy protection, because we will not have sufficient cash to repay the Senior Notes or continue our operations. Moreover, if we do complete the Sale, we will have no continuing operations that result in positive cash flow, which likewise raises substantial doubt about our ability to continue as a going concern.

Cash Flows

During the year ended March 31, 2011 cash was primarily used to fund exploration expenditures. See below for additional discussion and analysis of cash flow.

	Year ended	Year ended
	March 31,	March 31,
	2011	2010
Net cash provided by operating activities	$ 35,779,349	$ 14,094,980
Net cash used in investing activities	$ (35,078,949)	$ (11,410,131)
Net cash (used in)/provided by financing activities	$ (5,369,245)	$ (3,000,000)

NET CHANGE IN CASH AND CASH EQUIVALENTS	$ (4,668,845)	$ (315,151)
NET CHANGE IN CASH AND CASH EQUIVALENTS–CONTINUING OPERATIONS	$ (2,566,347)	$ (1,369,938)
NET CHANGE IN CASH AND CASH EQUIVALENTS–DISCONTINUED OPERATIONS	$ (2,102,498)	$ 1,054,787

Our principal source of liquidity during the year ended March 31, 2011 was cash and cash equivalents. At March 31, 2010 cash and cash equivalents from continuing and discontinued operations totaled to approximately $6.4 million. At March 31, 2011 cash and cash equivalents from continuing and discontinued operations totaled to approximately $1.8 million. During the year ended March 31, 2011 we spent approximately $35 million to fund Emir Oil’s exploration and development activities.

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

Contractual Obligations and Contingencies

The following table lists our significant commitments at March 31, 2011, excluding current liabilities as listed on our consolidated balance sheet:

	Payments Due By Period
Contractual obligations	Total	Less than 1 year	2-3 years	4-5 years	After 5 years
Capital Expenditure Commitment(1)	$ 27,550,000	$ 16,420,000	$ 11,130,000	$ -	$ -
Due to the Government of the Republic of Kazakhstan(2)	16,716,956	-	2,089,619	3,343,392	11,283,945
Liquidation Fund	5,207,842	-	5,207,842	-	-
Capital Lease Payments(3)	491,407	292,549	198,858	-	-
Convertible Notes with Interest(4)	79,324,673	5,400,000	73,924,673	-	-
Total	$ 129,290,878	$ 22,112,549	$ 92,550,992	$ 3,343,392	$ 11,283,945

(1)

Under the terms of our subsurface exploration contract we are required to spend a total of $27.6 million in exploration activities on our properties, including a minimum of $16.4 million by January 2012, $11 million by January 2013. The rules of the MOG provide a process whereby capital expenditures in excess of the minimum required expenditure in any period may be carried forward to meet the minimum obligations of future periods. Our capital expenditures in prior periods have exceeded our minimum required expenditures by more than $229 million.

(2)

In connection with our acquisition of the oil and gas contract covering the ADE Block, the Southeast Block and the Northwest Block, we are required to repay the ROK for historical costs incurred by it in undertaking geological and geophysical studies and infrastructure improvements. Our repayment obligation for the ADE Block is $5,994,200, for the Southeast Block is $5,350,680 and our repayment obligation for the Northwest Block is $5,372,076. The terms of repayment of these obligations, however, will not be determined until such time as we apply for and are granted commercial production rights by the ROK. Should we decide not to pursue commercial production rights, we can relinquish the ADE Block, the Southeast Block and/or the Northwest Block to the ROK in satisfaction of their associated obligations.

(3)	In December 2009 we entered into a capital lease agreement with a vehicle leasing company for the lease of oil trucks. Under the terms of the lease we are required to make payments in the amount of $292,549 for the year 2011 and $198,858 for the year 2012.

(4)

On July 16, 2007 the Company completed the private placement of $60 million in principal amount of 5.0% convertible senior notes due 2012. As discussed in more detail in this report in Item 1. Business, in April 2011 we restructured the terms of the Senior Notes. Pursuant to the Note Restructure, among other things, the principal amount of the Senior Notes increased to $61.4 million, the coupon rate increased to 10.75% and the maturity date was extended from July 2012 to July 2013. The Senior Notes constitute direct, unsubordinated and unsecured, interest bearing obligations of the Company. For additional details regarding the terms of the Senior Notes, see Note 8 – Convertible Notes Payable to the Notes to our Consolidated Financial Statements accompanying this report.

Off-Balance Sheet Financing Arrangements

As of March 31, 2011, we had no off-balance sheet financing arrangements.

Critical Accounting Policies

We have identified the accounting policies below as critical to our business operations and an understanding of our financial statements. The impact of these policies and associated risks are discussed throughout Management’s Discussion and Analysis where such policies affect our reported and expected financial results. A complete discussion of our accounting policies is included in Note 2 of the notes to consolidated financial statements.

Foreign Exchange Transactions

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

Share-Based Compensation

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

We have stock option plans as described in Note 10. Compensation expense for options and stock granted to employees is determined based on their fair value at the time of grant, the cost of which is recognized in the Consolidated Statements of Operations over the vesting periods of the respective options.

Share-based compensation incurred for the years ended March 31, 2011 and 2010 was $1,254,025 and $3,171,633, respectively.

Full Cost Method of Accounting

We follow the full cost method of accounting for oil and gas properties. Under this method, all costs associated with acquisition, exploration and development of oil and gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. These costs do not include any costs related to production, general corporate overhead or similar activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of our proved reserves are sold (greater than 25 percent), in which case a gain or loss is recognized.

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

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

plus the cost of properties not being amortized;

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

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

Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change. If oil and gas prices decline, even if only for a short period of time, it is possible that impairment of our oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the cost ceiling, revisions to proved oil and gas reserves occur or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.

All geological and geophysical studies, with respect to the licensed territory, have been capitalized as part of the oil and gas properties.

Our oil and gas properties primarily include the value of the license and other capitalized costs.

All capitalized costs of oil and gas properties, including the estimated future costs to develop proved reserves and estimated future costs to plug and abandon wells and costs of site restoration, less the estimated salvage value of equipment associated with the oil and gas properties, are amortized on the unit-of-production method using estimates of proved reserves as determined by independent engineers.

Ceiling test

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

Recent Accounting Pronouncements

For details of applicable new accounting standards, please, refer to Recent accounting pronouncements in Note 2 of our Consolidated Financial Statements accompanying this report.

Effects of Inflation and Pricing

The oil and natural gas industry is very cyclical and the demand for goods and services of oil field companies, suppliers and others associated with the industry puts extreme pressure on the economic stability and pricing structure within the industry. Typically, as prices for oil and natural gas increase, so do all associated costs. Material changes in prices have an impact on revenue, estimates of future reserves, borrowing base calculations of bank loans and the value of properties in purchase and sale transactions. Material changes in prices can impact the value of oil and natural gas companies and their ability to raise capital, borrow money and retain personnel.

Item 7A. Qualitative and Quantitative Disclosures about Market Risk

Item 8. Financial Statements and Supplementary Data

The Consolidated Financial Statements and supplementary data required by this Item 8 are included at page F-1 of this report.

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

During the fiscal year ended March 31, 2011 there were no changes in or disagreements with our independent registered public accounting firm on accounting and financial disclosure.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act.) Based upon this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2011, our disclosure controls and procedures were effective in ensuring that information required to be disclosed by us in the reports filed or submitted by us under the Exchange Act is (i) recorded, processed, summarized and reported, within the time periods specified in the Commission’s rules and forms and (ii) accumulated and communicated to our management, including our principal executive and accounting officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

Management's Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) and 15d-15(f) promulgated under the Exchange Act as a process designed by, or under the supervision of, the company’s principal executive officer and principal financial officer and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles and includes those policies and procedures that:

•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and
•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting is not intended to provide absolute assurance that a misstatement of our financial statements would be prevented or detected. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an assessment of the effectiveness of the our internal control over financial reporting based on the framework set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control - Integrated Framework. Based on this assessment, our management concluded that as of March 31, 2011, our internal control over financial reporting is effective to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles.

Attestation Report of Independent Registered Public Accounting Firm

This annual report on Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our independent registered public accounting firm pursuant to an exemption for non-accelerated filers set forth in Section 989G of the Dodd-Frank Wall Street Reform and Consumer Protection Act.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the quarter ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The following table sets forth our directors and persons nominated or chosen to become directors and executive officers and persons chosen to become executive officers and certain significant employees, their ages, and all offices and positions held. Directors are elected for a period of three years and thereafter serve until their successor is duly elected by the stockholders and qualified.

Name of Director or Executive Officer	Age	Positions with the Company	Director Since	Officer Since

Boris Cherdabayev	57	Chairman of the Board of Directors	November 2003

Jason M. Kerr	40	Independent Director	May 2008

Troy F. Nilson	45	Independent Director	December 2004

Daymon M. Smith	33	Independent Director	September 2009

Leonard M. Stillman	68	Independent Director	October 2006

Valery Tolkachev	45	Independent Director	December 2003

Gamal Kulumbetov	35	Chief Executive Officer		August 2007

Askar Tashtitov	32	President and Director	May 2008	May 2006

Evgeniy Ler	28	Chief Financial Officer		April 2009

Anuarbek Baimoldin	33	Chief Operating Officer		April 2009

A brief description of the background and business experience of each of the above listed individuals follows.

Boris Cherdabayev. Mr. Cherdabayev joined the Company’s board of directors and was appointed Chairman of the board of directors in November 2003. From May 2000 to May 2003, Mr. Cherdabayev served as Director at TengizChevroil LLP multi-national oil and gas company owned by Chevron, ExxonMobil, KazMunayGas and LukOil. From 1998 to May 2000, Mr. Cherdabayev served as a member of the Board of Directors, Vice-President of Exploration and Production and Executive Director on Services Projects Development for NOC “Kazakhoil”, an oil and gas exploration and production company. From 1983 to 1988 and from 1994 to 1998 he served as a people’s representative at Novouzen City Council (Kazakhstan); he served as a people’s representative at Mangistau Oblast Maslikhat (regional level legislative structure) and a Chairman of the Committee on Law and Order. For his achievements Mr. Cherdabayev has been awarded with a national “Kurmet” order. Mr. Cherdabayev earned an engineering degree from the Ufa Oil & Gas Institute, with a specialization in “machinery and equipment of oil and gas fields” in 1976. Mr. Cherdabayev also earned an engineering degree from Kazakh Polytechnic Institute, with a specialization in “mining engineer on oil and gas fields’ development.” During his career he also completed an English language program in the United States, the СНАМР Program (Chevron Advanced Management Program) at Chevron Corporation offices in San Francisco, California, and the CSEP Program (Columbia Senior Executive Program) at Columbia University. Mr. Cherdabayev is not currently, nor has he in the past five years been, a director or nominee of any other SEC registrant or registered investment company. We considered Mr. Cherdabayev’s extensive experience in the oil and gas industry in the Republic of Kazakhstan in concluding that he should serve as a director of the Company.

Jason M. Kerr. Mr. Kerr graduated from the University of Utah in 1995 with a Bachelors of Science degree in Economics and in 1998 with a Juris Doctorate from the same university where he was named the William H. Leary Scholar. Since 2006 Mr. Kerr has been the associate general counsel of Basic Research, LLC, concentrating in intellectual property litigation. Prior to joining Basic Research, Mr. Kerr was a partner with the law firm of Plant, Christensen & Kanell in Salt Lake City, Utah. Mr. Kerr was employed with Plant, Christensen & Kanell from 1996 through 2001 and from 2004 to 2006. From 2001 through 2004 Mr. Kerr was employed as a commercial litigator with the Las Vegas office of Lewis and Roca. Mr. Kerr became a Company director in May 2008. Mr. Kerr currently serves on the Company’s Audit Committee, the Compensation Committee and the Corporate Governance and Nominating Committee. Mr. Kerr is not currently, nor has he in the past five years been, a nominee or director of any other SEC registrant or registered investment company. In concluding that Mr. Kerr should serve as a Company director, we considered his educational background in economics and his professional experience as an attorney.

Troy F. Nilson, CPA. From February 2001 to August 2010, Mr. Nilson has served as an Audit Partner with Chisholm, Bierwolf Nilson & Morrill, Certified Public Accountants, in Bountiful, Utah. Currently he is an Audit Partner with Bierwolf, Morrill & Nilson PLLC. From December 2000 to February 2001, he served as an Audit Manager for Crouch, Bierwolf & Associates, Certified Public Accountants, in Salt Lake City, Utah. Prior to that time, Mr. Nilson served as the Senior Auditor for Intermountain Power Agency in Salt Lake City, Utah from March 1995 to December 2000. In the past five years, Mr. Nilson has had extensive public and private company audit, audit review and Securities and Exchange Commission disclosure and reporting experience. Mr. Nilson received licensure as a Certified Public Accountant in 1997. Mr. Nilson earned a Masters of Science Degree in Business Information Systems from Utah State University in December 1992, and a Bachelor of Science in Accounting from Utah State University in August 1990. Mr. Nilson became a Company director in December 2004. Mr. Nilson currently serves on the Company’s Audit Committee, the Compensation Committee and the Corporate Governance and Nominating Committee. Mr. Nilson is not currently, nor has he in the past five years been, a director or nominee of any other SEC registrant or registered investment company. We considered Mr. Nilson’s experience and expertise as a U.S. certified public accountant auditing SEC reporting issuers in concluding that Mr. Nilson should serve as a director of the Company.

Daymon M. Smith. Dr. Smith is currently engaged in independent research and writing projects. From August 2007 to June 2009 Dr. Smith was a Visiting Assistant Professor at the University of Alabama-Birmingham, where he was a lecturer and researcher. He has also taught at Weber State University and at Utah Valley University, and has received numerous research grants and academic awards. From 2001 to 2007 Dr. Smith was a William Penn Fellow at the University of Pennsylvania. As a Fellow, Dr. Smith was responsible for conducting course instruction and evaluation, student assessments and ethnographic research. From 2006 to 2007 Dr. Smith was employed with the Corporation of the Presiding Bishop as an International Media Scientist. Here Dr. Smith served as lead analyst for the Audiovisual Department. He also served from 2005 to 2006 as a cultural materials consultant to SynTech Energy, an oil-shale extraction company, providing support in its dealings with major U.S. airlines and with Jordanian firms. Dr. Smith earned a Bachelors of Science degree in Anthropology from the University of Utah in 2001, and a Ph.D. in Anthropology from the University of Pennsylvania in 2007. Dr. Smith currently serves on the Company’s Audit Committee and the Corporate Governance and Nominating Committee. Dr. Smith is not currently, nor has he in the past five years been, a director or nominee of any other SEC registrant or registered investment company. In concluding that Dr. Smith should serve as a director of the Company, we considered his background in anthropology and media messaging.

Leonard M. Stillman, Jr. Mr. Stillman received his Bachelor of Science degree in mathematics from Brigham Young University and Master of Business Administration from the University of Utah. He began his career in 1963 with Sperry UNIVAC as a programmer developing trajectory analysis software for the Sergeant Missile system. Mr. Stillman spent many years as a designer and teacher of computer language classes at Brigham Young University, where he developed applications for the Administrative Department including the school’s first automated teacher evaluation system. During that time, he was also a Vice-President of Research and Development for Automated Industrial Data Systems, Inc and the Owner of World Data Systems Company, which provided computerized payroll services for companies such as Boise Cascade. Mr. Stillman has over 40 years of extensive business expertise including strategic planning, venture capital financing, budgeting, manufacturing planning, cost controls, personnel management, quality planning and management, and the development of standards, policies and procedures. He has extensive skills in the design and development of computer software systems and computer evaluation. Mr. Stillman helped found Stillman George, Inc. in 1993 and founded Business Plan Tools, LLC in 2004. He was employed with Stillman George, Inc. until 2010 where his primary responsibilities included managing information, technical development and financial analysis projects and development as well as general company management and consulting activities. He is currently employed by Business Plan Tools, LLC which provides cloud-based SaaS business planning software and consolidates a broad variety of skills from a growing group of business professionals to provide needed support in finance, marketing, management, sales, planning, product development and more to businesses worldwide. Mr. Stillman currently serves on the Company’s Corporate Governance and Nominating Committee. Mr. Stillman is not currently, nor has he in the past five years been, a director or nominee of any other SEC registrant or registered investment company. In concluding that Mr. Stillman should serve as a director of the Company, we considered his training in business management, strategic planning, corporate finance and information management.

Valery Tolkachev. From 2009 to May 2011 Mr. Tolkachev served in various positions with Moscow-based Bank-T (f.k.a MaxWellBank), including CEO and as a member of the board of directors. In May 2011 when he sold his interest in, and left his employment with, the bank. Mr. Tolkachev is currently unemployed. From August 2008 to March 2009, Mr. Tolkachev was employed with Slavyansky Bank in Moscow, Russia, where he served as the Deputy Chairman. From 1991 to 2008, Mr. Tolkachev served in various positions with various employers including UniCreditAton, MDM Bank, InkomBank, InkomCapital and others. Mr. Tolkachev graduated with Honors from the High Military School in Kiev, USSR in 1989. In 2005 he completed his studies at the Academy of National Economy, as a qualified lawyer. Mr. Tolkachev serves on the Compensation Committee and the Corporate Governance and Nominating Committee of the Company. Mr. Tolkachev became a Company director in December 2003. Mr. Tolkachev also serves as a director of Caspian Services, Inc., an SEC registrant. During the past five years, Mr. Tolkachev also served as a director of Bekem Metals, Inc., which was an SEC registrant during the time Mr. Tolkachev served as a director. Other than as disclosed herein, Mr. Tolkachev is not currently, nor has he in the past five years been, a director or nominee of any other SEC reporting issuer or registered investment company. We took into account Mr. Tolkachev’s extensive investment experience and his related finance and banking background in concluding that he should serve as a director of the Company.

Gamal Kulumbetov. Mr. Kulumbetov graduated from the Kazakh National Technical University, Department of Oil and Gas Geology located in Almaty, Kazakhstan in 1997 where he was awarded a Bachelors degree in Geology. Mr. Kulumbetov is now in the process of completing a Ph.D. Since graduating in 1997 Mr. Kulumbetov has completed various oil and gas and geological trainings from Japan National Oil Corporation, MI Drilling Fluids LLC of Germany, Chevron Texaco of Houston, Petroleum Industry Training Center of Almaty, Kazakhstan, and Ernst & Young Company of Almaty, Kazakhstan. In 2000 Mr. Kulumbetov was employed by Halliburton as a Surface Data Logging Engineer. From 2001 through April 2005 Mr. Kulumbetov was employed by LLP TengizChevroil (“TCO”) as the Deputy Manager of the TCO Fields Development Project. From April 2005 to December 2005 Mr. Kulumbetov was employed at Big Sky Energy Corporation as Chief Geologist. Mr. Kulumbetov joined BMB Munai, Inc. as a Vice President of Operations in December of 2005 and has served as CEO since August 2007.

Askar Tashtitov. Mr. Tashtitov has been with the Company since 2004 and has served as President since May 2006 and as a director since May 2008. Prior to joining the Company, from 2002 to 2004, Mr. Tashtitov was employed by PA Government Services, Inc. Mr. Tashtitov worked as a management consultant specializing in oil and gas projects. In May 2002, Mr. Tashtitov earned a Bachelor of Arts degree from Yale University majoring in Economics and History. Mr. Tashtitov passed the AICPA Uniform CPA Examination in 2006. Mr. Tashtitov is not, nor has he in the past five years been, a director or nominee of any other SEC registrant or registered investment company. We considered Mr. Tashtitov’s detailed understanding of the Company’s operations and strategic goals in concluding that he should serve as a director of the Company.

Evgeniy Ler. Mr. Ler has been with the Company since 2006. Prior to being appointed CFO, Mr. Ler served in other capacities with the Company including Finance Manager and Reporting Manager. Prior to joining the Company, from 2002 to 2006, Mr. Ler was employed by Deloitte & Touche where he held the position of Senior Auditor in Financial Services & Industries Group, Audit. In that position he led large engagements for banks, financial institutions and oil and gas companies. In 2003 Mr. Ler was awarded a Bachelors degree in Financial Management from the Kazakh-American University located in Almaty, Kazakhstan. In 2008 Mr. Ler passed the AICPA Uniform CPA Examination. Mr. Ler has also completed trainings in London on oil and gas financial reporting in accordance with IFRS and US GAAP and internal Deloitte trainings on audit, financial reporting and due diligence.

Anuarbek Baimoldin. Mr. Baimoldin has been with the Company since October 2007. Prior to being appointed COO, Mr. Baimoldin served as the Company’s Facilities Manager. Prior to joining the Company, from March 2006 to November 2007, Mr. Baimoldin was the Managing Director of JSC National Innovation Fund where his responsibilities included researching potential innovation projects and performing project feasibility studies. From June 2005 through March 2006 Mr. Baimoldin served as the President of Caspiy Corporation LLP where he was responsible for general company management, financial and operational planning and coordination of the company’s departments. From August 2002 through June 2005 Mr. Baimoldin was employed by TengizChevroil LLP. From January 2003 to June 2005 he served as the Coordinator for the Field Development Project. His responsibilities included preparation and obtaining approval for the Second Generation Project, Gas Reinjection Project, Exploration and Development Program and compliance of operations and licensing with Kazakhstani authorities. From August 2002 through January 2003 Mr. Baimoldin served as Senior Specialist for Kazakhstani Companies Development Department and worked to replace foreign contractors with local contractors and assisted local contractors to enhance product and service quality. In 1999 Mr. Baimoldin received an Associate of Science in Management from Mount Ida College of Business located in Mount Ida, Massachusetts and in 2002 was awarded a Bachelors of Arts in International Economics from Boston University. In 2005 Mr. Baimoldin was awarded a Bachelors of Science in Exploration of Oil and Gas Fields from Atyrau Oil and Gas Institute located in Atyrau, Kazakhstan. Mr. Baimoldin has also received extensive trainings from the Ernst & Young Business Academy located in Almaty, Kazakhstan.

Family Relationships

Our Chief Operating Officer, Anuarbek Baimoldin, is the nephew of Boris Cherdabayev, a Company director and Chairman of the board of directors. There are no other family relationships among our directors, executive officers and/or nominees.

Involvement in Certain Legal Proceedings

On April 8, 2011, the United States Securities and Exchange Commission issued an order instituting public administrative and cease-and-desist proceedings pursuant to Section 4C and 21C of the Securities Exchange Act of 1934 and Rule 102(e) of the Commission’s Rules of Practice, making findings, and imposing remedial sanctions and a cease-and-desist order against Troy Nilson, one of our directors. Pursuant to the cease-and-desist order, it was ordered, effective immediately, that:

	•	Mr. Nilson cease and desist from committing or causing any violations and any future violations of Section 10A(a)(1) and 10A(a)(3) of the Exchange Act.
	•	Mr. Nilson cease and desist from committing or causing any violations and any future violations of Section 13(a) of the Exchange Act and Rules 13a-1, 13a-13 and 12b-20 promulgated thereunder.
	•	Mr. Nilson is denied the privilege of appearing or practicing before the Commission as an accountant.
	•	After five years from the date of the order, Mr. Nilson may request that the Commission consider his reinstatement by submitting an application to resume appearing or practicing before the Commission.

The board of directors believes Mr. Nilson continues to be capable to serve on the Company’s board of directors.

Other than the foregoing, during the past ten years none of our executive officers or directors has been subject to or involved in any of the following events that could be material to an evaluation of his ability or integrity, including:

(1) A petition under the Federal bankruptcy laws or any state insolvency law was filed against, or a receiver, fiscal agent or similar officer was appointed by a court for the business or property of such person, or any partnership in which he was a general partner at or within two year before the time of such filing, or any corporation or business association of which he was an executive officer at or within two years before the time of such filing;

(2) Any conviction in a criminal proceeding or being named a subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);

(3) Being subject to any order, judgment, or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him from, or otherwise limiting the following activities:

	(i) Acting as a futures commission merchant, introducing broker, commodity trading advisor, commodity pool operator, floor broker, leverage transaction merchant, and other person regulated by the Commodity Futures Trading Commission (“CFTC”), or an associated person of any of the foregoing, or as an investment adviser, underwriter, broker or dealer in securities, or as an affiliate person, director or employee of any investment company, bank savings and loan association or insurance company, or engaging in or continuing any conduct or practice in connection with such activity;
	(ii) Engaging in any type of business practice; or
	(iii) Engaging in any activity in connection with the purchase or sale of any security or commodity or in connection with any violation of Federal or State securities laws or Federal commodities laws.

(4) Being subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting for more than 60 days the rights of such person to engage in any activity described in (3)(i) above, or to be associated with persons engaged in any such activity.

(5) Being found by a court of competent jurisdiction in a civil action or by the Securities and Exchange Commission to have violated any Federal or State securities law, and the judgment in such civil action or finding by the Commission has not be subsequently reversed, suspended or vacated.

(6) Being found by a court of competent jurisdiction in a civil action or by the Commodity Futures Trading Commission to have violated any Federal commodities law, and the judgment in such civil action or finding by the Commodity Futures Trading Commission has not been subsequently reversed, suspended, or vacated.

(7) Being the subject of, or a party to any Federal or State judicial or administrative order, judgment, decree or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of:

	(i) Any Federal or State securities or commodities law or regulations; or
	(ii) Any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or

(8) Being the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act (15 U.S.C. 78c(a)(26)))), any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act (7 U.S.C. 1(a)(29))), or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

Section 16(a) Beneficial Ownership Reporting Compliance

Directors, executive officers and holders of more than 10% of our outstanding common stock are required to comply with Section 16(a) of the Exchange Act, which requires generally that such persons file reports regarding ownership of and transactions in securities of the Company on Forms 3, 4, and 5. Based solely on management’s review of these reports during the year ended March 31, 2011, it appears that Toleush Tolmakov, a greater than 10% shareholder and Vice President of Production of the Company, filed late a Form 4 disclosing the vesting of a restricted stock grant in January 2011.

Code of Ethics

We have adopted a code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar duties. The code is designed to deter wrongdoing and to promote:

·	honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;

·	full, fair, timely, accurate and understandable disclosure in reports and documents that we file with, or submit to the Commission and in our other public communications;

·	compliance with applicable governmental laws, rules and regulations;

·	prompt internal reporting of violations of the code to an appropriate person or persons identified in the code; and

·	accountability for adherence to the code.

A copy of our code of ethics was filed with the Commission as Exhibit 14.1 to the Company’s Annual Report on Form 10-KSB for the fiscal year ended March 31, 2004. A copy of the code of ethics has also been posted on our website and may be viewed at http://www.bmbmunai.com. A copy of the code of ethics will be provided to any person without charge upon written request to our Corporate Secretary at our U.S. offices, 324 South 400 West, Suite 225, Salt Lake City, Utah 84101.

Procedures for Security Holders to Nominate Candidates to the Board of Directors

There have been no material changes to the procedures set forth in our proxy statement filed with the SEC on November 18, 2009, by which security holders may recommend nominees to our board of directors.

BOARD COMMITTEES

The board has standing audit, compensation, and corporate governance and nominating committees. The board has adopted written charters for each of these committees. These charters are available on the Company’s website at www.bmbmunai.com.

Audit Committee

Our board of directors has adopted an audit committee charter and established an audit committee, as defined in accordance with section 3(a)(58)(A) of the Exchange Act and the rules of NYSE Amex, whose principal functions are to:

	•	assist the board in the selection, review and oversight of our independent registered public accounting firm;
	•	approve all audit, review and attest services provided by the independent registered public accounting firm;
	•	assess the integrity of our reporting practices and evaluate of our internal controls and accounting procedures; and
	•	resolve disagreements between management and the independent registered public accountants regarding financial reporting.

The audit committee has the sole authority to retain and terminate our independent registered public accounting firm and to approve the compensation paid to our independent registered public accounting firm. The audit committee is responsible for the pre-approval of all non-audit services provided by our independent registered public accounting firm. Non-audit services are only provided by our independent registered public accounting firm to the extent permitted by law. The audit committee is comprised of three independent directors, Troy Nilson, Daymon Smith and Jason Kerr. Mr. Nilson has and will continue to act as chairman of the committee. Our board of directors has determined that Mr. Nilson qualifies as an “audit committee financial expert” under the rules of the SEC adopted pursuant to the requirements of the Sarbanes-Oxley Act of 2002. As discussed above, our board of directors has also determined that Mr. Nilson, Mr. Smith and Mr. Kerr each qualifies as “independent” in accordance with the applicable regulations of the NYSE Amex for audit committee members.

Our board may establish other committees from time to time to facilitate our management.

Item 11. Executive Compensation

The table below summarizes compensation paid to or earned by: (i) all individuals serving as our principal executive officer or acting in a similar capacity during the last completed fiscal year (“PEO”) regardless of compensation level; (ii) our two most highly compensated executive officers other than our PEO who were serving as executive officers at the end of the last completed fiscal year; and (iii) two additional individuals who were not serving as executive officers of the Company at the fiscal year. These individuals are referred to herein collectively as our “named executive officers” or “NEOs.”

Summary Compensation Table

Name and Principal Position	Year	Salary ($)	Bonus ($)	Stock Awards(1) ($)	All Other Compen-sation ($)	Total ($)

Boris Cherdabayev	2011	192,000	-0-	-0-	63,164	255,164
Chairman of the	2010	192,000	-0-	319,200	59,309	570,509
Board of Directors

Gamal Kulumbetov	2011	95,619	-0-	-0-	34,444	130,063
CEO	2010	96,873	-0-	91,200	31,448	219,521

Evgeny Ler	2011	97,083	-0-	-0-	33,334	130,417
CFO	2010	89,309	-0-	125,400	29,927	244,636

Askar Tashtitov	2011	121,943	-0-	-0-	37,902	159,845
President	2010	115,200	-0-	262,200	37,417	414,817

Toleush Tolmakov	2011	103,201	-0-	-0-	37,827	141,028
Vice President	2010	108,473	-0-	245,100	27,608	381,181
of Production

(1)	For details regarding the assumptions made in the valuation of stock awards, please see subheading “Common Stock Grants” of “Note 10 – Shareholders’ Equity” of the Notes to the Consolidated Financial Statements included in this annual report on Form 10-K.

All Other Compensation

The table below provides additional information regarding all other compensation awarded to the named executive officers as disclosed in the “All Other Compensation” column of the “Summary Compensation Table” above.

Name	Year	Income Tax	Social Tax	Health Insurance	Pension Fund

Boris Cherdabayev	2011	$ 28,452	$ 25,665	$ 993	$ 8,054
	2010	27,119	23,885	912	7,393

Gamal Kulumbetov	2011	$ 13,722	$ 12,389	$ 279	$ 8,054
	2010	11,254	12,066	735	7,393

Evgeny Ler	2011	$ 13,311	$ 11,690	$ 279	$ 8,054
	2010	10,530	11,269	735	7,393

Askar Tashtitov	2011	$ 15,965	$ 15,510	$ 279	$ 6,148
	2010	14,776	14,513	735	7,393

Toleush Tolmakov	2011	$ 12,479	$ 13,718	$ 186	$ 11,444
	2010	9,881	9,197	-0-	8,530

Employment Agreements

We have employment agreements with Messrs. Kulumbetov, Tashtitov, Ler and Tolmakov and a consulting agreement with Mr. Cherdabayev. The terms and conditions of the Cherdabayev consulting agreement are further discussed herein and in Note 12 – Commitments and Contingencies to the Notes to the Consolidated Financial Statement accompanying this report.

The current employment agreements of Messrs. Kulumbetov, Tashtitov and Ler were entered into on December 31, 2009.

Except for annual salary, and as otherwise specifically addressed herein, the terms and conditions of the employment agreement of each of the foregoing NEOs are the same in all material respects. The employment agreements provide for an initial term of one year with three consecutive one-year renewals unless terminated by either party prior to the beginning of the renewal term.

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

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

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

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

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

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

Mr. Tolmakov’s current employment contract was entered into on December 1, 2010. His employment agreement provides for an initial term of one year. The employment agreement may be extended under the labor legislation of the ROK, unless terminated by either party prior to the beginning of the renewal term.

The agreement provides that Mr. Tolmakov is entitled to participate in such pension, bonus, social insurance, hospitalization, major medical and other employee benefit plans of the Company that may be in effect from time to time, to the extent the individual is eligible under the terms of those plans. Mr. Tolmakov is entitled to 28 days vacation in accordance with the vacation policies of the Company, as well as paid holidays and other paid leave set forth in the Company’s policies. There is no accrual of vacation days and holidays.

Mr. Tolmakov’s employment agreement and all obligations thereunder may be terminated upon the occurrence of the following events: i) on initiative of either the Company or the employee; ii) for other reasons provided in the labor legislation of the ROK; iii) for good reason upon not less than 30 days notice from an officer to the Company; or iv) an extraordinary event, unless otherwise agreed in writing.

Potential Payments Upon Termination or Change in Control

As discussed herein, the employment agreements provide for potential payments upon termination or change in control. The following table shows the cash and equity benefits payable to the named executive officers upon termination of employment for various reasons, including a change in control of the Company. For purposes of this table, it is assumed that the termination of employment occurred on March 31, 2011.

Name	Termination Scenario	Cash Benefit	Equity Awards

Gamal Kulumbetov	For Good Reason(1)	$ 64,502	$ 0
	For Cause(2)	$ 0	$ 0
	Disability(3)	$ 64,502	$ 0
	Death(4)	$ 0	$ 0
	Extraordinary Event(5)	$ 385,722	$ 76,800(6)

Askar Tashtitov	For Good Reason(1)	$ 76,589	$ 0
	For Cause(2)	$0	$ 0
	Disability(3)	$ 76,589	$ 0
	Death(4)	$ 0	$ 0
	Extraordinary Event(5)	$ 3,000,000	$ 220,800(6)

Evgeny Ler	For Good Reason(1)	$ 60,722	$ 0
	For Cause(2)	$ 0	$ 0
	Disability(3)	$ 60,722	$ 0
	Death(4)	$ 0	$ 0
	Extraordinary Event(5)	$ 363,118	$ 105,600(6)

Toleush Tolmakov	Termination for Any Reason	$ 7,000	$ 206,400

(1)

In the event of termination for good reason by the NEO, the Company will pay the NEO the remainder of his salary for the calendar month in which the termination is effective and for six consecutive calendar months thereafter. The NEO shall also be entitled to any portion of incentive compensation for the year, prorated to the date of termination. Notwithstanding the foregoing, if the NEO obtains other employment prior to the end of the six-month period, salary payments by the Company after he begins employment with a new employer shall be reduced by the amount of the cash compensation received from the new employer.

(2)	If the NEO is terminated for cause, he will receive salary only through the date of termination and will not be entitled to any incentive compensation for the year in which his employment is terminated.

(3)	If the termination is the result of a disability, the Company will pay salary for the rest of the month during which termination is effective and for the shorter of six consecutive months thereafter or until disability insurance benefits commence.

(4)	If employment is terminated as a result of the death of the NEO, his heirs shall be entitled to salary through the month in which his death occurs and to incentive compensation prorated through the month of his death.

(5)	If the employment is terminated as a result of an extraordinary event, the NEO shall be entitled to severance pay as follows:

Completed Years of Employment
Service with the Employer	Severance Amount

Less than one (1) year

10% of Basic Compensation Salary

At least one (1) year but less than two (2) years

150% of Basic Compensation Salary

More than two years

299% of Basic Compensation Salary

As of March 31, 2011, each of the NEOs had been employed with the Company more than two years.

(6)	This column reflects the dollar value of additional shares (if any) that would vest at such time as the occurrence of an extraordinary event, calculated at $0.96 per share, which was the closing price of the Company’s common stock on March 31, 2011.

All benefits terminate on the date of termination of the employment agreement. The NEO shall be entitled to accrued benefits pursuant to such plans as provided in such plans or grants thereunder. The NEO will not receive any payment or other compensation for vacation, holiday, sick leave, or other leave unused as of the date of the notice of termination.

On December 31, 2009 we entered into a consulting agreement with Boris Cherdabayev (the “Consulting Agreement”) the Chairman of the Company’s board of directors. Pursuant to the Consulting Agreement, in addition to his services as Chairman of the board of directors, Mr. Cherdabayev will provide such consulting and other services as may reasonably be requested by Company management. The Consulting Agreement became effective on January 1, 2010. The initial term of the Consulting Agreement is five years unless earlier terminated as provided therein. The initial term will automatically renew for additional one-year terms unless and until terminated. The Consulting Agreement may be terminated for Mr. Cherdabayev’s death or disability and by the Company for cause. The Company may also terminate the Consulting Agreement other than for cause, but will be required to pay the full fee required thereunder, which would have been $720,000, if the Consulting Agreement had been terminated as of March 31, 2011.

Pursuant to the Consulting Agreement, Mr. Cherdabayev will be paid a base compensation fee of $192,000 per year. The success of projects involving Mr. Cherdabayev shall be reviewed on an annual basis to determine whether the initial base consulting fee should be increased.

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

Outstanding Equity Awards at Fiscal Year End

As of March 31, 2011 none of our NEOs held outstanding stock options, unvested restricted stock grants or other shares of stock, units or other rights awarded under any equity incentive plan that have not vested or that have not been earned.

Compensation of Directors

We use a combination of cash and equity-based compensation to attract and retain candidates to serve on our board of directors. We compensate the non-employee members of our board of directors. Employee members of board of directors do not receive additional compensation for board service.

Director Fees

Members of the board of directors who are not employees of the Company or its subsidiary are paid a $40,000 stipend per year.

Meeting Fees

We also pay the non-employee members of our board of directors $1,000 for each directors meeting or shareholder meeting attended in person, plus airfare and hotel expenses.

Equity Compensation

We do not currently have a fixed plan for the award of equity compensation to our non-employee directors. Equity compensation of independent directors, if any, is typically recommended by the compensation committee or management and is subject to approval of the full board of directors. All equity grants to directors are granted at a price equal to the fair market value of our common stock on the date of the grant.

Director Compensation Table

The following table sets forth a summary of the compensation we paid to our non-employee directors for services on our board during our 2011 fiscal year.

Name	Fees Earned or Paid in Cash ($)	Stock Awards ($)	Option Awards ($)	Non-Equity Incentive Plan Compensation ($)	Nonqualified Deferred Compensation Earnings ($)	All Other Compen-sation ($)	Total ($)

Jason Kerr	44,000	-0-	-0-	-0-	-0-	-0-	44,000
Troy Nilson	44,000	-0-	-0-	-0-	-0-	-0-	44,000
Leonard Stillman	44,000	-0-	-0-	-0-	-0-	-0-	44,000
Valery Tolkachev	40,000	-0-	-0-	-0-	-0-	-0-	40,000
Daymon Smith	41,000	-0-	-0-	-0-	-0-	-0-	41,000

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

The following table sets forth as of June 11, 2011 the persons known to us to be the beneficial owners of more than five percent (5%) of the 55,787,554 shares of our outstanding common stock, other than directors and officers whose beneficial ownership is described in a subsequent table below.

Title of Class	Name and Address of Beneficial Owner	Amount & Nature of Beneficial Ownership	% of Class

Common	Caspian Energy Consulting Ltd.	5,197,539	9.3%
	P.O. Box 664
	Owen Sound, ON N4K 5R4

Common	Palaeontol B.V.	13,462,446(1)	24.1%
	Tower C-11
	Strawinskylaan 1143
	1077 XX Amsterdam
	The Netherlands

TOTAL		18,659,985	33.4%

(1)

In connection with the execution of the Purchase Agreement, certain of our principals, who collectively own approximately 24% of the outstanding shares of our common stock entered into voting agreements to vote their shares in favor of the Sale at the special meeting of our common stockholders held on June 2, 2011 and granted Palaeontol a proxy to vote their shares of common stock in favor of the Sale. The voting agreements shall expire on the earlier of: (a) the closing date of the Purchase Agreement and (b) the date upon which the Purchase Agreement is validly terminated in accordance with its terms. As a result of the voting agreements, the Buyer and the persons listed below may be deemed to have beneficial ownership of such shares. On February 24, 2011, Palaeontol B.V., Palaeontol Coöperatief U.A., MIE New Ventures Corporation, MIE Holdings Corporation, Far East Energy Limited, Zhang Ruilin and Zhao Jiangwei jointly filed a Schedule 13D with the Commission in connection with the execution of the voting agreements. Each of the foregoing expressly disclaimed beneficial ownership of the shares.

The following table sets forth, as of June 11, 2011 names and the number of shares of our 55,787,554 shares of outstanding common stock held of record beneficially by each director and of all officers and directors as a group.

Title of Class	Name of Beneficial Owner	Amount & Nature of Beneficial Ownership	% of Class

Common	Anuarbek Baimoldin	20,000	*

Common	Boris Cherdabayev	6,248,727(1)	11.2%

Common	Jason Kerr	-0-	*

Common	Gamal Kulumbetov	280,000	*

Common	Evgeniy Ler	190,000	*

Common	Troy Nilson	-0-	*

Common	Daymon M. Smith	-0-	*

Common	Leonard M. Stillman	-0-	*

Common	Askar Tashtitov	480,000	*

Common	Valery Tolkachev	81,579	*

Common	Toleush Tolmakov	6,251,960(2)	11.2%

Officers and Directors		13,552,266	24.3%
as a Group: (12 persons)

* Less than 1%.

(1)

The shares attributed to Mr. Cherdabayev include 4,128,601 shares held of record by Mr. Cherdabayev, 2,106,126 shares held by or for the benefit of Westfall Group Limited and 14,000 shares held of record by Asael T. Sorensen for the benefit of Boris Cherdabayev. Mr. Cherdabayev is the sole owner of Westfall Group Limited.

(2)	The shares attributed to Mr. Tolmakov include 3,265,365 shares held of record by Mr. Tolmakov and 2,986,595 shares held of record by Simage Limited. Simage Limited is a company owned by Mr. Tolmakov. Mr. Tolmakov is the Vice President of Production of the Company.

Mr. Baimoldin, Mr. Kulumbetov, Mr. Ler, Mr. Tashtitov and Mr. Tolmakov are officers of the Company. Mr. Cherdabayev, Mr. Kerr, Mr. Nilson, Dr. Smith, Mr. Stillman, Mr. Tashtitov and Mr. Tolkachev comprise the board of directors of the Company.

Change in Control

Other than the potential Conversion Price Reduction discussed in more detail in this report in Item 1. Business, which could result in the future issuance of up to an amount of shares that could be considered a controlling interest in the Company, to the knowledge of management, there are no present arrangements or pledges of our securities the operation of which may at a subsequent date result in a change in control of the Company.

Securities Authorized for Issuance Under Equity Compensation Plans

As of June 11, 2011, no shares of our common stock were subject to issuance upon the exercise of outstanding options or warrants as set forth below.

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in columns (a)) (c)
Equity compensation plans approved by security holders	-0-	-	4,025,000
Equity compensation plans not approved by security holders	-0-	-	-
Total	-0-	-	4,025,000

Item 13. Certain Relationships and Related Transactions and Director Independence

Related Party Transactions

During fiscal 2011, 2010 and 2009 we leased office space, oil storage facilities, fuel tanks, warehouses and fuel trucks, in Aktau, Kazakhstan, all of which are critical to Emir Oil’s business, from Term Oil LLC. During the fiscal years ended March 31, 2011, 2010 and 2009 we incurred lease expenses to Term Oil in the amount of $98,092, $96,541 and $221,903, respectively for the use of these facilities. During the fiscal years ended March 31, 2010 and 2009 we paid Term Oil $181,256 and $293,578, respectively. We did not made any payments to Term Oil during the year ended March 31, 2011, as the amounts billed for the 2011 fiscal year were covered by the prepayments made during the 2010 fiscal year. Toleush Tolmakov, a BMB shareholder and the Vice President of Production of the Company, is the sole owner of Term Oil.

On March 31, 2010 Emir Oil entered into an agreement for the Conduction of 3D Seismic Survey with Geo Seismic Service LLP (“Geo Seismic”) to carry out 3D seismic exploration activities of the Begesh, Aday, North Aday and West Aksaz structures, an area of approximately 96 square kilometers within the Company’s Northwest Block. In exchange for these services, Emir Oil will pay Geo Seismic 570,000,000 Kazakh tenge ($3,800,000) after closing of the Purchase Agreement. Toleush Tolmakov is a 30% owner of Geo Seismic.

On June 26, 2009 we entered into a Debt Purchase Agreement with Simage Limited, a British Virgin Islands international business corporation (“Simage”). Simage is a company owned by Mr. Tolmakov. Prior to the date of the Debt Purchase Agreement, Simage had acquired by assignment, certain accounts receivable owed by Emir Oil to third-party creditors of Emir Oil in the amount of $5,973,185 (the “Obligations”). Pursuant to the terms of the Agreement, Simage assigned to the Company all right, title and interest in and to the Obligations in exchange for the issuance of 2,986,595 shares of common stock of the Company. The market value of the shares of common stock issued to Simage, at the agreement date, was $3,076,193. The market value was based on $1.03 per share, which was the closing market price of the Company’s shares on June 26, 2009.

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

As discussed in more detail in this report in Item 11. Executive Compensation, on December 31, 2009, we entered into a Consulting Agreement with Boris Cherdabayev, the Chairman of our board of directors. Pursuant to the Consulting Agreement, in addition to his services as Chairman of the board of directors, Mr. Cherdabayev will provide such consulting and other services as may reasonably be requested by Company management. The Consulting Agreement is for an initial term of five years.

Interests of Related Parties in the Sale of Emir Oil

In connection with the Sale, Mr. Tolmakov and Mr.Cherdabayev agreed to contribute into escrow at closing (to form part of the $36 million in escrow funds described in this report in Item 1. Buisiness) the entirety of the cash distributions they would otherwise be entitled to receive in the initial stockholder distribution in respect of their shares of Company common stock. Mr. Tolmakov is the record or beneficial holder of 6,251,960 shares of common stock and is an officer of the Company. Mr. Cherdabayev is the record or beneficial holder of 6,248,727 shares of common stock and is the Chairman of our Board. The result is that these two stockholders have agreed to put at risk the entire value of their common stock for our indemnification purposes, deferring until the anticipated second stockholder distribution, if any, their portion of the initial stockholder distribution. By doing so, we will be able to pay to our other stockholders at the initial distribution the amount of cash that otherwise would have been paid to Mr. Tolmakov and Mr. Cherdabayev at such time.

The Sale constitutes an extraordinary event under the Consulting Agreement. Mr. Cherdabayev agreed, however, to an amendment to the Consulting Agreement that will defer until the escrow fund is released the $5 million extraordinary event payment that would otherwise have been payable to him upon our entering into the Purchase Agreement. In connection with the amendment to the Consulting Agreement, it was also agreed that the extraordinary event payment amount would be limited to the amount remaining in escrow if less than $5 million, with the possibility of it being reduced to zero if the escrow account is depleted entirely prior to the anticipated second stockholder distribution date. Payment of this liability to Mr. Cherdabayev will be made, if at all, before any escrow funds are distributed to our stockholders, as would have been the case had he not agreed to the amendment. Like the contributions of the initial cash distributions that would have otherwise been received by Mr. Tolmakov and Mr. Cherdabayev discussed above, the deferral of the extraordinary event payment will have the effect of accelerating $5 million of the Sale proceeds to our other stockholders that would have otherwise been required to fund the escrow holdback.

Upon release of the escrow funds (after payment to Mr. Cherdabayev of any amounts due to him at that time under his amended Consulting Agreement in respect of the extraordinary event payment), if any, Mr. Tolmakov and Mr. Cherdabayev will receive prior to any distributions to the other stockholders the initial distributions that they contributed into escrow, to the extent remaining, with the balance of any remaining escrow and other available funds to be distributed thereafter to all of our stockholders, including Mr. Tolmakov and Mr. Cherdabayev, pro rata in accordance with their shares of common stock. Due to the deferral of the extraordinary event payment and contribution of initial distributions to the escrow account the remaining stockholders will receive a larger initial distribution than they would otherwise receive and the risk associated with the escrowed funds will disproportionately fall on Mr, Tolmakov and Mr. Cherdabayev.

The Sale constitutes an extraordinary event under our employment agreements with various executives of the Company, resulting in a termination of such agreements. As a result of such termination due to the occurrence of the extraordinary event, the Company must make severance payments in the following amounts to each of the following officers: Gamal Kulumbetov (Chief Executive Officer), $385,722, Askar Tashtitov (President), $3,000,000, Evgeny Ler (Chief Financial Officer), $363,118, and Anuarbek Baimoldin (Chief Operating Officer), $363,118. In addition to payments to these officers and Mr. Cherdabayev described above, we are required to make extraordinary event payments to other employees and consultants in the aggregate amount of $3,774,690.

Director Independence

The board of directors has determined that Boris Cherdabayev the Chairman of our board of directors and Askar Tashtitov, our Company president would not be considered “independent directors” as that term is defined in the listing standards of the NYSE Amex. The board of directors has determined that Jason Kerr, Troy Nilson, Leonard Stillman, Daymon Smith and Valery Tolkachev are “independent directors” as that term is defined in the listing standards of the NYSE Amex. Such independence definition includes a series of objective tests, including that the director is not an employee of the company and has not engaged in various types of business dealings with the company. In addition, as further required by NYSE Amex listing standards, the board of directors has made a subjective determination as to each independent director that no relationships exist which, in the opinion of the board of directors, would interfere with the exercise of independent judgment in carrying out their responsibilities of a director.

Item 14. Principal Accountant Fees and Services

Hansen, Barnett and Maxwell, P.C. served as the Company’s independent registered public accounting firm for the years ended March 31, 2011 and 2010 and is expected to serve in that capacity for the 2012 fiscal year. Principal accounting fees for professional services rendered for us by Hansen, Barnett & Maxwell, P.C. for the years ended March 31, 2011 and 2010, are summarized as follows:

	Fiscal 2011	Fiscal 2010

Audit	$ 360,788	$ 231,949
Audit related	22,490	37,225
Tax	16,367	34,444
All other	-	-
Total	$ 399,645	$ 303,618

Audit Fees. Audit fees were for professional services rendered in connection with the audit of the financial statements included in our annual report on Form 10-K and review of the financial statements included in our quarterly reports of Form 10-Q and for services normally provided by our independent registered public accounting firm in connection with statutory and regulatory filings or engagements and fees for Sarbanes-Oxley 404 audit work.

Audit Related Fees. Audit related fees include due diligence and audit services related to certain attest services. The fees for 2011 include costs related to the Sale. The fees for 2010 include costs related to responding to SEC comments.

Tax Fees. Hansen Barnett & Maxwell, P.C. billed us an aggregate of $16,367 and $34,444 for professional services rendered for tax compliance, tax advice and tax planning within the United States for the fiscal years ended March 31, 2011 and 2010.

Audit Committee Pre-Approval Policies and Procedures. The Audit Committee had not, as of the time of filing this annual report on Form 10-K with the Commission, adopted policies and procedures for pre-approving all audit services and permitted non-audit services to be performed by our independent auditors. Instead, the Audit Committee has adopted a practice to meet as a whole to pre-approve any such services prior to the time they are performed. In the future, our Audit Committee may adopt pre-approval policies and procedures to approve the services of our independent registered public accounting, provided the policies and procedures are detailed as to the particular service, the Audit Committee is informed of each service, and such policies and procedures do not include delegation of the Audit Committee’s responsibilities to our management.

The Audit Committee has determined that the provision of services by Hansen, Barnett & Maxwell, P.C. described above are compatible with maintaining Hansen, Barnett & Maxwell, P.C.’s independence as our independent registered public accounting firm.

Item 15. Exhibits, Financial Statement Schedules

(a) The following documents are filed as part of this report:

Financial Statements

Report of Independent Registered Public Accounting Firm – Hansen, Barnett & Maxwell, P.C. dated June 28, 2011

Consolidated Balance Sheets as of March 31, 2011 and 2010

Consolidated Statements of Operations for the years ended March 31, 2011 and 2010

Consolidated Statements of Shareholders’ Equity for the years ended March 31, 2011 and 2010

Consolidated Statements of Cash Flows for the years ended March 31, 2011 and 2010

Notes to the Consolidated Financial Statements

Supplementary Financial Information of Oil and Natural Gas Exploration, Development and Production Activities (unaudited)

Financial Statement Schedules

Schedules are omitted because the required information is either inapplicable or presented in the Consolidated Financial Statements or related Notes.

Exhibits

Exhibit No.		Exhibit Description

2.1		Participation Interest Purchase Agreement, dated February 14, 2011, by and among the Company, MIE Holdings Corporation and Palaeontol B.V. (1)
3.1		Articles of Incorporation of BMB Munai, Inc.(2)
3.2		Amendment to Articles of Incorporation of BMB Munai, Inc.(3)
3.3		By-Laws of BMB Munai, Inc. (as amended through July 8, 2010)(4)
4.1		BMB Munai, Inc. 2004 Stock Incentive Plan(5)
4.2		Registration Rights Agreement dated July 13, 2007(6)
4.3		Paying and Conversion Agency Agreement dated July 13, 2007(6)
4.4		BMB Munai, Inc. 2009 Equity Incentive Plan(7) +
4.5		Amended and Restated Indenture, dated as of March 4, 2011, between the Company and The Bank of New York Mellon, as trustee(8)
10.1		Addendum No.3 to Emir Oil Contract(9)
10.2		Form Restricted Stock Agreement of BMB Munai, Inc. dated March 30, 2007 (10) +
10.3		Form Employment Agreement(11) +
10.4		Addendum No. 5 to Emir Oil Contract(12)
10.5		Form Restricted Stock Agreement of BMB Munai, Inc. dated July 17, 2008 (13) +
10.6		Addendum No. 6 to Emir Oil Contract(14)
10.7		Addendum No. 7 to Emir Oil Contract(15)
10.8		Contract No. EO-EAO/30-12 for the Sales and Purchase of Crude Oil (export) (16)
10.9		Additional Agreement #9A to the Contract No. EO-EAO/30-12(16)
10.10		Enclosure #1 to the Contract No. EO-EAO/30-12(16)
10.11		Additional Agreement #27A to the Contract No. EO-EAO/30-12(16)
10.12		Form of BMB Munai, Inc. Restricted Stock Agreement dated January 1, 2010(17) +
10.13		Form of Employment Agreement dated December 31, 2009(17) +
10.14		Consulting Agreement, dated December 31, 2009, between BMB Munai, Inc. and Boris Cherdabayev(17)+
10.15		Conduction of 3D Seismic Survey, dated March 31, 2011, between “Geo Seismic Services” LLP and “Emir-Oil” LLP(18)
10.16		Note Restructuring Agreement, dated as of March 4, 2011, by and among the Company and the holders of the Notes(8)
10.17		Supplemental Indenture No. 6, dated March 4, 2011, between BMB Munai, Inc. and The Bank of New York Mellon, as trustee(8)
10.18		Investors Rights Agreement, dated March 4, 2011, by and among the Company, Boris Cherdabayev, Toleush Tolmakov and the holders of the Senior Notes(8)
10.19		Form of Voting Agreement(1)
10.20		Amendment to the Consulting Agreement and Waiver Agreement, dated February 14, 2011, between BMB Munai, Inc. and Boris Cherdabayev*+
14.1		Code of Ethics(19)
21.1		Subsidiaries*
23.1		Consent of Chapman Petroleum Engineering Ltd., Independent Petroleum Engineers*
23.2		Consent of Hansen, Barnett & Maxwell, P.C., Independent Registered Public Accounting Firm*
31.1		Certification of the Chief Executive Officer Pursuant to Rule 13a-14(a)*
31.2		Certification of Chief Financial Officer Pursuant to Rule 13a-14(a)*
32.1		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350*
32.2		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350*
99.1		Chapman Petroleum Engineering Ltd. Letter on its estimation of our proved oil and gas reserves at March 31, 2011*

* Filed herewith.

+ Indicates management contract, compensatory plan or arrangement of the Company.

(1) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on February 18, 2011.

(2) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on January 18, 2005.

(3) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on June 26, 2006.

(4) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on July 13, 2010.

(5) Incorporated by reference to Registrant’s Definitive Proxy Statement on Schedule 14A filed with the Commission on September 20, 2004.

(6) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on July 19, 2007.

(7) Incorporated by reference to Registrant’s Revised Definitive Proxy Statement on Schedule 14A filed with the Commission on June 23, 2008.

(8) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on March 14, 2011.

(9) Incorporated by reference to Registrant’s Quarterly Report on Form 10-QSB filed with the Commission on February 14, 2005.

(10) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on April 5, 2007.

(11) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on April 12, 2007.

(12) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on June 25, 2008.

(13) Incorporated by reference to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on August 11, 2008.

(14) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on October 21, 2008.

(15) Incorporated by reference to Registrant’s Quarterly Report on Form 10-Q filed with the Commission on February 6, 2009.

(16) Incorporated by reference to Registrant’s Annual Report on Form 10-K filed with the Commission on June 15, 2009.

(17) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on January 6, 2010.

(18) Incorporated by reference to Registrant’s Current Report on Form 8-K filed with the Commission on April 6, 2010.

(19) Incorporated by reference to Registrant’s Annual Report on Form 10-KSB filed with the Commission on June 29, 2004.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed by the undersigned, thereunto duly authorized.

		BMB MUNAI, INC.


Date: June 29, 2011	By:	/s/ Gamal Kulumbetov
		Gamal Kulumbetov
		Chief Executive Officer
		(Duly Authorized Representative)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dated indicated.

Signatures	Title	Date


/s/ Gamal Kulumbetov	Chief Executive Officer	June 29, 2011
Gamal Kulumbetov


/s/ Evgeny Ler	Chief Financial Officer	June 29, 2011
Evgeny Ler


/s/ Boris Cherdabayev	Chairman of the Board of Directors	June 29, 2011
Boris Cherdabayev


/s/ Jason Kerr	Director	June 29, 2011
Jason Kerr


/s/ Troy Nilson	Director	June 29, 2011
Troy Nilson


/s/ Daymon Smith	Director	June 29, 2011
Daymon Smith


/s/ Leonard Stillman	Director	June 29, 2011
Leonard Stillman


/s/ Askar Tashtitov	Director	June 29, 2011
Askar Tashtitov


/s/ Valery Tolkachev	Director	June 29, 2011
Valery Tolkachev

CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED MARCH 31, 2011 AND 2010

Table of Contents

	Page

Report of Independent Registered Public Accounting Firm – Hansen, Barnett & Maxwell P.C.	F-1


Consolidated Balance Sheets as of March 31, 2011 and 2010	F-2

Consolidated Statements of Operations for the years ended March 31, 2011 and 2010	F-3

Consolidated Statements of Shareholders’ Equity for the years ended March 31, 2011 and 2010	F-4

Consolidated Statements of Cash Flows for the years ended March 31, 2011 and 2010	F-5

Notes to the Consolidated Financial Statements	F-7

Supplementary Financial Information on Oil and Natural Gas Exploration, Development, and Production Activities (unaudited)	F-50

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and

Stockholders of BMB Munai, Inc.

We have audited the accompanying consolidated balance sheets of BMB Munai, Inc. and subsidiary as of March 31, 2011 and 2010, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the two-year period ended March 31, 2011. BMB Munai, Inc.’s management is responsible for these financial statements. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of BMB Munai, Inc. and subsidiary as of March 31, 2011 and 2010, and the results of its operations and its cash flows for each of the years in the two-year period ended March 31, 2011 in conformity with accounting principles generally accepted in the United States of America.

As more fully discussed in Note 6, BMB Munai, Inc. is in the process of selling its subsidiary Emir Oil LLP. The stockholders of BMB Munai, Inc. approved the sale of Emir Oil LLP at a special meeting on June 2, 2011. Because of the pending sale of Emir Oil LLP, BMB Munai, Inc. has classified Emir Oil LLP’s assets, liabilities, and operations as discontinued for reporting purposes. Historically, the assets and operations of Emir Oil LLP, have represented the major portion of the consolidated total assets and results of operations of BMB Munai, Inc.

The accompanying financial statements have been prepared assuming that BMB Munai, Inc. will continue as a going concern. As a result of the pending sale of Emir Oil LLP, BMB Muni, Inc. will have no continuing operations that result in positive cash flow, which raise substantial doubt about its ability to continue as a going concern. Management's assessment concerning these matters is described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

HANSEN, BARNETT & MAXWELL, P.C.

Salt Lake City, Utah

June 28, 2011

F-1

BMB MUNAI, INC.

CONSOLIDATED BALANCE SHEETS

	Notes	March 31, 2011	March 31, 2010

ASSETS
CURRENT ASSETS
Cash and cash equivalents	3	$ 426,045	$ 2,992,392
Promissory notes receivable	4	154,725	-
Prepaid expenses and other assets, net	5	74,041	36,055
Current assets from discontinued operations	6	18,270,599	13,919,266

Total current assets		18,925,410	16,947,713

LONG TERM ASSETS
Other fixed assets, net	7	162,488	231,043
Convertible notes issue cost	8	738,062	1,201,652
Long term assets from discontinued operations	6	300,708,406	273,879,244

Total long term assets		301,608,956	275,311,939

TOTAL ASSETS		$ 320,534,366	$ 292,259,652

LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES
Accounts payable		$ 767,489	$ 232,588
Accrued coupon payment	8	1,430,108	641,667
Taxes Payable, Accrued liabilities and other payables		317,968	200,234
Current liabilities from discontinued operations	6	27,587,087	8,318,390

Total current liabilities		30,102,652	9,392,879

LONG TERM LIABILITIES
Convertible notes issued, net	8	61,703,728	62,178,119
Deferred taxes	9	3,977,385	5,344,016
Long term liabilities from discontinued operations	6	6,137,742	5,082,146

Total long term liabilities		71,818,855	72,604,281

COMMITMENTS AND CONTINGENCIES	12	-	-

SHAREHOLDERS’ EQUITY
Preferred stock - $0.001 par value; 20,000,000 shares authorized; no shares issued or outstanding	10	-	-
Common stock - $0.001 par value; 500,000,000 shares authorized, 55,787,554 and 51,865,015 shares outstanding, respectively	10	55,788	51,865
Additional paid in capital	10	164,118,640	160,653,969
Retained earnings		54,438,431	49,556,658

Total shareholders’ equity		218,612,859	210,262,492

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$ 320,534,366	$ 292,259,652

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

F-2

BMB MUNAI, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

	Notes	Year ended March 31, 2011	Year ended March 31, 2010


REVENUES		$ -	$ -

COSTS AND OPERATING EXPENSES
General and administrative		10,037,072	9,307,412
Interest expense	8	5,977,640	4,604,446
Amortization and depreciation		89,575	123,541

Total costs and operating expenses		16,104,287	14,035,399

LOSS FROM OPERATIONS		(16,104,287)	(14,035,399)

OTHER (EXPENSE) / INCOME
Foreign exchange (loss)/gain, net		(415,803)	42,927
Interest income		11,388	2,327
Other income / (expense), net		7,974	(179)

Total other (expense)/income		(396,441)	45,075

LOSS BEFORE INCOME TAXES		(16,500,728)	(13,990,324)

INCOME TAX BENEFIT	9	1,366,631	3,260,619

LOSS FROM CONTINUING OPERATIONS		(15,134,097)	(10,729,705)

INCOME FROM DISCONTINUED OPERATIONS	6	20,015,870	19,723,178

NET INCOME		$ 4,881,773	$ 8,993,473

BASIC NET LOSS PER COMMON SHARE FROM CONTINUING OPERATIONS	11	$ (0.28)	$ (0.21)
DILUTED NET LOSS PER COMMON SHARE FROM CONTINUING OPERATIONS	11	$ (0.28)	$ (0.21)
BASIC NET INCOME PER COMMON SHARE FROM DISCONTINUED OPERATIONS	11	$ 0.38	$ 0.39
DILUTED NET INCOME PER COMMON SHARE FROM DISCONTINUED OPERATIONS	11	$ 0.38	$ 0.39

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

F-3

BMB MUNAI, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

				Additional
		Common Stock		paid-in	Retained
	Notes	Shares	Amount	capital	earnings	Total

At March 31, 2009		47,378,420	$ 47,378	$ 151,513,638	$ 40,563,185	$ 192,124,201
Expense related to vesting stock-based compensation	10	-	-	2,744,133	-	2,744,133
Stock grants issued to employees	10	1,500,000	1,500	426,000	-	427,500
Debt conversion	6	2,986,595	2,987	5,970,198	-	5,973,185
Net income for the year		-	-	-	8,993,473	8,993,473

At March 31, 2010		51,865,015	$ 51,865	$ 160,653,969	$ 49,556,658	$ 210,262,492

Expense related to vesting stock-based compensation	10	-	-	1,254,025	-	1,254,025
Stock refunds from employees	10	(25,000)	(25)	25	-	-
Debt conversion	10	3,947,539	3,948	2,210,621	-	2,214,569
Net income for the year		-	-	-	4,881,773	4,881,773

At March 31, 2011		55,787,554	$ 55,788	$ 164,118,640	$ 54,438,431	$ 218,612,859

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

F-4

BMB MUNAI, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Notes	Year ended March 31, 2011		Year ended March 31, 2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	4,881,773	$	8,993,473
Adjustments to reconcile net income to net cash provided by operating activities:
Income from discontinued operations	6		(20,015,870)		(19,723,178)
Interest expense	8		5,977,640		4,604,446
Stock based compensation expense			1,254,025		3,171,633
Loss on disposal of fixed assets			26,297		69
Income tax benefit	9		(1,366,631)		(3,260,619)
Changes in operating assets and liabilities
(Increase)/decrease in prepaid expenses and other assets			(37,986)		(423,756)
Increase/(decrease) in accounts payable			534,901		(3,935,845)
Decrease in taxes payables and accrued liabilities			117,734		5,872,788
Net cash used in operating activities – continuing operations			(8,538,542)		(4,577,448)
Net cash provided by operating activities – discontinued operations	6		44,317,891		18,672,428
Net cash provided by operating activities			35,779,349		14,094,980

CASH FLOWS FROM INVESTING ACTIVITIES:
Investment in short term notes receivable	4		(154,725)		-
Purchase of other fixed assets	7		(47,317)		(112,327)
Net cash used in investing activities – continuing operations			(202,042)		(112,327)
Net cash used in investing activities – discontinued operations	6		(34,876,907)		(11,297,804)
Net cash used in investing activities			(35,078,949)		(11,410,131)

CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid for convertible notes coupon	8		(4,200,000)		(3,000,000)
Repayment of convertible notes issued	8		(1,000,000)		-
Intercompany advances(1)			11,374,237		6,319,837
Net cash (used in) provided by financing activities – continuing operations			6,174,237		3,319,837
Net cash used in financing activities – discontinued operations(2)	6		(11,543,482)		(6,319,837)
Net cash used in financing activities			(5,369,245)		(3,000,000)

NET CHANGE IN CASH AND CASH EQUIVALENTS			(4,668,845)		(315,151)
NET CHANGE IN CASH AND CASH EQUIVALENTS from discontinuing operations			(2,102,498)		1,054,787
NET CHANGE IN CASH AND CASH EQUIVALENTS from continuing operations			(2,566,347)		(1,369,938)
CASH AND CASH EQUIVALENTS at beginning of year			2,992,392		4,362,330
CASH AND CASH EQUIVALENTS at end of year		$	426,045	$	2,992,392

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

(1)	Intercompany advances represent payments and receipts between BMB Munai and Emir and are shown to break out the activity between continuing and discontinuing operations. Intercompany advances are eliminated and do not appear on the consolidated balance sheets.

(2)	Includes intercompany advances activity.

F-5

BMB MUNAI, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)

		Year ended March 31, 2011	Year ended March 31, 2010
Non-Cash Investing and Financing Activities
Transfer of inventory and prepayments for materials used in oil and gas projects to oil and gas properties	6	$ 2,946,704	$ 3,147,789
Issuance of common stock for services, capitalized to oil and gas properties	10	2,214,569	-
Depreciation on other fixed assets capitalized as oil and gas properties	6	561,871	454,174
Addition of other fixed assets under capital lease contract	6	-	369,801
Issuance of common stock for the settlement of liabilities	10	-	5,973,185

Supplemental Cash Flow Information
Cash paid for interest	8	$ 4,200,000	$ 3,000,000

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

F-6

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - DESCRIPTION OF BUSINESS

BMB Munai, Inc., is a Nevada corporation that originally incorporated in the State of Utah in 1981. Since 2003, our business activities have focused on oil and natural gas exploration and production in the Republic of Kazakhstan (also referred to herein as the “ROK” or “Kazakhstan”) through our wholly-owned operating subsidiary Emir Oil LLP, (“Emir Oil”). Emir Oil holds an exploration contract that allows the Company to conduct exploration drilling and oil production in the Mangistau Province in the southwestern region of Kazakhstan until January 2013. The exploration territory of our contract area is approximately 850 square kilometers and is comprised of three areas, referred to herein as the ADE Block, the Southeast Block and the Northwest Block. The ADE Block, the Southeast Block and the Northwest Block are collectively referred to herein as “our properties.” For additional information regarding the contract and license to our properties please see Item 2. Properties of this report.

On February 14, 2011, the Company entered into a Participation Interest Purchase Agreement (the “Purchase Agreement”) with MIE Holdings Corporation, a company with limited liability organized under the laws of the Cayman Islands (“MIE”), and its subsidiary, Palaeontol B.V., a company organized under the laws of the Netherlands (“Palaeontol”), pursuant to which the Company agreed to sell all of our interest in Emir Oil to Palaeontol (the “Sale.”) The initial purchase price is $170 million and is subject to various closing adjustments and the deposit of $36 million in escrow to be held for a period of twelve months following the closing for indemnification purposes. In connection with the Sale, all intercompany notes of Emir Oil in favor of BMB will be transferred to Palaeontol. Upon consummation of the Sale, the Company will use a portion of the proceeds to repay the Company’s outstanding convertible senior notes and to pay transaction costs and expenses. The Company also intends to make an initial cash distribution from the Sale proceeds to stockholders in the estimated range of $1.04 to $1.10 per share upon the closing, after giving effect to the estimated closing adjustments and escrow holdback amount, the repayment of the Senior Notes and providing for the payment or reserve of other projected liabilities and transaction costs. The Company intends to make a second distribution to stockholders that could range up to approximately $0.30 per share following termination of the escrow, subject to the availability of funds to be released from the escrow, actual costs incurred and other factors.

The Company has a representative office in Almaty, Republic of Kazakhstan.

NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The Company’s audited 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 audited consolidated financial statements.

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Certain reclassifications have been made in the financial statements for the year ended March 31, 2010 to conform to the March 31, 2011 classification of discontinued operations. These classifications were made because of the pending sale of Emir Oil LLP. Due to these classifications, consolidated total assets and liabilities increased $379,634 from previously reported figures. Emir Oil LLP’s deferred tax asset of $379,634 was disaggregated from the previously netted consolidated deferred tax liability. The reclassifications had no effect on net income.

Business condition

On February 14, 2011, the Company entered into a Purchase Agreement with MIE Holdings Corporation, and its subsidiary, Palaeontol B.V., (the “Purchase Agreement”) pursuant to which the Company has agreed to sell all of our interest in and intercompany loans to our wholly-owned operating subsidiary, Emir Oil LLP to the Palaeontol B.V. (the “Sale”). In addition, net losses and cash flow used in operations for each of the years ending March 31, 2011 and 2010 are summarized as follows:

	For the year ended March 31,
	2011	2010

Net loss from continuing operations	$ (15,134,097)	$ (10,729,705)
Cash used in operating activities from continuing operations	$ (8,538,542)	$ (4,577,448)

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

	•	increased the coupon rate of the Original Notes from 9.0% to 10.75%;
	•	made a $1.0 million cash payment to holders of the Original Notes;
	•	increased the aggregate principal amount of the Original Notes from $60.0 million to $61.4 million;
	•	extended the maturity date of the Original Notes from July 13, 2012 to July 13, 2013;
	•	granted the holders of the Original Notes a new put option, exercisable one year prior to the new maturity date;

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

	•	agreed to additional covenant restrictions, including a limitation on indebtedness that the Company may incur, a restriction on the capital expenditures the Company may make, a prohibition on paying dividends on shares of the Company’s common stock and a limitation on the investments the Company may make;
	•	agreed to semi-annual principal amortization payments of 30% of the Company’s excess cash flow, if any; and
	•	granted the holders of the Original Notes director nominee rights with respect to the Company and Emir Oil.

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

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

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

Going concern

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

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Subsequent event

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

Use of estimates

The preparation of audited consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect certain reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the audited 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 audited consolidated financial statements.

Concentration of credit risk and accounts receivable

Financial instruments that potentially subject the Company to a concentration of credit risk consist principally of cash and accounts receivable. The Company places its cash with high credit quality financial institutions. Substantially all of the Company’s accounts receivable are from purchasers of oil and gas. Oil and gas sales are generally unsecured. The Company has not had any significant credit losses in the past and believes its accounts receivable are fully collectable. Accordingly, no allowance for doubtful accounts has been provided.

Foreign currency translation

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Share-based compensation

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

The Company has a stock option plan as described in Note 10. Compensation expense for options and stock granted to employees is determined based on their fair values at the time of grant, the cost of which is recognized in the Consolidated Statements of Operations over the vesting periods of the respective options.

Share-based compensation incurred for the years ended March 31, 2011 and 2010 was $1,254,025 and $3,171,633, respectively.

Full Cost Method of Accounting

The Company follows the full cost method of accounting for oil and gas properties. Under this method, all costs associated with acquisition, exploration and development of oil and gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. These costs do not include any costs related to production, general corporate overhead or similar activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of our proved reserves are sold (greater than 25 percent), in which case a gain or loss is recognized.

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

	a)	the present value of estimated future net revenues computed by applying current prices of oil and gas reserves to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves computed using a discount factor of ten percent and assuming continuation of existing economic conditions;
	b)	plus the cost of properties not being amortized;
	c)	plus the lower of cost or estimated fair value of unproven properties included in the costs being amortized;
	d)	less income tax effects related to differences between the book and tax basis of the properties.

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

All geological and geophysical studies, with respect to the licensed territory, have been capitalized as part of the oil and gas properties.

Our oil and gas properties primarily include the value of the license and other capitalized costs.

Ceiling test

Risks and uncertainties

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

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Recognition of revenue and cost

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

Export duty

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

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

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

Mineral extraction tax

The mineral extraction tax replaced the royalty expense the Company had paid. The rate of this tax depends on annual production output. The new code currently provides for a 5% mineral extraction tax rate on production sold to the export market, and a 2.5% tax rate on production sold to the domestic market. The mineral extraction tax expense is reported as part of oil and gas operating expense.

Rent export tax

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

F-13

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Income taxes

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

Fair value of financial instruments

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

Cash and cash equivalents

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

Prepaid expenses and other assets

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

Prepayments for materials used in oil and gas projects

The Company periodically makes prepayments for materials used in oil and gas projects. These prepayments are presented as long term assets due to their transfer to oil and gas properties after materials are supplied and the prepayments are closed.

Inventories

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

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

The Company periodically assesses its inventories for obsolete or slow moving stock and records an appropriate provision, if there is any. The Company has assessed inventory at March 31, 2011 and no provision for obsolete inventory has been provided.

Oil and gas properties

The Company uses the full cost method of accounting for oil and gas properties. Under this method, all costs associated with acquisition, exploration, and development of oil and gas properties are capitalized. Costs capitalized include acquisition costs, geological and geophysical expenditures, and costs of drilling and equipping productive and non-productive wells. Drilling costs include directly related overhead costs. These costs do not include any costs related to production, general corporate overhead or similar activities. Under this method of accounting, the cost of both successful and unsuccessful exploration and development activities are capitalized as property and equipment. Proceeds from the sale or disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion of the Company’s proved reserves are sold (greater than 25 percent), in which case a gain or loss is recognized.

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

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

b) plus the cost of properties not being amortized;

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

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

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Given the volatility of oil and gas prices, it is reasonably possible that the estimate of discounted future net cash flows from proved oil and gas reserves could change. If oil and gas prices decline, even if only for a short period of time, it is possible that impairments of oil and gas properties could occur. In addition, it is reasonably possible that impairments could occur if costs are incurred in excess of any increases in the cost ceiling, revisions to proved oil and gas reserves occur, or if properties are sold for proceeds less than the discounted present value of the related proved oil and gas reserves.

All geological and geophysical studies, with respect to the licensed territory, have been capitalized as part of the oil and gas properties.

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

Liquidation fund

Liquidation fund (site restoration and abandonment liability) is related primarily to the conservation and liquidation of the Company’s wells and similar activities related to its oil and gas properties, including site restoration. Management assessed an obligation related to these costs with sufficient certainty based on internally generated engineering estimates, current statutory requirements and industry practices. The Company recognized the estimated fair value of this liability. These estimated costs were recorded as an increase in the cost of oil and gas assets with a corresponding increase in the liquidation fund which is presented as a long-term liability. The oil and gas assets related to liquidation fund are depreciated on the unit-of-production basis separately for each field. An accretion expense, resulting from the changes in the liability due to passage of time by applying an interest method of allocation to the amount of the liability, is recorded as accretion expenses in the Consolidated Statement of Operations.

The adequacies of the liquidation fund are periodically reviewed in the light of current laws and regulations, and adjustments made as necessary.

Other fixed assets

Other fixed assets are valued at historical cost adjusted for impairment loss less accumulated depreciation. Historical cost includes all direct costs associated with the acquisition of the fixed assets.

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Depreciation of other fixed assets is calculated using the straight-line method based upon the following estimated useful lives:

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

Maintenance and repairs are charged to expense as incurred. Renewals and betterments are capitalized as leasehold improvements, which are amortized on a straight-line basis over the shorter of their estimated useful lives or the term of the lease.

Other fixed assets of the Company are evaluated annually for impairment. If the sum of expected undiscounted cash flows is less than net book value, unamortized costs of other fixed assets will be reduced to a fair value. Based on the Company’s analysis at March 31, 2011, no impairment of other assets is necessary.

Convertible Notes payable issue costs

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

Restricted cash

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

Functional currency

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

Income per common share

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

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

New accounting policies

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

Modernization of Oil and Gas Reporting – In January 2010, the FASB issued Accounting Standards Update No. 2010-03 to align the oil and gas reserve estimation and disclosure requirements of Topic 932 (“Extractive Industries — Oil and Gas”) with the requirements of SEC Release 33-8994. This release is effective for financial statements issued on or after January 1, 2010. The Company adopted this guidance effective March 31, 2010. This release changes the accounting and disclosure requirements of oil and gas reserves and is intended to modernize and update the oil and gas disclosure requirements, to align them with current industry practices and to adapt to changes in technology. The new rules permit the use of new technologies to determine proved reserves, allow companies to disclose their probable and possible reserves and allow proved undeveloped reserves to be maintained beyond a five-year period only if justified by specific circumstances. The new rules require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of its reserve estimates, and to file reports when a third party is relied upon to prepare or audit its reserve estimates. The new rules also require that the net present value of oil and gas reserves reported and used in the full cost ceiling test calculation be based upon average market prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period.

NOTE 3 - CASH AND CASH EQUIVALENTS

As of March 31, 2011 and 2010 cash and cash equivalents included:

	March 31, 2011	March 31, 2010

US Dollars	$ 274,870	$ 2,914,499
Foreign currency	151,175	77,893

	$ 426,045	$ 2,992,392

As of March 31, 2011 and 2010, cash and cash equivalents included $21,823 and $1,321,774 placed in money market funds having 30 day simple yields of 0.01%.

F-18

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4 – PROMISSORY NOTES RECEIVABLE

On December 17, 2010 the Company entered into agreement with Montclair Technology, LLC (the “Borrower”) and Michael Williams (the “Guarantor’) to loan funds to the Borrower in an amount of up to $200,000. The Guarantor owns a patent and has proprietary know-how to develop oil refining and regeneration plants and Borrower desires to grant the Company a license to use and employ the technology. As further inducement for the Company to loan funds to the Borrower, Guarantor has agreed to guarantee Borrower’s obligations under any promissory note made by Borrower pursuant to this agreement.

As a result at December 17, 2010, Borrower issued the Company a Promissory note for $50,000 with interest rate of 18% per annum. The outstanding principal sum and all accrued and unpaid interest or other sums under this Promissory note shall be payable one year after the December 17, 2010. Borrower may prepay any or all accrued and unpaid interest and unpaid principal at any time without penalty. After the first transfer in December 2010, the Company made additional transfers on January 19, 2011, February 24, 2011 and March 31, 2011 in the amounts of $50,000, $25,000 and $25,000, respectively.

As a result the Company treated the loan as Promissory note receivable in its financial statements. At March 31, 2011 Promissory notes receivable amounted to $154,725, with $150,000 principal amount and $4,725 representing the amount of interest accrued.

NOTE 5 - PREPAID EXPENSES AND OTHER ASSETS

Prepaid expenses and other assets as of March 31, 2011 and 2010, were as follows:

	March 31, 2011	March 31, 2010

Advances for services	$ 31,375	$ 31,409
Other	42,666	4,646

	$ 74,041	$ 36,055

NOTE 6 – DISCONTINUED OPERATIONS

Emir Oil LLP

As noted in detail in the Current Report of the Company on Form 8-K filed with the SEC on February 18, 2011, the Company has entered into a Participation Interest Purchase Agreement (the “Purchase Agreement”) with MIE Holdings Corporation and its subsidiary Palaeontol B.V., pursuant to which the Company agreed to sell all of its interest in its wholly-owned operating subsidiary, Emir Oil. Accordingly, the results of operations and the financial position of Emir Oil has been reclassified in the accompanying consolidated financial statements as discontinued operations.

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BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Net assets of discontinued operations at March 31, 2011 and 2010 consisted of following:

	March 31, 2011	March 31, 2010

ASSETS
CURRENT ASSETS
Cash and cash equivalents	$ 1,345,504	$ 3,448,002
Trade accounts receivable	13,857,331	6,423,402
Prepaid expenses and other assets, net	3,067,764	4,047,862

Total current assets	18,270,599	13,919,266

LONG TERM ASSETS
Oil and gas properties, full cost method, net	262,951,788	238,601,842
Gas utilization facility, net	12,325,847	13,569,738
Inventories for oil and gas projects	13,964,385	13,717,847
Prepayments for materials used in oil and gas projects	2,141,928	141,312
Other fixed assets, net	3,798,801	3,584,379
Long term VAT recoverable	4,640,396	3,113,939
Deferred tax asset	-	379,634
Restricted cash	885,261	770,553

Total long term assets	300,708,406	273,879,244

TOTAL ASSETS	$ 318,979,005	$ 287,798,510

LIABILITIES

CURRENT LIABILITIES
Accounts payable	$ 20,608,547	$ 3,716,263
Accrued coupon payment	6,634,184	4,412,702
Taxes payable, accrued liabilities and other payables	344,356	189,425

Total current liabilities	27,587,087	8,318,390

LONG TERM LIABILITIES
Liquidation fund	5,207,842	4,712,345
Deferred tax liabilities	757,462	-
Capital lease liability	172,438	369,801

Total long term liabilities	6,137,742	5,082,146

TOTAL LIABILITIES	$ 33,724,829	$ 13,400,536

F-20

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Summary of discontinued operations for years ended March 31, 2011 and 2010 were as follows:

	Year ended March 31, 2011	Year ended March 31, 2010

Revenue	$ 64,417,933	$ 57,274,526

Expenses:
Rent export tax	(13,338,869)	(10,032,857)
Export duty	(1,951,794)	-
Production	(5,188,517)	(5,144,650)
Transportation	(4,345,700)	(3,423,803)
General and administrative	(6,227,597)	(4,735,165)
Depletion	(10,332,115)	(11,075,590)
Depreciation of gas utilization facility	(1,243,891)	-
Amortization and depreciation	(495,537)	(490,412)
Accretion expenses on ARO	(495,497)	(448,351)

Income from operations	20,798,416	21,923,698

Other income/(expense)	354,550	(491,963)

Income before income taxes	21,152,966	21,431,735

Income tax expense	(1,137,096)	(1,708,557)

Income from discontinued operations, net of income taxes	$ 20,015,870	$ 19,723,178

ACCOUNTING FOR VARIABLE INTEREST ENTITIES

The Company has relationship with Term Oil LLC where it has an implicit VIE through common ownership. Management has evaluated this relationship and concluded that the Company does not have the ability to control Term Oil LLC and the Company does not have the obligation to absorb losses or the right to receive returns of the VIE. Therefore this implicit VIE is not consolidated in these financial statements.

F-21

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

LICENCES AND CONTRACTS

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

On October 15, 2008, the MEMR approved Addendum # 6 to Contract No. 482 with Emir Oil, dated June 09, 2000 extending Emir Oil’s exploration territory from 460 square kilometers to a total of 850 square kilometers (approximately 210,114 acres). The additional territory is located to the north and west of the Company’s current exploration territory, extending the exploration territory toward the Caspian Sea and is referred to herein as the “Northwest Block.” The Northwest Block is governed by the terms of the Company’s exploration stage contract on the ADE Block and the Southeast Block.

To move from the exploration stage to the commercial production stage, the Company must apply for and be granted a commercial production contract. The Company is legally entitled to apply for a commercial production contract and has an exclusive right to negotiate this contract. The Government is obligated to conduct these negotiations under the Law of Petroleum in Kazakhstan. If the Company does not move from the exploration stage to the commercial production stage, it has the right to produce and sell oil, including export oil, under the Law of Petroleum for the term of its existing contract.

OIL AND GAS PROPERTIES

Oil and gas properties using the full cost method as of March 31, 2011 and 2010, were as follows:

	March 31, 2011	March 31, 2010

Cost of drilling wells	$ 103,668,624	$ 96,562,442
Professional services received in exploration and development activities	80,480,267	62,967,506
Material and fuel used in exploration and development activities	55,573,806	52,221,735
Subsoil use rights	20,788,119	20,788,119
Deferred tax	7,219,219	7,219,219
Geological and geophysical	9,346,602	7,883,856
Capitalized interest, accreted discount and amortised bond issue costs on convertible notes issued	6,633,181	6,633,181
Infrastructure development costs	1,654,177	1,429,526
Other capitalized costs	22,221,956	17,198,306
Accumulated depletion	(44,634,163)	(34,302,048)

	$ 262,951,788	$ 238,601,842

F-22

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

GAS UTILIZATION FACILITY

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

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

The GUF is evaluated annually for impairment. If the sum of expected undiscounted cash flows is less than net book value, unamortized costs of the GUF will be reduced to fair value. At March 31, 2011, no impairment of the GUF was considered necessary.

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

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

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

Based on the selling agreement mentioned above, the Company officially placed the GUF into service on May 1, 2010 and is depreciating the GUF over an estimated useful life of 10 years. During the year ended March 31, 2011, depreciation expense for the GUF was $1,243,891. No depreciation expense for the GUF has been recognized for the year ended March 31, 2010.

F-23

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

INVENTORIES FOR OIL AND GAS PROJECTS

As of March 31, 2011 and 2010 inventories included:

	March 31, 2011	March 31, 2010

Construction material	$ 13,146,303	$ 12,756,417
Spare parts	94,960	87,722
Crude oil produced	3,276	2,895
Other	719,846	870,813

	$ 13,964,385	$ 13,717,847

LIQUIDATION FUND

Reconciliation on the Liquidation Fund (Asset Retirement Obligation) at March 31, 2010 and 2011 is as follows:

	Total

At March 31, 2009	$ 4,263,994

Accrual of liability	-
Accretion expenses	448,351

At March 31, 2010	$ 4,712,345

Accrual of liability	-
Accretion expenses	495,497

At March 31, 2010	$ 5,207,842

Management believes that the liquidation fund should be accrued for future abandonment costs of 24 wells located in the Dolinnoe, Aksaz, Emir and Kariman oil fields. Management believes that these obligations are likely to be settled at the end of the production phase at these oil fields.

At March 31, 2011, undiscounted expected future cash flows that will be required to satisfy the Company’s obligation by 2013 for the Dolinnoe, Aksaz, Emir and Kariman fields, respectively, are $6,204,545. After application of a 10% discount rate, the present value of the Company’s liability at March 31, 2011 and 2010, was $5,207,842 and $4,712,345 respectively.

F-24

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

REVENUES

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

The Company recognized revenue from sales as follows:

	Year ended March 31, 2011	Year ended March 31, 2010

Export sales – oil	$ 62,804,043	$ 56,135,006
Domestic sales – oil	231,718	1,139,520
Domestic sales – gas	1,382,172	-

	$ 64,417,933	$ 57,274,526

During the years ended March 31, 2011 and 2010, oil sales to one customer represented 97% and 98% of total sales, respectively. At March 31, 2011 and 2010, this customer made up 96% of accounts receivable from oil sales, respectively. While the loss of this foregoing customer could have a material adverse effect on the Company in the short-term, the loss of this customer should not materially adversely affect the Company in the long-term because of the available market for the Company’s crude oil and natural gas production from other purchasers.

The Company began realizing revenue from natural gas sales to the domestic market in May 2010. During the year ended March 31, 2011 the Company realized revenue from natural gas sales of $1,382,172. Prior to May 2010 the Company did not realize revenue from natural gas sales, because the amounts realized from natural gas sales were insignificant and thus were included in revenue from oil sales.

RELATED PARTY TRANSACTIONS

Non-Consolidated VIE

The Company has an implicit VIE through common ownership with Term Oil LLC from which Company leases ground fuel tanks and other oil fuel storage facilities and warehouses. Management has evaluated and concluded that the Company is not the primary beneficiary because it does not have the ability to control the VIE and does not have the obligation to absorb losses or the right to receive returns. The VIE leases fuel tanks and other fuel storage facilities to third parties. The maximum exposure to loss due to involvement with the VIE is the amount of advances paid to Term Oil LLC.

F-25

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The lease expenses for the years ended March 31, 2011 and 2010, totaled to $98,092 and $96,541, respectively. During the fiscal year ended March 31, 2010 the Company paid Term Oil $181,256. The Company has not made any payments to Term Oil during the year ended March 31, 2011; the expenses were covered by the advance prepayment made during the fiscal year 2010. Mr. Toleush Tolmakov, the Vice President of the Company and a holder of more than 10% of the outstanding common stock of the Company, is 100% owner of Term Oil LLC.

3D Seismic Survey

On March 31, 2010 the Company entered into an agreement for conducting a 3D seismic survey with Geo Seismic Service LLP (“Geo Seismic”). Mr. Toleush Tolmakov is a 30% owner of Geo Seismic.

The agreement provides that Geo Seismic will carry out 3D field seismic exploration activities of the Begesh, Aday, North Aday and West Aksaz structures, an area of approximately 96 square kilometers within the Company’s Northwest Block. In exchange for these services, Emir Oil will pay in cash Geo Seismic 570,000,000 Kazakh tenge ($3,800,000) after selling of all of our interest in our wholly-owned operating subsidiary, Emir Oil, to the Buyer (the “Sale”) to MIE Holdings Corporation (“Parent”), and its subsidiary, Palaeontol B.V. (the “Buyer”) according to Purchase Agreement.

On June 26, 2009 the Company entered into a Debt Purchase Agreement (the “Agreement”) with Simage Limited, a British Virgin Islands international business corporation (“Simage”). Simage is a company owned by Toleush Tolmakov.

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

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

F-26

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

COMMITMENTS AND CONTINGENCIES

Historical Investments by the Government of the Republic of Kazakhstan

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

Capital Commitments

To retain its rights under the contract, the Company must spend $16.4 million between January 10, 2011 and January 9, 2012 and $11.1 million between January 10, 2012 and January 9, 2013.

In addition to the minimum capital expenditure requirement, the Company must also comply with the other terms of the work program associated with the contract, which includes the drilling of at least six new wells by January 9, 2013. The failure to meet the minimum capital expenditures or to comply with the terms of the work program could result in the loss of the subsurface exploration contract.

During the year ended March 31, 2011, the Company made payment in the amount of $200,000 to social projects of the Mangistau Oblast for 2010 and payment of $200,000 to the Astana Fund.

NOTE 7 - OTHER FIXED ASSETS

	Vehicles	Office equipment	Furniture and fixtures	Software	Total
Cost
at March 31, 2010	$ 395,389	$ 142,430	$ 58,146	$ 36,898	$ 632,863
Additions	-	36,959	8,383	1,975	47,317
Disposals	83,430	25,125	45,435	24,225	178,215
at March 31, 2011	311,959	154,264	21,094	14,648	501,965

Accumulated depreciation
at March 31, 2010	233,715	118,149	17,551	32,405	401,820
Charge for the period	57,913	22,522	4,012	5,128	89,575
Disposals	83,430	25,536	18,524	24,428	151,918
at March 31, 2011	208,198	115,135	3,039	13,105	339,477

Net book value at March 31, 2010	$ 161,674	$ 24,281	$ 40,595	$ 4,493	$ 231,043

Net book value at March 31, 2011	$ 103,761	$ 39,129	$ 18,055	$ 1,543	$ 162,488

F-27

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8 - CONVERTIBLE NOTES PAYABLE

As of March 31, 2011 and March 31, 2010, the Notes payable amount is presented as follows:

	March 31, 2011	March 31, 2010

Convertible notes redemption value	$ 65,824,673	$ 64,323,785
Unamortized discount	(4,120,945)	(2,145,666)
	$ 61,703,728	$ 62,178,119

As of March 31, 2011 and March 31, 2010, the Company has accrued interest of $1,430,108 and $641,667, respectively, relating to the Notes outstanding. The Company has amortized the discount on the Notes (difference between the redemption amount and the carrying amount as of the date of issue) in the amount of $1,703,728 and $2,178,119 as of March 31, 2011 and March 31, 2010, respectively. The carrying value of Notes will be accreted to the redemption value of $65,824,673. During the years ended March 31, 2011 and 2010 the Company recorded interest expense in the amount of $5,977,640 and $4,604,446, respectively.

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

	•	increased the coupon rate of the Original Notes from 9.0% to 10.75%;
	•	made a $1.0 million cash payment to holders of the Original Notes;
	•	increased the aggregate principal amount of the Original Notes from $60.0 million to $61.4 million;
	•	extended the maturity date of the Original Notes from July 13, 2012 to July 13, 2013;
	•	granted the holders of the Original Notes a new put option, exercisable one year prior to the new maturity date;
	•	agreed to additional covenant restrictions, including a limitation on indebtedness that the Company may incur, a restriction on the capital expenditures the Company may make, a prohibition on paying dividends on shares of our common stock and a limitation on the investments the Company may make;
	•	agreed to semi-annual principal amortization payments of 30% of our excess cash flow, if any;
	•	granted the holders of the Original Notes director nominee rights with respect to the Company and Emir Oil;

F-28

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

	•	agreed, subject to approval of our common stockholders and to receipt of any necessary regulatory approvals, to reduce the conversion price of the Original Notes from $7.2904 per share to $2.00 per share with a corresponding reduction in the minimum conversion price from $6.95 per share to $1.00 per share (the “Conversion Price Reduction”); and
	•	entered into various agreements including an amended and restated indenture (the “Amended Indenture”) reflecting the changes discussed herein and the Original Notes were delivered to the Trustee for cancellation and in substitution the Company issued $61.4 million in principal amount of 10.75% Convertible Senior Notes due 2013 (the “Senior Notes”).

In connection with the Note Restructure, the Noteholders approved the Sale pursuant to the Purchase Agreement. Upon consummation of the Sale, the Company is required to redeem each Senior Note for 100% of such Senior Note’s outstanding principal amount, together with interest accrued to such date, out of the proceeds of the Sale.

On June 2, 2011, at a special meeting of our common stockholders, our common stockholders voted on and approved the Conversion Price Reduction. The Conversion Price Reduction may also be subject to approval of the MOG. The Company have agreed with the Noteholders that the Company will seek clarification from the MOG as to whether MOG approval of the Conversion Price Reduction is necessary. The Company is not, however, obligated to seek such clarification until the Company has received the approval of the MOG of the Sale, and if approval of the Sale has been obtained, the Company may delay seeking such clarification to the extent the Company believes in good faith that it would adversely affect the approval of the MOG granted for the Sale. If the MOG confirms that approval is not necessary, the Company will execute a supplemental indenture to effect the Conversion Price Reduction upon receipt of such confirmation that the approval of the MOG is not required for the Conversion Price Reduction. If the MOG confirms that its approval is required, the Company is required to promptly seek that approval, and to cause the Conversion Price Reduction to become effective by the earlier of (a) the date that is 10 business days after approval of the MOG has been obtained or the date on which it is determined that such approval is not required, or (b) December 30, 2011.

If the Company does not complete the Sale, the Company anticipates that it will lack sufficient funds to retire the restructured Senior Notes when they become due.

NOTE 9 - INCOME TAXES

The Company’s consolidated pre-tax income is comprised primarily from operations in the Republic of Kazakhstan. Pre-tax losses from continuing operations, comprised of Almaty and Salt Lake City operations were $16,500,728 and $13,990,324, for the years ended March 31, 2011 and 2010, respectively.

F-29

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

Undistributed earnings of the Company’s foreign subsidiaries since acquisition amounted to approximately $141,311,738 at March 31, 2011. Those earnings are considered to be indefinitely reinvested and, accordingly, no U.S. federal and state income taxes have been provided thereon. Upon distribution of those earnings, in the form of dividends or otherwise, the Company would be subject to both U.S. income taxes (subject to an adjustment for foreign tax credits) and withholding taxes payable to the Republic of Kazakhstan. Determination of the amount of unrecognized deferred U.S. income tax liability is not practical because of the complexities associated with its hypothetical calculation; however, unrecognized foreign tax credits may be available to reduce a portion of the U.S. tax liability.

The Company does not expect to have either current or accumulated earnings and profits in order to cause the distributions expected to be made after the Sale to be treated as dividends for U.S. federal tax purposes.

During the year ended March 31, 2010 the Company changed the method of tax accounting for the U.S. tax jurisdiction from a cash to accrual basis. The change in method was made because the Company exceeded the gross receipt threshold to be eligible for the cash method.

This change in tax method mainly resulted in the Company recognizing interest income from intercompany loans between the U.S. parent and its wholly owned foreign subsidiary, which amounts were previously deferred for income tax purposes under the cash method of accounting. The Company has calculated a Code Section 481 adjustment, to account for this change in method, in the amount of $25,116,879. The Code Section 481 adjustment primarily provides for all accrued intercompany interest amounts, previously deferred, to be recognized as taxable income, by the U.S. parent, during fiscal years 2010 through 2014. The yearly amount to be recognized is $6,279,219, which represents 25% of the total Code Section 481 adjustment.

Net operating losses of the Company in its U.S. tax jurisdiction for the year ended March 31, 2011 totalled $10,789,137. This loss has been offset with the recognized portion of the Code Section 481 adjustment of $6,279,219 which resulted in an adjusted net operating loss of $4,509,918.

F-30

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Losses before income taxes derived from United States operations are for the year ended March 31, 2011 and 2010 amounted $16,500,728 and $13,990,324, respectively.

The income tax benefit in the Consolidated Statements of Operations is comprised of:

	Year ended March 31, 2011	Year ended March 31, 2010

Current tax expense	$ -	$ -
Deferred tax benefit	(1,366,631)	(3,260,619)

	$ (1,366,631)	$ (3,260,619)

The difference between the income tax benefits reported and amounts computed by applying the U.S. Federal rate to pretax income consisted of the following:

	Year ended March 31, 2011	Year ended March 31, 2010

Tax at federal statutory rate (34%)	$ (1,850,382)	$ (2,473,697)
Effect of lower foreign tax rates	57,382	(786,922)
Non-deductible expenses	426,369	-

	$ (1,366,631)	$ (3,260,619)

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

Non-deductible expenses are comprised of the non-deductible portion of interest expense on intercompany loans accrued by subsidiary.

As of March 31, 2011, the Company had net operating loss carry forwards for income tax purposes of $17,888,838, which if unused, will begin to expire in years 2024 through 2031.

No valuation allowance was recorded against the deferred tax assets resulting from Net Operating Loss because the Company believes it will have sufficient future taxable domestic income to be offset with, primarily from accrued interest income related to loans to subsidiary.

F-31

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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:

	March 31, 2011	March 31, 2010

Deferred tax assets:
Tax losses carried forward	$ 6,082,205	$ 4,606,215
	6,082,205	4,606,215
Deferred tax liabilities:
Accrued interest income	10,059,590	9,950,231
	10,059,590	9,950,231

Net deferred tax liability	$ 3,977,385	$ 5,344,016

The Company has deferred income taxes only in US jurisdiction.

Accounting for Uncertainty in Income Taxes - In accordance with generally accepted accounting principles, the Company has analyzed its filing positions in all jurisdictions where it is required to file income tax returns. The Company’s U.S. federal income tax returns for the fiscal years ended March 31, 2006 through 2010 remain subject to examination. The Company currently believes that all significant filing positions are highly certain and that all of its significant income tax filing positions and deductions would be sustained upon an audit. Therefore, the Company has no reserves for uncertain tax positions. No interest or penalties have been levied against the Company and none are anticipated, therefore no interest or penalties have been included in the provision for income taxes.

NOTE 10 - SHAREHOLDERS’ EQUITY

Share-Based Compensation

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

Common Stock Grants

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

F-32

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

The shares representing the restricted stock grants (the “Restricted Shares”) shall be issued as soon as practicable, will be deemed outstanding from the date of grant, and will be held in escrow by the Company subject to the occurrence of a Vesting Event. The time between the date of grant and the occurrence of a Vesting Event is referred to as the “Restricted Period.” The grantees may not sell, transfer, assign, pledge or otherwise encumber or dispose of the Restricted Shares during the Restricted Period. During the Restricted Period, the grantees will have the right to vote the Restricted Shares, receive dividends paid or made with respect to the Restricted Shares, provided however, that dividends paid on unvested Restricted Shares will be held in the custody of the Company and shall be subject to the same restrictions that apply to the Restricted Shares. The Restricted Shares will only vest to the grantee if the grantee is employed by the Company at the time a Vesting Event occurs. If a Vesting Event has not occurred at the time a grantee’s employment with the Company ceases, for any reason, the entire grant amount shall be forfeited back to the Company. These grants vested during the fiscal year ended March 31, 2011.

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

Non-cash compensation expense in the amount of $1,254,025, which is net of the expense reversal discussed above, was recognized in the Consolidated Statement of Operations and Consolidated Balance Sheet for the year ended March 31, 2011.

F-33

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Consulting Agreement

On October 15, 2008 the MEMR increased Emir Oil’s contract territory from 460 square kilometers to 850 square kilometers. In connection with this extension, and any other territory extensions or acquisitions, the Consultant will be paid a share payment in restricted common stock for resources and reserves associated with any acquisition. The value of any acquisition property will be determined by reference to a 3D seismic study and a resource/reserve report by a qualified independent petroleum engineer acceptable to the Company. The acquisition value (“Acquisition Value”) will be equal to the total barrels of resources and reserves, as defined and determined by the engineering report multiplied by the following values:

Resources at $.50 per barrel;

Probable reserves at $1.00 per barrel; and

Proved reserve at $2.00 per barrel.

The number of shares to be issued to the Consultant shall be the Acquisition Value divided by the higher of $6.50 or the average closing price of the Company’s trading shares for the five trading days prior to the issuance of the reserve/resource report, provided that in no event shall the total number of shares issuable to the Consultant exceed more than a total of 4,000,000 shares. With the completion of the 3D seismic study the resources associated with the territory extension have now been determined and the Company anticipates compensation due to the consultant will be approximately 4,000,000 shares. To date, the Consultant has not requested payment. The Company anticipates a request for payment will be forthcoming and anticipates issuing the shares during the upcoming fiscal quarter.

On July 20, 2010 the Company incurred an obligation to issue 3,947,539 common shares to the Consultant as the success fee for assisting the Company to obtain an extension of the territory for exploration. The calculation for amount of shares to be issued was based on resource report, which confirms 51,318,000 barrels of oil on extended territory multiplied by $0.50 rate as per contract divided by $6.50. The shares have been valued at $0.56 per share, which was the closing market price of Company’s shares on July 20, 2010. As a result of this transaction $2,214,569 was capitalized to oil and gas properties.

On November 18, 2010 3,947,539 common shares have been issued to the Consultant for assisting the Company to obtain extension of the territory for exploration.

F-34

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Stock Options

Stock options outstanding and exercisable as of March 31, 2011 were as follows:

	Number of Shares	Weighted Average Exercise Price

As of March 31, 2009	1,170,583	$ 5.33

Granted	-	-
Exercised	-	-
Expired	(249,800)	$ 6.40

As of March 31, 2010	920,783	$ 5.04

Granted	-	-
Exercised	-	-
Expired	(920,783)	$ 5.04

As of March 31, 2011	-	-

NOTE 11 - EARNINGS PER SHARE INFORMATION

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

	Year ended March 31, 2011	Year ended March 31, 2010

Net loss from continuing operations	$ (15,134,097)	$ (10,729,705)
Net income from discontinued operations	20,015,870	19,723,178

Basic weighted-average common shares outstanding	53,284,666	50,018,895

Effect of dilutive securities
Warrants	-	-
Stock options	-	-
Non-vesting share grants	-	-

Dilutive weighted average common shares outstanding	53,284,666	50,018,895

Basic loss per common share from continuing operations	$ (0.28)	$ (0.21)
Diluted loss per common share from continuing operations	$ (0.28)	$ (0.21)

Basic income per common share from discontinued operations	$ 0.38	$ 0.39
Diluted income per common share from discontinued operations	$ 0.38	$ 0.39

Total basic income per common share	$ 0.09	$ 0.18
Total diluted income per common share	$ 0.09	$ 0.18

F-35

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The diluted weighted average common shares outstanding for the years ended March 31, 2011 and 2010 does not include the effect of potential conversion of certain warrants and stock options as their effects are anti-dilutive.

The dilutive weighted average common shares outstanding for the years ended March 31, 2011 and 2010, respectively, does not include the effect of the potential conversion of the Notes because the average market share price the years ended March 31, 2011 and 2010 was lower than potential conversion price of the convertible notes for this period.

The diluted weighted average common shares outstanding for the year ended March 31, 2009 does not include the effect of the potential conversion of the Notes because conversion of the Notes is not contingent upon any market event. Rather, the Notes are convertible to common stock upon the first to occur of (a) the tenth New York business day following the Shelf Registration Statement Effective Date and (b) 13 July 2008.

NOTE 12 - COMMITMENTS AND CONTINGENCIES

Executive Contracts

On December 31, 2009, the Company entered into employment agreements with executive officers of the Company. The employment agreements contain confidentiality, non-competition and non-interference provisions and provide for the Company’s executive officers to receive payments upon termination or change in control.

Upon consummation of the Sale of Emir Oil, an extraordinary event, the Company expects to pay out severance payments to its executives totaling $4,111,958.

F-36

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Consulting Agreement with Boris Cherdabayev

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

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

Pursuant to the Consulting Agreement, Mr. Cherdabayev will be paid $192,000 per year. The success of projects involving Mr. Cherdabayev shall be reviewed on an annual basis to determine whether the initial base consulting should be increased.

Litigation

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

F-37

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

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

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

After the Court reaffirmed its decisions, plaintiffs agreed that with respect to the unfair competition claim plaintiffs had no evidence of damages other than the evidence the District Court had excluded pursuant to its ruling on a motion in limine. Therefore, plaintiffs orally stipulated to the entry of summary judgment against plaintiffs on that count as well. A stipulation as to the remaining claim of unfair competition was read into the record and accepted by the Court on October 5, 2010. On February 8, 2011 the Trial Court signed a final Order granting judgment against plaintiffs and in favor of the BMB defendants on all counts based on the Court's prior Orders and the stipulations of the parties entered on the record on October 5, 2010. The judgment was filed on February 9, 2011.

Plaintiffs filed a Notice of Appeal on February 22, 2011, and the appeal was docketed with the United States Court of Appeals for the Second Circuit. Plaintiffs filed their appellate brief on April 6, 2011. Defendants filed their brief in opposition on May 16, 2011, and plaintiffs filed a reply brief on May 31, 2011. Oral argument on plaintiffs' appeal was held before the United States Court of Appeals for the Second Circuit on June 13, 2011. The case is scheduled for expedited disposition. However, there is no set time within which the Second Circuit will render a decision on the appeal.

F-38

BMB MUNAI, INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Plaintiffs’ appeal questions the correctness of the decisions of the District Court in granting the BMB defendants summary judgment on all claims, other than the claim to which they stipulated, and also contends that the District Court abused its discretion in refusing to allow plaintiffs leave to amend their complaint after the close of fact discovery.

The Company is not currently in a position to assess the possibility of an unfavorable outcome of the appeal. If plaintiffs' appeal is successful, the case will be remanded to the Trial Court for a trial on any issue the Appellate Court determines that the Trial Court improperly dismissed as a matter of law. The Company intends to continue to defend the case vigorously if there is a reversal on appeal.

Economic Environment

In recent years, Kazakhstan has undergone substantial political and economic change. As an emerging market, Kazakhstan does not possess a well-developed business infrastructure, which generally exists in a more mature free market economy. As a result, operations carried out in Kazakhstan can involve significant risks, which are not typically associated with those in developed markets. Instability in the market reform process could subject the Company to unpredictable changes in the basic business infrastructure in which it currently operates. Uncertainties regarding the political, legal, tax or regulatory environment, including the potential for adverse changes in any of these factors could affect the Company’s ability to operate commercially. Management is unable to estimate what changes may occur or the resulting effect of such changes on the Company’s financial condition or future results of operations.

Legislation and regulations regarding taxation, foreign currency translation, and licensing of foreign currency loans in the Republic of Kazakhstan continue to evolve as the central government manages the transformation from a command to a market-oriented economy. The various legislation and regulations are not always clearly written and their interpretation is subject to the opinions of the local tax inspectors. Instances of inconsistent opinions between local, regional and national tax authorities are not unusual.

NOTE 13 - FINANCIAL INSTRUMENTS

As of March 31, 2011 and March 31, 2010 cash and cash equivalents included deposits in Kazakhstan banks in the amount $224,163 and $273,699, respectively, and deposits in U.S. banks in the amount of $201,882 and $2,718,693, respectively. Kazakhstan banks are not covered by FDIC insurance, nor does the Republic of Kazakhstan have an insurance program similar to FDIC. Therefore, the full amount of our deposits in Kazakhstan banks was uninsured as of March 31, 2011 and 2010. The Company’s deposits in U.S. banks are also in non-FDIC insured accounts which means they too are not insured to the $250,000 FDIC insurance limit. To mitigate this risk, the Company has placed all of its U.S. deposits in a money market account that invests in U.S. Government backed securities.

F-39

BMB MUNAI, INC.

SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited)

This footnote provides unaudited information required by FASC № 932-325-55, “Disclosures about Oil and Natural Gas Producing Activities.” The Company’s oil and natural gas properties are located in the Republic of Kazakhstan, which constitutes one cost center.

As noted in detail in the Current Report of the Company on Form 8-K filed with the Securities and Exchange Commission (“SEC”) on February 18, 2011, the Company has entered into a Participation Interest Purchase Agreement (the “Purchase Agreement”) with MIE Holdings Corporation and its subsidiary Palaeontol B.V., pursuant to which the Company agreed to sell all of its interest in its wholly-owned operating subsidiary, Emir Oil. As a result of this transaction all of the oil and gas properties will be sold with the sale of Emir Oil.

Capitalized Costs - Capitalized costs and accumulated depletion, depreciation and amortization relating to oil and natural gas producing activities, all of which are conducted in the Republic of Kazakhstan, are summarized below:

	March 31, 2011	March 31, 2010

Developed oil and natural gas properties	$281,183,314	$246,979,803
Unevaluated oil and natural gas properties	26,402,637	25,924,087
Accumulated depletion, depreciation and amortization	(44,634,163)	(34,302,048)
Net capitalized cost	$ 262,951,788	$ 238,601,842

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

	For the year ended March 31, 2011	For the year ended March 31, 2010

Acquisition costs:
Unproved properties	$ -	$ -
Proved properties	-	-
Exploration costs	7,079,146	-
Development costs	27,602,915	10,949,019
Subtotal	34,682,061	10,949,019
Asset retirement costs	-	-
Total costs incurred	$ 34,682,061	$ 10,949,019

F-40

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

	For the year ended March 31, 2011	For the year ended March 31, 2010

Oil and natural gas revenues	$ 64,417,933	$ 57,274,526

Operating expenses:
Rent export tax	13,338,869	10,032,857
Export duty	1,951,794	-
Oil and natural gas operating expenses and ad valorem taxes	9,534,217	8,568,453
Accretion expense	495,497	448,351
Depletion expense	10,332,115	11,075,590
Results of operations from oil and gas producing activities	$ 28,765,441	$ 27,149,275

Reserves – Proved reserves are estimated quantities of oil and natural gas, which geological and engineering data demonstrate with reasonable certainty to be, recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. Proved oil and natural gas reserve quantities and the related discounted future net cash flows before income taxes (see Standardized Measure) for the periods presented are based on estimates prepared by Chapman Petroleum Engineering Ltd., independent petroleum engineers. Such estimates have been prepared in accordance with guidelines established by the SEC.

The Company’s net ownership in estimated quantities of proved oil reserves, and changes in net proved reserves, all of which are located in the Republic of Kazakhstan, is summarized below:

	Oil, Condensate and Natural Gas Liquids (Bbls)
	For the year ended March 31, 2011	For the year ended March 31, 2010
Proved developed and undeveloped reserves
Beginning of the year	$ 22,726,000	$ 23,641,000
Revisions of previous estimates	6,450,122	101,221
Purchase of oil and gas properties	-	-
Extensions and discoveries	-	-
Sales of properties	-	-
Production	(1,099,030)	(1,016,221)

End of year	28,077,092	22,726,000
Proved developed reserves at year end	$ 24,824,911	$ 20,155,000

(1)

During the year ended March 31, 2009 the Company drilled four wells (gross and net) on the Kariman structure, one well (gross and net) on the Dolinnoe structure, one well (gross and net) on the Aksaz structure and one well (gross and net) on the Emir structure. These additions to the Kariman, Dolinnoe, Aksaz and Emir structures during the year ended March 31, 2009 resulted in an increase in our estimated proved developed reserves of approximately 7.3 million BOE. These were the only extensions and discoveries made during the year ended March 31, 2009.

F-41

Standardized Measure – The Standardized Measure of Discounted Future Net Cash Flows relating to the Company’s ownership interests in proved oil reserves for the year ended March 31, 2011 and 2010 is shown below:

	For the year ended March 31, 2011	For the year ended March 31, 2010

Future cash inflows	$ 1,146,697,000	$ 931,885,000
Future oil and natural gas operating expenses	155,372,000	157,667,000
Future development costs	39,450,000	30,890,000
Future income tax expense	280,323,000	279,763,000
Future net cash flows	671,552,000	463,565,000
10% discount factor	279,115,000	195,243,000
Standardized measure of discounted future net cash flows	$ 392,437,000	$ 268,322,000

The Company’s standardized measure of discounted future net cash flows relating to proved oil reserves was prepared in accordance with the provisions of FASC № 932-325-55. Future cash inflows are computed by applying year end prices of oil and natural gas to year end quantities of proved oil and natural gas reserves. During the fiscal years ended March 31, 2011 and 2010 revenue from export sales accounted for 97% and 98%, respectively, of total revenue. To take into account the price differential for oil and natural gas exported versus sold domestically, the Company applies year end prices for export sales to 90% of the quantity of proved oil and natural gas reserves and the year end prices for domestic sales to 10% of the quantity of proved oil and natural gas reserves. Future oil and natural gas production and development costs are computed by estimating the expenditures to be incurred in producing and developing the proved oil and natural gas reserves at year end, based on year end costs and assuming continuation of existing economic condition.

Future income tax expenses are calculated by applying appropriate yearend tax rates to future pre-tax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. The Standardized Measure of Discounted Future Net Cash Flows is not intended to represent the replacement cost or fair market value of the Company’s oil and natural gas properties.

F-42

BMB MUNAI, INC.

SUPPLEMENTARY FINANCIAL INFORMATION ON OIL AND NATURAL GAS EXPLORATION DEVELOPMENT AND PRODUCTION ACTIVITIES (unaudited)

Changes in Standardized Measure – Changes in Standardized Measure of Discounted Future Net Cash Flows relating to proved oil reserves are summarized below:

	For the year ended March 31, 2011	For the year ended March 31, 2010

Changes due to current year operations:
Sales of oil and natural gas, net of oil and natural gas operating expenses	$ (54,883,716)	$ (38,673,216)
Sales of oil and natural gas properties	-	-
Purchase of oil and gas properties	-	-
Extensions and discoveries	-	-
Net change in sales and transfer prices, net of production costs	23,204,224	163,113,547
Changes due to revisions of standardized variables	-	-
Prices and operating expenses	-	-
Revisions to previous quantity estimates	124,180,163	1,776,460
Estimated future development costs	(4,906,406)	1,426,515
Income taxes	641,000	(123,077,000)
Accretion of discount	26,832,200	25,335,200
Production rates (timing)	(20,529,710)	10,405,096
Other	29,577,245	(25,336,602)
Net Change	124,115,000	14,970,000
Beginning of year	268,322,000	253,352,000
End of year	$ 392,437,000	$ 268,322,000

Sales of oil and natural gas, net of oil and natural gas operating expenses are based on historical pre-tax results. Sales of oil and natural gas properties, extensions and discoveries, purchases of minerals in place and the changes due to revisions in standardized variables are reported on a pre-tax discounted basis, while the accretion of discount is presented on an after tax basis.

F-43

EXHIBIT INDEX

Exhibit No.		Exhibit Description

10.20		Amendment to the Consulting Agreement and Waiver Agreement, dated February 14, 2011, between BMB Munai, Inc. and Boris Cherdabayev
21.1		Subsidiaries
23.1		Consent of Chapman Petroleum Engineering Ltd., Independent Petroleum Engineers
23.2		Consent of Hansen, Barnett & Maxwell, P.C., Independent Registered Public Accounting Firm
31.1		Certification of the Chief Executive Officer Pursuant to Rule 13a-14(a)
31.2		Certification of the Chief Financial Officer Pursuant to Rule 13a-14(a)
32.1		Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350
32.2		Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350
99.1		Chapman Petroleum Engineering Ltd. Letter on its estimation of proved oil and gas reserves at March 31, 2011