Overview

In March 2008 we terminated the Company's merger agreement with Trans Meridian International, Inc. ("TMI"), a British Virgin Islands company formed by the Company's Chairman and Chief Executive Officer, Lorrie T. Olivier. This action did not require the Company to pay any termination fee to TMI and is without any other liability to the Company. Termination of the definitive agreement with TMI resulted in a downward adjustment to the conversion price of our Junior Preferred Stock from the previous conversion price of $1.90 per share (equivalent to a conversion rate of 52.63 shares of common stock for each share of Junior Preferred Stock) to $1.50 per share (equivalent to a conversion rate of 66.67 shares of common stock for each share of Junior Preferred Stock).

We will continue to seek proposals from other parties with respect to a potential acquisition of our company. There can be no assurance, however, that these efforts will result in any agreement or transaction. Further, if we do enter into an agreement to be acquired, the value to be received by our common stockholders would likely be substantially less than the $3.00 per share contained in the terminated TMI agreement. We are also in preliminary discussions with interested parties regarding an investment of capital into our company. Again, there can be no assurance that such discussions will result in any agreement or transaction, or that any agreement or transaction would not be substantially dilutive to our stockholders. Furthermore, any potential transaction would be subject to the negotiation and execution of a definitive agreement and other related agreements, as well as to regulatory and other customary approvals and conditions, which may include stockholder approval and other factors including financing, and there can be no assurance that we would be successful in consummating any such transaction.

In the first quarter of 2008, we completed four wells that were drilled in 2007. The new wells are currently producing an aggregate of approximately 300 bopd, and are expected to produce substantially more once they have been acid stimulated, currently planned for the third quarter of 2008. Historically, acid stimulation has been required to optimize a newly completed well's production. However, while wells in the Field that have been acid stimulated have shown improved flow rates, results have been inconsistent and we are not able to accurately predict the future performance of these new wells. Currently, we have 14 producing wells and six wells temporarily shut-in for work over.

Results of Operations

The following table presents selected operational and financial data for the
three months ended March 31, 2008 and 2007, respectively.



                                                    Three Months Ended
                                                        March 31,
                                                     2008        2007
             Revenue, net (in thousands)          $   15,252   $   7,138
             Number of barrels sold                  221,355     266,437
             Average price per barrel             $    72.25   $   28.19
             Production (barrels)                    188,588     316,164
             Average daily production (barrels)        2,072       3,513

Revenue and oil production

Net revenues for the three months ended March 31, 2008 increased approximately $8.0 million, or 113%, over the comparable period of 2007 although the total volumes sold decreased. This is due primarily to the higher average price per bbl and the mix of export and domestic sales. For the three months ended March 31, 2008, we sold 221,355 bbls at an average price of $72.25 per bbl. Export sales accounted for approximately 176,930 bbls at an average price of $83.32 per bbl and domestic sales were approximately 44,425 bbls at an average price of $28.12 per bbl. In the first quarter of 2007, we sold 130,180 bbls in the export market at an average price of $31.22 per bbl and 136,258 bbls in the domestic market at an average price of $25.30 per bbl. In April 2007, we began export pipeline sales which have allowed us to receive a higher price per bbl as compared to export sales via rail where the purchaser is responsible for transportation costs, thus resulting in a higher discount from quoted crude oil prices. Additionally, crude oil prices on the quoted global exchanges were significantly higher on average in the first quarter of 2008 as compared to the first quarter of 2007.

The average number of producing wells increased from 10.4 wells in the first quarter of 2007 to 12.3 wells in the first quarter of 2008. Average daily production, however, decreased, due primarily to the lack of acid stimulation on newly completed wells, deferred workovers on existing wells and the delay of a pressure maintenance project because of a lack of sufficient operating funds, which has not allowed wells to flow at their optimal levels.

We recognize revenue from the sale of oil when the purchaser takes physical delivery of the oil. As of March 31, 2008, we had 18,817 bbls of oil in inventory that had not yet been sold, as compared to 59,373 bbls as of December 31, 2007.

Depreciation, depletion and amortization

Depreciation, depletion and amortization ("DD&A") of proved oil and gas properties is calculated under the units of production method, following the successful efforts method of accounting. For the first quarter of 2008, depletion of our proved oil and gas properties was $6.1 million, or $32.07 per bbl, as compared to $6.1 million, or $19.17 per bbl, for the first quarter of 2007. The increase is primarily due to the increase in the amount of costs being depleted as the number of wells completed and put into production has increased over the prior year's quarter. The increase was partially offset by the approximate 40% decrease in production volumes in the first quarter of 2008 compared to the first quarter of 2007. Production volumes decreased by 127,576 bbls from the 316,164 bbls produced in the first quarter of 2007 as discussed above.

Depreciation expense for non-oil and gas property was $774,000 in the first quarter of 2008 as compared to $205,000 for the three months ended March 31, 2007. The increase is due primarily to the increase in capitalized costs for our central production facility, the connection to the regional pipeline system and other Field related assets that were completed in 2007 and began depreciating in the third quarter of 2007.

Transportation expense

For the three months ended March 31, 2008, transportation and storage costs were $1.5 million, or $6.72 per bbl, as compared to $1.1 million, or $3.58 per bbl, for the first quarter of 2007. The increase is due to the increase of export pipeline sales in the first quarter of 2008 for which we incur pipeline charges on the crude oil transported to the applicable ports of loading. Although transportation costs have increased, we realize higher sales prices per bbl for export pipeline sales as compared to export sales via rail where the customer is responsible for the transportation costs, thus resulting in a higher discount from quoted crude oil prices. When we export crude oil via rail we incur transportation costs to move the crude oil from the Field to the rail terminal and then storage costs at the rail terminal until the crude oil is loaded into railcars. Prior to the commissioning of our central production facility, we incurred costs at some of the terminals to remove salts and other impurities from the crude oil prior to shipment. All export sales in the first quarter of 2008 were via pipeline while all export sales in the first quarter of 2007 were via rail.

Operating and administrative expense - Kazakhstan

For the three month period ended March 31, 2008, operating and administrative expense in Kazakhstan was $4.6 million, as compared to $3.6 million for the same period in 2007. The increase between periods is primarily a result of a reduction of inventory between periods. Inventory decreased from 96,000 bbls in March of 2007 to approximately 18,800 bbls this quarter, resulting in an overall increase in operating expense of approximately $1.0 million. Also, in the three months ended March 2008, we had increased workover expenses of $89,000 compared to the same period in 2007.

General and administrative expense - Houston

For the three month period ended March 31, 2008, general and administrative expense in Houston was $2.6 million, as compared to $2.6 million for the three month period ended March 31, 2007. During the quarter ended March 31, 2008, we recognized approximately $225,000 in expenses related to delays in effectiveness of registration statements and legal expenses of $54,000 in connection with the proposed merger with TMI. These increases in expenses were offset by decreases in employee costs, including payroll and benefits, and stock-based compensation expense related to reduced staffing levels in the first quarter of 2008 as compared to the comparable quarter of 2007.

Interest expense

Interest expense, net of capitalized interest of $181,000, was $10.6 million for the three month period ended March 31, 2008 as compared to interest expense of $9.0 million, net of $1.8 million of capitalized interest, for the three month period ended March 31, 2007. This increase is primarily due to the decrease in the amount of interest capitalized in the first quarter of 2008 as compared to the same quarter of 2007. Capitalized interest decreased in the first quarter of 2008 primarily due to decreased drilling activity and the commissioning of our central production facility and related equipment and the connection to the regional pipeline system in the second half of 2007.

Liquidity and Capital Resources

The accompanying consolidated financial statements have been prepared on the basis of accounting principles applicable to a going concern, which contemplate the realization of assets and satisfaction of liabilities in the normal course of business. As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $56.2 million and a stockholders' deficit of approximately $31.5 million at March 31, 2008. Approximately 89% of our accounts payable at March 31, 2008 have been outstanding more than 120 days. These matters raise substantial doubt about our ability to continue as a going concern. Included in our current liabilities is approximately $17.8 million in returns obligations incurred in connection with the issuance of our Junior Preferred Stock. However, the returns are not payable until the earlier of (i) the occurrence of a change of control of the Company (as defined in the certificate of designations, as amended, governing the Junior Preferred Stock) or (ii) June 18, 2008; provided, however, that if the returns become due and payable on June 18, 2008 in the absence of a change of control transaction, we may elect to satisfy our payment obligations by delivery of shares of our common stock valued at 97% of the common stock's market value at such time. Additionally, there is approximately $5.7 million in preferred stock dividends that can be satisfied by the issuance of additional preferred shares or common shares subject to certain restrictions. We have incurred operating losses since our inception. To date, we have funded our development operations and working capital requirements through a combination of debt and equity proceeds and cash flow from operations.

For the three months ended March 31, 2008 and 2007, our ongoing capital expenditures were $4.1 million and $44.8 million, respectively. Our primary sources of funding have been our private placement of Senior Secured Notes and warrants to purchase shares of our common stock in December 2005, the additional debt and shares of our common stock issued in May 2006, private placements of common stock, preferred stock and warrants and the exercise of previously issued warrants. The total capitalized cost attributable to the Field as of March 31, 2008 was $428.8 million, which includes $22.4 million of capitalized interest.

In March 2008 we terminated the Company's merger agreement with TMI. We will continue to seek proposals from other parties with respect to a potential acquisition of our Company. There can be no assurance, however, that these efforts will result in any agreement or transaction. Further, if we do enter into an agreement to be acquired, the value to be received by our common stockholders may be substantially less than the $3.00 per share contained in the terminated agreement with TMI. We are also in preliminary discussions with interested parties regarding an investment of capital into our company. Again, there can be no assurance that such discussions will result in any agreement or transaction, or that any agreement or transaction would not be substantially dilutive to our stockholders. Furthermore, any potential transaction would be subject to the negotiation and execution of a definitive agreement and other related agreements, as well as to regulatory and other customary approvals and conditions, which may include stockholder approval and other factors including financing, and there can be no assurance that we would be successful in consummating any such transaction.

Operating cash flow is dependent upon many factors, including production levels, sales volumes, oil prices and other factors that may be beyond our control. World oil prices hovered around $100 per bbl in the first quarter of 2008 and we have received substantially better prices for the crude oil we export as compared to the first quarter of 2007 when all of our export crude oil sales were via rail. With the commissioning of our central production facility, including a demercaptan unit, and proprietary connection to the regional pipeline system, we have been able to produce and export pipeline quality crude oil on a consistent basis.

We utilized much of our excess liquidity during the period in 2007 when the Field was shut-in to fund operating costs, overhead, scheduled interest payments and necessary capital expenditures. As a result, we do not currently have the necessary resources to allow for continued drilling of exploration and development wells and to meet other working capital obligations. We are currently carrying out a limited workover program in the Field to clean out paraffin deposits in wells and install continuous gas lift equipment in selected wells. At current production levels of approximately 2,100 bopd, and at the prices we currently receive, management believes we are able to generate sufficient cash flow to cover our operating costs, overhead and scheduled interest payments on our debt. However, as discussed above, we had a working capital deficit of $56.2 million at March 31, 2008, and do not have sufficient liquidity to carry out a full development program of the Field. Furthermore, no assurance can be given that production from the new wells and the cost cutting measures that have been instituted will result in sufficient additional cash flow to cover the working capital deficit and to fund continued Field development. If we are unable to either complete a strategic transaction, or if we are unable to increase production to a sufficient level, we will have to seek additional capital to fund interest payments, operating expenses and continued Field development. If we are unable to secure adequate additional capital, we may not be able to carry out the development plan for the Field, in which case our business, financial condition, results of operations and possibly our reported proved reserves would be materially and adversely affected. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should we be unable to continue as a going concern.

Critical Accounting Policies and Recent Accounting Pronouncements

We have identified the policies below as critical to our business operations and the 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 included in our Annual Report on Form 10-K for the year ended December 31, 2007.

Oil and Gas Reserve Information

The information regarding our oil and gas reserves, the changes thereto and the estimated future net cash flows are dependent upon engineering, price and other assumptions used in preparing our annual reserve study. A qualified independent petroleum engineering firm was engaged to prepare the estimates of our oil and gas reserves in accordance with applicable engineering standards and in accordance with SEC guidelines. Changes in prices and cost levels, as well as the timing of future development costs, may cause actual results to vary significantly from the data presented. Our oil and gas reserve data represent estimates only and are not intended to be a forecast or fair market value of our assets.

The net revenue interests used in this report are calculated using a sliding-scale royalty based on gross annual production payable to the Kazakhstan government during the period of the production contract relating to this license, and an additional 3.5% net revenue interest payable to a third party. Based on the forecast annual production, the government royalty rate will be between 2.0% to 2.2%.

Successful Efforts Method of Accounting

We follow the successful efforts method of accounting for our investments in oil and gas properties, as more fully described in Note 1 of the Notes to Consolidated Financial Statements included in our Annual Report on Form 10-K for the year ended December 31, 2007. This accounting method has a pervasive effect on our reported financial position and results of operations.

Revenue Recognition

We sell our production both in the export and domestic market on a contract basis. Revenue is recognized when the purchaser takes delivery of the oil and is presented in our consolidated financial statements net of royalties. At the end of the period, oil that has been produced but not sold is recorded as inventory valued at the lower of cost or market. Cost is determined on a weighted average basis based on production costs.

Capitalized Interest Costs

We capitalize interest costs on oil and gas projects under development, including the costs of unproved leasehold and property acquisition costs, wells in progress and related facilities. During the three month periods ended March 31, 2008 and 2007, we capitalized approximately $181,000 and $1.8 million, respectively, of interest costs, which reduced our reported net interest expense to $10.6 million and $9.0 million, respectively.

Recent Accounting Pronouncements

In September 2006, FASB issued SFAS No. 157, Fair Value Measurements ("SFAS No. 157"), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles ("GAAP") and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS No. 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. In November 2007, the FASB placed a one year deferral for the implementation of SFAS No. 157 for nonfinancial assets and liabilities; however, SFAS No. 157 is effective for fiscal years beginning after November 15, 2007 for financial assets and liabilities. Consistent with its requirements, we adopted SFAS No. 157 as of January 1, 2008, except as it relates to nonfinancial assets and liabilities, which will be adopted on January 1, 2009, as allowed under SFAS No. 157. The adoption did not have a material impact on our consolidated financial statements.

In March 2008, the Financial Accounting Standards Board issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No. 133" ("SFAS No. 161"). SFAS No. 161 requires enhanced disclosure related to derivatives and hedging activities and thereby seeks to improve the transparency of financial reporting. Under SFAS No. 161, entities are required to provide enhanced disclosures relating to: (a) how and why an entity uses derivative instruments; (b) how derivative instruments and related hedge items are accounted for under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"), and its related interpretations; and (c) how derivative instruments and related hedged items affect an entity's financial position, financial performance, and cash flows. SFAS No. 161 must be applied prospectively to all derivative instruments and non-derivative instruments that are designated and qualify as hedging instruments and related hedged items accounted for under SFAS No. 133 for all financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application permitted. We do not expect the adoption of SFAS No. 161 to significantly impact our financial position, results of operations or cash flows.