Emir Oil LLP

On September 19, 2011 the Company completed the sale of all of its interests in Emir Oil LLP to a subsidiary of MIE Holdings Corporation.  In anticipation of the sale of Emir Oil all operations of Emir Oil have been reclassified as discontinued operations.

The sale of Emir Oil was valued at $170 million in cash, net of $10.4 million in purchase adjustments. In accordance with the Purchase Agreement, the Company has placed $36 million in cash in escrow to indemnify the buyer for losses arising from the Company’s breaches of representations and warranties, failure to perform covenants, litigation matters, compliance with (and validity of) Emir Oil’s exploration contract, transfer of certain payables, defects in ownership of certain facilities and pipelines, or violations of applicable environmental law. Defense of such claims may result in additional costs to maintain the Company’s interest in the restricted cash or to limit potential liability. In the event that claims are successful, the balance payable to the buyer may include cash amounts in excess of the $36 million escrowed, including potentially an additional $3 million up to a total of $39 million under certain conditions. Accordingly, at December 31, 2011, the Company has classified the $36 million held in escrow as restricted cash, as a current asset.

The following is the summary of the net assets sold at September 19, 2011 and the resulting loss on sale:

The assets and liabilities of Emir Oil have been classified on the balance sheet as discontinued operations. The asset and liabilities comprising the balances, as classified in our balance sheets consist of:

The components of discontinued operations for three and nine months ended December 31, 2011 and 2010 were as follows:

Accounting policies – Discontinued operations

Oil and gas properties

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

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

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

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

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

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

Risks and uncertainties

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

Recognition of revenue and cost

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

Export duty

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

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

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

Mineral extraction tax

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

Rent export tax

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

Prepayments for materials used in oil and gas projects

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

Inventories

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

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

Liquidation fund

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

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

Other fixed assets

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

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

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