Edgar Filing: TRANSMERIDIAN EXPLORATION INC

Form 10-K for the Fiscal Year Ended December 31, 2005

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x	Annual Report pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

For the fiscal year ended December 31, 2005

¨	Transition Report pursuant to Section 13 or 15(d) of the

Securities Exchange Act of 1934

Commission File Number: 000-50715

TRANSMERIDIAN EXPLORATION INCORPORATED

(Exact name of registrant as specified in its charter)


Delaware		76-0644935
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

397 N. Sam Houston Pkwy E., Suite 300 Houston, Texas		77060
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (281) 999-9091

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


Title of each class		Name of each exchange on which registered
Common Stock, $0.0006 par value per share		American Stock Exchange

Securities registered pursuant to 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 ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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 filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ¨		Accelerated filer þ		Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þ

The aggregate market value of the common stock of the registrant held by non-affiliates of the registrant was approximately $119.9 million on June 30, 2005 based upon the closing sale price of common stock on such date of $2.12 per share on the American Stock Exchange. As of March 10, 2006, the registrant had 88,183,142 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Proxy Statement for the 2006 Annual Meeting of Stockholders to be held in

May 2006 are incorporated by reference, with respect to Part III of this Form 10-K.

TABLE OF CONTENTS


		Page
PART I		1

Item 1.	Business	1
Item 1A.	Risk Factors	3
Item 1B.	Unresolved Staff Comments	8
Item 2.	Properties	9
Item 3.	Legal Proceedings	14
Item 4.	Submission of Matters to a Vote of Security Holders	15

PART II		17

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
Item 6.	Selected Financial Data	18
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	26
Item 8.	Financial Statements and Supplementary Data	27
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	55
Item 9A.	Controls and Procedures	55
Item 9B.	Other Information	59

PART III		59

Item 10.	Directors and Executive Officers of the Registrant.	59
Item 11.	Executive Compensation	59
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
Item 13.	Certain Relationships and Related Transactions	59
Item 14.	Principal Accounting Fees and Services	59

PART IV		59

Item 15.	Exhibits, Financial Statement Schedules	59

Exhibit Index		E-1

PART I

Item 1.

Business

Transmeridian Exploration Incorporated is an independent energy company engaged in the business of acquiring, developing and producing oil and natural gas. Our activities are primarily focused on the Caspian Sea region of the former Soviet Union, and our primary oil and gas property is the South Alibek Field in the Republic of Kazakhstan, covered by License 1557 and the related exploration contract with the government of Kazakhstan. We are currently pursuing additional projects in the Caspian Sea region and surrounding basins. We were founded in 2000 as a Delaware corporation.

We conduct our operations in Kazakhstan through our wholly owned subsidiary, JSC Caspi Neft TME, a joint stock company organized under the laws of Kazakhstan. In December 2005, we acquired all of the issued and outstanding shares of Bramex Management, Inc., which owns 50% of Caspi Neft. In December 2005, we acquired the 10% carried working interest in the Field held by Kornerstone Investment Group, Ltd. As a result of these transactions, our interest in both Caspi Neft and the South Alibek Field is 100%.

At December 31, 2005, our estimated total proved reserves were 72,936,622 barrels of oil. All of these reserves are attributable to the South Alibek Field. The present value of the estimated future net revenues from our proved reserves before income tax, discounted at 10% per annum, based on prices being received as of December 31, 2005 and with oil pricing assumptions held constant throughout the estimated producing life of the reserves, was $1,015,427,446. The estimates of our proved reserves and the present value of the estimated future net revenues have been prepared by Ryder Scott Company, independent petroleum engineers, in accordance with SEC guidelines.

We are in the early stages of developing the South Alibek Field. As of December 31, 2005, 3,331,580 barrels of oil, or 5% of the South Alibek Field’s estimated proved reserves, were classified as proved developed reserves. The balance of our estimated proved reserves are classified as proved undeveloped and will require the drilling of future wells to produce these reserves. We have an active development program in the South Alibek Field, including plans to drill wells that are not currently included within the boundaries of our proved reserves. See Item 2, “Properties—Proved Reserves” below and note 12 of the notes to our consolidated financial statements for further information about our estimated proved reserves.

Strategy

Our strategy is to increase our reserves, production and cash flows by (i) acquiring and developing oil and gas reserves, (ii) exploring for new reserves and (iii) optimizing production and value from our existing reserve base. We prefer to target medium-sized fields with proved or probable reserves, relatively low entry costs and significant upside reserve potential. Through the industry contacts, technical knowledge and experience of our management team, we believe we can successfully identify, obtain financing for and acquire additional properties in the Caspian Sea region and surrounding basins.

Customers

In 2005, approximately 45% of our sales were into the Kazakhstan market to two different purchasers, and 55% were export sales to two different purchasers. Until our pipeline transfer connections and handling facilities are complete, we are temporarily storing our oil at the field facilities and at rail loading terminals in the vicinity until it can be transferred to the buyers. Our oil sales revenues to date are derived solely from our operations in Kazakhstan. For each of fiscal years 2004 and 2003, we sold oil exclusively to customers located in Kazakhstan and neighboring countries. Beginning in August 2005, we began export sales in the international markets. See Item 2, “Properties—Transportation and Marketing” below for further discussion of our current transportation

and marketing arrangements and future plans. See also Item 1A, “Risk Factors—Our business and results of operations depend on our ability to transport our production to viable markets and on the price at which we can sell our production.”

Competition

The oil and gas industry is highly competitive, and our future business plans could be jeopardized by competition from larger and better-financed companies. We compete for reserve acquisitions, exploration leases, licenses, concessions and marketing agreements against companies with financial and other resources substantially greater than ours. Many of our competitors have more established positions and stronger governmental relationships, which may make it more difficult for us to compete effectively with them. In Kazakhstan, more than 100 fields (approximately 44%) are under foreign ownership and we estimate there are 45 non-Kazakh companies operating these fields. We believe Lukoil and Chinese National Petroleum Corporation (CNPC) are the largest foreign-owned petroleum companies operating in Kazakhstan, both of which have made recent significant reserve acquisitions. A high level of interest by non-Kazakh companies also exists in the other most prospective oil and gas areas of the Caspian Sea region. See Item 1A, “Risk Factors—Competition in our industry is intense, and many of our competitors in the Kazakhstan region have greater financial and other resources than we do.”

Government Regulation

Our operations are subject to various levels of government controls and regulations in the United States and in Kazakhstan, including environmental controls and regulations. We attempt to comply with all legal requirements in the conduct of our operations and employ business practices which 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 these controls and 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 on the oil and gas industry by increasing the cost of doing business and, consequently can adversely affect our results of operations. 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.

Offices and Employees

Our corporate headquarters are in Houston, Texas, where we lease 6,725 square feet of office space. As of March 10, 2006, we had 9 full-time employees in Houston. We also maintain two offices in Kazakhstan, the first an administrative office in Aktobe, Kazakhstan, where we lease approximately 9,020 square feet of office space and have 71 full-time employees, and the second a small administrative office in Almaty, Kazakhstan, where we have five employees. Our field operations for the South Alibek Field have approximately 72 employees.

Availability of Reports

We make available free of charge on our internet website, www.tmei.com, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and any amendments to such reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after we electronically file such reports with, or furnish such reports to, the SEC. We also make available free of charge on our internet website other electronic filings that we make with the SEC as well as the Forms 3, 4 and 5 filed by our directors, executive officers and significant stockholders with respect to their beneficial ownership of our common stock. These filings and reports are also available on the SEC’s website at www.sec.gov.

Item 1A.

Risk Factors

We have a history of losses.

We have a history of losses. We incurred net losses of $3.3 million, $5.7 million, $3.8 million and $20.5 million for the years ended December 31, 2002, 2003, 2004 and 2005, respectively. Our results of operations in the future will depend on many factors, but largely on our ability to execute our exploration and development program and successfully market our current and future production. Our failure to achieve profitability in the future could adversely affect our ability to raise additional capital and, accordingly, our ability to grow our business.

Our exploration and development activities may not result in economic quantities of oil and gas.

Our success is dependent on finding, developing and producing economic quantities of oil and gas. Our drilling operations may not be successful in finding, developing and producing economic quantities of oil and gas. In addition, we may not be able to sustain production from wells that initially produce.

The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. In addition, technological difficulties encountered in well completion or following the establishment of production may result in reduced or ceased production from a well.

Our efforts will be unprofitable if we drill dry holes or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled, or subject to higher costs as a result of a variety of factors, including:

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unexpected drilling conditions;

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high pressure or irregularities in geological formations;

•

equipment failures or accidents;

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adverse weather conditions, such as winter snowstorms; and

•

increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and qualified personnel.

Oil and gas operations can be hazardous and may expose us to environmental liabilities.

We are subject to the operating risks normally associated with the exploration, development and production of oil and gas, including well blowouts, cratering and explosions, pipe failure, fires, geological formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Moreover, our drilling operations involve risks from high pressures in geological formations and from mechanical difficulties such as stuck pipe, collapsed casing and separated cable. If any of these events actually occur, we could sustain substantial losses as a result of:

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injury or loss of life;

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severe damage to or destruction of property, natural resources or equipment;

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pollution or other environmental damage;

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environmental clean-up responsibilities;

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regulatory investigations and penalties;

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delays in our operations or curtailment of our production; and

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suspension of our operations.

Because in many cases insurance coverage for these risks is either not available or is not available at premium levels that are economically feasible and justify its purchase, we maintain very limited insurance coverage. As a result, the insurance coverage we maintain may not fully compensate us, or compensate us at all, if we incur losses as a result of these risks. Moreover, in the future we may not be able to maintain all or even part of our current insurance coverage at premium levels that justify its purchase.

In addition, as an owner and operator of oil and gas properties, we are subject to various laws and regulations relating to the discharge of materials into, and the protection of, the environment. These laws and regulations may impose liability on us for the cost of environmental cleanup resulting from our operations and could further subject us to liability for environmental damages.

The actual quantities of, and future net revenues from, our proved reserves may prove to be lower than we have estimated.

The information included herein contains estimates of our proved reserves and the estimated future net revenues from our proved reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.

We engage an independent petroleum engineering firm to review our estimates of our proved reserves. During 2005, 2004 and 2003, their review covered 100% of the reserve value. Estimates of our proved reserves are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities of, and future net revenues from, our proved reserves. In addition, we may adjust estimates of our proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties. In addition, our reserves are contained in carbonate reservoirs, and there is a larger uncertainty inherent in carbonate reservoirs as compared to sandstone reservoirs.

At December 31, 2005, approximately 95% of our estimated proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. These reserve estimates include the assumption that we will make significant capital expenditures to develop the reserves. You should be aware that our estimates of such costs may not be accurate, development may not occur as scheduled and our results may not be as estimated.

You should not assume that the present values referred to in the information included herein represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of present values are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimates. There are currently no economic markets for our natural gas production and our gas reserves have been given no value in the future net cash flow data included herein.

The timing of both production from our properties and the expenses we incur from the development and production of our properties will affect both the timing of the actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor.

If oil and gas prices decrease or our exploration efforts are unsuccessful, we may be required to write down the capitalized cost of individual oil and gas properties.

A writedown of the capitalized cost of individual oil and gas properties could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved oil and gas reserves, increases in our estimates of development costs or nonproductive exploratory drilling results.

We use the successful efforts accounting method. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves are discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. All geological and geophysical costs on exploratory prospects are expensed as incurred.

The capitalized costs of our oil and gas properties, on a field-by-field basis, may exceed the estimated undiscounted future net cash flows of that field. If so, we record impairment charges to reduce the capitalized costs of each such field to our estimate of the field’s fair market value. Unproved properties are evaluated at the lower of cost or fair market value. These types of charges will reduce our earnings and stockholders’ equity.

We assess our properties for impairment periodically, based on future estimates of proved reserves, oil and gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. Once incurred, an impairment charge cannot be reversed at a later date even if we experience increases in the price of oil or gas, or both, or increases in the amount of our estimated proved reserves.

All of our operations are conducted in areas with inherent international and governmental risks.

We are subject to risks inherent in international operations, including adverse governmental actions, political risks, expropriation of assets and the risk of civil unrest or war. Our 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 from the former Soviet Union, but has developed 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 the agreements to which we are party and, in the event of dispute, we may have limited recourse within the legal and political system.

We have not finalized a long-term production contract with the government of Kazakhstan and our current exploration contract is scheduled to expire in 2007.

We currently produce and sell oil pursuant to an exploration contract with the government of Kazakhstan which expires in April 2007. Under our exploration contract and the Law of Petroleum, we hold the exclusive right to negotiate and execute a production contract with the Ministry of Energy and Mineral Resources (“MEMR”) in the event of a commercial discovery in the license area, and the government is required to conduct these negotiations. In December 2004, the State Committee on Reserves (“SCR”) approved commercial reserves for development and exploitation in the South Alibek Field. On this basis, the MEMR granted us the exclusive right to execute a long-term production contract in June 2005. We concluded negotiations of the final commercial and legal terms of the contract in September 2005, when the working group of the MEMR formally approved the draft production contract. The final draft was then circulated to the relevant governmental ministries and committees for their formal acceptance prior to contract execution. In the course of this process, several of these governmental bodies requested additional changes to the contract, most of which we successfully negotiated and included in the written contract.

As of March 10, 2006, approval of one remaining government ministry was still pending. Once this final approval is obtained, the production contract will be signed by the prime minister, at which time it will enter into effect. We believe that this approval will be obtained and the production contract signed during the first half of 2006. However, there can be no assurance that we will be successful in finalizing the production contract by such time or at all. If we are unable to finalize the production contract in a timely manner or at all, our business, financial condition and results of operations could be materially and adversely affected.

Our business and results of operations depend on our ability to transport our production to viable markets and on the price at which we can sell our production.

Our future success depends on our ability to transport and market our production either within Kazakhstan or through export to other markets. Our ability to sell our production and, in turn, our revenues could be materially and adversely affected by issues which are outside our control relating to the crude oil transportation infrastructure both within and outside Kazakhstan. The exportation of oil from Kazakhstan depends on access to transportation routes, primarily pipeline systems, which can have limited available capacity and are subject to other restrictions.

We currently export our oil by rail. The rail terminal is accessed by truck from our field facilities. Our future plans include the shipment of oil by pipeline, which is the preferred and most cost effective method to sell crude oil production into the export market. We expect the implementation of our plans to result in higher realized prices for our crude oil than our current marketing arrangements, but we cannot be assured that we will be successful in implementing our plans. Unless we obtain access to pipelines to transfer our crude oil out of Kazakhstan, the prices at which we sell our crude oil may remain well below world market prices.

Oil prices are volatile. A decline in prices could adversely affect our financial position, results of operations, cash flows, access to capital and ability to grow.

Our revenues, results of operations and future growth depend primarily upon the prices we receive for the oil we sell. Historically, the markets for oil have been volatile and they are likely to continue to be volatile. Wide fluctuations in worldwide oil prices may result from relatively minor changes in the supply of and demand for oil, market uncertainty and other factors that are beyond our control, including:

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worldwide supplies of oil and gas;

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weather conditions;

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the level of consumer demand;

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the price and availability of alternative fuels;

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governmental regulations and taxes;

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the ability of the members of the Organization of Petroleum Exporting Countries to agree to, and maintain, oil price and production controls;

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political instability or armed conflict in oil-producing regions; and

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the overall economic environment.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil price movements with any degree of certainty. Declines in oil prices would not only reduce our revenues, but could reduce the amount of oil that we can produce economically and, as a result, could have a material adverse effect on our business, financial condition and results of operations.

Our substantial indebtedness could adversely affect our financial condition.

We have substantial debt, namely our senior secured notes due 2010, and, in turn, substantial debt service requirements. Our ability to make payments on our senior secured notes due 2010 and any future indebtedness we may incur depends on our ability to generate sufficient cash flow. We cannot assure you that:

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our business will generate sufficient cash flow from operations to service our indebtedness;

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future borrowings or proceeds from equity issuances will be available in an amount sufficient to enable us to pay our indebtedness on or before the maturity date of such indebtedness; or

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we will be able to refinance any of our indebtedness on commercially reasonable terms, if at all.

Factors beyond our control may affect our ability to service our indebtedness. These factors include those discussed in this “Risk Factors” section.

If, in the future, we cannot generate sufficient cash flow from our operations to meet our debt service obligations, we may need to refinance our debt, obtain additional financing, issue equity or sell assets, which we may not be able to do on commercially reasonable terms, if at all, and which we may be prohibited from doing under the terms of our indebtedness. We cannot assure you that our business will generate cash flow, or that we will be able to obtain funding, sufficient to satisfy our debt service obligations. Our inability to generate cash flow or obtain funding sufficient to satisfy our debt service obligations could materially and adversely affect our financial condition.

Covenants in the indenture governing our senior secured notes due 2010 impose significant restrictions on us.

The indenture governing our senior secured notes due 2010 contains a number of covenants imposing significant restrictions on us. The restrictions these covenants place on us include restrictions on our repurchase of, and payment of dividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets and create liens on our assets. These restrictions may affect our ability to operate our business and may limit our ability to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial condition and results of operations.

Significant capital expenditures are required to execute our development program.

Our development and production activities, including our exploration contract with the government of Kazakhstan, require us to make substantial capital expenditures. Historically, we have funded our capital expenditure requirements through a combination of cash flows from operations, borrowings under bank credit facilities, private placements of our common stock, preferred stock and debt securities and borrowings from our affiliates. Our cash flows from operations are subject to a number of variables, such as the level of production from our existing wells, the prices of oil, and our success in developing and producing our reserves. If our revenues were to decrease as a result of lower oil prices or decreased production, and our access to capital were limited, we may not be able to meet our capital expenditure requirements, which could, in turn, materially and adversely affect our business, financial condition and results of operations.

Competition in our industry is intense, and many of our competitors in the Kazakhstan region have greater financial and other resources than we do.

We operate in the highly competitive areas of oil exploration, development and production. We face intense competition from both major and other independent oil and natural gas companies in seeking to acquire:

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desirable producing properties or new leases for future exploration; and

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the equipment and expertise necessary to develop and operate our properties.

Many of our competitors have financial and other resources substantially greater than ours and, moreover, some of them are fully integrated oil companies with operations in the exploration, development, production, pipeline transportation, refining and marketing sectors of the oil and gas industry. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit.

In addition, our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and successfully consummate transactions, and there can be no assurance that we will be able to do so.

Compliance with governmental regulations could be costly.

Our operations are subject to various levels of government controls and regulations in the United States and in Kazakhstan, including environmental controls and regulations. It is not possible for us to separately calculate the costs of compliance with these controls and 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 on the oil and gas industry by increasing the cost of doing business and, consequentially, can adversely affect our results of operations. 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.

The loss of key personnel could have an adverse effect on our business.

Our success is dependent on the performance of our senior management and key technical personnel. The loss of our chief executive officer or other key employees could have a material and adverse effect on our business. We do not currently have employment or non-compete agreements in place with any of our senior management or key employees. In addition, we do not carry life insurance covering any of our senior management or key employees.

We have reported a material weakness in our internal control over financial reporting that, if not remedied, could adversely affect our ability to meet reporting obligations and provide timely and accurate financial statements.

In connection with our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005, we concluded that, as of December 31, 2005, we did not maintain effective internal control over our financial reporting due to a material weakness resulting from lack of a sufficient number of accounting staff with experience in public company SEC reporting and technical expertise to enable us to maintain adequate controls over our financial accounting and reporting processes regarding the accounting for non-routine and non-systematic transactions. A material weakness is a control deficiency, or a combination of control deficiencies, that results in more than a remote likelihood that a material misstatement in our annual or interim financial statements would not be prevented or detected. Our management’s assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 was audited by UHY Mann Frankfort Stein & Lipp CPAs, LLP, which expressed an unqualified opinion on management’s assessment and an adverse opinion on the effectiveness of our internal control over financial reporting as of December 31, 2005.

We have taken, and are currently taking, steps to remedy this material weakness. See Item 9A, “Controls and Procedures—Corporate Disclosure Controls—Changes in Internal Controls.” Although we believe we will address the material weakness with the remedial measures we have implemented and are currently implementing, these measures may not remedy the material weakness reported and, as a result, we may not be able to implement and maintain effective internal control over financial reporting in the future. In addition, additional deficiencies in our internal controls may be discovered in the future.

Any failure to remedy the reported material weakness or to implement new or improved controls, or difficulties encountered in their implementation, could harm our operating results, cause us to fail to meet our reporting obligations or result in material misstatements in our financial statements. Any such failure also could affect the ability of our management to certify that our internal controls are effective when it provides an assessment of our internal control over financial reporting, and could affect the results of our independent registered public accounting firm’s attestation report regarding our management’s assessment. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock.

Item 1B.

Unresolved Staff Comments

None.

Item 2.

Properties

Petroleum Industry in Kazakhstan

Kazakhstan was one of 15 independent republics that comprised the former Soviet Union. After gaining independence in 1991, it joined with Russia and several other former Soviet republics in the Confederation of Independent States, a union of economic and political cooperation. Kazakhstan is an area of significant investment activity for the international oil and gas industry. Based upon publicly available information, Kazakhstan’s proved reserves rank it among the top 15 countries in the world, with over 250 producing oil fields and 20 billion barrels of proved reserves. Its current production is approximately 1.3 million barrels of oil per day, of which approximately 85% is exported.

Regulation of the oil and gas industry in Kazakhstan has been codified in the Law of Petroleum, which sets out the conduct of the oil and gas industry and the roles of participants, both private and governmental. The industry is regulated in Kazakhstan by the Ministry of Energy and Mineral Resources (“MEMR”), which administers all contracts, licenses and investment programs.

The national oil company, Kazmunaigas, has been through several stages of consolidation. The Kazakhstan government has been in the process of merging the various regional governmental companies, which previously handled the extraction and transportation sectors of the industry, into one consolidated entity to eliminate redundant bureaucracy and provide for a more efficient management of the country’s natural resources. This consolidated entity maintains a direct ownership interest on behalf of the Kazakhstan government in most of the large oil field development projects in Kazakhstan as well as sole ownership and operation of many of the interconnecting oil and gas pipeline systems. However, governmental ownership or participation in exploration and development projects is not required, and the Kazakhstan government has no ownership interest in the South Alibek Field.

Acquisition of the South Alibek Field

In May 1999, we engaged Kornerstone Investment Group, Ltd. (“Kornerstone”) to identify and assist in the acquisition of oil and gas properties in Kazakhstan and elsewhere in the Caspian Sea region. Since we had not received any significant funding at that time, the consulting agreement with Kornerstone provided that Kornerstone’s compensation would be in the form of a 10% carried working interest (which we reacquired from Kornerstone in January 2006) in all properties shown to us and in which we acquired an interest. The controlling shareholder of Kornerstone is a citizen of Kazakhstan who is involved in oil and gas production and other business endeavors. This individual is also currently employed on a part-time basis as a consultant and manager of Caspi Neft.

In early 2000, Kornerstone identified an opportunity in Kazakhstan known as the South Alibek License 1557, which covered what is now known as the South Alibek Field. The adjacent Alibekmola Field had been discovered in 1980 by a regional exploration unit of the Soviet Ministry of Geology. A total of 31 wells had been drilled in the Alibekmola Field to delineate the oil bearing reservoirs and structure of the field. This delineation work continued following the breakup of the Soviet Union.

The South Alibek Field was first identified by an Alibekmola Field delineation well, known as Alibekmola 29, drilled by a geological association of the Kazakhstan government. It was determined to be in a separate fault block adjacent to the Alibekmola Field, and in 1996 produced flowing oil from several intervals in the Middle-Lower Carboniferous (KT2) reservoirs during well testing. Due to lack of funds for further drilling, the area was offered for public tender and was awarded in the tender to a subsidiary of AIL Alpha Corporation, Ltd. License 1557 was granted to the subsidiary in April 1999. In March 2000, we acquired this subsidiary. Subsequent work by us has resulted in this license area being designated as the South Alibek Field.

License and Exploration Contract

We signed an exploration contract with the Kazakhstan government in March 2000. The contract, whose original term extended to April 2005 with two two-year extensions, required us to make total capital expenditures of approximately $18.0 million. In April 2004, we were granted the first of these two-year extensions, through April 2007. In connection with this extension, we agreed to an additional work program commitment of $30.5 million. As of December 31, 2005, we had satisfied these capital expenditure commitments. Pursuant to the exploration contract, we can produce wells under a test program, provided we make 2% royalty payments (based on production) to the Kazakhstan government. We intend to apply for the next two-year extension to continue the exploration of the license area and expand the South Alibek Field before the existing exploration contract term expires.

Production Contract

Under our exploration contract and the Law of Petroleum, we hold the exclusive right to negotiate and execute a production contract with the MEMR in the event of a commercial discovery in the license area, and the government is required to conduct these negotiations. In December 2004, the State Committee on Reserves (“SCR”) approved commercial reserves for development and exploitation in the South Alibek Field. On this basis, the MEMR granted us the exclusive right to execute a long-term production contract in June 2005. We concluded negotiations of the final commercial and legal terms of the contract in September 2005, when the working group of the MEMR formally approved the draft production contract. The final draft was then circulated to the relevant governmental ministries and committees for their formal acceptance prior to contract execution. In the course of this process, several of these governmental bodies requested additional changes to the contract, most of which we successfully negotiated and included in the written contract.

effect. We believe that this approval will be obtained and the production contract signed during the first half of 2006. The terms of the production contract establish the royalty and other payments due to the government in connection with our production of oil and gas. A bonus payment of $0.6 million will be required upon execution, based on the SCR reserves audit approving the commercial discovery, which defined the initial production area of 3,500 acres, or about 25% of the total area under license. If additional area is added on the basis of successful exploratory drilling, additional bonus payments would be assessed at a rate of 0.1% of the recoverable reserves added. The contract will also allow the government to recover approximately $4.7 million of historical exploration costs incurred before privatization out of future revenues beginning in January 2007 at a rate of approximately $50,000 per quarter.

The production contract is tax and royalty based. Under this financial arrangement, we will pay 100% of the development and operating costs and will be entitled to receive 100% of the revenues from the Field, subject to a royalty based on production from the Field and corporate income taxes. The royalty is a sliding scale based on annual production, ranging from 2% to 2.5% for production up to approximately 60,000 barrels per day. Corporate income taxes in Kazakhstan vary from 30% to 40%. Additionally, there is an excess profit tax on oil and gas production which can vary from 15% to 60% based on the ratio of net income to deductions. These taxes can significantly affect the economics of the project. The government may also require that we make available, if requested, up to 20% of our production to local refineries at domestic market prices. We would expect these prices to be lower than prices we would receive in the export market. However, our transportation costs would likely be lower as well. Most of the smaller producers in the region are not currently being required to sell into the domestic market and we do not expect this to change.

Overview of Regional Geology

The South Alibek Field is located in a fairway of large fields in northwestern Kazakhstan within the prolific Pre-Caspian Basin. Within 20 miles of the South Alibek Field are three giant producing fields with resources estimated between 500 million to 1 billion barrels each: the Kenkiyak and Zhanazhol Fields and the immediately adjacent Alibekmola Field. Production from the area’s carbonate reservoirs was first established in the 1950s, before the area was limited to military use and closed to oil and gas activity for 20 years. The Zhanazhol Field was the first to be discovered following the release of some of the area to exploration in the 1970s, and is now producing from the Upper-Middle Carboniferous (KT1) and Middle-Lower Carboniferous (KT2) reservoirs. The Alibekmola Field was discovered in the 1980s as additional areas were released, with production tests and reserves in both the KT1 and KT2 reservoirs. South Alibek was identified by the last well drilled during the delineation of Alibekmola following the breakup of the Soviet Union and independence of Kazakhstan. Development of these fields began after 2000.

The KT1 and KT2 reservoirs were deposited throughout the Middle and Late Carboniferous periods and into the Early Permian as a basin-wide and massive carbonate platform in the shallow waters of the ancient Uralian paleo-ocean on the southeastern boundary of the East European Plate. Regional closing of the ocean during the Permian period created a restricted sea that makes up the Pre-Caspian Basin. Prolific oil field trends are established in the southern half and northern margins of this Basin, with the South Alibek Field located on the southeastern margin of the Basin on the Zharamys Uplift. The carbonate fields lying within the Pre-Caspian Basin, including the Devonian carbonates which were deposited earlier, account for approximately 75% of Kazakhstan’s oil reserves and production. These fields are projected to ultimately contain over 40.0 billion barrels of recoverable reserves, and include two super-giant fields: Tengiz, which is estimated to have 9.0 billion barrels of recoverable reserves; and Kashagan, which is estimated to have 13.0 billion barrels of recoverable reserves.

The tectonic history specific to the Zhanazhol, Alibekmola and South Alibek Fields area was extensively studied by Soviet scientists during the last four decades of the Soviet era. The carbonates were deposited on a stable block removed from the influence of the Ural Mountain building processes to the northeast. Soviet geologists speculated the block was significantly closer to Tengiz at that time than it is today. The movement of

the block to the northeast, of up to 450 miles, and the later folding and thrust faulting, began in the Middle Permian through the Late Triassic period. This faulting created the northeast-southwest trending enechalon structures that characterize these fields and provides the trap for oil and gas. The main defining thrust faults are generally oriented in a north-south direction, with a pattern of small stress transfer crossfaulting and fracturing that can enhance the fracture characteristics of the carbonate reservoirs. At present day, the platform trends southwest to northeast over an area approximately 125 miles long and 50 miles wide. It is bounded to the north by a major fault which separates this area from the Urals western fold and thrust belt.

Zhanazhol, Alibekmola and South Alibek Fields are ideally situated for favorable migration of hydrocarbons. The source for the oil and gas was provided by three source rocks, Devonian through Carboniferous in age, with the filling of the structures beginning at the end of the Permian with peaks of generation at the end of the Triassic and end of the Jurassic and with one source rock believed to be generating today.

Field Geology

The South Alibek Field is immediately adjacent to the producing Alibekmola Field. Structurally it has three-way dip closure and is bounded and separated from Alibekmola on the east by a major north-south thrust fault. The Field is up to 1,000 feet lower than the Alibekmola Field and has a lower oil-water contact established from testing of the Alibekmola 29 well. The Zhanazhol Field lies 10 miles along the regional structural trend to the south. The East Zhagabulak Field is on the northwest corner of the South Alibek license area.

The KT1 and KT2 are the primary oil bearing reservoirs in all four fields, all of which have established production in the KT2. The KT1 is produced in the Zhanazhol Field. It has been found productive by testing in the Alibekmola and East Zhagabulak Fields, but has not been developed in those fields or in South Alibek. Evaluation of field data indicates reservoir properties of the KT1 and KT2 are very similar in the Alibekmola and South Alibek Fields. Production from the Zhanazhol Field is estimated to be in excess of 100,000 barrels of oil per day, and from the Alibekmola Field, which is still in the early phases of development, over 30,000 barrels of oil per day.

Within the South Alibek Field, the KT1 and KT2 reservoirs are porous and fractured carbonates of shallow marine-terriginous origin. The porosity is both primary and secondary, by diagenesis to dolomite and by fracturing. Porosity averages between 9-10% for both the KT1 and KT2, and is estimated as high as 15% in the KT2 and 20% in the KT1 from core analysis of open porosity. Permeability estimates range between 5mD to 300mD. The identified net thickness of the oil bearing reservoir averages approximately 200 feet for both the KT1 and KT2. The KT2 reservoir is a series of massive stacked platform carbonates, subdivided into five stratigraphically defined zones, totalling more than 3,000 feet thick, with the top at approximately 10,500 feet in depth. The shallower KT1 is subdivided into three zones: the lowest zone is a series of massive stacked platform carbonates and the shallower zones are more characteristic of the back-stepping progradational nature of the carbonate platform The top of the KT1 reservoir is at a depth of approximately 7,000 feet, and is about 2,300 feet thick.

We have conducted an extensive evaluation of the information available for the South Alibek Field and adjacent fields, including vintage and recent logging, core, pressure and testing data, and 2D and 3D seismic data to which we have rights. Based on our evaluation, we believe that the oil-bearing reservoirs within the KT1 and KT2 may be present over a substantial part of the area covered by License 1557. We continue to update the technical appraisal of our field and collect and evaluate reservoir and fluid data from our wells. Based on available regional data, the possibility exists that the prospective Devonian carbonates may underlie the KT2 at significantly greater depths, but this possibility remains undefined due to insufficient data at the present time.

Proved Reserves

Our estimated proved oil and gas reserve quantities were prepared by Ryder Scott Company, independent petroleum engineers. There are numerous uncertainties in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. These uncertainties are greater for properties which are undeveloped or have a limited production history, such as the South Alibek Field. Our actual reserves, future rates of production and timing of development expenditures may vary substantially from these estimates. All of our proved reserves are in the South Alibek Field. Our net quantities of proved developed and undeveloped reserves of crude oil and standardized measure of future net cash flows are reflected in the table below. See further information about the basis of presentation of these amounts in note 12 of the notes to our consolidated financial statements.

As of December 31, 2005, we own a 100% working interest in the South Alibek Field, subject to Kazakhstan government royalties and a 3.5% net revenue interest in favor of a third party. The effect of these interest deductions is reflected in the calculation of our net proved reserves. Our proved reserves have been prepared under the assumption that we obtain a commercial production contract which will allow production for the expected 25-year term of the contract, as more fully discussed above under “Production Contract.” Based on forecast production volumes, the average royalty over the term of the production contract is expected to be 2.2% or less.

Net Proved Crude Oil Reserves and Future Net Cash Flows

As of December 31, 2005

(Quantities in Barrels)


	Actual
Proved Developed		3,331,580
Proved Undeveloped		69,605,042

Total Proved Reserves		72,936,622

Future Net Income Before Income Taxes, Discounted @10%	$	1,015,427,446

Standardized Measure of Discounted Future Net Cash Flows	$	746,980,814

The following table shows the number of developed and undeveloped acres in the South Alibek Field as of the dates indicated:


	As of December 31,
	2005	2004	2003
Developed acres	640	232	160
Undeveloped acres	1360	1,448	765

Total acreage	2000	1,680	925

For information regarding our production from the South Alibek Field, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” below.

Transportation and Marketing

Oil producers in the area of the South Alibek Field utilize both the KazTrans Oil and Russian Transneft pipeline systems to export crude oil to regional hub locations such as Samara, Ukraine, the Port of Odessa on the Black Sea and European locations such as Poland, Hungry, Lithuania, Germany and Finland. Pipeline capacity in the area has significantly increased with the opening of the Caspian Pipeline Consortium (“CPC”) pipeline, which ultimately will boost regional export capacity from 250,000 barrels of oil per day to an expected 800,000

barrels of oil per day. Two Soviet-era oil pipelines in the local area of the Field, with combined capacity of 143,000 barrels of oil per day, continue to service nearby producing fields. These pipelines transport oil to the Bestamak rail terminal and the oil refinery in Orsk via Kenkiyak Field, and can be used as a transfer point for oil exchanges to Western markets. Several rail loading oil terminals are also in the area and can be used for export sales. The nearest is approximately 30 miles from the South Alibek Field at Zhem.

Two important connecting pipelines in the vicinity of the South Alibek Field became operational in 2003. The Kenkiyak-Atyrau pipeline, with an initial capacity of 120,000 barrels of oil per day, originates at the Kenkiyak Field and provides a link to the CPC pipeline for nearby producing fields, including the Zhanazhol Field. The Alibekmola-Kenkiyak pipeline provides direct pipeline access from the Alibekmola Field to the Kenkiyak-Atyrau pipeline for export to western markets via the CPC pipeline. The pump station at the Alibekmola Field is one mile from the site of our central production facilities.

We currently export the majority of our oil production to international markets by rail from the Zhem terminal. The terminal is accessed by truck from our field facilities. A portion of the oil continues to be sold in the local markets to alleviate storage constraints of the existing field facilities. Our future plans include the shipment of all our production by pipeline, which is the preferred and most cost effective method to sell oil into the export markets. Based upon our discussions with the operator of the Alibekmola-Kenkiyak pipeline, we believe we will be able to begin exporting our oil via this pipeline during 2006, subject to possible capacity limitations. To obtain access, we will be required to make certain processing and delivery investments or arrangements with nearby producers. In addition, CNPC is finalizing the extension of the rail line from Zhem to Zhanazhol Field, placing rail access within approximately four miles of the South Alibek Field. Construction of a rail spur from our field to the Zhanazhol Field is under consideration, which would eliminate the need to truck the oil to Zhem. See “Item 1. Business—Customers.”

Drilling Rig

In December 2001, we purchased a drilling rig for our operations in the South Alibek Field for total consideration of $5.3 million, including a note payable for $3.3 million and the issuance of $2.0 million in redeemable common stock. The rig is a National 1320UE, with a 2,000 horsepower rating, a depth rating of approximately 20,000 feet and a 320-ton rating on the drawworks. At the time of purchase, the rig was in storage in South America. During 2002, we moved the rig to Kazakhstan and refurbished and modified the rig to make it suitable for use in our operations. We contracted the operation and manning of the rig to a third party. The rig has been idle since December 2004. In the first quarter of 2006, we reached an agreement to dispose of the rig. See note 3 of the Notes to Our Consolidated Financial Statements. As more fully discussed in Item 3, “Legal Proceedings” below, we settled litigation relating to the drilling rig in December 2005.

Item 3.

Legal Proceedings

Drilling Rig Dispute

In December 2001, we purchased a land drilling rig for total consideration of $5.3 million, including a note payable for $3.3 million and the issuance of $2.0 million in redeemable common stock. We were not informed that the rig was subject to a lien in favor a prior owner of the rig. Beginning in December 2003, the seller, us and the lienholder engaged in litigation to determine the parties’ rights and obligations with respect to the rig, the lien and payments due the seller and the lienholder. In August 2004, we and the seller of the rig entered into a settlement and release agreement, pursuant to which the remaining balance on the note of $1.6 million, plus accrued interest of $550,000 was cancelled, and we agreed to endeavor to negotiate a settlement with the lienholder pursuant to which we would assume the obligation of the seller of the rig to the lienholder. In December 2005, the parties engaged in a court-supervised mediation at which they agreed to settle all outstanding claims against one another. Pursuant to the settlement agreement, we paid approximately $1.8 million to the first lienholder to settle the remaining payment obligations to the lienholder, plus $120,000 for legal fees. See notes 5 and 8 of the notes to our consolidated financial statements.

Former Chief Financial Officer

In May 2003, Jim W. Tucker, our former chief financial officer, filed suit in state district court in Texas against us in connection with his separation from service in January 2003. The suit alleged breach of an oral employment agreement. We took a default judgment in November 2003 in the amount of $0.9 million. In February 2005, the court granted our motion to vacate the default judgment. The plaintiff subsequently passed away in July 2005. The case may still be reinstated by the deceased’s estate prior to April 2007, and would begin as if we had just been served notice. We believe we have meritorious defenses to the allegations against us and intend to vigorously contest this matter and pursue all available legal remedies; however, we believe the chances that the estate will refile the suit to be remote.

Item 4.

Submission of Matters to a Vote of Security Holders

No matters were submitted to a vote of security holders during the quarter ended December 31, 2005.

Executive Officers of the Registrant

Certain information as of March 10, 2006 about our executive officers, including their position or office with the company, is set forth in the following table and accompanying text:


Name and Age	Age	Position(s)
Lorrie T. Olivier	55	Chairman of the Board, President and Chief Executive Officer

Earl W. McNiel	47	Vice President and Chief Financial Officer

Nicolas J. Evanoff	43	Vice President, General Counsel and Secretary

Bruce A. Falkenstein	47	Vice President—Exploration and Geology

Joseph S. Thornton	55	Vice President—Operations

Edward G. Brantley	51	Vice President and Chief Accounting Officer

Lorrie T. Olivier has served as President and Chief Executive Officer of the company since its inception in 2000. Mr. Olivier became Chairman of the Board in 2002. From 1991 to 2000, Mr. Olivier was employed by American International Petroleum Corporation (AIPC) as Vice President of Operations and President of AIPC Kazakhstan. He was the key executive in charge of developing AIPC’s interests in the Caspian Sea region. Mr. Olivier has devoted his entire career to international oil and gas exploration and production, also having served with Occidental Petroleum in South America and Shell Oil.

Earl W. McNiel joined the company in July 2004 as our Vice President and Chief Financial Officer. Mr. McNiel has 24 years of experience with public companies, primarily in the energy industry, and has broad experience with corporate finance, M&A and financial reporting. From 1994 until 2004, Mr. McNiel was a senior officer with Pride International, Inc., an oilfield services provider and drilling contractor, serving as Chief Financial Officer, Chief Accounting Officer and Vice President of Planning and Corporate Development. Before joining Pride, Mr. McNiel served as Chief Financial Officer of several publicly owned waste management companies and as Manager, Finance with ENSCO International, Inc., an international offshore drilling contractor. He began his career in public accounting with a major international accounting firm.

Nicolas J. Evanoff joined the company in January 2006 as our Vice President, General Counsel and Secretary. Previously, he was engaged in the private practice of law with Phillips & Reiter PLLC, during which time he served as outside general counsel to the company since May 2005. From 2002 to 2004, Mr. Evanoff was employed by Pride International Inc., an oilfield services provider and drilling contractor, as Vice President – Corporate & Governmental Affairs. Prior to joining Pride, he served as Associate General Counsel and then as

General Counsel, Asia & Middle East, of Transocean Inc., an international offshore drilling contractor, from 1997 to 2002. Mr. Evanoff began his legal career with Baker Botts L.L.P. in Houston, Texas, where he practiced corporate and securities law from 1992 to 1997.

Bruce A. Falkenstein has served as Vice President—Exploration and Geology since the company’s inception in 2000 and has 27 years experience in international oil and gas exploration and production. Prior to joining the company, he served for 20 years with Amoco and its successor, BP Amoco (now BP), where he last held the position of Manager and Chief Geophysicist of the Kazakhstan exploration team. Including his tenure at BP Amoco, since 1992, he has worked extensively on the technical evaluation and acquisition of oil fields and operating licenses in Kazakhstan and the Caspian Sea region. From 1986 until 1992, he served in Amoco’s corporate field development and reserves estimation group for Egypt, Africa and the Middle East. Mr. Falkenstein is licensed in the State of Texas as a professional geologist and geophysicist and is a Trustee Associate of the American Association of Petroleum Geologists Foundation.

Joseph S. Thornton joined the company in January 2005 as our Vice President—Operations. Mr. Thornton has in excess of 30 years experience in oil and gas exploration, development and production operations. Most recently he served as Manager of Affiliates for Vanco Energy Company, an independent oil and gas producer, where he served as the principal liaison between the company’s local operating branches and the host governments and as compliance officer under the production sharing agreements. Prior to that, he was Project Manager in Moscow and Algeria for Schlumberger, Inc. an international oilfield services provider, where he was responsible for production optimization and complex horizontal drilling operations. He has also held senior positions with Ashland Exploration Benin and United Meridian International Corporation, including Vice President and General Manager for UMIC Côte d’Ivoire based in Abidjan. Mr. Thornton holds a petroleum engineering degree and is a registered professional engineer.

Edward G. Brantley joined the company in September 2005 as our Vice President and Chief Accounting Officer. Prior to joining the company, Mr. Brantley was employed by Pride International, Inc., an oilfield services provider and drilling contractor, from 2000 to 2005, where he served in several capacities, including Treasurer and Vice President and Chief Accounting Officer. Prior to joining Pride, Mr. Brantley was employed by Baker Hughes, Inc., an international oilfield services provider, for 11 years in various positions, including Controller of Baker Hughes Inteq.

PART II

Item 5.

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

Common Stock

Our common stock, par value $0.0006 per share, began trading on the American Stock Exchange under the symbol “TMY” on March 21, 2005; prior to this time, our common stock traded on the OTC Bulletin Board under the symbol “TMXN.” There are 200,000,000 shares of common stock authorized by our amended and restated certificate of incorporation. As of March 10, 2006, we had 88,183,142 shares issued and outstanding, which were held by an estimated 2,517 beneficial owners. The following table presents the high and low sales prices and high and low bid prices (as the case may be) per share for our common stock, as reported by the American Stock Exchange and the OTC Bulletin Board.


2005:	High		Low
Fourth quarter	$	6.10	$	2.66
Third quarter	$	4.20	$	1.81
Second quarter	$	2.75	$	1.50
First quarter	$	3.00	$	1.53

2004:	High		Low
Fourth quarter	$	1.97	$	1.24
Third quarter	$	1.35	$	0.81
Second quarter	$	1.88	$	0.98
First quarter	$	2.15	$	0.78

Preferred Stock

We are authorized by our amended and restated certificate of incorporation to issue up to 5,000,000 shares of preferred stock. As of December 31, 2005, we had 1,547.714 shares of our Series A cumulative convertible preferred stock (“Series A Preferred”) issued and outstanding, which are held by an estimated nine beneficial owners. There is no established trading market for the shares of our Series A Preferred.

Dividend Policy on Common Stock

We have never paid cash dividends on our common stock. We intend to retain future earnings, if any, to meet our working capital requirements and to finance the future operations of our business. Therefore, we do not plan to declare or pay cash dividends to the holders of our common stock in the foreseeable future. Moreover, our ability to pay dividends on our common stock is restricted by the terms of our Series A Preferred and by the indenture governing our senior secured notes due 2010.

Item 6.

Selected Financial Data

The following selected financial information should be read in conjunction with the consolidated financial statements and the notes thereto included under “Item 8. Financial Statements and Supplementary Data.”


	Year ended December 31,
	2005			2004			2003			2002			2001
	(Amounts in thousands, except per share amounts)
OPERATING RESULTS:
Oil revenues	$	8,443		$	3,923		$	797		$	—		$	51
Loss from operations		(9,823	)		(3,305	)		(4,915	)		(2,936	)		(1,924	)
Net loss		(20,541	)		(3,848	)		(5,686	)		(3,270	)		(2,112	)
Net loss attributable to common stockholders		(21,622	)		(4,002	)		(5,706	)		(3,308	)		(2,236	)
Basic and diluted net loss per share		(0.26	)		(0.05	)		(0.09	)		(0.06	)		(0.04	)
Oil sales price per barrel		27.62			11.87			10.52			0.00			0.00
Operating cost per barrel produced		3.98			1.55			3.41			0.00			0.00
BALANCE SHEET DATA:
Total current assets	$	74,705		$	29,205		$	2,067		$	813		$	377
Total property and equipment, net of accumulated depreciation		226,815			70,389			54,560			24,396			13,105
Total assets		313,993			99,810			57,099			26,271			13,883
Total current liabilities		33,697			25,671			31,918			6,637			2,475
Long term debt, net of current maturities		223,407			23,683			24,674			13,752			3,368
Stockholders’ equity		56,704			42,345			506			3,881			6,038
CASH FLOW DATA:
Net cash used in operating activities	$	(11,351	)	$	(10,105	)	$	(3,654	)	$	(2,056	)	$	(1,880	)
Net cash used in investing activities		(144,703	)		(17,647	)		(23,640	)		(10,299	)		(1,813	)
Net cash provided by financing activities	$	173,752		$	43,177		$	27,991		$	12,873		$	3,289

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis addresses changes in our financial position and results of operations during the three year period 2003 through 2005. There is limited or no comparability for revenue and operating expense in 2003, as sales and production did not commence until the third quarter of 2003.

Management’s primary goals for 2005 were to:

•

Continue development drilling in the Field;

•

Increase production from all wells in the Field;

•

Improve efficiency of drilling and completion programs;

•

Improve prices received for oil sales;

•

Negotiate a long-term production contract; and

•

Secure additional financing for Caspi Neft.

We believe that these goals were largely achieved in 2005. Our primary goals for 2006 include optimizing completions of the existing wells in the Field to maximize production from those wells, accelerating development

of the Field by increasing the number of drilling rigs under operation from one to at least four, continuing to improve the price received for our oil sales, completing production and treatment facilities and connecting to the regional pipeline system.

Current Activities

Through December 31, 2005, we had drilled a total of eight wells in our South Alibek evaluation and development program. The SA-14 and the SA-3 were completed and placed into production in May and October 2005, respectively. Drilling of the eighth well in the program, the SA-15, began in late September 2005 and reached target depth in December 2005. The well was perforated in January 2006 and allowed to begin flowing naturally without stimulation. These three wells are infill development wells. With the exception of SA-4, all the wells in the Field have been producing oil on an extended production testing program. The ninth and tenth wells in the Field, the SA-11 and SA-12, were spudded on January 30 and February 1, 2006 respectively.

Our field operations and scheduled workovers were adversely affected by abnormally extreme subzero temperatures during late December and early 2006 that affected the region’s transportation, infrastructure and contractor services. The interruptions caused by these circumstances significantly affected timing of planned work and our ability to meet year-end production goals, with two of the seven producing wells temporarily shut-in. Once scheduled work is completed and these wells are placed back on production, we expect production from the existing wells producing simultaneously to be approximately 2,500-3,000 bopd.

Production from the wells is currently run through temporary production facilities, with oil storage capacity at the site of this facility as well as at the site of the central production facility. Production is currently being constrained by equipment and flowline limitations pending completion of the central facility, which has been delayed by the inability of the previous general contractor to complete the required installation. That contractor has been dismissed, and we engaged a leading international contractor in February 2006 to inspect and submit a plan to complete the facilities. We expect to have a revised plan and definitive construction schedule during the first quarter of 2006, resume construction work in the second quarter and commission the facility by the fourth quarter. We are implementing an interim solution to improve production capacity until the central facility is completed. The design and permitting work on our pipeline connection to the Alibekmola-Kenkiyak pipeline, and the associated support facilities began in 2005, and commissioning is also planned before the fourth quarter of 2006. See “Item 2. Properties—Transportation and Marketing” for an overview of pipeline connections and activity in the South Alibek area.

During 2005, workover programs initiated in 2004 were completed and new programs for selected wells were initiated to prepare the wells for long-term commercial production. These programs included reservoir stimulation, installation of more efficient production tubing and packers and the testing of down-hole electric submersible pumps with the aim to increase production. To address numerous delays and inefficiences encountered in our execution of the workover program, a dedicated workover rig has been sourced for the Field that will replace the locally provided workover units used previously. This new unit is expected to significantly reduce the time required to conduct our workovers and reduce the shut-in time experienced while work is in progress. We expect the unit to begin working in the second quarter of 2006, when Field activity levels increase as a result of the accelerated drilling program.

Our drilling program is currently using two drilling rigs contracted from Great Wall Drilling Company, the second of which arrived in the Field in December 2005. We plan to accelerate the program by adding at least two additional drilling rigs during the first half of 2006, bringing the total rigs in operation in the Field to four. In addition, the Company is evaluating opportunities to further speed development by adding a fifth and possibly a sixth drilling rig later in the year.

We have significantly reduced the time required to drill to our programmed final depths through improvement in drilling practices, bit selection and drilling fluids control. SA-15 reached its total depth of 12,600

feet in 87 days and was the first of our wells that met the benchmark of 92 days established from competitor drilling data. We expect to continue to improve on the timing for drilling and completion of wells as increased equipment and new highly skilled personnel will allow for more continuity in operations.

Results of Operations

Oil Production and Revenue

For the year ended December 31, 2005, we produced 400,425 barrels (“Bbls”) of crude oil, or an average of 1,097 Bbls per day (Bopd), as compared to 313,305 Bbls, or an average of 858 Bopd, for the year ended December 31, 2004 and 117,376 Bbls, or an average of 641 Bopd for the year ended December 31, 2003. The increase in 2005 when compared to 2004, and the increase in 2004 from 2003, are primarily a result of the Field having five wells contributing to production in 2005 as compared to three wells in 2004 and only one well in 2003, and the Field being on production throughout 2004 versus only six months in 2003, as production from the Field commenced in July of 2003.

For the year ended December 31, 2005, we sold (by physical delivery to the purchaser) 324,355 Bbls of crude oil at an average price of $27.62 per Bbl, for net revenues of $8,442,787, as compared to 336,440 Bbls of crude oil at an average price of $11.87 per Bbl, for net revenues of $3,922,990, for the year ended December 31, 2004 and 77,293 Bbls at an average price of $10.52, for net revenue of $797,411 for the year ended December 31, 2003. The increase in net revenue in 2005 as compared to 2004 was primarily a result of substantially higher sales prices we received for our oil. Through a series of new sales arrangements, we realized increases over 2004 in the net price received for our crude oil to an average of approximately $20.00 per Bbl for the first half of 2005 and an average of approximately $37.00 per Bbl for the second half of 2005. The last price we received in December 2005 was $42.45 per Bbl. The increase in net revenue in 2004 as compared to 2003 is primarily due to the Field having three producing wells in 2004 as compared to only one producing well in 2003, and the Field producing for all of 2004 versus only six months of 2003. Sales from the Field commenced in the third quarter of 2003.

We recognize revenue from the sale of oil when the purchaser takes delivery of the oil. As of December 31, 2005, we had 87,296 Bbls of oil in inventory that had not yet been sold, pending commencement of oil sales arrangements with new purchasers. As of December 31, 2004, we had 16,576 Bbls in inventory for which we had received payment but had not recognized revenue because delivery had not yet been taken by the purchaser. The average sales price for this oil was $11.61 per Bbl, which was recognized as revenue in 2005 upon delivery to the purchaser.

Our crude oil sales since June 2005 have primarily take place at a nearby rail terminal. We incurred transportation and storage costs of approximately $1.54 per Bbl to transport our oil by truck to the rail terminal, where it is stored in rented tanks until delivery to the purchasers. Our crude oil sales in the last eight months of 2004 and the first six months of 2005 occurred at the Field and were not subject to transportation costs. See Item 7, “Results of Operation—Transportation Expense”.

Exploration Expense

Exploration expense, which includes geological and geophysical expense and the cost of unsuccessful exploratory wells, is recorded as an expense in the period incurred under the successful efforts method of accounting. During the year ended December 31, 2005, we incurred $9,470 in exploration expense, primarily associated with geological interpretations of the Field. During 2004, we recognized exploration expense of $130,926, which included costs associated with geological interpretations of the Field and a write off of the remaining book value of non-producing lease cost of a property in South Texas. During 2003, we incurred $592,553 in exploration expense, which was primarily related to the purchase and interpretation costs of geologic data and a charge for the unsuccessful completion attempt on one of our two U. S. properties.

Depreciation, Depletion and Amortization

Depreciation, depletion and amortization (“DD&A”) of oil and gas properties is calculated under units of production method, following the successful efforts method of accounting. For the year ended December 31, 2005, DD&A of oil and gas properties was $2,442,263, or $6.10 per Bbl, as compared to $709,496, or $2.11 per Bbl for the year ended December 31, 2004 and $189,635, or $2.45 per Bbl, for the year ended December 31, 2003. The increase in 2005 from 2004 is primarily a result of the change in classification of reserves attributable to the KT1 reservoir to “proved undeveloped” from “proved developed behind pipe,” due to a change in the assumed Field development plan. The new plan assumes that separate wells will be drilled to produce reserves in the KT1 reservoir, rather than “dual-completing” wells to produce from both the KT2 and KT1 reservoirs simultaneously. As a result, beginning in the fourth quarter of 2005, reserves in the KT1 reservoir, which account for approximately 40% of our total “proved” reserves as of December 31, 2005, have been excluded from the total reserve base currently being depleted. Costs incurred are now spread over a substantially smaller quantity of oil until such time as wells are drilled to produce from the KT1 reservoir and those reserves are classified as “proved developed.” In addition, we had an average of four producing wells during 2005 versus only 1.5 producing wells in 2004. The increase in DD&A of oil and gas properties in 2004 from 2003 is primarily due to the increase in oil production between the periods.

Non-oil and gas property DD&A for 2005, 2004 and 2003 was $942,630, $79,262 and $56,077, respectively. The increase between the years is primarily due to additions of transportation and other equipment, and commencement of depreciation on our drilling rig, which we no longer plan to use for development of the Field.

Transportation Expense

During the third quarter of 2005, we began incurring transportation and storage costs relating to the transport of our oil to a nearby rail terminal for sale and export. During the second half of 2005, we incurred transportation and storage costs of $321,313, or $1.54 per Bbl. From the second quarter of 2004 through the second quarter of 2005, oil sales were made directly from the Field, with no transportation costs incurred. For the year ended December 31, 2004, transportation and storage costs were $173,847, or $2.12 per Bbl produced. For the year ended December 31, 2003, we incurred transportation and storage costs of $235,264 or $2.00 per Bbl produced. When the treating facilities and pipeline pump station discussed in Item 2, “Properties—Transportation and Marketing,” are operational, expected in late 2006, we plan to deliver crude oil production directly into the regional pipeline system, which should result in a significant improvement in sales pricing for our crude oil.

Impairment Loss

In the first quarter of 2006, we reached an agreement to dispose of our drilling rig. An impairment charge writing the value of the rig down to the estimated proceeds and reclassifying the net book value of the rig to current asset held for sale was recorded as of December 31, 2005.

Operating and Administrative Expense—Kazakhstan

For the year ended December 31, 2005, operating and administrative expense in Kazakhstan was $3.9 million, as compared to $3.6 million for the year ended December 31, 2004 and $2.5 million for the year ended December 31, 2003. The increases between years are primarily a result of increased personnel costs due to increased activity in our exploration, development and production program for the Field.

General and Administrative Expense—Houston

For the year ended December 31, 2005, general and administrative expense in Houston was $6.6 million, as compared to $2.6 million for the year ended December 31, 2004 and $2.1 million for the year ended

December 31, 2003. The increase in 2005 from 2004 is primarily due to costs incurred for listing on the American Stock Exchange, Sarbanes-Oxley Act compliance and addition of new corporate staff, as well as the cost of stock-based compensation related to employee stock options and restricted stock grants recognized during the year. The increase in 2004 from 2003 is primarily due to increased legal costs associated with two lawsuits ongoing during the year.

Interest Expense

Interest expense, net of the capitalized portion, for the years ended December 31, 2005, 2004 and 2003 was $10.3 million, $1.4 million and $.7 million, respectively. The increase in interest expense between years is primarily due to increased debt levels between the periods, as well as the commencement of expensing interest, as opposed to capitalizing interest, on those assets which have been placed in service and are being used for their intended purpose. In addition, $4.4 million of debt discount amortization related to short-term borrowing was recognized in 2005.

Liquidity and Capital Resources

For the years ended December 31, 2005, 2004 and 2003, our on-going capital expenditures were $20.7 million, $26.1 million and $31.2 million, respectively. Our primary sources of funding have been private placements of common and preferred stock, borrowings under our credit facilities with a Kazakhstan bank and our private placement of senior secured notes due 2010 and warrants to purchase shares of common stock (as described in more detail below and in notes 5 and 6 to the notes to consolidated financial statements). The total capitalized cost attributable to the South Alibek Field as of December 31, 2005 was $230.1 million, which includes $12.5 million of capitalized interest.

In February 2002, Caspi Neft entered into a credit facility with a Kazakhstan bank that provided for borrowings totaling $20.0 million with an interest rate of 15% and a fee of 0.5% per annum on the unutilized portion of the commitment. The original maturity date was February 2005; however, the terms were renegotiated to allow for deferral of all principal and interest payments until the earlier of (i) the closing date of the acquisition of Bramex or (ii) December 23, 2005.

In June 2003, Caspi Neft entered into a new $30.0 million credit facility with the same Kazakhstan bank. This facility provided for borrowings up to $30.0 million with an interest rate of 15% and a commitment fee of 0.5% per annum on the unutilized portion. Upon execution of the credit facility, Caspi Neft paid the bank an arrangement fee of $300,000, which was capitalized as a deferred financing cost and was being amortized over the five-year life of the facility. Originally, the amount outstanding as of May 31, 2005 was scheduled to be repaid over 36 equal monthly installments beginning June 2005 through the final maturity date of May 31, 2008; however, those terms were renegotiated to allow for deferral of all principal and interest payments until the earlier of (i) the closing date of the acquisition of Bramex or (ii) December 23, 2005.

Both credit facilities were repaid in full in December 2005 in connection with our acquisition of Bramex and our December 2005 private placement of senior secured notes and warrants discussed below.

In November 2004, we sold 1,785.714 shares of our Series A Preferred in a private placement at a purchase price of $14,000 per share, and issued warrants to purchase up to 4,464,286 shares of our common stock at an exercise price equal to $1.55 per share. The aggregate purchase price for the Series A Preferred and the related warrants was cash consideration of $25.0 million. Proceeds from the private placement of Series A Preferred and warrants were used for general corporate purposes, including funding our development drilling program in the South Alibek Field in Kazakhstan, and to pursue growth opportunities.

The Series A Preferred has a liquidation value of $14,000 per share and is convertible at the holders’ option into common stock at a conversion price of $1.40 per share, subject to adjustments in certain circumstances. The holders of the Series A Preferred are entitled to a quarterly dividend payable at the rate of 4.5% per annum, payable in cash. The holders of the Series A Preferred have full voting rights and powers (subject to a beneficial ownership cap as described below) equal to the voting rights and powers of the holders of our common stock, and vote together with the holders of common stock as one class. A holder of the Series A Preferred may not, unless it chooses in advance not to be governed by this limitation, convert the Series A Preferred or exercise the warrants into common stock such that the number of shares of common stock issued after the conversion would exceed, when aggregated with all other shares of our common stock owned by such holder at such time, 4.999% of our then issued and outstanding shares of common stock. So long as at least 20% of the Series A Preferred remains outstanding, we may not issue any new securities or financial instruments that rank pari passu or senior to the Series A Preferred without the approval of at least 75% of the Series A Preferred outstanding. Beginning in July 2006, the Series A Preferred will automatically convert into our common stock at the conversion price of $1.40 per share (subject to adjustments), if our common stock trades at a price greater than $4.15 per share for twenty consecutive trading days and the average daily trading volume of our common stock during such period exceeds 200,000 shares, subject to the applicable ownership limitations. In the event a holder is prohibited from converting into common stock due to the 4.999% ownership limitation, the excess portion of the Series A Preferred remains outstanding, but ceases to accrue a dividend. During 2005, 238 shares of Series A Preferred were converted into 2,380,000 shares of our common stock.

In May 2005, we borrowed an aggregate of $2,240,000 from a group of individuals pursuant to unsecured, short-term notes. The notes bore interest at 15% per annum and were repaid along with accrued interest in July and September 2005. In July 2005, we borrowed $1,000,000 from an individual pursuant to an unsecured short-term note, which bore interest at 15% per annum and was repaid with accrued interest in December 2005. In connection with these borrowings, we issued detachable warrants to purchase 420,000 shares of common stock at exercise prices ranging from $2.00 to $2.12 per share. The warrants have a three-year term.

In August 2005, we issued convertible promissory notes (the “Convertible Notes”) in the original aggregate principal amount of $22,500,000. The Convertible Notes, which bore interest at 10% per annum, were repaid in full, including accrued interest, in December 2005. We used a portion of the proceeds from our private placement of senior secured notes and warrants in December 2005 discussed below to repay the Convertible Notes.

In October 2005, one of our wholly-owned subsidiaries, Transmeridian Exploration Inc. (“TEI”), entered into a share sale and purchase agreement with Seeria Alliance Ltd. to purchase 100% of the authorized and issued shares of Bramex, the owner of 50% of Caspi Neft. In December 2005, the transaction was completed and TEI now owns, directly or indirectly, 100% of Caspi Neft. The total purchase price was $168 million, of which approximately $44 million was to repay the bank credit facilities of Caspi Neft discussed above.

In December 2005, TEI, issued in a private placement 250,000 units (the “Units”) consisting of (i) an aggregate $250 million principal amount of its senior secured notes due 2010 (the “Notes”) and (ii) warrants to purchase in the aggregate approximately 17.3 million shares of our common stock (the “Warrants”). The Units were issued and sold for a purchase price of $1,000 per Unit. Each Unit consists of $1,000 principal amount of Notes and 69.054 Warrants to purchase an equal number of shares of our common stock. The Notes, which will mature on December 15, 2010, bear interest at the rate of 12% per annum. Interest on the Notes is payable quarterly on March 15, June 15, September 15 and December 15, beginning on March 15, 2006, and at maturity. The first year of interest payments have been escrowed and are recorded as restricted cash on the consolidated balance sheet as of December 31, 2005.

The Notes are secured by first priority pledges of all the capital stock of TEI and of all of our other material subsidiaries. In addition, the Notes are fully and unconditionally guaranteed by us and all of our other material subsidiaries other than TEI. The Notes contain provisions that limit our ability to enter into transactions with affiliates; pay dividends or make other restricted payments; incur debt; create, incur or assume liens; sell assets;

and consolidate, merge or transfer all or substantially all of our assets. We are required to offer to repurchase the Notes in connection with certain specified change of control events. The Notes are subject to redemption, in whole or in part, at our option at any time on or after December 15, 2008 at redemption prices starting at 106% of the principal amount redeemed and declining to 100% by June 15, 2010. Prior to December 15, 2008, we may redeem up to 35% of the Notes with proceeds of certain equity offerings at a specified redemption price.

We used the net proceeds from the private placement of the Units of $237.4 million, after expenses, to fund the acquisition of Bramex, to retire the existing bank credit facility indebtedness of Caspi Neft, to repay the Convertible Notes and related accrued interest and to pre-fund the first year of interest payments of $30 million on the Notes. In addition, in December 2005, we entered into a purchase agreement with Kornerstone Investment Group Ltd. (“Kornerstone”) pursuant to which we acquired the 10% carried working interest in the South Alibek Field held by Kornerstone for $15.25 million in cash and one million shares of our common stock. The cash portion of the purchase price obligation was funded from the net proceeds of the placement of Units.

Management expects cash flow from operations to increase throughout 2006 and, together with the excess proceeds from the private placement of Units discussed above, to provide a portion of the funds needed to further develop the field and repay debt. Such cash flow is dependent upon many factors, such as achieving and sustaining adequate production rates, oil prices and other factors which may be beyond the our control.

The following table presents our future contractual obligations, which consist of long-term debt and lease commitments:


	2005		2006		2007		2008		Thereafter
Long-term debt⁽¹⁾	$	—	$	—	$	—	$	—	$	250,000,000
Lease commitments⁽²⁾		273,324		76,126		—		—		349,540

Total contractual obligations	$	273,324	$	76,126	$	—	$	—	$	250,349,540

⁽¹⁾	See note 5 to the Notes to the Consolidated Financial Statements.

⁽²⁾	See note 8 to the Notes to the Consolidated Financial Statements.

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 1 of the Notes to Consolidated Financial Statements.

Principles of Consolidation

The consolidated financial statements include our accounts and our majority-owned or controlled subsidiaries and are prepared in accordance with generally accepted accounting principles in the United States. All significant intercompany transactions and balances have been eliminated in consolidation. The assets and results of operations of Caspi Neft represent substantially all of our consolidated assets and operations.

We continued to exercise significant control over Caspi Neft after Bramex exercised its option to acquire 50% of Caspi Neft in February 2004 and accordingly, believed the most meaningful accounting treatment was to fully consolidate Caspi Neft with the 50% share owned by Bramex reflected as a minority interest. To exercise its option, Bramex contributed $15.0 million in cash to Caspi Neft, the proceeds of which were used by Caspi Neft to retire debt. The difference between the $15.0 million of capital contributed to Caspi Neft and 50% of the book equity of Caspi Neft after such capital contribution represents an excess purchase price paid by Bramex of $6.0 million. This amount was included in additional paid-in capital on the accompanying 2004 consolidated balance sheet.

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 engineer was engaged to prepare the estimates of our oil and gas reserves in accordance with applicable engineering standards and in accordance with Securities and Exchange Commission 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.

Our oil and gas reserve data and estimated future net cash flows have been prepared assuming we execute a commercial production contract with the Kazakhstan government, which will allow production for the expected 25-year term of the contract. The estimate of the royalty used in this report is a sliding scale based on annual production over the 25-year term, based on the provisions of the final production contract that is awaiting approval from the Kazakhstan government. Based on the forecast annual production, the government royalty rate is between 2.0% to 2.2%, with the royalty rate capped at 5%. If we are not successful in obtaining final government approval of the production contract, it will materially change our oil and gas reserve data and estimated future net cash flows.

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. This accounting method has a pervasive effect on our reported financial position and results of operations.

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. We also capitalized interest on our drilling rig during the time it was being prepared for its intended use. During the year ended December 31, 2005, 2004 and 2003, we capitalized $2.5 million, $4.5 million and $4.2 million, respectively, of interest costs, which reduced our reported net interest expense to $10.3 million, $1.4 million and $772,409 respectively. Since a significant portion of our financial resources has been dedicated to the exploration and development of our Kazakhstan property, since 2001, the resulting interest capitalized has been significant. This capitalized interest becomes part of the capitalized costs of our properties which will be amortized as a part of depreciation, depletion and amortization or charged to expense if the results of our drilling should prove unsuccessful.

Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued the revised SFAS No. 123, Share-Based Payment (“SFAS No. 123(R)”). SFAS 123(R) is a revision of SFAS No. 123 and supersedes APB No. 25. SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured at each reporting date through the settlement date. Compensation cost will be recognized over the period that an employee provides services in exchange for the award. We had previously adopted SFAS No. 123, and, the adoption of SFAS 123(R) on January 1, 2006 is not expected to have a material effect on our consolidated financial statements.

reporting of a change in accounting principle. SFAS No. 154 requires retrospective application of changes in accounting principle to prior periods’ financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We adopted SFAS No. 154 on January 1, 2006. Any impact on our consolidated results of operations and earnings per share will be dependent on the amount of any accounting changes or corrections of errors whenever recognized.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Oil Prices

Our future success is dependent on our being able to transport and market our production either within Kazakhstan or preferably through export to international markets. Crude oil prices are subject to significant volatility in response to changes in supply, market uncertainty and a variety of other factors beyond our control. The majority of our sales of crude oil prior to June 2005 were based on prevailing local market prices at the time of sale.

Interest Rate Risk

At December 31, 2005, we had long-term debt outstanding of $223.4 million, net of discount of $26.6 million. The debt bears interest at a fixed rate of 12% per annum and the first year’s interest payments have been escrowed.

Foreign Currency Risk

Our functional currency is the U.S. dollar. The financial statements of our foreign subsidiaries are measured in U.S. dollars. Accordingly, transaction costs for the conversion to various currencies for foreign operations are recognized in earnings at the time of each transaction.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements, In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or the negative thereof or variations thereon or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. Important factors that could cause actual results to differ materially from our expectations (“cautionary statements”) include, but are not limited to, our assumptions about energy markets, production levels, reserve levels, operating results, competitive conditions, technology, the availability of capital resources, capital expenditure obligations, the supply and demand for oil, natural gas and other products or services, the price of oil, natural gas and other products or services, currency exchange rates, the weather, inflation, the availability of goods and services, drilling risks, future processing volumes and pipeline throughput, general economic and political conditions, either internationally or nationally or in the jurisdictions in which we or our subsidiaries are doing business, legislative or regulatory changes, including changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations, the securities or capital markets and other factors disclosed under “Item 2. Properties—Proved Reserves,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and

Qualitative Disclosures About Market Risk” and elsewhere in this report. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

Item 8.

Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Reports of Independent Registered Public Accounting Firms		27
Consolidated Balance Sheet as of December 31, 2005 and 2004		28
Consolidated Statement of Operations for the Years Ended December 31, 2005, 2004 and 2003		29
Consolidated Statement of Stockholders’ Equity for the Years Ended December 31, 2005, 2004 and 2003		30
Consolidated Statement of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003		31
Notes to Consolidated Financial Statements		33

REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMS

To the Board of Directors and Stockholders

Transmeridian Exploration Incorporated and Subsidiaries

Houston, Texas

We have audited the accompanying consolidated balance sheet of Transmeridian Exploration Incorporated and subsidiaries (“the Company”) as of December 31, 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transmeridian Exploration Incorporated and subsidiaries as of December 31, 2005, and the consolidated results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO criteria”) and our report dated March 16, 2006 expressed an unqualified opinion on management’s assessment that the Company did not maintain effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria, and because of the effects of the material weakness described therein, Transmeridian Exploration Incorporated has not maintained effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.

/s/ UHY MANN FRANKFORT STEIN & LIPP CPAs, LLP

Houston, Texas

March 16, 2006

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

Board of Directors

Transmeridian Exploration, Inc. and Subsidiaries

We have audited the accompanying consolidated balance sheets of Transmeridian Exploration, Inc. and Subsidiaries as of December 31, 2004, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the two year period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with standards of Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transmeridian Exploration Inc. and Subsidiaries at December 31, 2004 and 2003 and the consolidated results of their operations and cash flows for each of the years in the three year period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.



By:		/S/ JOHN A. BRADEN & COMPANY, P.C.
		John A. Braden & Co., P.C.

Houston, Texas

March 14, 2005

TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET


	December 31,
	2005			2004
ASSETS
Current Assets:
Cash and cash equivalents	$	34,443,457		$	16,746,137
Restricted cash		31,960,491			—
Accounts receivable		3,623,399			3,644,891
Crude oil inventory		1,625,934			192,465
Other current assets		51,264			75,850
Asset held for sale		3,000,000			8,545,897

Total current assets		74,704,545			29,205,240

Property and Equipment:
Oil and gas properties, successful efforts method		230,139,394			71,048,574
Transportation equipment		239,821			239,821
Office and technology equipment		339,580			291,305

Total property and equipment		230,718,795			71,579,700
Less accumulated depreciation, depletion and amortization		3,903,446			1,190,791

Property and equipment, net		226,815,349			70,388,909

Other assets, net		12,473,536			216,111

	$	313,993,430		$	99,810,260

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	31,869,443		$	7,137,016
Current maturities of long-term debt		—			12,005,208
Accrued interest payable		1,583,333			6,132,477
Deferred revenue		—			192,465
Preferred dividends payable		244,003			154,110
Notes payable to related parties		—			50,000

Total current liabilities		33,696,779			25,671,276

Long-term debt, net of discount of $26,592,924 at December 31, 2005		223,407,076			23,682,999
Other long term liabilities		186,000			186,000
Minority interest		—			7,924,558
Stockholders’ Equity:
Preferred stock, $0.0006 par value per share, 5,000,000 shares authorized, 1,547.714 and 1,785.714 issued and outstanding		1			1
Common stock, $0.0006 par value per share, 200,000,000 shares authorized 87,128,021 and 79,829,062 issued and outstanding		52,277			47,897
Additional paid-in capital		94,336,744			58,361,256
Accumulated deficit		(37,685,447	)		(16,063,727	)

Total stockholders’ equity		56,703,575			42,345,427

	$	313,993,430		$	99,810,260

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

TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS


	Year ended December 31,
	2005			2004			2003
Revenue from oil sales	$	8,442,787		$	3,922,990		$	797,411
Operating costs and expenses:
Exploration expense		9,470			130,926			592,553
Depreciation, depletion and amortization		3,384,893			788,758			245,712
Transportation expense		321,313			154,993			235,264
Impairment loss on drilling rig		4,022,015			—			—
Operating and administrative expense—Kazakhstan		3,896,332			3,591,529			2,503,674
General and administrative expense—Houston		6,631,490			2,562,033			2,135,237

Total operating costs and expenses		18,265,513			7,228,239			5,712,440

Operating loss		(9,822,726	)		(3,305,249	)		(4,915,029	)
Other income (expense):
Interest income		337,815			34,242			870
Interest expense, net of capitalized interest		(10,344,217	)		(1,400,227	)		(772,409	)

Total other income (expense)		(10,006,402	)		(1,365,985	)		(771,539	)

Loss before minority interest		(19,829,128	)		(4,671,234	)		(5,686,568	)
Minority interest income (expense)		(711,558	)		823,053			—

Net loss		(20,540,686	)		(3,848,181	)		(5,686,568	)
Preferred dividends		(1,081,034	)		(154,110	)		(19,736	)

Net loss attributable to common stockholders	$	(21,621,720	)	$	(4,002,291	)	$	(5,706,304	)

Basic and diluted loss per share	$	(0.26	)	$	(0.05	)	$	(0.09	)

Weighted average common shares outstanding, basic and diluted		82,004,175			78,615,433			64,573,627

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

TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY


	Preferred Stock					Common Stock			Additional Paid-In Capital			Accumulated Deficit			Total
	Shares		Amount			Shares (000’s)	Amount		Additional Paid-In Capital			Accumulated Deficit			Total
Balance December 31, 2002	3,000		$	2		59,147	$	35,488	$	10,201,625		$	(6,355,132	)	$	3,881,983
Conversion of preferred stock	(3,000	)		(2	)	1,546		928		56,329			—			57,255
Common stock issued for services	—			—		5,320		3,192		830,075			—			833,267
Proceeds from the sale of common stock, net of offering costs	—			—		3,333		2,000		998,000			—			1,000,000
Common stock used to retire debt	—			—		1,327		796		295,421			—			296,217
Stock-based compensation	—			—		—		—		122,800			—			122,800
Issuance of warrants in connection with services	—			—		—		—		21,000			—			21,000
Convertible preferred stock dividends	—			—		—		—		—			(19,736	)		(19,736	)
Net loss	—			—		—		—		—			(5,686,568	)		(5,686,568	)

Balance December 31, 2003	—			—		70,673		42,404		12,525,250			(12,061,436	)		506,218
Exercise of warrants	—			—		358		214		(214	)		—			—
Issuance of common stock to retire debt	—			—		800		480		703,520			—			704,000
Proceeds from the sale of common stock, net of offering costs	—			—		7,268		4,361		4,377,689			—			4,382,050
Proceeds from the sale of preferred stock, net of offering costs	1,786			1		—		—		20,762,056			—			20,762,057
Issuance of warrants in connection with sale of preferred stock sale	—			—		—		—		2,678,570			—			2,678,570
Stock-based compensation	—			—		730		438		395,851			—			396,289
Private placement termination fee	—			—		—		—		200,000			—			200,000
Elimination of minority interest	—			—		—		—		16,718,534			—			16,718,534
Convertible preferred stock dividends	—			—		—		—		—			(154,110	)		(154,110	)
Net loss	—			—		—		—		—			(3,848,181	)		(4,002,291	)

Balance December 31, 2004	1,786			1		79,829		47,897		58,361,256			(16,063,727	)		42,345,427
Exercise of warrants	—			—		1,757		1,054		2,762,112			—			2,763,166
Proceeds from the sale of common stock	—			—		882		529		1,790,252			—			1,790,781
Conversion of preferred stock	(238	)		—		2,380		1,428		(1,428	)		—			—
Issuance of warrants in connection with debt offerings	—			—		—		—		31,520,394			—			31,520,394
Stock-based compensation	—			—		1,609		966		2,089,363			—			2,090,329
Preferred stock registration costs	—			—		—		—		(2,312,500	)		—			(2,312,500	)
Exercise of stock options	—			—		671		403		127,295			—			127,698
Convertible preferred stock dividends	—			—		—		—		—			(1,081,034	)		(1,081,034	)
Net loss	—			—		—		—		—			(20,540,686	)		(20,540,686	)

Balance December 31, 2005	1,548		$	1		87,128	$	52,277	$	94,336,744		$	(37,685,447	)	$	56,703,575

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

TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS


	Year ended December 31,
	2005			2004			2003
Operating Activities:
Net loss	$	(20,540,686	)	$	(3,848,181	)	$	(5,686,568	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation, depletion and amortization		3,384,893			788,758			245,712
Amortization of debt financing costs		1,114,930			193,332			184,166
Debt discount amortization		4,633,470			—			—
Impairment charge		4,022,015			—			—
Amortization of prepaid contracts		—			61,250			411,355
Stock-based compensation expense		2,090,329			396,289			122,800
Exploration expense		—			130,926			277,012
Stock issued for services		—			—			285,299
Minority interest (income) expense		711,558			(823,053	)		—
Increase in receivables		(1,978,508	)		(3,501,756	)		(49,465	)
Decrease in prepaid expenses		24,586			18,149			89,392
Increase in crude oil inventory		(1,625,934	)		—			—
Increase in accounts payable and accrued liabilities		1,361,311			732,738			40,687
Increase (decrease) in interest payable		(4,549,144	)		(4,253,422	)		424,920

Net cash used in operating activities		(11,351,180	)		(10,104,970	)		(3,654,690	)
Investing Activities:
Capital expenditures		(20,703,352	)		(17,647,162	)		(23,574,311	)
Acquisitions		(123,999,769	)		—			—
Increase in other assets.		—			—			(65,997	)

Net cash used in investing activities		(144,703,121	)		(17,647,162	)		(23,640,308	)
Financing Activities:
Proceeds from long-term debt		250,000,000			16,891,972			28,807,214
Repayments of long-term debt		(35,350,037	)		(16,539,868	)		(1,515,509	)
Proceeds from short-term borrowings		25,740,000			—			—
Repayments of short-term borrowings		(25,740,000	)		—			—
Decrease in notes payable to related parties		(50,000	)		(198,025	)		—
Payment of deferred financing costs		(12,578,355	)		—			(300,000	)
Payment of dividends on preferred stock		(991,142	)		—			—
Proceeds from sale of stock by Caspi Neft		—			15,000,000			—
Proceeds from sale of common stock, net		1,790,781			4,582,050			1,000,000
Proceeds from sale of preferred stock		—			23,440,626			—
Proceeds from exercise of stock options		127,700			—			—
Proceeds from exercise of warrants		2,763,165			—			—
Increase in restricted cash		(31,960,491	)		—			—

Net cash provided by financing activities		173,751,621			43,176,755			27,991,705
Net increase in cash and cash equivalents		17,697,320			15,424,623			696,707
Cash and cash equivalents, beginning of year		16,746,137			1,321,514			624,807

Cash and cash equivalents, end of year	$	34,443,457		$	16,746,137		$	1,321,514

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

TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS—SUPPLEMENTAL INFORMATION


	Year ended December 31,
	2005			2004			2003
Cash paid for:
Interest	$	11,642,884		$	4,864,749		$	187,613
Interest capitalized (non-cash)		(2,497,923	)		(4,519,759	)		(4,164,694	)
Income taxes		—			—			—
Non-cash investing and financing transactions:
Issuance of warrants in connection with debt	$	31,250,394		$	—		$	—
Accrual for acquisition of carried working interest		20,250,000			—			—
Accrued and unpaid dividends on convertible preferred stock		244,003			154,110			19,736
Exchange of convertible preferred stock for common stock		1,428			—			2
Issuance of common stock for services		—			—			833,267
Issuance of common stock to retire debt		—			704,000			296,217
Settlement of drilling rig dispute		—			(2,345,188	)		—
Assumption of note payable on drilling rig		—			3,393,158			—
Issuance of warrants in connection with services		—			1,004,464			21,000
Other long term liabilities		—			—			186,000

The accompanying notes are an integral part of these financial statements

TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Summary of Significant Accounting Policies

Transmeridian Exploration Incorporated (the “Company”) was incorporated in the State of Delaware in April 2000. The Company is engaged in the business of acquiring, developing and producing oil and gas with its activities primarily focused on the Caspian Sea region of the former Soviet Union. The Company’s primary oil and gas property is the South Alibek Field (“South Alibek” or the “Field”) in the Republic of Kazakhstan covered by License 1557 (the “License”) and the related exploration contract with the government of Kazakhstan.

The Company’s operations in Kazakhstan are conducted through the now wholly-owned subsidiary, JSC Caspi Neft TME (“Caspi Neft”), an open joint stock company organized under the laws of Kazakhstan. In February 2004, Bramex Management, Inc. (“Bramex”) exercised its option to acquire 50% of the issued and outstanding shares of Caspi Neft. In December 2005, the Company acquired all of the issued and outstanding shares of Bramex and, thus, the Company owns 100% of Caspi Neft.

Principles of Consolidation and Reporting

The consolidated financial statements include the accounts of the Company and its majority-owned and controlled subsidiaries and are prepared in accordance with generally accepted accounting principles in the United States. All significant intercompany transactions and balances have been eliminated in consolidation. The assets and results of operations of Caspi Neft represent substantially all of the consolidated assets and operations of the Company.

The Company continued to exercise significant control over Caspi Neft after Bramex exercised its option to acquire 50% of Caspi Neft in February 2004 and accordingly, believed the most meaningful accounting treatment was to fully consolidate Caspi Neft with the 50% share owned by Bramex reflected as a minority interest. To exercise its option, Bramex contributed $15.0 million in cash to Caspi Neft, the proceeds of which were used by Caspi Neft to retire debt. The difference between the $15.0 million of capital contributed to Caspi Neft and 50% of the book equity of Caspi Neft after such capital contribution represents an excess purchase price paid by Bramex of $6.0 million. This amount was included in additional paid-in capital on the accompanying 2004 consolidated balance sheet.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates and judgments on historical experience and on other information and assumptions that are believed to be reasonable under the circumstances. Estimates and judgments about future events and their effects cannot be perceived with certainty; accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as the Company’s operating environment changes and as new events occur. While it is believed that such estimates are reasonable, actual results could differ materially from those estimates. Estimates are used for, but not limited to, determining the following: inventory valuation, recoverability of long-lived assets, useful lives and oil and gas reserves used in depreciation, depletion, and amortization, income taxes and related valuation allowances and insurance, environmental and legal accruals.

Revenue Recognition

The Company sells its production both in the export and domestic market on a contract basis. Revenue is recorded when the purchaser takes delivery of the oil. At the end of the period, oil that has been produced but not

sold is recorded as inventory at the lower of cost or market. Cost is determined on a weighted average basis based on production costs.

Cash and Cash Equivalents

The Company considers all highly liquid instruments with an original maturity of three months or less to be cash equivalents. Certain of the Company’s cash balances are maintained in foreign banks which are not covered by deposit insurance. The cash balances in the Company’s U.S. accounts may exceed federally insured limits. Cash that is escrowed for specific purposes such as interest payments is shown as restricted cash in the accompanying consolidated balance sheet.

Property and Equipment

The Company follows the “successful efforts” method of accounting for its costs of acquisition, exploration and development of oil and gas properties.

Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs which are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.

Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Such costs include seismic expenditures and other geological and geophysical costs. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, exploratory drilling costs are expensed. Costs to develop proved reserves are capitalized, including the costs of all development wells and related equipment used in the production of crude oil and natural gas.

Depreciation, depletion and amortization of the costs of proved oil and gas properties is computed using the unit-of-production method based upon estimated proved reserves. Estimated future restoration and abandonment costs, if any, will be recognized as incurred as the Company does not have an ownership interest in the South Alibek Field and all property reverts to the government of Kazakhstan at the end of the License period. The Company does not have any legal obligations associated with the retirement of long-lived assets.

The Company reviews its oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.

In December 2001, the Company purchased a drilling rig that, beginning in October 2002, was used in the development of the South Alibek Field. The rig was depreciated on the straight-line method over an estimated useful life of ten years and while being used for development drilling, the depreciation of the rig and related support equipment was capitalized under the successful efforts method as part of the cost of the wells. Subsequent depreciation was expensed when the rig was stacked. In the first quarter of 2006, the Company reached an agreement to dispose of the rig. In accordance with generally accepted accounting principles, an impairment charge writing the value of the rig down to the estimated net proceeds and reclassifying the net book value of the rig to current asset held for sale was recorded in the accompanying consolidated financial statements.

Transportation equipment and office and technology equipment are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from three to five years.

Maintenance and repairs are charged to expense as incurred. Replacements and expenditures which improve or extend the life of assets are capitalized. When assets are sold, retired or otherwise disposed of, the applicable costs and accumulated depreciation and amortization are removed from the accounts, and the resulting gain or loss is recognized.

Capitalized Interest Costs

Certain interest costs have been capitalized as part of the cost of oil and gas properties, including property acquisition costs, wells in progress and related facilities. Additionally, interest was capitalized on the drilling rig while it was being readied for its intended use. Total interest costs capitalized during the years ended December 31, 2005, 2004 and 2003 totaled $2.5 million, $4.5 million and $4.2 million, respectively.

Income Taxes

The Company accounts for income taxes using the asset and liability method. The asset and liability method requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of (i) temporary differences between financial statement carrying amounts of assets and liabilities and the basis of these assets and liabilities for tax purposes and (ii) operating loss and tax credit carry-forwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when management concludes that it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.

Debt Financing Costs

Debt financing costs are amortized over the term of the related financing facility.

Loss per Common Share

Basic net loss per common share is calculated by dividing the net loss attributable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted net loss per common share is computed based upon the weighted average number of common shares outstanding plus the common shares which would be issuable upon the conversion or exercise of all potentially dilutive securities. Diluted net loss per share equals basic net loss per share for all periods presented because the effects of potentially dilutive securities are anti-dilutive.

Net loss attributable to common stockholders is calculated as the net loss after deductions for cumulative preferred stock dividends, whether paid or accrued.

Foreign Exchange Transactions

The Company’s functional currency is the U.S. dollar because it primarily contracts with customers, finances capital and purchases equipment and services using the U.S. dollar. Certain assets and liabilities are translated at historical exchange rates, revenues and expenses in foreign currency are translated at the average rate of exchange for the period and all translation gains or losses are reflected in the period’s results of operations.

Concentration of Credit Risk

Financial instruments that potentially subject the Company to concentrations of credit risk consist principally of cash and cash equivalents and accounts receivable. The Company deposits its cash and cash equivalents in high credit quality financial institutions, however amounts on deposit do exceed the maximum amount insured by the Federal Deposit Insurance Corporation.

Stock-Based Compensation

The Company accounts for employee stock-based compensation using the fair value method as prescribed in Statement of Financial Accounting Standards (“SFAS”) No. 123. Under this method, the Company records the fair value attributable to stock options or stock grants, based on the Black-Scholes model, and amortizes that amount to expense over the service period required to vest the options.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying values of cash and cash equivalents, receivables and accounts payable approximate fair value due to their short-term nature. The carrying value of long-term debt approximates its fair value based on the market interest rate of the debt instrument.

Reclassifications

Prior period amounts primarily related to the Company’s drilling rig have been reclassified to conform to the current period presentation.

New Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (“FASB”) issued the revised SFAS No. 123, Share-Based Payment (“SFAS No. 123(R)”). SFAS 123(R) is a revision of SFAS No. 123 and supersedes APB No. 25. SFAS 123(R) requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured at each reporting date through the settlement date. Compensation cost will be recognized over the period that an employee provides services in exchange for the award. The Company had previously adopted SFAS No. 123, and, the adoption of SFAS 123(R) on January 1, 2006 is not expected to have a material effect on the Company’s consolidated financial statements.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections. SFAS No. 154 replaces Accounting Principles Board Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Internal Financial Statements, and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application of changes in accounting principle to prior periods’ financial statements, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company adopted SFAS No. 154 on January 1, 2006. Any impact on the Company’s consolidated results of operations and earnings per share will be dependent on the amount of any accounting changes or corrections of errors whenever recognized.

Note 2—Acquisitions

In October 2005, a wholly-owned subsidiary of the Company entered into a share sale and purchase agreement with Seeria Alliance Ltd. to purchase 100% of the authorized and issued shares of Bramex, the owner of 50% of Caspi Neft. In December 2005, the transaction was completed and the subsidiary now owns, directly or indirectly, 100% of Caspi Neft. The total consideration of $168 million, of which approximately $44 million was to pay the outstanding indebtedness of Caspi Neft, was funded from the net proceeds of the private placement of units as described in note 5.

In December 2005, the Company entered into a purchase agreement with Kornerstone Investment Group Ltd. (“Kornerstone”) pursuant to which the Company acquired the 10% carried working interest in the South Alibek Field held by Kornerstone. Pursuant to the purchase agreement, the Company paid Kornerstone a

purchase price consisting of $15.25 million in cash and one million shares of the Company’s common stock. The cash portion of the purchase price obligation was funded from the net proceeds of the private placement of units.

Note 3—Property and Equipment

Oil and Gas Properties

The License covering the South Alibek Field, was granted by the Republic of Kazakhstan on April 29, 1999 and originally covered 3,396 acres. In March 2000, the Company acquired the License from an unrelated third-party for $4.0 million. During 2001, based on its technical review and analysis of the probable productive area of the Field, the Company applied to the Kazakhstan Ministry of Energy and Mineral Resources to expand the area covered by the License. In November 2001, the Company’s application was approved and the License was expanded to cover an area of 14,111 acres.

The exploration contract associated with the License had a six-year term which expired in April 2005 and has been extended through April 2007, and may be extended by mutual agreement for an additional two years. The exploration contract required capital expenditures during the initial period of approximately $18.0 million, which has been satisfied. In connection with the recent two-year extension, the Company has committed to an additional work program of $30.5 million. During the primary and extended terms, the Company can produce from wells under a test program and pay a royalty of 2% to the government. The exploration contract also contains a provision which will allow the government to recover, from future revenues, approximately $4.9 million of exploration costs which were incurred prior to privatization. The final terms for the recovery of these costs will be contained in the production contract when executed, The Company has received approval from the government of Kazakhstan for a production contract covering a portion of the License area, and is currently awaiting final signature of the production contract from the Kazakhstan government.

Drilling Rig and Equipment

In December 2001, the Company purchased a drilling rig that was used in the development of the South Alibek Field beginning in October 2002. The rig was depreciated on the straight-line method over an estimated useful life of ten years and while being used for development drilling, the depreciation of the rig and related support equipment was capitalized under the successful efforts method as part of the cost of the wells. Subsequent depreciation was expensed when the rig was stacked. In the first quarter of 2006, the Company reached an agreement to dispose of the rig. An impairment charge writing the value of the rig down to the estimated net proceeds and reclassifying the net book value of the rig to current asset held for sale was recorded as of December 31, 2005. As more fully discussed in note 8, there was a legal dispute between the Company and the holder of an apparent first lien on the drilling rig that was settled in December 2005.

Note 4—Notes Payable to Related Parties

In a series of notes issued between June 2002 and November 2002, certain stockholders and related parties, including the Chief Executive Officer of the Company, loaned the Company $248,025. These notes had interest rates of 17% and were paid in full in September 2005.

Note 5—Debt

Short-Term Debt

In May 2005, the Company borrowed an aggregate of $2,240,000 from a group of individuals pursuant to unsecured, short-term notes. The notes bore interest at 15% per annum and were repaid along with accrued interest in July and September 2005. In July 2005, the Company borrowed $1,000,000 from an individual pursuant to an unsecured short-term note, which bore interest at 15% per annum and was repaid with accrued

interest in December 2005. In connection with these borrowings, the Company issued detachable warrants to purchase 420,000 shares of common stock at exercise prices ranging from $2.00 to $2.12 per share. The warrants have a three-year term.

In August 2005, the Company issued convertible promissory notes (the “Convertible Notes”) in the original aggregate principal amount of $22,500,000. The Convertible Notes bore interest at 10% per annum and matured on the earlier of December 15, 2005 or the closing of certain equity financings. The Convertible Notes were repaid in full, including accrued interest, in December 2005 utilizing a portion of the proceeds from the private placement of units.

Long-Term Debt

Long-term debt consists of the following:


	December 31,
	2005		2004
Senior Secured Notes due 2010, net of discount of $26,592,924	$	223,407,076	$	—
$20 million credit facility with a Kazakhstan bank		—		3,583,863
$30 million credit facility with a Kazakhstan bank		—		29,399,585
Note payable secured by drilling rig		—		2,704,759

Total long—term debt		223,407,076		35,688,207
Less current maturities		—		12,005,208

Long-term portion	$	223,407,076	$	23,682,999

Senior Secured Notes

In December 2005, a wholly-owned subsidiary of the Company issued in a private placement an aggregate of 250,000 units (the “Units”) consisting of (1) an aggregate $250 million principal amount of the subsidiary’s senior secured notes due 2010 (the “Notes”) and (2) warrants to purchase in the aggregate approximately 17.3 million shares of the Company’s common stock (the “Warrants”). The Units were issued and sold for a purchase price of $1,000 per Unit. Each Unit consists of $1,000 principal amount of Notes and 69.054 Warrants to purchase an equal number of shares of the Company’s common stock. The Notes, which will mature on December 15, 2010, bear interest at the rate of 12% per annum. Interest on the Notes is payable quarterly on March 15, June 15, September 15 and December 15 of each year, beginning on March 15, 2006, and at maturity. The first year of interest payments have been escrowed and are recorded as restricted cash on the Company’s consolidated balance sheet as of December 31, 2005. The fair value of the warrants of approximately $26,816,000 was recorded as a discount to the face amount of the Notes and will be amortized to interest expense over the life of the Notes.

The Notes are secured by first priority pledges of all the capital stock of Transmeridian Exploration Inc., the issuing wholly-owned subsidiary, and of all of the Company’s other material subsidiaries. In addition, the Notes are fully and unconditionally guaranteed by the Company and all of the Company’s other material subsidiaries. The Notes contain provisions that limit the ability of the Company and its subsidiaries to enter into transactions with affiliates; pay dividends or make other restricted payments; incur debt; create, incur or assume liens; sell assets; and consolidate, merge or transfer all or substantially all of the Company’s assets. The Company is required to offer to repurchase the Notes in connection with certain specified change of control events. The Notes are subject to redemption, in whole or in part, at the option of the Company at any time on or after December 15, 2008 at redemption prices starting at 106% of the principal amount redeemed and declining to 100% by June 15, 2010. Prior to December 15, 2008, the Company may redeem up to 35% of the Notes with proceeds of certain equity offerings at a specified redemption price.

The Company used the proceeds from the offering of the Units of $237.4 million, after expenses, to fund the acquisition of Bramex and to retire the existing bank credit facility indebtedness of Caspi Neft, to repay $22.5 million of convertible promissory notes and to pre-fund the first year of interest payments on the Notes of $30 million.

$20 Million and $30 Million Credit Facilities

Both credit facilities were repaid in full in December 2005 in connection with the acquisition of Bramex by a wholly-owned subsidiary of the Company and the Company’s December 2005 private placement of Units discussed above.

Note Payable Secured by Drilling Rig

In December 2001, the Company purchased a drilling rig for $5.3 million by the issuance, to the seller, of a note payable for $3.3 million and 1.0 million shares of redeemable common stock having a value at that time of $2.0 million. In July 2003, the Company was notified by the holder of an apparent first lien on the rig that the seller was in default under its note payable obligation to the lienholder. The Company was not informed of the existence of the prior lienholder by the seller of the rig. The note payable was in dispute as a result of the seller’s apparent default to the lienholder. The Company held discussions with the lienholder with the intent to resolve the seller’s default by making certain payments directly to the lienholder. The Company made installment payments to the lienholder totaling $688,400 during 2003. However, in December 2003, the Company ceased installment payments to the lienholder as it had not been able to reach a settlement agreement with both the seller and the lienholder. In August 2004, the Company settled its legal dispute with the seller. Pursuant to the terms of the settlement, the remaining balance due on the note of $1.6 million, plus accrued interest of $550,000, was cancelled, and the Company agreed to seek a settlement with the lienholder pursuant to which the Company would assume the obligation of the seller of the rig to the lienholder. Also under the terms of the settlement, the seller returned 200,000 shares to the Company, the remaining 800,000 shares were retained by the seller and such shares are no longer redeemable. In December 2005, the Company settled the remaining outstanding obligation to the lienholder for approximately $1.8 million, plus $120,000 for legal fees. This amount was held in escrow at December 31, 2005 and is recorded as restricted cash on the consolidated balance sheet as of December 31, 2005.

Future maturities of long-term debt, exclusive of discount, at December 31, 2005, are as follows:


	Amount
2006	$	—
2007		—
2008		—
2009		—
2010		250,000,000

Total long-term debt	$	250,000,000

Management believes the fair value of debt at December 31, 2005 approximates its carrying value based on the market interest rate of the debt instrument.

Note 6—Stockholders’ Equity

Series A Convertible Preferred Stock

In November 2004, the Company sold 1,785.714 shares of its Series A Cumulative Convertible Preferred Stock (the “Series A Preferred”) in a private placement at a purchase price of $14,000 per share, and issued warrants to purchase up to 4,464,286 shares of the Company’s common stock at an exercise price equal to $1.55 per share. The aggregate purchase price, net of offering costs, for the Series A Preferred and the related warrants was $22.5 million, which includes the value of warrants attributable to offering cost. The proceeds from the private placement of Series A Preferred and warrants were used for general corporate purposes, including funding the Company’s development drilling program in the South Alibek Field, and to pursue growth opportunities.

The Series A Preferred has a liquidation value of $14,000 per share and is convertible at the holders’ option into common stock at a conversion price of $1.40 per share, subject to adjustments in certain circumstances. The holders of the Series A Preferred are entitled to a quarterly dividend payable at the rate of 4.5% per annum, payable in cash. The holders of the Series A Preferred have full voting rights and powers (subject to a beneficial ownership cap as described below) equal to the voting rights and powers of the holders of the Company’s common stock, and vote together with the holders of common stock as one class. A holder of the Series A Preferred may not, unless it chooses in advance not to be governed by this limitation, convert the Series A Preferred or exercise the warrants into common stock such that the number of shares of common stock issued after the conversion would exceed, when aggregated with all other shares of common stock owned by such holder at such time, 4.999% of the then issued and outstanding shares of the Company’s common stock. So long as at least 20% of the Series A Preferred remains outstanding, the Company is not permitted to issue any new securities or financial instruments that rank pari passu or senior to the Series A Preferred without the approval of at least 75% of the Series A Preferred outstanding. In July 2006, the Series A Preferred automatically converts into the common stock of the Company at the conversion price of $1.40 per share (subject to adjustments), if the common stock trades at a price equal to or greater than $4.15 per share for twenty consecutive trading days and the average daily trading volume of the Company’s common stock during such period exceeds 200,000 shares, subject to the applicable ownership limitations. In the event a holder is prohibited from converting into common stock due to the 4.999% ownership limitation, the excess portion of the Series A Preferred remains outstanding, but ceases to accrue a dividend. During 2005, 238 shares of Series A Preferred stock were converted into 2,380,000 shares of the Company’s common stock. The Company has accrued $2.3 million for costs associated with the delayed effectiveness of the required registration statement for the conversion shares.

Common Stock Reserved for Issuance

There are 200,000,000 common shares authorized by the Company’s Amended and Restated Certificate of Incorporation and 87,128,021, 79,829,062, and 70,673,207 common shares were issued and outstanding as of December 31, 2005, 2004 and 2003, respectively. Shares of common stock reserved for issuance are summarized as follows:


	December 31,
	2005	2004
2001 Incentive Stock Option Plan	1,365,000	2,955,000
2003 Stock Compensation Plan	1,813,021	706,673
Convertible preferred stock	15,477,140	17,857,140
Warrants to purchase common stock	26,565,285	6,138,393

Total	45,220,446	27,657,206

Warrants

In connection with certain 2005 short-term borrowings from individuals, the Company issued detachable warrants to purchase 420,000 shares of common stock at exercise prices ranging from $2.00 to $2.12 per share. The warrants have a three-year term.

In connection with the Convertible Notes issued in August 2005, the Company issued detachable warrants to purchase 4,500,000 shares of the Company’s common stock at an exercise price equal to $2.40 per share. The warrants have a five-year term, and beginning six months after the closing of the issuance of the Convertible Notes, the exercise price of the warrants is subject to adjustment for issuances of common stock at a purchase price of less than the then-effective exercise price of the warrants.

The warrants issued in December 2005 as part of the Units entitle the holder to purchase one share of the Company’s common stock at an exercise price of $4.27 per share; pursuant to the warrant agreement, the exercise price of the warrants was adjusted from the initial exercise price of $4.31 per share to $4.27 per share as a result of the issuance of 1,000,000 shares of the Company’s common stock to Kornerstone in connection with the acquisition of Kornerstone’s carried working interest in the South Alibek Field discussed in Note 2. The warrant agreement contains anti-dilution provisions and the exercise price of the warrants will be adjusted upon the conversion of any shares of the Company’s outstanding Series A Preferred. The warrants will be exercisable at any time on or after the earlier of (i) December 12, 2006 or (ii) the date a registration statement covering the issuance of the warrant shares upon exercise of the warrants and resales of the warrants and the warrant shares becomes effective, subject to the accelerated exercisability exceptions with respect to dividend declarations and certain corporate events described in the warrant agreement. The warrants will expire on December 15, 2010.

2001 Incentive Stock Option Plan

The Company has a 2001 Incentive Stock Option Plan (the “Plan”) under which options to purchase 5.0 million shares of common stock may be granted to officers, board members, key employees and consultants through December 31, 2010. Under the Plan, the exercise price of each option is equal to the fair market value of the Company’s common stock on the date of grant and all options granted have a term of five years. The vesting period is determined by the Board of Directors at the date of grant.

No stock options were granted under the Plan prior to 2003. The following table summarizes activity under the Plan for the last three years.


	Number of Shares (In thousands)		Weighted Average Exercise Price Per Share
Outstanding at December 31, 2002	—		$	—
Granted	1,740			0.25
Exercised	—			—
Forfeited	—			—

Outstanding at December 31, 2003	1,740			0.25
Granted	555			1.50
Exercised	(650	)		0.23
Forfeited	(250	)		0.22

Outstanding at December 31, 2004	1,395			0.78
Granted	1,740			1.61
Exercised	(705	)		0.31
Forfeited	(150	)		0.12

Outstanding at December 31, 2005	2,280		$	1.53

Shares exercisable at December 31
2005	833		$	1.41
2004	790		$	0.27
2003	75		$	0.24

The aggregate fair value of options granted during 2005, 2004 and 2003 was $969,900, $355,200 and $212,700, respectively, which is being amortized to expense over the vesting period in accordance with SFAS No. 123. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions: risk-free interest rates of 5%; expected lives between 1.5 and 2.5 years; and volatility of the price of the underlying common stock of 45-75%. Compensation expense of $400,920, $105,997 and $117,383 was recognized during the years ended December 31, 2005, 2004 and 2003, respectively.

The following table summarizes additional information about the Company’s stock options outstanding exercisable at December 31, 2005:


	Outstanding				Exercisable
Exercise Price	Number Outstanding (In thousands)	Weighted Average Remaining Life (In Years)	Weighted Average Exercise Price		Number Outstanding (In thousands)	Weighted Average Exercise Price
$0.24	100	2.36	$	0.24	100	$	0.24
$0.57	10	2.96		0.57	10		0.57
$1.50	430	3.88		1.50	143		1.50
$1.61	1,740	4.38		1.61	580		1.61

Total at December 31, 2005	2,280	4.19	$	1.53	833	$	1.41

2003 Stock Compensation Plan

In May 2003, the Company established its 2003 Stock Compensation Plan with the registration of 2.5 million shares under the plan. The plan was amended in May 2005 to increase the number of shares authorized for issuance to a total of 5,000,000 shares. Under the terms of the plan, such stock may be issued for

restricted stock awards; payments of bonuses in stock; payments for services to consultants in the form of stock; employer contributions to a 401(k) plan; stock appreciation rights and warrants. Any shares issued in lieu of cash are recognized as expense based on the fair value of the shares on the date of grant. The fair value of restricted stock awards on the date of grant is amortized ratably over the vesting period. The following table summarizes the shares issued during the years ended December 31:


	2005		2004		2003
Number of shares issued		1,357,216		600,000		1,234,047
Fair value at date of grant	$	2,800,549	$	750,000	$	283,625

Note 7—Income Taxes

The Company provides for deferred taxes on temporary differences between the financial statements and tax basis of assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse. The Company has not recorded any deferred tax assets or income tax benefits from the net deferred tax assets for the years ended December 31, 2005, 2004 and 2003. The Company has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.

Income before income taxes is composed of the following:


	Year ended December 31,
	2005			2004			2003
United States	$	(16,508,000	)	$	(3,185,000	)	$	(2,940,000	)
International		(4,033,000	)		(817,000	)		(2,767,000	)

	$	(20,541,000	)	$	(4,002,000	)	$	(5,707,000	)

A reconciliation of the federal statutory income tax (34%) amounts to the effective amounts is shown below:


	Year ended December 31,
	2005			2004			2003
Income tax benefit computed at statutory rates	$	(6,983,000	)	$	(1,361,000	)	$	(1,940,000	)
Effect of foreign tax rate differential		885,000			—			—
Return to provision adjustments		(5,510,000	)		—			—
Other		294,000			—			—
Adjustment to valuation allowance		11,314,000			1,361,000			1,940,000

	$	—		$	—		$	—

At December 31, 2005, 2004 and 2003 the components of the Company’s deferred tax assets and liabilities were as follows:


	December 31,
	2005			2004			2003
Current deferred tax assets
Cost basis of assets held for sale	$	1,367,000		$	—		$	—
Accrual to cash adjustments in foreign subsidiary		1,239,000			—			—

Total current deferred tax assets		2,606,000			—			—

Noncurrent deferred tax assets
Domestic net operating loss carryforwards		7,999,000			5,614,000			2,100,000
Foreign net operating loss carryforwards		—			3,183,000			3,766,000
Foreign oil and gas exploration and development costs		6,542,000			—			—
Other		128,000			—			—

Total noncurrent deferred tax assets		14,669,000			8,797,000			5,866,000

Total deferred tax assets	$	17,275,000		$	8,797,000		$	5,866,000
Noncurrent deferred tax liabilities
Domestic property, plant, and equipment	$	(458,000	)	$	—		$	—
Foreign capitalized interest		—			(3,390,000	)		(1,853,000	)
Other		(95,000	)		—			—

Total noncurrent deferred tax liabilities		(553,000	)		(3,390,000	)		(1,853,000	)

Net deferred tax assets		16,722,000			5,407,000			4,013,000
Valuation allowance		(16,722,000	)		(5,407,000	)		(4,013,000	)

	$	—		$	—		$	—

As of December 31, 2005, the Company has estimated domestic net operating loss carryforwards of $24.6 million which will expire between 2020 and 2025. There are no foreign net operating loss carryforwards.

The change in valuation allowance is as follows:


	Year Ended December 31,
	2005		2004		2003
Balance at the beginning of the period	$	5,407,000	$	4,013,000	$	2,106,000
Current year addition		5,805,000		1,394,000		1,997,000
Return to provision adjustments		5,510,000		—		—

Balance at the end of the period	$	16,722,000	$	5,407,000	$	4,013,000

Note 8—Commitments and Contingencies

Drilling Rig Dispute

In December 2001, the Company purchased a land drilling rig for total consideration of $5.3 million, including a note payable for $3.3 million and the issuance of $2.0 million in redeemable common stock. The

Company was not informed that the rig was subject to a lien in favor of a prior owner of the rig. Beginning in December 2003, the seller, the Company and the lienholder engaged in litigation to determine the parties’ rights and obligations with respect to the rig, the lien and payments due the seller and the lienholder. In August 2004, the Company and the seller of the rig entered into a settlement and release agreement, pursuant to which the remaining balance on the note of $1.6 million, plus accrued interest of $550,000 was cancelled, and the Company agreed to endeavor to negotiate a settlement with the lienholder pursuant to which the Company would assume the obligation of the seller of the rig to the lienholder. In December 2005, the parties engaged in a court-supervised mediation at which they agreed to settle all outstanding claims against one another. Pursuant to the settlement agreement, which was signed in February 2006, the Company paid approximately $1.8 million to the first lienholder to settle the remaining payment obligations to the lienholder, plus $120,000 for legal fees.

Former Chief Financial Officer

In May 2003, Jim W. Tucker, a former chief financial officer of the Company, filed suit in state district court in Texas against the Company in connection with his separation from service in January 2003. The suit alleged breach of an oral employment agreement. The Company took a default judgment in November 2003 in the amount of $0.9 million. In February 2005, the court granted our motion to vacate the default judgment. The plaintiff subsequently passed away in July 2005. The case may still be reinstated by the deceased’s estate prior to April 2007, and would begin as if the Company had just been served notice. The Company believes it has meritorious defenses to the allegations against it and intends to vigorously contest this matter and pursue all available legal remedies; however, the Company believes the chances that plaintiff’s estate will refile the suit to be remote.

International Commitments

The Company, through its subsidiary Caspi Neft, is subject to the terms of License 1557 and the related exploration contract covering 14,111 acres in the South Alibek Field in Kazakhstan. In connection with the exploration contract, the Company has committed to spend approximately $18.0 million on development of the Field through 2005. As of December 31, 2005, the cumulative capital expenditures which are creditable to our obligation under the Contract have exceeded the minimum contract commitment. In connection with the two-year extension granted on July 8, 2004, the Company committed to spend approximately $30.5 million from 2005 to 2007.

Purchase commitments are made in the ordinary course of business in connection with ongoing operations in the South Alibek Field.

Our operations are subject to various levels of government controls and regulations in the United States and in the Republic of Kazakhstan. 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 the Republic of 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 on the industry by increasing the cost of doing business and, consequentially, can adversely affect our profitability. 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.

Environmental

The Company, as an owner and operator of oil and gas properties, is subject to various federal, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of, the

environment. These laws and regulations may impose liability on the lessee under an oil and gas lease or concession for the cost of pollution clean-up resulting from operations and also may subject the lessee to liability for pollution damages.

Lease Commitments

The Company has operating leases for office facilities and certain equipment. Net rental expense under all operating leases and rental agreements was $570,086, $546,639 and $930,698 in 2005, 2004 and 2003, respectively. The Company leases office facilities in Houston and Kazakhstan under leases greater than one year. Future minimum lease commitments under operating leases are as follows:


	Amount
2006	$	273,324
2007		76,216
2008		—
2009		—
Thereafter		—

	$	349,540

Note 9—Business Segment Information

The Company’s business activities relate solely to oil and gas exploration, development and production. The primary emphasis since its formation in 2000 has been the development of the South Alibek Field and substantially all of the Company’s assets are located in Kazakhstan. For each of the three years ended December 31, 2005 substantially all of the Company’s results of operations consisted of revenues, operating, general and administrative, and other costs associated with its operations in Kazakhstan.

For the year ended December 31, 2005, two customers accounted for approximately 38% and 37%, respectively, of consolidated revenues. For the year ended December 31, 2004, two customers accounted for approximately 57% and 28%, respectively, of consolidated revenues. One customer accounted for 100% of consolidated revenues for the year ended December 31, 2003.

Note 10—Supplemental Financial Information

Other Assets

Other assets at December 31, 2005 and 2004, consisted of debt financing costs, net of amortization, of $12,473,536 and $216,111, respectively.

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities consisted of the following:


	December 31,
	2005		2004
Accounts payable	$	419,456	$	152,158
Salaries and bonus		1,032,357		12,458
Preferred stock registration costs		2,035,000		—
Acquisition costs		21,450,000		—
Rig lawsuit settlement		1,960,491		446,482
Rig rentals		2,737,722		1,446,587
Oil and gas properties costs		1,826,554		3,893,727
Other		407,863		1,185,604

Total accounts payable and accrued liabilities	$	31,869,443	$	7,137,016

Note 11—Subsidiary Guarantors

In December 2005, Transmeridian Exploration Inc., a wholly-owned subsidiary of the Company (the “Issuer”), issued an aggregate of 250,000 Units, consisting of (i) an aggregate $250 million principal amount of senior its secured notes due 2010 and (ii) warrants to purchase approximately 17.3 million shares of the Company’s common stock. The Company and all material subsidiaries of the Company fully and unconditionally guaranteed the senior secured notes. Prior to the Units offering, the Company financed its operations primarily through borrowings from banks in Kazakhstan or other private sources. As previously disclosed in 2005 and prior years, substantially all of the Company’s assets are located in Kazakhstan. For each of the three years ended December 31, 2005, substantially all of the results of operations consisted of revenue, operating, general and administrative and other costs associated with the operations of its subsidiary, Caspi Neft, in Kazakhstan. Accordingly, there was no requirement for condensed consolidating financial information and the results for 2004 and 2003 are not presented herein due to lack of comparability and the information is not material for evaluation of the sufficiency of the guarantee and the omission of the information does not cause the financials to be inaccurate in reasonable detail.

The following is condensed consolidating financial information for the Company, the Issuer and the subsidiary guarantors of the senior secured notes:

Condensed Consolidating Balance Sheet


	December 31, 2005
	Parent		Issuer			Subsidiary Guarantors		Eliminations			Consolidated
Cash and cash equivalents	$	21,147,921	$	45,250,000		$	6,027	$	—		$	66,403,948
Other current assets		2,764,674		—			5,535,923		—			8,300,597

Total current assets		23,912,595		45,250,000			5,541,950		—			74,704,545
Property and equipment, net		305,657		—			226,509,692		—			226,815,349
Investment in and advances to subsidiaries		100		9,082,519			—		(9,082,619	)		—
Other assets		—		32,973,536			—		(20,500,000	)		12,473,536

Total Assets	$	24,218,352	$	87,306,055		$	232,051,642	$	(29,582,619	)	$	313,993,430

Total current liabilities	$	5,759,807	$	23,328,142		$	4,608,830	$	—		$	33,696,779
Debt		—		223,407,076			31,000,000		(31,000,000	)		223,407,076
Other long-term liabilities		—		—			186,000		—			186,000
Stockholder’s equity		18,458,545		(159,429,163	)		196,256,812		1,417,381			56,703,575

Total Liabilities	$	24,218,352	$	87,306,055		$	232,051,642	$	(29,582,619	)	$	313,993,430

Condensed Consolidating Statements of Operations


	Year Ended December 31, 2005
	Parent			Issuer			Subsidiary Guarantors			Consolidated
Revenue	$	—		$	—		$	8,442,787		$	8,442,787
Operating costs and expenses		11,099,038			—			7,166,475			18,265,513

Operating income (loss)		(11,099,038	)		—			1,276,312			(9,822,726	)
Other expense		(5,408,632	)		(2,411,623	)		(2,186,147	)		(10,006,402	)
Minority interest expense		—			—			(711,558	)		(711,558	)

Net loss		(16,507,670	)		(2,411,623	)		(1,621,393	)		(20,540,686	)
Preferred dividends		(1,081,034	)		—			—			(1,081,034	)

Net loss attributable to common stockholders	$	(17,588,704	)	$	(2,411,623	)	$	(1,621,393	)	$	(21,621,720	)

Condensed Consolidating Statements of Cash Flow


	Year Ended December 31, 2005
	Parent			Issuer		Subsidiary Guarantors			Consolidated
Net cash used in operating activities	$	(4,371,558	)	$	1,456,366	$	(8,435,988	)	$	(11,351,180	)
Net cash used in investing activities		(17,322	)		—		(144,685,799	)		(144,703,121	)
Net cash provided by financing activities		12,916,826			13,793,634		147,041,161			173,751,621

Net increase (decrease) in cash		8,527,946			15,250,000		(6,080,626	)		17,697,320
Cash and cash equivalents, beginning of the year		10,659,484			—		6,086,653			16,746,137

Cash and cash equivalents, end of the year	$	19,187,430		$	15,250,000	$	6,027		$	34,443,457

Note 12—Supplemental Oil and Gas Disclosures

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities, whether expensed or capitalized, are reflected in the table below. This schedule does not include the costs of acquiring the minority interest in Caspi Neft and the carried working interest of approximately $138,314,000 or the costs of the drilling rig which was purchased and modified for use in the Company’s development activities in Kazakhstan. Costs incurred for the drilling rig were $444,000 in 2003.


	Kazakhstan		United States		Total
Year ended December 31, 2005
Acquisition costs of properties:
Proved	$	—	$	—	$	—
Unproved		—		—		—
Exploration costs		9,470		—		9,470
Development costs		24,599,684		—		24,599,684
Capitalized interest		2,497,923		—		2,497,923

Total	$	27,107,077	$	—	$	27,107,077

Year ended December 31, 2004
Acquisition costs of properties:
Proved	$	—	$	—	$	—
Unproved		—		—		—
Exploration costs		3,477,336		—		3,477,336
Development costs		18,651,179		—		18,651,179
Capitalized interest		4,519,759		—		4,519,759

Total	$	26,648,274	$	—	$	26,648,274

Year ended December 31, 2003:
Acquisition costs of properties:
Proved	$	—	$	—	$	—
Unproved		—		—		—
Exploration costs		26,292,534		118,893		26,411,427
Development costs		56,255		—		56,256
Capitalized interest		4,164,694		—		4,164,693

Total	$	30,513,483	$	118,893	$	30,632,376

Capitalized Costs

The aggregate amount of capitalized costs related to oil and gas producing activities and the aggregate amount of the related accumulated depreciation, depletion and amortization (“DD&A”), including any accumulated valuation allowances, are reflected in the table below. These capitalized costs do not include the drilling rig which was purchased and modified for use in the Company’s development activities in Kazakhstan. Capitalized costs for the drilling rig were $3.0 million, $8.5 million and $6.5 million at December 31, 2005, 2004 and 2003, respectively.


	Kazakhstan		United States		Total
As of December 31, 2005
Proved properties	$	62,876,028	$	—	$	62,876,028
Unproved properties		167,263,366		—		167,263,366

Total oil and gas properties		230,139,394		—		230,139,394
Accumulated DD&A		3,471,351		—		3,471,351

Net oil and gas properties	$	226,668,043	$	—	$	226,668,043

As of December 31, 2004
Proved properties	$	39,487,758	$	—	$	39,487,758
Unproved properties		31,560,816		—		31,560,816

Total oil and gas properties		71,048,574		—		71,048,574
Accumulated DD&A		899,131		—		899,131

Net oil and gas properties	$	70,149,443	$	—	$	70,149,443

As of December 31, 2003
Proved properties	$	16,300,263	$	—	$	16,300,263
Unproved properties		32,483,389		16,604		32,499,993

Total oil and gas properties		48,783,652		16,604		48,800,256
Accumulated DD&A		189,635		—		189,635

Net oil and gas properties	$	48,594,017	$	16,604	$	48,610,621

Oil and Gas Reserve Information (Unaudited)

Basis of Presentation

Proved oil and gas reserve quantities are based on estimates prepared by Ryder Scott Company, independent petroleum engineers. There are numerous uncertainties in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. These uncertainties are greater for properties which are undeveloped or have a limited production history, such as the South Alibek Field. The following reserve data represents estimates only and actual reserves may vary substantially from these estimates. All of the Company’s proved reserves were in Kazakhstan as of December 31, 2005, 2004 and 2003. The Company’s net quantities of proved developed and undeveloped reserves of crude oil and changes therein are reflected in the table below.

As of December 31, 2005, the Company owned a 100% working interest in the South Alibek Field, subject to government royalties and an additional 3.5% net revenue interest retained by a third party in connection with the Company’s buyout of its former partners to be deducted from the remaining revenue interest. The effect of this overriding revenue interest is reflected in the calculation of the Company’s net proved reserves and future net cash flows.

As of December 31, 2005, the Company is operating under an exploration contract, which was extended by the government of Kazakhstan in July 2004 for two years ending on April 2007. Final terms for the South Alibek

production contract have been agreed to and the contract is waiting on final approval from the Kazakhstan government. The Company’s oil and gas reserve data and future net cash flows have been prepared assuming a commercial production contract is obtained, beginning on January 1, 2006, which will allow production for the expected 25 year term of the production contract and utilizes all the terms and costs associated with the production contract. Net revenue interest used in the report are calculated from a sliding-scale royalty payment to the Kazakhstan government during the production contract life. Based on the forecast annual production, the government royalty rate is between 2.0% to 2.2%. Royalty rate is capped at 5%.

The proved reserves as of December 31, 2005 represent the reserves that were estimated to be recovered from eight wells (South Alibek 1, 2, 3, 4, 5, 14, 15 and 17), and a total of seventeen development offsets not yet drilled. All reserves were estimated using either historical performance or volumetric methods. All direct offset well locations in this report are proved undeveloped and are based on 80 acre drainage patterns, unless current developed completions are estimated to drain an area larger than their volumetric assignment, and in these cases the reserves of certain offset locations have been reduced. All locations have a scheduled KT1 and a KT2 reservoir completion and each of these reservoir completions includes the cost of drilling a separate wellbore. Based on the separate development program for the KT1 and KT2 reservoirs, reserves assigned to the KT1 reservoir are undeveloped whereas in previous year-end estimates these reserves were developed. The associated additional costs required for a separate KT1 reservoir development program has also been included in the reserves estimate. The total primary and secondary recovery of 30% was based on analogy data from other fields. A 15% primary recovery factor was assigned to each developed and undeveloped well in the KT1 and KT2 reservoirs. A secondary recovery factor of 15% was assigned to the KT1 reservoir and to the KT2 reservoir. Based on separate primary and secondary recoveries, reserves assigned to the secondary recoveries are undeveloped whereas in previous year-end estimates these reserves were developed. The associated additional capital and operating costs required for a separate KT1 and KT2 reservoir water flood program has also been included in the reserves estimate, requiring the drilling of 25 injector wells in the KT1 reservoir and 25 injector wells in the KT2 reservoir and related surface facilities to support these programs. As of December 31, 2005, the Company had three new wells, the SA-3, SA-14, and SA-15, which have reserves assigned as behind-pipe and are forecast to start producing in the first quarter of 2006 from the KT2 reservoir. The Ryder Scott reserve estimate as of December 31, 2005 included these three wells and SA-1, SA-2, SA-5 and SA-17 as proved developed in the KT2 reservoir. SA-1 was shut-in during a workover program. The completion in SA-5 may have been damaged during a previous work-over and an undeveloped redrill has been included in the estimates to capture the volumetric reserves assigned to this location. SA-4, which has reservoir damage that prevented placing the well on production during 2005 and sixteen additional offset locations are also proved undeveloped in the KT2 reservoir.

Estimated Quantities of Net Proved Crude Oil Reserves

(Quantities in Barrels)


	December 31,
	2005		2004		2003
Net proved crude oil reserves:
Beginning of year	26,813,736		45,744,788		17,110,741
Revisions of previous estimates	(322,972	)	(521,118	)	(5,079,386	)
Extensions, discoveries and other additions	6,096,959		6,827,529		33,830,809
Revision of net interest	41,194,007		(25,085,729	)
Production	(845,108	)	(151,734	)	(117,376	)

End of year	72,936,622		26,813,736		45,744,788

Net proved developed reserves:
Beginning of year	4,476,364		7,815,861		5,695,613

End of year	3,331,580		4,476,364		7,815,861

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

Basis of Presentation

The standardized measure data includes estimates of oil and gas reserve volumes and forecasts of future production rates over the reserve lives. Estimates of future production expenditures, including taxes and future development costs, are based on management’s best estimate of such costs assuming a continuation of current economic and operating conditions. No provision is included for depletion, depreciation and amortization of property acquisition costs or indirect costs. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. The sales prices used in the calculation are the year-end prices of crude oil, including condensate and natural gas liquids, which as of December 31, 2005, 2004 and 2003 were $40.21, $20.09 and $12.44 per barrel, respectively. The sales prices were based on the last sales price received for December 2005, 2004 and 2003, respectively. No value was assigned to natural gas reserves, as there is not currently an established market or pipeline facilities for gas sales. 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. This information is not intended to represent a forecast or fair market value of the Company’s oil and gas assets, but does present a standardized disclosure of discounted future net cash flows that would result under the assumptions used. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves for 2005, 2004 and 2003 were as follows:

Standardized Measure of Discounted Future Net Cash Flows

(Amounts in Thousands)


December 31, 2005:
Future cash inflows	$	3,096,160
Future production costs		(406,539	)
Future development costs		(397,879	)

Undiscounted future net cash flows before income tax		2,291,742
10% discount for estimated timing of cash flows		(1,276,314	)

Present value of future net cash flows before income tax		1,015,428
Future income tax expense, discounted at 10%		(268,447	)

Standardized measure of discounted future net cash flows	$	746,981

December 31, 2004:
Future cash inflows	$	538,688
Future production costs		(74,001	)
Future development costs		(65,260	)

Undiscounted future net cash flows before income tax		399,427
10% discount for estimated timing of cash flows		(179,431	)

Present value of future net cash flows before income tax		219,996
Future income tax expense, discounted at 10%		(43,142	)

Standardized measure of discounted future net cash flows	$	176,854

December 31, 2003:
Future cash inflows	$	569,065
Future production costs		(74,723	)
Future development costs		(76,373	)

Undiscounted future net cash flows before income tax		417,969
10% discount for estimated timing of cash flows		(176,618	)

Present value of future net cash flows before income tax		241,351
Future income tax expense, discounted at 10%		(60,908	)

Standardized measure of discounted future net cash flows	$	180,443

The following table presents a reconciliation of changes in the standardized measure of discounted future net cash flows:

Changes in the Standardized Measure of Discounted Future Net Cash Flows

(Amounts in Thousands)


	Year ended December 31,
	2005			2004			2003
Standardized Measure, beginning of year	$	176,854		$	180,443		$	143,999
Sales and transfers of oil and gas produced, net of production costs		(324	)		(152	)		(397	)
Net changes in prices, development and production costs		320,930			151,644			(107,366	)
Extensions, discoveries and improved recovery, less related costs		596,505			65,492			171,513
Purchase of minerals in place		—			—			—
Development costs incurred and changes during the period		(213,411	)		17,754			(2,887	)
Revisions of previous quantity estimates		(6,948	)		(4,458	)		(30,436	)
Increase in present value due to passage of one year		21,999			24,135			20,431
Exercise of Option by Bramex		—			(203,699	)		—
Net changes in production rates and other		225,304			(36,563	)		(13,824	)
Net change in income taxes		(373,928	)		(17,742	)		(590	)

Standardized Measure, end of year	$	746,981		$	176,854		$	180,443

Note 13—Supplemental Quarterly Information (Unaudited)

The following table reflects a summary of the unaudited interim results of operations for the quarterly periods in the years ended December 31, 2005 and 2004.


	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2005
Revenue	$	1,153,739		$	2,032,310		$	3,852,122		$	1,404,616
Operating expenses		2,858,923			2,286,599			3,270,940			9,849,051
Minority interest		507,818			(355,896	)		(791,171	)		(72,309	)
Preferred dividends		277,397			280,479			279,155			244,003

Net loss attributable to common shareholders		(2,129,546	)		(1,930,106	)		(2,802,111	)		(14,759,957	)

Basic and diluted loss per share	$	(0.03	)	$	(0.02	)	$	(0.03	)	$	(0.17	)

Weighted average common shares outstanding		79,993,732			80,213,343			81,561,819			86,179,295

2004
Revenue	$	642,927		$	1,562,656		$	843,348		$	874,059
Operating expenses		1,463,781			2,235,200			1,735,301			1,793,957
Minority interest		207,379			(117,481	)		401,802			331,353
Preferred dividends		—			—			—			154,110

Net loss attributable to common shareholders		(1,028,233	)		(555,063	)		(1,293,755	)		(1,125,240	)

Basic and diluted loss per share	$	(0.01	)	$	(0.01	)	$	(0.02	)	$	(0.01	)

Weighted average common shares outstanding		77,382,894			78,208,663			79,153,647			79,685,312

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Corporate Disclosure Controls

Evaluation of Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our internal controls over financial reporting pursuant to Rule 13a-15 under the Securities Exchange Act of 1934 as of the end of the period covered by this annual report. In the course of this evaluation, our management considered the material weakness in our internal control over financial reporting discussed below. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as a result of the material weakness discussed below, our disclosure controls and procedures as of December 31, 2005 were not effective in ensuring that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. To address the material weakness, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this annual report have been prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

Management’s Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as that term is defined in Exchange Act Rule 13a-15(f). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of our Code of Business Conduct and Ethics and our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer, which sets the tone of our company. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.

In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2005, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management conducted an assessment, including testing, based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Framework”). Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, 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.

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting and, based on that assessment, identified a material weakness. A material weakness is a

control deficiency, or a combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of our annual or interim financial statements will not be prevented or detected. The material weakness was our lack of a sufficient number of accounting staff with experience in public company SEC reporting and technical expertise to enable us to maintain adequate controls over our financial accounting and reporting processes regarding the accounting for non-routine and non-systematic transactions. This control deficiency resulted in us recording certain adjustments prior to the issuance of our consolidated financial statements.

Changes in Internal Controls

To address the issues associated with the material weakness, management has been implementing and will continue to implement changes that are both organizational and process-focused to improve the control environment. The changes made since late 2005 and through the date of this annual report include, among others:

•

we appointed a new Vice President and Chief Accounting Officer, effective September 2005;

•

we appointed a new Vice President, General Counsel and Secretary in January 2006;

•

we retained an outside consulting firm to assist us in the evaluation and testing of our internal control system and to identify improvement opportunities related to our accounting and financial reporting processes in order to streamline and improve the efficiency of these processes; and

•

we retained an outside accounting firm to assist us in the preparation of complex tax calculations and disclosures related to our public filings and to prepare tax records and returns.

These organizational and process changes have improved our internal controls environment and increased the likelihood of our identifying non-routine and non-systematic transactions. We will continue our efforts to improve our control environment and to focus on:

•

improving our organizational structure to help achieve the proper number of, and quality of our, accounting and finance personnel;

•

refining our period-end financial reporting processes to improve the quality and timeliness of our financial information; and

•

improving our processes and systems to help ensure that our financial reporting, operational and business requirements are met in a timely manner;

UHY Mann Frankfort Stein & Lipp CPAs, LLP has issued an audit report on our management’s assessment of our internal control over financial reporting as of December 31, 2005 that follows.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Transmeridian Exploration Incorporated and Subsidiaries

Houston, Texas

We have audited management’s assessment, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting appearing in Item 9A, that Transmeridian Exploration Incorporated and subsidiaries ( “ the Company”) did not maintain effective internal control over financial reporting as of December 31, 2005, because of the effect of the material weakness identified in management’s assessment and described below, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with 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 (3) 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 may not prevent or detect misstatements. 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.

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be

prevented or detected. A material weakness was identified and included in management’s assessment, related to inadequate controls over the financial accounting and reporting process regarding the accounting for non-routine type transactions and activities. The Company’s lack of adequate accounting resources, in terms of size and technical expertise, was the underlying cause of this material weakness. As a result of this material weakness, the Company recorded certain adjustments prior to the issuance of its consolidated financial statements. Additionally, this material weakness could result in a material misstatement to the Company’s annual or interim consolidated financial statements that would not be prevented or detected. This material weakness was considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2005 consolidated financial statements, and this report does not affect our report dated March 16, 2006 on those consolidated financial statements.

In our opinion, management’s assessment that Transmeridian Exploration Incorporated and subsidiaries did not maintain effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by COSO. Also, in our opinion, because of the effect of the material weakness described above on the achievement of the objectives of the control criteria, Transmeridian Exploration Incorporated and subsidiaries has not maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Transmeridian Exploration Incorporated and subsidiaries as of December 31, 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for the year then ended, and our report dated March 16, 2006 expressed an unqualified opinion on those consolidated financial statements.

/s/ UHY MANN FRANKFORT STEIN & LIPP CPAs, LLP

Houston, Texas

March 16, 2006

Item 9B.

Other Information

None.

PART III

Item 10.

Directors and Executive Officers of the Registrant.

The information required by Item 10 regarding our executive officers appears in a separately captioned heading after Item 4 in Part I of this report. The other information required by Item 10 is incorporated by reference to our definitive proxy statement relating to our 2006 annual meeting of stockholders, which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.

Item 11.

Executive Compensation

The 2006 Proxy Statement is hereby incorporated by reference for the purpose of providing information about executive compensation.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The 2006 Proxy Statement is hereby incorporated by reference for the purpose of providing information about security ownership of certain beneficial owners and management and related stockholder matters.

Item 13.

Certain Relationships and Related Transactions

The 2006 Proxy Statement is hereby incorporated by reference for the purpose of providing information about certain relationships and related transactions.

Item 14.

Principal Accounting Fees and Services

The 2006 Proxy Statement is hereby incorporated by reference for the purpose of providing information about principal accounting fees and services.

PART IV

Item 15.

Exhibits, Financial Statement Schedules

(a)(1) Financial Statements. Reference is made to the Index to Consolidated Financial Statements appearing under Item 8 hereof.

(a)(2), (c) Financial Statement Schedules. All financial statement schedules are omitted because they are not required under the related instructions, are inapplicable or the required information has been included in the consolidated financial statements or the accompanying notes to consolidated financial statements appearing under Item 8 hereof.

(a)(3), (b) Exhibits. Reference is made to the Exhibit Index beginning on page E-1 hereof.

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 on its behalf by the undersigned, thereunto duly authorized.


TRANSMERIDIAN EXPLORATION INCORPORATED

/S/ LORRIE T. OLIVIER
Lorrie T. Olivier Chairman of the Board, President and Chief Executive Officer

Date: March 16, 2006

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 dates indicated.


Signature	Title	Date

/S/ LORRIE T. OLIVIER Lorrie T. Olivier	Chairman of the Board, President and Chief Executive Officer (Principal Executive Officer)	March 16, 2006

/S/ EARL W. MCNIEL Earl W. McNiel	Vice President and Chief Financial Officer (Principal Financial Officer)	March 16, 2006

/S/ EDWARD G. BRANTLEY Edward G. Brantley	Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 16, 2006

/S/ MARVIN R. CARTER Marvin R. Carter	Director	March 16, 2006

/S/ JAMES H. DORMAN James H. Dorman	Director	March 16, 2006

/S/ PHILIP J. MCCAULEY Philip J. McCauley	Director	March 16, 2006

/S/ GEORGE E. REESE George E. Reese	Director	March 16, 2006

/S/ DR. FERNANDO J. ZÚÑIGA Y RIVERO Dr. Fernando J. Zúñiga y Rivero	Director	March 16, 2006

S-1

EXHIBIT INDEX


Exhibit Number		Description
3.1		Amended and Restated Certificate of Incorporation (filed as Exhibit 3.1(b) to the Company’s Registration Statement on Form SB-2 filed with the Commission as of March 15, 2001 and incorporated by reference herein)

3.2		Bylaws (filed as Exhibit 3.2 to the Company’s Registration Statement on Form SB-2 filed with the Commission as of March 15, 2001 and incorporated by reference herein)

3.3		Certificate of Designations, Rights and Preferences of Series A Cumulative Convertible Preferred Stock (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K dated November 12, 2004 and filed with the Commission on November 15, 2004 and incorporated by reference herein)

4.1		Indenture, dated as of December 12, 2005, by and among the Company, Transmeridian Exploration Inc., TMEI Operating, Inc., Transmeridian (Kazakhstan) Incorporated and The Bank of New York, as Trustee (filed as Exhibit 4.1 to the Company’s Current Report on Form 8-K dated December 16, 2005 and incorporated by reference herein)

4.2		First Supplemental Indenture, dated as of December 22, 2005, by and among the Company, Transmeridian Exploration Inc., TMEI Operating, Inc., Transmeridian (Kazakhstan) Incorporated, JSC Caspi Neft TME, Bramex Management, Inc. and The Bank of New York, as Trustee (filed as Exhibit 4.5 to the Company’s Registration Statement on Form S-3 filed with the Commission on March 13, 2006 and incorporated by reference herein)

4.3		Form of Senior Secured Note due 2010 (included as part of Exhibit 4.1)

4.4		Form of Registration Rights Agreement, dated as of December 12, 2005, by and among the Company, Transmeridian Exploration Inc., TMEI Operating, Inc., Transmeridian (Kazakhstan) Incorporated and each of the purchasers party thereto (filed as Exhibit 4.3 to the Company’s Current Report on Form 8-K dated December 16, 2005 and incorporated by reference herein)

4.5		Form of Purchase Agreement, dated as of December 12, 2005, by and among the Company, Transmeridian Exploration Inc., TMEI Operating, Inc., Transmeridian (Kazakhstan) Incorporated and each of the purchasers party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated December 16, 2005 and incorporated by reference herein)

10.1†		Share Sale and Purchase Agreement, dated as of October 14, 2005, by and between Transmeridian Exploration Inc. and Seeria Alliance Ltd.

10.2†		Deed of Amendment, by and between Transmeridian Exploration Inc. and Seeria Alliance Ltd., dated as of December 12, 2005, relating to the Share Sale and Purchase Agreement, dated as of October 14, 2005, by and between Transmeridian Exploration Inc. and Seeria Alliance Ltd.

10.3		Escrow Agreement, dated as of December 12, 2005, by and between Transmeridian Exploration Inc. and The Bank of New York, as Escrow Agent and Trustee (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K dated December 16, 2005 and incorporated by reference herein)

10.4		Pledge Agreement, dated as of December 12, 2005, by and between Transmeridian Exploration Incorporated and The Bank of New York, as Collateral Agent and Trustee (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K dated December 16, 2005 and incorporated by reference herein)

10.5†		Pledge Agreement, dated as of December 22, 2005, by and between Transmeridian Exploration Inc. and The Bank of New York, as Collateral Agent and Trustee

E-1


Exhibit Number		Description
10.6		Warrant Agreement, dated as of December 12, 2005, by and between the Company and The Bank of New York, as Warrant Agent (including form of Warrant Certificate) (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K dated December 16, 2005 and incorporated by reference herein)

10.7†		Purchase Agreement, dated as of December 12, 2005, by and between Transmeridian Exploration Inc. and Kornerstone Investment Group, Ltd.

10.8†		Registration Rights Agreement, dated as of December 12, 2005, by and between the Company and Kornerstone Investment Group, Ltd.

10.9†		Conditional Share Transfer Agreement, dated as of January 3, 2006, by and among Transmeridian Exploration Inc., Bramex Management, Inc. and JSC TuranAlem Securities

10.10†		Share Encumbrance and Pledge Agreement, dated as of January 3, 2006, by and among Transmeridian Exploration Inc., Bramex Management, Inc. and TuranAlem Securities JSC

10.11†		Securities Agency Agreement, dated as of January 3, 2006, by and among Transmeridian Exploration Inc., Bramex Management, Inc., JSC TuranAlem Securities and The Bank of New York

10.12†		Agreement for Brokerage Services, dated as of January 23, 2006, by and between Transmeridian Exploration Inc. and “VISOR Investment Solutions” Joint Stock Company

10.13†		Agreement for Brokerage Services, dated as of January 23, 2006, by and between Bramex Management, Inc. and “VISOR Investment Solutions” Joint Stock Company

10.14		Form of Convertible Promissory Note and Warrant Purchase Agreement, dated as of August 30, 2005, by and among the Company and each of the investors party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated September 6, 2005 and incorporated by reference herein)

10.15		Form of Investor Rights Agreement, dated as of August 30, 2005, by and among the Company and each of the investors party thereto (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K dated September 6, 2005 and incorporated by reference herein)

10.16		Form of Convertible Promissory Note, dated as of August 30, 2005 (filed as Exhibit 10.3 to the Company’s Current Report on Form 8-K dated September 6, 2005 and incorporated by reference herein)

10.17		Form of Warrant, dated as of August 30, 2005 (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K dated September 6, 2005 and incorporated by reference herein)

10.18		Form of Subscription Agreement and Investment Representation, by and between the Company and each of the investors party thereto (relating to the Company’s July 2005 private placement under Regulation S of common stock) (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated August 4, 2005 and incorporated by reference herein)

10.19		Investor Rights Agreement, dated as of November 12, 2004, by and among the Company and each of the purchasers party thereto (filed as Exhibit 10.2 to the Company’s Current Report on Form 8-K dated November 15, 2004 and incorporated by reference herein)

10.20		Preferred Stock and Warrant Purchase Agreement, dated as of November 12, 2004, by and among the Company and each of the purchasers party thereto (filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated November 15, 2004 and incorporated by reference herein)

10.21		Form of Common Stock Purchase Warrant (filed as Exhibit 4.2 to the Company’s Current Report on Form 8-K dated November 15, 2004 and incorporated by reference herein)

E-2


Exhibit Number		Description
10.22		Amended and Restated 2003 Stock Compensation Plan of the Company (filed as Exhibit 4.1 to Post-Effective Amendment No. 2 to the Company’s Registration Statement on Form S-8 filed with the Commission on July 20, 2005 and incorporated by reference herein)

10.23		2001 Incentive Stock Option Plan of the Company (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-8 filed with the Commission on May 28, 2003 and incorporated by reference herein)

10.24		Exploration Contract, dated as of March 7, 2000, with respect to the South Alibek Field (filed as Exhibit 10.2 to the Company’s Registration Statement on Form SB-2 filed with the Commission on May 15, 2001 and incorporated by reference herein)

10.25		License 1557 from the Government of the Republic of Kazakhstan with respect to the South Alibek Field, dated as of April 29, 1999 (filed as Exhibit 10.1 to the Company’s Registration Statement on Form SB-2 filed with the Commission on May 15, 2001 and incorporated by reference herein)

14.1		Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer (filed as Exhibit 14 to the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004 and incorporated by reference herein)

16.1		Letter from John A. Braden & Co., P.C., dated October 25, 2005, to the Office of the Chief Accountant, Securities and Exchange Commission (filed as Exhibit 16.1 to Amendment No. 1 to the Company’s Current Report on Form 8-K dated October 25, 2005 and incorporated by reference herein)

21.1†		Subsidiaries of the Company

23.1†		Consent of UHY Mann Frankfort Stein & Lipp CPAs, LLP

23.2†		Consent of John A. Braden & Company, P.C.

23.3†		Consent of Ryder Scott Company (independent reserve engineers)

31.1†		Rule 13a-14(a) Certification of Chief Executive Officer

31.2†		Rule 13a-14(a) Certification of Chief Financial Officer

32.1†		Section 1350 Certification of Chief Executive Officer

32.2†		Section 1350 Certification of Chief Financial Officer

†	Filed herewith.

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