U.S. SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

For Annual and Transition Reports pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

(Mark One)

Commission File Number: 000-50715

Transmeridian Exploration, Inc.

(Exact name of Registrant as specified in its charter)

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

Securities registered pursuant to Section 12(b) of the Exchange Act:  None.

Securities registered pursuant to Section 12(g) of the Exchange Act:  Common Stock.

Check 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   ý        No   o

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.        o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).   Yes   ý        No   o

The aggregate market value of the common stock held by non-affiliates of the Registrant was approximately $134,922,328 on March 4, 2005 based upon the closing sale price of common stock on such date of $2.20 per share on the OTC Bulletin Board.  As of March 4, 2005, the Registrant had 80,092,318 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the Proxy Statement for the 2005 Annual Meeting of Shareholders to be held in
May 2005 are incorporated by reference, with respect to Part II and III of this Form 10-K.

TABLE OF CONTENTS

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PART I

Item 1.  Description of Business

Transmeridian Exploration, Inc. (the “Company” or “Transmeridian”) was incorporated in the State of Delaware in April 2000.  We are engaged in the business of development and production of oil and gas properties.  Our activities are primarily focused on the Caspian Sea region of the former Soviet Union and our primary oil and gas property is License 1557 and the related Exploration Contract for the development of the South Alibek Field (“South Alibek” or the “Field”) in the Republic of Kazakhstan.  We conduct our operations in Kazakhstan through a 50% owned subsidiary, Caspi Neft TME (“Caspi Neft”).  Caspi Neft is an Open Joint Stock Company (“OJSC”) organized under the laws of Kazakhstan.  The remaining 50% of Caspi Neft is owned by Bramex Management, Inc. (“Bramex”), the successor to Kazstroiproekt, Ltd.

At December 31, 2004, the Company’s 50% share of Caspi Neft’s estimated total proved reserves were 26,813,736 barrels of oil (“Bbls”).  All of these reserves are attributable to the South Alibek Field.  The present value of estimated future net revenues before income taxes, discounted at 10% per annum, based on prices being received at the end of the year, with assumptions held constant throughout the estimated producing life of the reserves (“10% Present Value”) was $219,996,017.  After deducting estimated future taxes, the Company’s share of the net present value of such reserves was $176,841,559.  The total proved reserve estimates and the net present value before income tax have been prepared by Ryder Scott Company, an independent petroleum engineering company, in accordance with SEC guidelines.

We are in the early stages of developing the South Alibek Field.  As of December 31, 2004, only 4,476,364 Bbls, or 17% of Caspi Neft’s proved reserves were classified as proved developed reserves.  The balance of our estimated 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 Field, including plans to drill wells which are not currently included within the boundaries of our proved reserves. See Item 2, “Properties: Proved Reserves” and Note 12 of the Notes to Consolidated Financial Statements for further information about our estimated proved reserves.

 In February 2004, Bramex exercised its option to acquire 50% of the common stock of Caspi Neft.  Thus, our equity ownership of Caspi Neft was reduced to 50%, which reduced our effective net interest in the proved reserves in the Field to 50%.

Availability of Reports

Transmeridian makes available free of charge on its internet website, www.tmei.com, its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13 (a) or 15 (a) of the Securities Act of 1934 as soon as reasonably practicable after it electronically files or furnishes them to the Securities and Exchange Commission.  Such filings and reports are also available from the Securities and Exchange Commission at its website at www.sec.gov.

Strategy

Our business strategy is to build reserves, production and cash flow through (a) the acquisition and development of oil and gas reserves, (b) exploring for new reserves, and (c) optimizing production and value from the existing reserve base.  We prefer to target oil and gas properties with proved or probable reserves and avoid significant exploration risk.  Through the contacts, technical knowledge and experience of our management team, we believe we can successfully identify and acquire additional properties in Kazakhstan and the Caspian Sea region.  The execution of our business strategy is largely dependent on the successful development of the South Alibek Field, which is intended to provide a base of production, operations and cash flow to enable us to exploit future opportunities.

Drilling Activity

During 2004, we drilled and placed on extended production testing four wells, the South Alibek #2 (SA-2), South Alibek #4 (SA-4), South Alibek #5 (SA-5) and South Alibek #17 (SA-17) and began drilling of one additional well, the South Alibek #14 (SA-14). The SA-14 is the sixth well of an initial seven well drilling program in the South

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Alibek Field.  The SA-5 and SA-17 are in-field development wells.  As of December 31, 2004, SA-14 was within 3,300 feet of its programmed depth. All wells are planned to drill the same KT1 and KT2 carbonate reservoirs of the South Alibek Field.  Production casing has been set on all completed wells for the well testing program.  With the exception of SA-4, all completed wells have been producing oil on an extended production testing program.  In late November, a workover program was initiated to prepare the wells for long-term commercial production and includes reservoir stimulation and installation of production tubing and packers with the aim to increase the field’s oil production.

The following table shows the number of wells drilled:

Customers

We began selling oil from our first well, the SA-1, during the second quarter of 2003.  In 2004 we sold 100% of our production into the domestic market, to six different purchasers.  Until the pipeline transfer connections and handling facilities are complete, we are producing our oil into the central production facility where it is temporarily stored until being transferred to the buyer.  See Item 2: “Properties: Transportation and Marketing” for further discussion of our current marketing arrangements and future plans.   See also below under “Risk Factors: Marketing and Oil Prices” regarding various risk factors relating to marketing and crude oil prices.

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.

Government Regulation

Our operations are subject to various levels of government controls and regulations in the United States and in the Republic of Kazakhstan.  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 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.

Offices and Employees

Our corporate headquarters office is in Houston, Texas, where we lease 6,725 square feet of office space.  As of December 31, 2004, we had 8 full-time employees in Houston.  We also maintain two offices in Kazakhstan, operated by Caspi Neft.  Caspi Neft’s administrative offices are in Aktobe where it leases approximately 9,020 square feet of office space and has 60 full-time employees.  Caspi Neft’s field operations for the South Alibek Field have approximately 61 employees.  Caspi Neft maintains a small administrative office in Almaty, Kazakhstan with five employees.

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Risk Factors

Exploration and Development Risks

Our success is dependent on finding, developing and producing economic quantities of oil and gas.  Our future drilling operations may not be successful in finding and producing economic reserves.  We are also subject to operating risks normally associated with the exploration, development and production of oil and gas.  These risks include high pressure or irregularities in geological formations, blowouts, cratering, fires, shortages or delays in obtaining equipment and qualified personnel, equipment failure or accidents, and adverse weather conditions, such as winter snowstorms.  These risks can result in catastrophic events, or they may result in higher costs and operating delays.  We maintain very limited insurance coverage and such coverage may not be effective to fully compensate for these risks.  In many cases, such coverage is either not available or is not cost-effective.

Oil and Gas Reserve Risks

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reserves are considered proved if economical production is supported by either actual production or conclusive formation tests. Reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program is based. Proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods.

Transmeridian emphasizes that the volumes of reserves are estimates which, by their nature, are subject to revision. The estimates 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. In addition, our reserves are contained in carbonate reservoirs, and there is a larger uncertainty inherent in carbonate reservoirs as compared to sandstone reservoirs.

We engage an independent petroleum engineering firm to review our estimates of proved reserves. During 2004, 2003 and 2002, their review covered 100 percent of the reserve value. This value, which represents estimated future net cash flows, is based on prices at year-end and is calculated in accordance with Statement of Financial Accounting Standards (SFAS) No. 69, “Disclosures about Oil and Gas producing Activities.” Disclosure of this value and related reserves has been prepared in accordance with SEC Regulation S-X Rule 4-10 and is presented in Note 12 of the Notes to Consolidated Financial Statements.

Risks of International Operations

We are subject to risks inherent in international operations, including adverse governmental actions, political risks, expropriation of assets, loss of revenues and the risk of civil unrest or war.  Our primary oil and gas property is 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 our agreements and in the event of dispute, may have limited recourse within the legal and political system.

We have commenced negotiations, through CaspiNeft, of a production contract and we anticipate that these negotiations will be concluded and a production contract in place by the end of 2005. The Company has the exclusive right to negotiate this contract for the Field, and the government is required to conduct these negotiations under Kazakhstan’s “Law of Petroleum.”  Such contracts are customarily awarded upon determination that the field is capable of commercial rates of production and that the applicant has complied with the other terms of its license and exploration contract.  However, the Company is not guaranteed the right to a production contract.  The terms of the production contract establish the royalty and other payments due to the government in connection with commercial production.  While we believe that we can successfully negotiate a production contract, we cannot be

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assured that we will be able to do so or that the terms of such contract will be acceptable.  If satisfactory terms cannot be negotiated, it could have a material adverse effect on our financial position.

Marketing and Oil Prices

Our future success is dependent on being able to transport and market our production either within Kazakhstan or preferably through export to international markets.  Thus, our revenues could be 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.  Pipeline access is the preferred and most cost effective method to sell crude oil production into the export market, and thus the Company is subject to the risk that unless the Company obtains access to pipelines to transfer crude oil out of Kazakhstan, the price at which the Company sells its crude oil may remain well below world market prices.  We currently do not have a long-term contract for the transportation or sale of our crude oil.  We are producing our oil into the early production facility where it is temporarily stored until being transferred to the buyer. Our longer-term plans include the shipment of oil by pipeline.  We would expect the implementation of these plans to result in higher realized prices than our current marketing arrangements, but we cannot be assured that we will be successful in implementing these plans.

The prices we have received thus far for the sale of our crude oil are significantly less than the full world market price for crude oil. For example, in June 2004, Caspi Neft entered into a contract to sell approximately 157,500 barrels of crude oil to a local purchaser for approximately $11.61 per barrel, and in December 2004, Caspi Neft entered into a contract to sell approximately 15,000 barrels of crude oil to a local purchaser for approximately $20.00 per barrel.  In comparison to the full world market price for crude oil at such times, these prices are significantly lower.  The Company believes the primary reason we have not received the full world market price is because we have not yet been able to produce crude oil in sufficient quantities to attract customers that supply the world oil markets.  Unless and until such time as we are able to produce crude oil in sufficient quantities to attract customers that supply the world oil markets, the price at which we are able to sell crude oil may be significantly lower than the full world market price, and the Company will be at a competitive disadvantage compared to other exploration and production companies that receive full world market price for their crude oil.

In addition, prices of oil and gas are subject to significant volatility in response to changes in supply, market uncertainty and a variety of other factors beyond our control.  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 presented herein.

Environmental Risks

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

Transferability of Our Common Shares

Our stock has limited trading volume and is not listed on a national exchange.  Because our stock price is less than $5.00 and is not listed on a national exchange, broker-dealers face additional restrictions on transactions in our stock.  Such restrictions include the requirement to deliver to purchasers a standardized risk disclosure document prepared by the SEC, which specifies information about low-priced stocks and the risks involved with such investments.  Additionally, these rules require that broker-dealers make a written determination that the stock is a suitable investment for the purchaser and receive the purchaser’s written consent to the transaction.  These factors could adversely affect the liquidity, trading volume and transferability of our common shares.

In March 2005, the Company received approval for listing our common shares on the American Stock Exchange (“AMEX”).

Control by Our Officers and Directors

In the aggregate, our executive officers and directors control approximately 23.2% of the outstanding shares of our common stock.  These stockholders, acting together, would be able to significantly influence matters requiring stockholder approval.

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Key Personnel

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 an adverse effect on our business.  We do not have employment agreements in place with all of our senior management or key employees.

Item 2.  Properties

Petroleum Industry in Kazakhstan

Until 1991, Kazakhstan was one of 15 independent republics which comprised the former Soviet Union.  It has chosen to align with Russia and 10 of the former republics in the Confederation of Independent States (“CIS”), 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, its proved reserves rank among the top 15 countries in the world, with over 180 producing oil fields and 20 billion barrels of proved reserves.  Its current production is approximately 1.25 million barrels of oil per day (“Bopd”), of which approximately 85% is exported.

Regulation of the oil industry in Kazakhstan has been codified with the development of 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 by the Ministry of Energy and Natural Resources, which administers all contracts, licenses and investment programs.  The national oil company, Kazmunaigas, has been through several stages of consolidation since the country’s independence in 1991.  The government has been 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 entity maintains a direct ownership on behalf of the state in most large oil field development projects as well as sole ownership and operation of many of the interconnecting oil and gas pipeline systems.  It is responsible for about 25% of Kazakhstan’s oil production and for 80% of oil transportation, contributing $850 million to the state budget in 2004.  However, governmental ownership or participation in exploration and development projects is not required and the government has no ownership interest in the South Alibek Field.

Acquisition of the South Alibek Field

In May 1999, prior to the official formation of the Company, Transmeridian signed a consulting agreement with Kornerstone Investment Group Ltd. (“Kornerstone”).  The controlling shareholder in Kornerstone is a citizen of Kazakhstan who is involved in oil and gas production and other business endeavors.  He is also employed on a part-time basis as a consultant and manager of Caspi Neft, handling governmental matters and contract negotiations with governmental entities.  Under this agreement, we engaged Kornerstone to identify and assist in the acquisition of oil and gas properties in Kazakhstan and the Caspian Sea region.  Since we had not received any significant funding for the Company at that time, the agreement with Kornerstone provided that its compensation would be in the form of a 10% carried working interest in all properties shown to the Company in which the Company acquired an interest.  The agreement required us to pay all costs of acquisition, development and operations attributable to the 10% carried working interest.  We are entitled to recover all of our costs related to the carried interest from the production revenues attributable to this interest.  After these costs have been fully recovered, Kornerstone will participate as a 10% working interest owner in all development and operating costs incurred subsequent to that point.

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 Alibekmola Field had been discovered in 1980 by a regional exploration unit of the Ministry of Geology of the former Soviet Union.  A total of 31 wells were 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 initially identified by an Alibekmola Field delineation well drilled by the Kazakh successors of the Soviet Ministry of Geology, Alibekmola 29 (A-29).  It was identified to be in a separate fault block adjacent to the Alibekmola Field, and from testing in 1996 produced flowing oil from several intervals in the KT2 during well testing.  Three of the initial delineation wells are within the area covered by our License  The successor to the Ministry of Geology did not have sufficient funding to begin delineation drilling around A-29, and the license area was offered in a public tender in

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Kazakhstan’s privatization program.  The subsequent work by us has resulted in this license area being designated as the South Alibek Field.

The license and related exploration contract were initially acquired in the tender by a subsidiary of AIL Alpha Corporation, Ltd. (“Alpha”).  License 1557 was granted by the Republic of Kazakhstan on April 29, 1999.  On March 24, 2000, we signed a Share Purchase Agreement with Alpha to acquire the subsidiary which held the title to License 1557.

License and Exploration Contract

Our Exploration Contract (the “Exploration Contract”), entered into with the government of Kazakhstan in March 2000, has a six-year term expiring in April 2005 and requires total capital expenditures during this period of approximately $18.0 million.  As of December 31, 2004, the cumulative capital expenditures which are creditable to our obligations under the Exploration Contract have exceeded the minimum commitment.  Under the terms of the Contract, we can produce wells under a test program subject to royalty payments of 2% of production.  The Exploration Contract may be extended by mutual agreement for two extension periods of two years each. In 2003 the Company requested an extension and in April 2004, we were granted the first of these two-year extensions through April 2007. In connection with such extension, we also agreed to an additional work program commitment of $30.5 million. As of December 31, 2004, $15 million of this additional minimum commitment has been made through the cumulative capital expenditures creditable to our obligations under the Exploration Contract.  Future extension periods require negotiation with and approval by the government and may require additional capital commitments and other changes to the terms.

We have commenced negotiations for a production contract (“Production Contract”) and we anticipate that these negotiations will be concluded and a Production Contract in place by the end of 2005. We have the exclusive right to negotiate for a Production Contract for the Field, and the government is required to conduct these negotiations under the Law of Petroleum.  However, we are not guaranteed the right to a Production Contract.  Such contracts are customarily awarded upon determination that the field is capable of commercial rates of production and that the applicant has complied with the other terms of its license and Exploration Contract.  A Production Contract will typically require a bonus payment upon execution, the amount of which is predetermined based upon the reserves approved by the State Committee of Reserves (“SRC”). If satisfactory terms cannot be negotiated, we have the right to produce and sell oil under the Law of Petroleum for the term of our existing Exploration Contract through April 2007, or as extended, at a royalty rate of 2%.  The royalty rate under production contracts is on a sliding scale, based on production.  The royalty rate ranges from 2% to 6%.  The Exploration Contract 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, usually over a 10 year period beginning one year following the approval of the Production Contract.  The Production Contract, when executed, will contain the final terms for recovery of these costs.

In December 2004, The State Committee of Reserves (“SCR”) of the Republic of Kazakhstan approved the commercial reserves for development and exploitation of the South Alibek Field. This approval provides the Company with the basis to finalize the terms of a Production Contract relating to this portion of the Field with the Ministry of Energy and Mineral Resources. The Government has assessed a commercial bonus of $1.2 million based on the SCR reserves audit as provided under the country’s Petroleum Code.

The reserve audit covered by the SCR approval defines an initial production area of about 3,500 acres, about 25% of the total area under license. This area can be extended based on the drilling of additional exploration wells pursuant to the Company’s current Exploration Contract, which was recently extended for another 2 years until 2007

There are two general forms of production contracts in Kazakhstan, production sharing contracts and tax and royalty based contracts.  We favor a tax and royalty based contract and will seek to negotiate and expect to operate under this structure.  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.  In addition to an up-front bonus payment and recovery of certain costs incurred prior to conveyance of the Field, the government will be entitled to a royalty based on production from the Field and corporate income taxes.  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

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Company is requesting an Exploration and Production Contract to allow for continued exploration while developing the known reserves. This type of contract should allow for maintaining the pre-January 2004 tax regime.

The government may also require that a percentage of our production, which we do not expect to exceed 10%, be sold into domestic markets at local prices.  We would expect these prices to be lower than prices which we could 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.

Overview of Regional Geology

The South Alibek Field is located in a fairway of large producing fields in the oil region of Aktobe in northwestern Kazakhstan.  The largest city in the Aktubinsk Oblast is Aktobe, approximately 125 miles north of the Field.  Within this fairway, the South Alibek Field is among a set of fields which are formed from a carbonate platform and which produce from carbonate reservoirs of Upper and Middle Carboniferous age.  The trend follows the carbonate shelf which was deposited in the shallow waters of an ancient sea in what is now the margins of the Pre-Caspian Basin.  Prolific oil field trends are established in the southern and northern margins of the basin, as well as in the southeastern margins where the South Alibek Field is located.  The carbonate fields found along the margins of the Pre-Caspian Basin account for approximately 75% of Kazakhstan’s oil reserves and production.  The fields in the trend are projected to ultimately contain over 40.0 billion barrels of recoverable reserves, including the super-giant Tengiz Field, which is estimated to hold 9.0 billion barrels of recoverable reserves and the Kashagan Field that is estimated to have 13.0 billion barrels of recoverable reserves.

South Alibek Field is located within 40 miles of two large developed fields, Kenkiyak and Zhanazhol, which contain ultimate recoverable reserves of 200 and 900 million barrels of oil, respectively, including cumulative oil produced and estimated remaining reserves.  South Alibek is immediately adjacent to the producing Alibekmola Field, from which it is separated by a large fault.  The South Alibek Field is about 1,000 feet lower than the Alibekmola Field and has a lower oil water contact.  Production from the Zhanazhol Field is estimated to be in excess of 100,000 Bopd and the Alibekmola Field, still in the early phase of development, reports production to be over 25,000 Bopd.

This region contains good infrastructure for oil and gas development and production, including oil and gas pipelines, electrical transmission connections, all-weather roads, small towns and trained oilfield labor.  This improves our development logistics and lowers our costs compared to drilling in a more remote location.

Field Geology

The primary oil reservoirs in the South Alibek and Alibekmola Fields are in the Upper – Middle Carboniferous (KT1) and Middle-Lower Carboniferous (KT-2) limestones, which are the main reservoirs for many of the fields throughout the Southeastern margin of the Pre-Caspian Basin.  The tops of these formations are found at an initial depth of 6,500 feet and they have a combined gross thickness of as much as 5,000 feet in the area.  The thickness of net productive intervals can be several hundred feet.

We have conducted an extensive evaluation of the information available for the Field and adjacent fields.  This information consists of log data from the 31 wells drilled prior to privatization, the five new wells we have drilled under our License, recent vintage 2D seismic data and use of the results of 3D seismic for which we have rights to. Based on the evaluation of this data, we believe that the oil-bearing reservoirs within the KT-1 and KT-2 carbonates may be present over a substantial part of the area covered by our License.

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.  They are only estimates and actual reserves may vary substantially from these estimates.  All of our proved reserves are in the South Alibek Field in Kazakhstan.  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 Consolidated Financial Statements.

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As of December 31, 2004, we own a 50% working interest in the South Alibek Field, subject to government royalties and a 10% carried working interest after recovery of costs. The effect of the carried interest 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 in “License and Production Contract”, above. In February 2004, Bramex exercised its option to acquire 50% of the common stock of Caspi Neft.  Thus, our equity ownership of Caspi Neft was reduced to 50%, which reduces our effective net interest in the proved reserves in the Field to 50%.   This 50% working interest is also subject to government royalties.  Based on forecast production volumes, the average royalty over the term of the production contract is expected to be 6% or less under current law.

Net Proved Crude Oil Reserves and Future Net Cash Flows
As of December 31, 2004

(Quantities in Barrels)

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

Transportation and Marketing

Companies 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 improved with the opening of the Caspian Pipeline Consortium (“CPC”) pipeline, which ultimately will increase capacity from 250,000 Bopd to an expected 800,000 Bopd.  Two Soviet era oil pipelines, with capacities of 50,000 Bopd and 93,000 Bopd, respectively, service nearby producing fields.  One of the pipelines is operating at less than full capacity.  These pipelines transport oil to the Bestamak rail terminal and the oil refinery in Orsk, which is a transfer point for swaps to Western markets.  The nearest rail terminal for export is approximately 30 miles from the South Alibek Field at Zhem, and is utilized by local producers for domestic and export oil sales by rail. The Kenkiyak-Atyrau pipeline became operational in 2003 with an initial capacity of 120,000 Bopd. This pipeline originates at the Kenkiyak Field and provides a link to the CPC pipeline for the producers in the region.  The Alibekmola Field, adjacent to South Alibek, has begun commercial production, and KazTrans Oil has commissioned a 20” pipeline across our license to connect Alibekmola production to the Kenkiyak-Atyrau pipeline for export markets via the CPC pipeline.  A pump station has been installed about 1.5 kilometers from our central production facility.  We expect to have access to this pipeline, subject to possible capacity limitations, after we make certain required processing and delivery investments.  Our goal for the South Alibek Field is to complete the installation of crude oil treating facilities, pipeline connections and handling equipment so that we can secure a pipeline allotment and export quotas for the Field.  Prior to this, our production will be transported by truck for sale into the local market or for rail shipment to export markets, depending on the best pricing available at the time.

In 2002, we acquired the Emba Terminal, which is located 35 miles from the Field.  The Emba Terminal is a facility for storing and loading crude oil for shipment by rail.  The facility has not been operational for several years and will require capital improvements to make it suitable for use.  As of December 31, 2004 , we have advanced

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approximately $1.465 million to Emba Trans Ltd. which was used to acquire the Emba Terminal, fund the engineering study and begin construction and refurbishment of the facilities.  We may also use the terminal to ship crude oil for third parties if we do not require all of the capacity.  The Emba Terminal is intended primarily for use as an interim solution to sell our production prior to the completion of pipeline and processing facilities.  However, it will also serve as an alternative transportation outlet if our pipeline capacity is constrained.  Caspi Neft owns 75% of Emba Trans Ltd., with the balance of 25% owned by Transmeridian.

Another operator in the immediate area of the Field is in the planning stages of extending the rail line from Zhem to its field. The planned construction of this extension will cross our Field, thereby giving us another alternative for transporting our crude oil and making it available to the export market.

Drilling Rig

On December 28, 2001, we purchased a land drilling rig for $5.3 million in total consideration, including a note payable for $3.3 million and the issuance by the Company of $2.0 million in redeemable common stock.  The rig was acquired for drilling operations in the South Alibek Field.  The rig is a diesel and electric powered National 1320UE, with 2,000 horsepower rating.  It has a depth rating of approximately 20,000 feet and has a 320 ton rating on the draw works.  At the time of the purchase, the rig was in storage in South America.  During 2002, we moved the rig by marine transport vessel to Kazakhstan and undertook various refurbishments and modifications to the rig to make it suitable for use in our operations.  We entered into a contract with a firm experienced with international drilling to oversee the operation of the rig and provide expatriate drilling personnel.

As more fully discussed in Item 3 and Notes 2, 5 and 9 of the Notes to Consolidated Financial Statements, there is a legal dispute between the Company and the holder of an apparent first lien on the drilling rig.

Item 3.  Legal Proceedings

Drilling Rig Dispute

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 redeemable common stock of $2.0 million.  Further discussion of this transaction can be found in Notes 2, 5 and 9 of the Notes to Consolidated Financial Statements.  In July 2003, the Company was notified by the holder of an apparent first lien on the drilling rig (the “First Lien Holder”) that the seller of the rig was in default under its note payable obligation to the First Lien Holder.  The Company was not informed of the existence of the First Lien Holder in the Asset Purchase Agreement related to the acquisition of the drilling rig.  The note payable and the redeemable common stock are now in dispute as a result of the Seller’s default to the First Lien Holder.  During 2003, the Company held discussions with the First Lien Holder with the intent to resolve the Seller’s default by making certain payments directly to the First Lien Holder.  During the year ended December 31, 2003, the Company made installment payments to the First Lien Holder totaling $688,400.

Discussions with the seller of the rig became increasingly adversarial during late 2003 and on December 15, 2003, the seller filed suit in District Court, Harris County, Texas, 334^th Judicial District relating to the Company’s alleged default under the note payable and redeemable common stock agreements with the seller.  At this time, the Company ceased installment payments to the First Lien Holder as it had not been able to successfully negotiate a settlement agreement with both the seller and the First Lien Holder.  On February 27, 2004, the First Lien Holder filed suit in United States District Court, Southern District of Texas, against the seller and named the Company and two of its affiliates as additional defendants.  This action seeks payment of debts owed to the First Lien Holder by the seller related to the drilling rig.

In April 2004, the Company filed a Counterclaim and Third-Party Claim against the seller and certain of its affiliates.  This action seeks recovery of repair costs incurred by the Company in connection with undisclosed latent defects in the drilling rig, recovery of payments made to the seller, including the redeemable common stock, and recovery of additional costs associated with the drilling rig.

In August 2004, the Company and the seller of the rig entered into a Settlement and Release Agreement whereby the seller of the rig agreed to cancel the promissory note of $1.6 million, plus accrued interest of $700,000, and return 200,000 of the 1.0 million shares of redeemable common stock. Pursuant to the terms of the Settlement and Release Agreement the remaining balance due on the note of $1.6 million, plus accrued interest of $550,000 has been

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cancelled and was replaced by assuming the obligation of the seller of the rig to the First Lien Holder. The Company has estimated this liability to be approximately $2.9 million including accrued and unpaid interest. The Company also agreed to pay $120,000 of the legal fees incurred by the seller of the rig in its lawsuit with the First Lien Holder. In December 2004, the Company began making the seller’s payment obligation to the First Lien Holder of $137,680 per month.

Former Chief Financial Officer

In May 2003, Jim W. Tucker (the “Plaintiff”), the former Chief Financial Officer of the Company, filed suit in the 359th District Court, Montgomery County, Texas, against Transmeridian Exploration, Inc., in connection with his separation from service with the Company on January 3, 2003.  The suit alleges breach of an oral employment agreement.  The Company was never served with notice and had no knowledge of this suit.  Counsel for the Plaintiff claimed they were unable to serve the Company’s registered agent with notice of this suit.  Based on these representations, the Court awarded the Plaintiff a Default Judgment on November 25, 2003, in the amount of $922,275.61.  The Company was notified of a Writ of Garnishment and Writ of Execution on March 29, 2004 and April 6, 2004, respectively.

On April 5, 2004, the Company filed a Petition for Bill of Review and a Motion to Vacate the Writ of Garnishment.  A hearing was held on the Motion to Vacate the Writ of Garnishment on April 8, 2004. On May 11, 2004, the court granted the Motion to Vacate the Writ of Garnishment, but has not issued a ruling on the Petition for Bill of Review. In February 2005, the court granted the Motion to Vacate the Default Judgment and the Company withdrew its Petition for a Change of Venue.  The case going forward will be reinstated and will begin as if the Company had just been served notice.  The Company intends to vigorously contest this matter and pursue all legal remedies available to it.

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, 2004.

PART II

Item 5.  Market for Registrant’s Common Equity and Related Stockholder Matters

Common Stock

Our common stock, par value $0.0006 per share, began trading publicly on February 26, 2002 and is traded on the OTC Bulletin Board under the symbol “TMXN”.  There are 200,000,000 shares authorized by our Amended and Restated Certificate of Incorporation.  As of December 31, 2004, we had 79,829,062 shares issued and outstanding, which were held by an estimated 1,850 beneficial owners.  The following table presents the high and low closing prices per share for our common shares, as reported by the OTC Bulletin Board.  Such over-the-counter market prices reflect inter-dealer prices, without retail markup, markdown or commissions:

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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, 2004, we had 1,785.714 shares of Series A Cumulative Convertible Preferred Stock issued and outstanding which are held by an estimated nine beneficial owners.

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.

Recent Issuance of Unregistered Securities

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 for the Series A Preferred and the related warrants was cash consideration of $25.0 million.  This issuance is more fully discussed in Note 8 of the Notes to Consolidated Financial Statements.

The foregoing issuance of Series A Preferred stock were made in reliance upon the exemption from registration set forth in Section 4(2) of the Securities Act of 1933 for transactions not involving a public offering.  No underwriters were engaged in connection with the foregoing issuances of securities.  The sales were made without general solicitation or advertising.  Each purchaser was an “accredited investor” or a sophisticated investor with access to all relevant information necessary to evaluate the investment who represented to the Company that the sales were being acquired for investment.

Stock Option Plan

During 2003, the Company filed a Form S-8 registration statement with the Securities and Exchange Commission to register 5.0 million shares under its 2001 Incentive Stock Option Plan (the “Option Plan”).  The options may be granted to officers, board members, key employees and consultants through December 31, 2010.  Under the Option Plan, the exercise price of each option is equal to the fair market value of the Company’s common stock on the date of the grant and all options granted have a term of five years.  The vesting period is determined by the Board of Directors on the date of grant.  As of December 31, 2004, options to purchase 2,045,000 shares had been granted and options to purchase 2,955,000 shares were available for future grants under the Option Plan.

Stock Compensation Plan

During 2003, the Company filed a Form S-8 registration statement with the Securities and Exchange Commission to register 2.5 million shares under its 2003 Stock Compensation Plan (the “Stock Compensation Plan”).  Under the Stock Compensation Plan, such stock can be issued in lieu of cash to compensate officers, employees, directors and third-party consultants for services rendered.  As of December 31, 2004, 1,443,327 shares had been issued and 775,000 shares have been granted, but have not yet been earned. There are 281,673 shares available for future grants under the Stock Compensation Plan.

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Item 6.  Selected Financial Data

The following selected financial information (which is not covered by the independent auditors’ report) should be read in conjunction with the consolidated financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.”

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

SEE DISCUSSION OF RISK FACTORS IN ITEM 1 OF THIS ANNUAL REPORT ON FORM 10-K.

Introduction

The following discussion and analysis addresses changes in Transmeridian’s financial condition and results of operations during the three year period 2002 through 2004.

There is limited or no comparability for revenue and operating expense to the comparable periods in 2002 and 2003, as sales and production did not commence until the third quarter of 2003.

Management’s primary goals for 2004 were:

•                  Continue the development of the Field by operating two drilling rigs;

•                  Secure additional financing for our 50% share of the 2004 budget;

•                  Complete Phase I of the production facilities;

•                  Position the Company for pipeline sales in 2005.

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We believe that these primary goals were achieved in 2004. We are currently developing our goals for 2005, which will be finalized in the first quarter of 2005. We anticipate, however, that these goals will include increased production from all the wells in the Field, more efficient drilling and completion programs, improving our price received for oil sales, execution of a Production Contract and securing additional financing for Caspi Neft.

Current Activities

During 2004, we drilled and placed on extended production testing four wells, the South Alibek #2 (SA-2), South Alibek #4 (SA-4), South Alibek #5 (SA-5) and South Alibek #17 (SA-17) and began drilling of one additional well, the South Alibek #14 (SA-14). The SA-14 is the sixth well of an initial seven well drilling program in the South Alibek Field.  The SA-5 and SA-17 are in-field development wells.  As of December 31, 2004, SA-14 was within 3,300 feet of its programmed depth. All wells are planned to drill the same KT1 and KT2 carbonate reservoirs of the South Alibek Field.  Production casing has been set on all completed wells for the well testing program.  With the exception of SA-4, all completed wells have been producing oil on an extended production testing program.  In late November, a workover program was initiated to prepare the wells for long-term commercial production and includes reservoir stimulation and installation of production tubing and packers with the aim to increase the field’s oil production. The additional perforation and stimulation programs for wells SA-2 and SA-5 have been completed.  The wells are being flowed and evaluated to determine their optimum flow potential.

We plan to perform a hydraulic fracture stimulation of well SA-17 during the first quarter of 2005.  Logistical challenges in procuring the high strength proppant material and a lack of availability of service company equipment have caused a delay in performing this operation.  The service company has mobilized its team to the field and last minute preparations are underway. Once this operation is completed the well will undergo long term testing to evaluate the effectiveness of the hydraulic fracture stimulation for application to the other existing and future wells.

The Central Production Facility is being completed.  One of the three oil storage tanks has been commissioned and is currently being used for crude oil storage. We expect the facility to become fully operational during 2005. A de-marcaptane unit is being designed to meet quality specifications required for entry into the regional pipeline system. Our contractors estimate that completion and Field commissioning should occur in the third quarter of 2005.

In July 2004, we established an office in Baku, Azerbaijan to evaluate prospects in that country. We will be allowed to view data from the national oil company’s archives to evaluate the available properties and enter into a Memorandum of Understanding to undertake the study of various plays in the country. We seek properties which meet our objectives of 1) low up-front acquisition costs, 2) identified reserves, 3) significant upside reserve potential, 4) reasonably short payback period and 5) lower than average international finding costs. We are not obligated to purchase or participate in a property and have an indefinite time to review the data.

Results of Operations

Oil production and revenue

For the year ended December 31, 2004, Caspi Neft produced 313,305 barrels (“Bbls”) of crude oil, or an average of 858 Bopd, as compared to 117,376 Bbls, or an average of 641 Bopd for the year ended December 31, 2003. The increase in 2004 when compared to 2003 is due to the Field having three producing wells in 2004 as compared to only one producing well in 2003, and the Field was on production for all of 2004 and only six months of 2003.  There is no comparability of production for the years ended December 31, 2003 and 2002, because production from the Field did not commence until July of 2003.

For the year ended December 31, 2004, we sold (by physical delivery to the purchaser) 336,440 Bbls of crude oil at an average price of $11.87 per Bbl, for net revenues of $3,922,990, as compared to 77,293 Bbls at an average price of $10.52 and net revenue of $797,411 for the year ended December 31, 2003.  The increase in 2004 when compared to 2003 is 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 and only six months of 2003.  There is no comparability of revenue for the years ended December 31, 2003 and 2002, because sales from the Field did not commence until the third quarter of 2003.

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We recognize revenue from the sale of oil when the purchaser takes delivery of the oil at the Field. As of December 31, 2004, the Company had 16,576 Bbls in inventory for which it had received payment, but had not recognized the revenue because delivery had not yet been taken by the purchaser. The average price received for these Bbls was $11.61, which will be recognized as revenue in future periods of 2005 upon delivery to the purchaser.

Our crude oil sales in the last eight months of 2004 occurred at the Field and were not subject to transportation costs.  Consequently, our net realization improved by approximately $2.00 per Bbl compared to year end 2003. (For additional discussion on transportation, see Transportation Expense, below).

In December, we entered into a new contract for sales of crude oil from South Alibek Field. The arrangement provides for deliveries to take place at the field and a net sales price of approximately $20 per barrel. While the agreement is short-term in nature, it may be extended by mutual agreement of the parties.

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 2004 we incurred $130,926 in exploration expense as compared to $592,553 for the comparable period in 2003. The decrease is primarily due to the fact no new geologic data was purchased and interpreted in 2004. In 2004 we expensed the remaining book value of our South Texas properties, $66,844, due to the unsuccessful reentry in the third quarter. 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. For the year ended December 31, 2002, there were no charges to exploration expense.

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, as described in Note 1 of the Notes to Consolidated Financial Statements. In 2004 we sold 336,440 Bbls of oil resulting in DD&A of $709,496, as compared to 77,293 Bbls of oil sales resulting in DD&A of $189,635 for 2003. This increase is primarily due to increased oil sales in 2004.  There is no comparability for DD&A for the years ended December 31, 2003 and 2002, because sales from the Field did not commence until the third quarter of 2003.

Non-oil and gas property DD&A for 2004 was $79,261 and $56,079 for 2003. This increase is primarily due to asset additions in the Kazakhstan operation. For the year ended December 31, 2002 we recorded $28,320, in non-oil and gas property DD&A. The increases in 2003 and 2002 are primarily due to additional transportation and other equipment acquired by Caspi Neft.

Transportation and Expenses

During the second quarter of 2004, the first of three storage tanks at our permanent production facility was commissioned for use.  This allowed us to begin oil sales from the Field, resulting in a cost savings of approximately $517,887.  For the year ended December 31, 2004, transportation and storage costs were $173,847, or $0.55 per Bbl produced. For the year ended December 31, 2003, we incurred $235,264 or $2.00 per Bbl produced. We are currently negotiating to have a railroad spur built from our production facility to the main rail line. See Item 2. “Properties: Transportation and Marketing.” This will allow for direct shipment of the crude oil to the export terminals located on the railroad.  Additionally, when the treating facilities and pipeline pump station discussed in Item 2 are operational, expected during 2005, we should be able 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.  The prices received for pipeline sales should be much closer to prevailing world oil prices than our current sales arrangements.

Operating and administrative expense - Kazakhstan.

For the year ended December 31, 2004 operating and administrative expense in Kazakhstan was $3.6 million, as compared $2.5 million for the year ended December 31, 2003. This increase is primarily due to increased activity in our exploration, development and production program for the South Alibek Field. In 2002 operating and

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administrative cost in Kazakhstan was $1.2 million. The increase of $1.3 million, when comparing 2002 to 2003, is primarily due to increased personnel costs at Caspi Neft, which is a result of increased activity.

General and administrative expense – Houston

For the year ended December 31, 2004 general and administrative expense in Houston was $2.6 million, as compared $2.1 million for the year ended December 31, 2003. This increase is primarily due to increased legal costs associated with the lawsuits explained in Item 3. In 2002 general and administrative expense in Houston was $1.8 million. The increase when comparing 2002 to 2003 is primarily due to legal costs and investor relation cost.

Interest expense

Interest expense, net of the capitalized portion, for the years ended December 31, 2004, 2003 and 2002, was $1,400,227, $772,409 and $338,229, respectively. The increase in interest expense when comparing 2004 to 2003 is primarily due to increased debt levels and expensing of interest that had been capitalized in the prior year. Once a well has been completed and is producing oil, we no longer continue to capitalize interest. The increase in 2003 compared to 2002 is primarily due to capitalizing the interest on our drilling rig in 2002 during the time it was being prepared for its intended use. We expect interest expense to increase in 2005 due to more wells being placed on production. However, if we are successful in securing a new credit facility or renegotiating the current facility at more favorable interest rates, we would expect interest expense to decrease.

Liquidity and Capital Resources

For the years ended December 31, 2004, 2003 and 2002, capital expenditures were $26.1 million, $31.2 and $11.5 million, respectively. The primary sources of funding have been private placements of common and preferred stock,  borrowings under our credit facilities with a Kazakhstan bank (as described in more detail below and in Note 5 to the Notes to Consolidated Financial Statements) and loans from the Company and Bramex to Caspi Neft. From inception through December 31, 2004, we have received a total of $12.0 million in net cash proceeds from sales of common stock and $23.4 million in net cash proceeds from the sale of preferred stock. Our cumulative proceeds from all borrowings, net of repayments, have amounted to $34.6 million since inception. These proceeds have been used to conduct remedial work and production tests on SA - 29, drill and complete the SA - 1, SA-2, SA-4,  SA-5 and SA-17, the drilling of the SA – 14, the initial construction costs of support and production facilities and the administrative cost of the office in Kazakhstan. The total capitalized cost attributable to the South Alibek Field as of December 31, 2004, was $78.9 million, which includes $10.0 million of capitalized interest.

In February 2002, Caspi Neft obtained a $20.0 million credit facility with a Kazakhstan bank to fund operations in the South Alibek Field.  The available capacity under the facility was fully utilized in April 2003 and the bank extended $1.5 million in additional financing as an interim step pending arrangements for an additional facility. Under the terms of the credit facility, a portion of this debt and accrued interest was due in August 2003. This amount was subsequently paid in February 2004 in conjunction with the Bramex option exercise discussed below. See Note 5 to the Notes to Consolidated Financial Statements for further discussion.

In connection with this bank financing, the Company granted an option to Bramex to acquire 50% of the common stock of Caspi Neft.  To exercise this option, Bramex made a capital contribution to Caspi Neft of $15.0 million, which was used to repay part of the bank’s credit facility. The option was exercised in February 2004. For additional information, see Note 5 of the Notes to Consolidated Financial Statements.

In September 2003, Caspi Neft entered into a second facility with this bank in the amount of $30.0 million. The funds from this facility were used for the ongoing development of the project.  As of December 31, 2004, the total amount available had been fully utilized. The principal balance with accrued interest is payable in 36 monthly installments from June 2005 through May 2008. For additional information, see Note 5 of the Notes to Consolidated Financial Statements.

In February 2005, the Company, through its subsidiary Caspi Neft, entered into an agreement with the bank in Kazakhstan to defer all payments of principal and interest due on both credit facilities for six months or until July 15, 2005. At the expiration of the extension the total amount of principal and interest deferred, $13.7 million will become due and payable. In exchange for this deferral the Company has agreed to advance up to $10.0 million to Caspi Neft to fund 100% of anticipated capital requirements for the first six months of 2005.

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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 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 Stock and Warrants will be used for general corporate purposes, including funding the Company’s 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 will be entitled to a quarterly dividend payable at the rate of four and one-half percent (4.5%) per annum, payable in cash.  The holders of the Series A Preferred Stock shall 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 common stock, voting together with the holders of common stock as one class.  Each holder of the Series A Preferred shall not, unless it chooses in advance not to be governed by this limitation, convert the Series A Preferred or exercise the Warrant Shares 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, in excess of 4.999% of the then issued and outstanding shares of common stock outstanding of the Company.   So long as at least twenty (20%) percent of the Series A Preferred remains outstanding, the Company shall not issue any new securities or financial instruments that rank pari pasu or senior to the Series A Preferred without the approval of at least 75% of the Series A Preferred outstanding. Beginning one year following the effective date of the registration statement to be filed for the underlying shares of common stock, the Series A Preferred shall automatically convert 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 (20) consecutive trading days, 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 described above, the excess portion of the Series A Preferred shall remain outstanding, but shall cease to accrue a dividend.

We contributed $10.5 million of the Series A preferred Stock proceeds to the working capital of Caspi Neft. The other 50% owner of Caspi Neft has also contributed $10.5 million.

Management expects cash flow from operations to increase throughout 2005 and 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 control of the Company.

By the end of 2005, we expect to drill and complete four new wells, bringing our total number of producing wells to ten, complete the construction of the production facility, tie into the regional pipeline system, and complete negotiation of a Production Contract. We have an approved budget of approximately $36.6 million for capital expenditures and an operating budget (lease operating expense and general and administrative expense) budget of approximately $12.0 million. We currently anticipate that this capital spending plan will result in a cash shortfall of approximately $10.0 - $15.0 million, before including debt service. We are currently discussing new financing alternatives with several financial institutions, but cannot be assured that we will be successful in securing the new financing. If an agreement is not achieved for new financing we will have to reduce or suspend our capital program in order to fund operating expenses and debt service. The Company believes it will be successful in obtaining new financing to continue development of the Field in accordance with its current development plan. However, the Company cannot provide assurance that it will be successful, as many factors required to execute its plans are outside the control of the Company.

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

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

(2)          See Note 9 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

Our consolidated financial statements include all of our subsidiaries.  Our most significant subsidiary is Caspi Neft, which holds License 1557 and the related Exploration Contract for the South Alibek Field.  Except for the drilling rig, which is owned by the parent company, the assets and results of operations of Caspi Neft represent substantially all of our consolidated assets and operations at December 31, 2004.

During February 2004, Bramex Management, Inc., successor in interest to Kazstroiproekt, Ltd. (“Bramex”), exercised its option to acquire 50% of the common stock of OJSC Caspi Neft TME (“Caspi Neft”), the Company’s primary operating subsidiary in Kazakhstan and the entity which holds the license and exploration contract covering the South Alibek Field.  Accordingly, as of December 31, 2004, the Company owns a 50% equity interest in this subsidiary.  Based on the Company’s ability to exercise significant control over Caspi Neft, the Company believes that the most meaningful accounting treatment is to fully consolidate this entity, with the 50% share owned by Bramex reflected as a minority interest.

To exercise its option to acquire 50% of Caspi Neft, Bramex contributed $15 million in cash to Caspi Neft, the proceeds of which were used by Caspi Neft to retire debt.  The difference between the $15 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 has been included in additional paid-in capital on the accompanying 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 are successful in negotiating a commercial production contract which will allow production for the expected 25-year term of the contract.  The current maximum statutory royalty rate of 6%, as dictated by new tax rules which came into effect in

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2004, has been used to calculate the government royalty.  Production contracts are customarily awarded upon determination that the field is capable of commercial rates of production and that the applicant has complied with the other terms of its license and exploration contract.  However, we are not guaranteed the right to a production contract.  If we are not successful in negotiating a production contract on acceptable terms, 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, 2004, 2003 and 2002, we capitalized $4.5 million, $4.2 million and $1.3 million, respectively, of interest costs, which reduced our reported net interest expense to $1.4 million, $772,409 and $338,645 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 Statement of Financial Accounting Standards No. 123 (R), Share-Based Payment (“SFAS No. 123 (R)”) that 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 each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. This Statement replaces SFAS No. 123 and is effective as of the first interim or annual reporting period that begins after June 15, 2005. The cumulative effect of applying this Statement, if any, is not expected to be material.

In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, Inventory Costs (“SFAS No. 151”) to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and spoilage. The Statement requires that abnormal expenses be recognized in the period in which they were incurred. The Statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. SFAS No. 151 is not expected to effect our consolidated financial statements.

In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153, Exchanges of Nonmonetary Assets (“SFAS No. 153”) to eliminate an exception from fair value measurement in APB Opinion No. 29, for nonmonetary exchanges of similar productive assets. SFAS No. 153 replaces this exception with a general exception from fair value measurement for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 is not expected to effect our consolidated financial statements.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

Oil Prices

Our future success is dependent on the Company being able to transport and market its 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 have been based on prevailing current local market prices at the time of sale.  In

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June 2004, Caspi Neft entered into a contract to sell approximately 157,500 barrels of crude oil to a local purchaser for approximately $11.61 per barrel. As of December 31, 2004, the purchaser has not taken delivery of approximately 39,260 barrels on this contract.

Interest Rate Risk

At December 31, 2003, Transmeridian had long-term debt outstanding of $23.7 million.  The total amount bears interest at a fixed rate of 15% per annum.

Foreign Currency Risk

The Company’s functional currency is the U.S. dollar.  The financial statements of the Company’s foreign subsidiaries are measured in U.S. dollars.  Accordingly, transaction costs for the conversion to various currencies for foreign operations are recognized in the consolidated financial statements 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 facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company’s 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 the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.  Important factors that could cause actual results to differ materially from the Company’s expectations (“cautionary statements”) include, but are not limited to, the Company’s 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 conditions, either internationally or nationally or in the jurisdictions in which Transmeridian or its 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 and Estimated Future Net Revenue,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosure About Market Risk” and elsewhere in this report.  All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements.  The Company assumes no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.

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Item 8.  Financial Statements

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

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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 2003, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the three 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.

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TRANSMERIDIAN EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

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

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TRANSMERIDIAN EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

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

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TRANSMERIDIAN EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

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

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TRANSMERIDIAN EXPLORATION, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF CASH FLOWS