Washington, D.C.  20549

 

FORM 10-K

 

 

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:  None.

 

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.           ý

 

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

 

The aggregate market value of the common stock held by non-affiliates of the Registrant was approximately $12,754,554 on June 30, 2003 based upon the closing sale price of common stock on such date of $0.29 per share on the OTC Bulletin Board.  As of March 22, 2004, the Registrant had 78,132,084 shares of common stock issued and outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

Portions of the Proxy Statement for the 2004 Annual Meeting of Shareholders to be held in May 2004 are incorporated by reference, with respect to Part II and III of this Form 10-K.

 

 

TABLE OF CONTENTS

 

PART I
Item 1.	Description of Business
Item 2.	Description of Properties
Item 3.	Legal Proceedings
Item 4.	Submission of Matters to a Vote of Security Holders
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters
Item 6.	Selected Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Financial Statements and Supplementary Data
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A.	Controls and Procedures
PART III
Item 10.	Directors, Executive Officers, Promoters and Control Persons
Item 11.	Executive Compensation
Item 12.	Security Ownership of Certain Beneficial Owners and Management
Item 13.	Certain Relationships and Related Transactions
Item 14.	Principal Accountant Fees and Services
PART IV
Item 15.	Exhibits and Reports on Form 8-K
SIGNATURES
Certifications

 

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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 wholly-owned subsidiary, Caspi Neft TME (“Caspi Neft”).  Caspi Neft is an Open Joint Stock Company (“OJSC”) organized under the laws of Kazakhstan.

 

At December 31, 2003, our estimated proved reserves were 45,744,788 barrels of oil (“Bbls”).  All of these reserves are attributable to the South Alibek Field.  The present value of pre-tax future net revenues discounted at 10% per annum, based on prices being received at the end of the year, with assumptions held constant throughout the producing life of the reserves (“10% Present Value”) was $241,351,419.  After deducting estimated future taxes, the net present value of such reserves was $180,443,372.  These reserve estimates 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, 2003, 7,815,681 Bbls, or 17%, of our estimated 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.  If these future wells are successful, they would be expected to result in an increase in our proved reserves.  See Item 2, “Properties: Proved Reserves” and Note 13 of the Notes to the Consolidated Financial Statements for further information about our estimated proved reserves.

 

The reserve quantities and values discussed above represent our 100% ownership of the reserves in the field, reduced by estimated government royalties and a 10% carried working interest after payout which is owned by a third party.  Subsequent to December 31, 2003, as discussed in “Item 2. Properties: Subsequent Events Affecting Net Proved Reserves”, our equity ownership of Caspi Neft was reduced to 50%, which reduces our effective net interest in the proved reserves of the Field.

 

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 (d) 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 focused on building 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 exploit future opportunities.

 

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Drilling Activity

 

In 2003 the Company completed the drilling of the South Alibek #1 (SA-1) and began drilling operations on two new wells, the South Alibek #2 (SA-2) and the South Alibek #4 (SA-4).  These are the second and third wells of an initial seven well drilling program in the South Alibek Field.  The SA-2 well is 1.5 miles northwest of SA-1 and the SA-4 is located 1 mile southeast of SA-1.  Both wells are planned to drill the same KT1 and KT2 carbonate reservoirs encountered in SA-1.  As of December 31, 2003, SA-4 had been drilled to its total depth and logged and we were in the process of running production casing in the well, while SA-2 was within 1,300 feet of its programmed depth.  In January 2004, the SA-2 reached total depth.  Analysis of the log data indicated significant apparent oil pay in multiple zones on both wells.  Production casing has been set on both wells in preparation for the well testing program, which began in late February.  Both wells will be placed on an extended production testing program.

 

Customers

 

We began selling oil from our first well, the SA-1, during the second quarter of 2003.  All sales during 2003 were to one customer.  However, we have signed agreements with two additional customers for sales of crude oil in 2004.  Until our central production facility, pipeline transfer connections and handling facilities are completed, we are shipping our oil by truck from the field to an oil storage 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.

 

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, 2003, 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

 

Limited Capital Resources and Liquidity

 

We are a development stage company and are in the early stages of establishing production and revenues from the development of our primary property in Kazakhstan.  We have accumulated significant operating losses and our current liabilities exceed our current assets by a substantial amount.  Furthermore, the development of our primary asset, the South Alibek Field, will require additional funding before we can achieve significant production and revenues from operations.  These factors raise substantial doubt about our ability to continue as a going concern.  Our plans regarding the operations and financing of the Company are discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 2 of the Notes to Consolidated Financial Statements.  However, there can be no assurance that we will be successful in executing these plans.

 

Exploration and Development Risks

 

Our success is dependent on finding, developing and producing economic quantities of oil and gas.  We make use of the best information available to us and employ current technologies and consultants to attempt to mitigate risks.  However, despite these efforts, our 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

 

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and projecting future rates of production and 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.  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.  The oil and gas reserve data shown herein represent estimates only and are not intended to be a forecast or fair market value of our assets.  The economic success of the Field is dependent on finding and developing sufficient reserves and rates of production to generate positive cash flow and provide an economic rate of return on our investments in the Field.

 

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.

 

If we are successful in establishing commercial production from the Field, an application will be made for an exploration and production contract.  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 exploration and production contract establish the royalty and other payments due to the government in connection with commercial production.  While we believe that we can successfully

 

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negotiate an exploration and production contract, we cannot be 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.  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 do not have a long-term contract for the transportation or sale of our crude oil.  We currently ship our oil by truck to an oil storage facility where it is temporarily stored pending delivery to the buyer.  After the buyer takes possession of the oil, it is generally shipped by rail from the oil storage facility.  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.  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 receive for our oil production will have a significant impact on our future financial position and results of operations.  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 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.

 

Control by Our Officers and Directors

 

In the aggregate, our executive officers and directors control approximately 27% of the outstanding shares of our common stock.  These stockholders, acting together, would be able to significantly influence matters requiring stockholder approval.

 

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.

 

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Item 2.  Properties

 

Petroleum Industry in Kazakhstan

 

Until 1990, 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 1.0 million barrels of oil per day (“Bopd), of which approximately 80% 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.  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 would 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 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,

 

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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, 2003, 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.  Any extension periods require negotiation with and approval by the government and may require additional capital commitments and other changes to the terms.  The Company has requested a two year extension until April 2007 and has offered to increase the total expenditure commitment to $31.8 million.

 

If we are successful in establishing commercial production from the Field, an application will be made for a production contract (the “Production Contract”).  We have the exclusive right to negotiate this 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 subject to negotiation.  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 2005, 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.  The production contract, when executed, will contain the final terms for recovery of these costs.

 

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 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 northwestern Kazakhstan within the prolific oil region of Aktobe.  It is in the Aktubinsk Oblast, 75 miles south of the city of Aktobe.  South Alibek lies in a fairway of oil fields that 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 are 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

 

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billion barrels of recoverable reserves and the Kashagan Field that is estimated to have 13.0 billion barrels of recoverable reserves.

 

South Alibek 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 15,000 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 Middle Carboniferous (KT1) and Lower Carboniferous (KT-2) limestones, which are the main reservoirs for many of the fields throughout the Southeastern Shelf 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 three 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 13 of the Notes to Consolidated Financial Statements.

 

As of December 31, 2003, we owned a 100% 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.”  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.

 

Subsequent Events Affecting Net Proved Reserves

 

In February 2002, we granted Bramex Management, Inc. (“Bramex”), the successor to Kazstroiproekt, Ltd. (“KSP”), a two-year option to acquire a 50% equity interest in Caspi Neft, the subsidiary which holds the rights to the South Alibek Field.  In order to exercise the option, Bramex was required to provide $50.0 million in commercial financing to Caspi Neft in two tranches of $20.0 million and $30.0 million, respectively.  After this financing had been provided, Bramex could exercise the option by the payment of

 

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$15.0 million, the proceeds of which were to be dedicated to the retirement of part of Caspi Neft’s debt.  Bramex completed all terms and paid $15.0 million to Caspi Neft to exercise the option on February 4, 2004.  As a result of the option exercise by Bramex, our net interest in the oil and gas reserves of the Field will be proportionally reduced to reflect the new ownership structure.

 

During late January 2004, the SA-2 well reached its planned total depth, was logged and production casing was run to undertake completion operations.  As this well had not reached total depth as of December 31, 2003, it could not be included in the proved reserves of the Company at that date.  However, Ryder Scott Company attributed proved reserves to this well in an evaluation subsequent to the end of the year.

 

Net Proved Crude Oil Reserves and Future Net Cash Flows
As of December 31, 2003
(Quantities in Barrels)

 

		Actual			Pro Forma (a)
Proved Developed		7,815,861			4,537,063
Proved Undeveloped		37,928,927			20,456,511
Total Proved Reserves		45,744,788			24,993,574
Standardized Measure of Future Net Cash Flows		$	180,443,372		$	99,651,089

 

(a) As discussed above, the Pro Forma reserve quantities and standardized measure of future net cash flows reflect (1) the exercise of the option by Bramex to acquire a 50% interest in Caspi Neft and (2) the completion of the SA-2 well, both of which occurred subsequent to December 31, 2003.

 

Transportation and Marketing

 

Companies in the area of the South Alibek Field utilize both the KazTrans Oil and Russian Transneft pipeline system 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 is increasing 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 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 constructed a pipeline across our license area 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, 2003, we have advanced 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.

 

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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 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 Note 10 of the Notes to Consolidated Financial Statements, there is a legal dispute between the Company, the seller of the rig and the holder of an apparent first lien on the drilling rig.

 

Item 3.  Legal Proceedings

 

On March 5, 2003, Private Capital Group LLC filed suit against the Company in connection with its $200,000 investment in convertible debentures of the Company.  On June 18, 2003, the Company entered into a Settlement Agreement with Private Capital Group LLC.  Pursuant to the terms of the Settlement Agreement, the convertible debentures, plus accrued interest and litigation settlement costs, were subsequently retired through the issuance of 1,081,865 shares of common stock and the payment of $30,000 in cash.

 

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 3, 6 and 7.  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 increasing 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.

 

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, 2003.

 

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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, 2003, we had 71,673,207 shares issued and outstanding, including 1,000,000 shares subject to mandatory redemption, which were held by an estimated 1,500 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:

 

		High			Low
2003:
Fourth quarter		$	0.87		$	0.33
Third quarter		0.39			0.19
Second quarter		0.42			0.23
First quarter		0.39			0.10
2002:
Fourth quarter		$	0.37		$	0.11
Third quarter		0.52			0.15
Second quarter		0.76			0.20
Period from February 26, 2002 to March 31, 2002		2.20			1.20

 

Preferred Stock

 

We are authorized by our Amended and Restated Certificate of Incorporation to issue up to 5,000,000 shares of preferred stock.  No shares of preferred stock were outstanding as of December 31, 2003.

 

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

 

Pursuant to a Subscription Agreement dated October 15, 2003, we sold 3,333,333 shares of common stock, for cash proceeds of $1,000,000, to a foreign investment company in a private placement which was exempt from registration pursuant to Regulation S.

 

On November 13, 2003, we issued 25,000 shares of common stock, valued at $10,000 to an individual as compensation for investor relations services.

 

During the year ended December 31, 2003, we issued 1,081,865 shares of common stock, including 269,551 shares issued during the fourth quarter, and $30,000 in cash to settle litigation and retire convertible debentures with an original principal amount of $200,000.  This matter is more fully discussed in Note 6 of the Notes to Consolidated Financial Statements.

 

The foregoing issuances of common 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.

 

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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 “Plan”).  The options 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 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, 2003, options to purchase 1.74 million shares had been granted and 3.26 million options were available for future grants under the 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.  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, 2003, approximately 1.23 million shares had been issued under the Stock Compensation Plan and 1.27 million shares were available for future issuance.

 

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.”

 

		Years ended December 31,
		2003			2002			2001			2000
OPERATING RESULTS:
Oil revenues		$	797,411		$	—		$	51,289		$	—
Loss from operations		(4,915,029		)	(2,936,603		)	(1,924,245		)	(187,140		)
Net loss		(5,686,568		)	(3,270,903		)	(2,112,890		)	(810,548		)
Net loss attributable to common stockholders		$	(5,706,304	)	$	(3,308,423	)	$	(2,236,161	)	$	(810,548	)
Basic and diluted loss per share		$	(0.09	)	$	(0.06	)	$	(0.04	)	$	(0.06	)

 

		As of December 31,
		2003			2002			2001			2000
BALANCE SHEET DATA:
Total current assets		$	2,067,804		$	813,725		$	377,388		$	561,675
Total property and equipment, net of  accumulated depreciation		54,560,575			24,396,599			13,105,859			4,452,067
Total assets		57,099,072			26,271,414			13,883,247			5,013,742
Total current liabilities		31,918,658			6,637,127			2,475,669			1,617,281
Long term debt, net of current maturities		24,674,196			13,752,304			3,368,796			—
Stockholders’ equity		506,218			3,881,983			6,038,782			3,396,461
CASH FLOW DATA:
Net cash used in operating activities		$	(3,654,690	)	$	(2,056,297	)	$	(1,880,297	)	$	(495,465	)
Net cash used in investing activities		(23,640,308		)	(10,299,391		)	(1,813,713		)	(3,038,871		)
Net cash provided by financing activities		27,991,705			12,873,219			3,289,171			1,046,451

 

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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 address changes in Transmeridian’s financial condition and results of operations during the three year period ended December 31, 2003.

 

In June 2003 Caspi Neft, the Company’s operational subsidiary in Kazakhstan, began producing its first well, the SA-1, on a test basis.  In early September, we completed an acid treatment which increased the production rate to over 1,100 Bopd on a 7/16ths inch choke.  We are continuing to test the well on various size chokes to determine which is operationally most efficient.  Currently the well is producing approximately 975 Bopd on a 9/16ths inch choke.  The production is currently being sold to a single purchaser on a month to month basis.  For the year ended December 31, 2003 we produced 117,376 Bbls, sold 77,293 Bbls and had 39,863 Bbls in inventory.  During 2003 we received an average price of $10.52 per Bbl, or net revenue of $797,411.  The price received for oil sales has increased during the year as we have been able to sell larger volumes and we realized $12.44 per barrel for sales during the month of December 2003.  We expect our pricing to continue to improve as we develop new marketing arrangements, improve the quality of the crude with our treatment and processing facilities, are able to sell larger volumes and gain direct pipeline access by early 2005.

 

Transportation and Expenses

 

Caspi Neft is transporting its oil production by truck for sale at a rail terminal approximately 65 miles from the field.  During 2003, we incurred $235,264 in transportation and storage cost, or $2.00 per Bbl produced.  When our handling facilities at Emba are completed in 2004, we believe we will achieve a reduction in handling and storage costs.  Additionally, when the treating facilities and pipeline pump station is operational, expected in early 2005, we will be able to deliver our crude directly into the Kenkiyak / Atyrau pipeline, which should result in a significant reduction in the transportation and storage expense and improved sales pricing for our crude oil.  See Item 2, “Properties: Transportation and Marketing” for further discussion of this matter.

 

Administrative cost consists of two primary components, personnel costs and office expense.  The increase in administrative expense is due to increased personnel costs, at Caspi Neft, which is a result of the increased activity in our exploration and development program for the South Alibek Field.  We do not expect these costs to increase appreciably in 2004, based on our current operational plans.

 

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 the Consolidated Financial Statements.  During 2003, we sold 77,293 Bbls of oil resulting in DD&A of $189,635, or an average of $2.45 per barrel.

 

Non-oil and gas property DD&A increased $27,759 in 2003 compared to 2002.  This increase is primarily the result of additions to transportation and other equipment in Caspi Neft.

 

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 2003, Caspi Neft incurred $473,659 in exploration expense which was primarily related to the purchase and interpretation costs of geologic data.  In July 2003, Transmeridian conducted an operation on one of its two U. S. properties.  A downhole obstruction was encountered which prevented a successful test of the target formation.  We recorded a charge to exploration expense of $118,893 in the third quarter of 2003 for this unsuccessful completion attempt.

 

Interest expense, net of the capitalized portion, for the years ended December 31, 2003, 2002 and 2001, was $772,409, $338,229 and $188,645, respectively.  The increase in interest expense when comparing 2003 to 2002 is primarily attributable to capitalized interest on our drilling rig in 2002 during the time it was being prepared for its intended use.  The increase in 2002 compared to 2001 is primarily due to the

 

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amortization of debt financing costs, as described in Note 1 of the Notes to the Consolidated Financial Statements.

 

Property and Equipment

 

The following schedule shows the property and equipment, by project, for each of the periods shown.

 

		As of December 31,
		2003			2002			2001
Drilling and completion costs (a)		$	25,506,735		$	8,139,075		$	1,886,270
Production facility (b)		10,083,732			2,596,251			172,893
Emba terminal (b)		1,465,310			—			—
Drilling rig (c)		6,484,983			6,040,818			5,300,000
License cost		5,706,402			5,706,402			5,706,402
Other equipment		558,355			393,691			50,724
Capitalized interest		5,972,894			1,726,152			—
Total property and equipment		$	55,778,411		$	24,602,389		$	13,116,289

 

(a)          These amounts include costs incurred to construct future well locations, inventory of equipment and supplies for the drilling of future wells and rig mobilization costs.

(b)         These projects are under construction and have not been placed in service.

(c)          These amounts include the initial purchase price and capital improvements and refurbishments.

 

In 2003 the Company began drilling operations on two new wells the SA-2 and the SA-4.  These are the second and third wells of an initial seven well drilling program in the South Alibek Field.  The SA-2 well is 1.5 miles northwest of SA-1 and the SA-4 is located 1 mile southeast of SA-1.  Both wells were planned to drill through the same KT1 and KT2 carbonate reservoirs encountered in A-29 and SA-1.

 

As of December 31, 2003, SA-4 had been drilled to its total depth and logged and we were in the process of running production casing in the well, while SA-2 was within 1,300 feet of its programmed depth.  In January 2004, the SA-2 reached total depth.  Analysis of the log data indicated significant apparent oil pay in multiple zones on both wells.  Production casing has been set on both wells in preparation for the well testing program, which began in late February.  Both wells will be placed on an extended production testing program.

 

We made considerable progress on the construction of our permanent production facility in 2003.  The tanks and separators have been installed and are currently being prepared for testing and certification.  The field loading facilities are approximately 75% complete.  We expect the facility to become operational during the second quarter of 2004.  The construction and installation of the demercaptane unit has been delayed by technical issues and we currently do not expect it to be operational until 2005.

 

Capital Expenditures, Capital Resources and Liquidity

 

For the years ended December 31, 2003, 2002 and 2001, capital expenditures were $31.2, $11.5 and $1.9 million, respectively.  The primary sources of funding have been borrowings under our credit facilities with a Kazakhstan bank (as described in more detail below and in Note 6 to the Notes to Consolidated Financial Statements) and private placements of common stock.  From inception through December 31, 2003, we have received a total of $7.4 million in net cash proceeds from sales of common stock.  Our cumulative proceeds from all borrowings, net of repayments, have amounted to $40.9 million since inception.

 

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.  However, this amount remained unpaid at December 31, 2003.  It was

 

15

 

subsequently paid in February 2004 from the proceeds of a private placement of common stock.  In connection with this bank financing, in February 2002, the Company granted an option to Bramex to acquire 50% of the common stock of Caspi Neft.  In order to exercise this option, Bramex was required to arrange $30.0 million in additional financing for Caspi Neft and was also required to pay $15.0 million to Caspi Neft, the proceeds of which were to be dedicated to the repayment of debt.  Bramex completed all required terms to exercise the option and paid the $15.0 million exercise price in February 2004.  See Notes 6 and 12 of the Notes to Consolidated Financial Statements for further information.

 

In June 2003, Caspi Neft entered into a second facility with the same Kazakhstan bank in the amount of $30.0 million.  The funds from this facility have been and will continue to be used for the ongoing development of the project.  As of December 31, 2003, the amount utilized totaled $23.0 million.  The balance outstanding under the credit facility in May 2005 is payable in 36 monthly installments from June 2005 through May 2008.  The available borrowing capacity at December 31, 2003 was approximately $7.0 million.  Management intends to utilize this amount in connection with its continuing capital program in the South Alibek Field.

 

Caspi Neft has a 2004 capital budget for the South Alibek Field of approximately $25.9 million.  This budget contemplates the continuous operation of two drilling rigs in the Field and also includes expenditures to complete construction of the central production facility and other support facilities for the Field.  The drilling budget includes the completion of the two wells in progress at the end of 2003, the SA-2 and SA-4, the drilling and completion of four additional wells during 2004 and the commencement of two additional wells before the end of 2004.  Accordingly, including the SA-1 which is currently producing, the 2004 budget would envision a cumulative total of seven wells drilled and completed in the Field by the end of next year, assuming all of such wells are successful, and two wells in progress.

 

In order to execute the 2004 Budget, Caspi Neft will be dependent on additional funding.  The Company currently estimates the minimum funding requirements for 2004 related to its 50% interest in Caspi Neft to be between $5.0 million and $10.0 million.  The other 50% owner of Caspi Neft, Bramex, has indicated that they have available funds to finance their proportionate share of the capital required to fully fund the 2004 budget.  The Company may seek to raise capital in excess of this amount to allow it fund new initiatives, further accelerate development of the Field and provide greater assurance of its ability to meet its future financial commitments.  The minimum amount of funding required is highly dependent on the amount and timing of cash flows from the existing and future wells drilled on the property.  The Company’s near-term goal is to develop sufficient revenues from production to fund continuing capital expenditures and meet its minimum debt service requirements.  The amount of capital needed is also dependent on many factors outside the control of the Company, including the costs and results of drilling operations, the ability to effectively bring its future crude oil production to market and future world oil prices.  If the Company is not able to secure such additional funding, it may be necessary to delay certain capital expenditures, including drilling costs.  Such actions could result in delays in the timing of future cash flows and could adversely affect the financial position of the Company.  The Company believes that it will be able to secure the necessary funding to continue development of the Field in accordance with its current development plans.  However, the Company cannot provide assurance that it will be successful as many of the factors required to execute its plans are outside the control of the Company.

 

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

 

Contractual obligations		2004(3)			2005			2006			2007			Thereafter
Long-tern debt (1)		$	19,990,125		$	6,140,366		$	7,669,199		$	7,669,199		$	3,195,512
Lease commitments(2)		186,000			186,000			186,000			151,000			—
Total contractual obligations		$	20,176,125		$	6,326,366		$	7,855,199		$	7,820,199		$	3,195,512

 

(1)          See Note 6 of the Notes to Consolidated Financial Statements.

 

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(2)          See Note 10 of the Notes to Consolidated Financial Statements.

 

(3)   The amounts shown for 2004 do not include interest payable, redeemable common stock and other amounts which are considered short term liabilities.  See Note 6 and 7, respectively, of the Notes to 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.

 

Development Stage and Going Concern

 

We are a development stage company and are in the early stages of establishing production and revenues from the development of our primary property in Kazakhstan.  Our ability to realize the carrying value of our assets is dependent on being able to produce and sell significant quantities of oil from the South Alibek Field.  Our financial statements have been presented on the basis that we are a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business.  We have accumulated losses of approximately $12.1 million and have incurred a significant amount of debt in the development phase of our operations.  To fully develop the Field and achieve positive cash flow, we will require additional funding.  The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts and classification of liabilities which might be necessary should the Company be unable to continue in existence.

 

Principles of Consolidation

 

Our consolidated financial statements include all of our consolidated subsidiaries.  Our most significant wholly-owned 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.

 

In February 2002, we granted Bramex a two-year option to acquire a 50% equity interest in Caspi Neft, the subsidiary which holds our interest in the South Alibek Field.  In order to exercise the option, Bramex was required to provide $50.0 million in commercial financing to Caspi Neft in two tranches of $20.0 million and $30.0 million, respectively.  After this financing had been provided, Bramex could exercise the option by the payment of $15.0 million, the proceeds of which were to be dedicated to the retirement of part of Caspi Neft’s debt.  Bramex completed all terms and funding necessary to exercise the option on February 4, 2004.  As a result of the option exercise by Bramex, we may no longer be eligible to fully consolidate Caspi Neft after February 4, 2004, which would materially affect the presentation of our financial statements.  The resulting accounting treatment would be dependent on the degree of management control we retain over Caspi Neft and other factors related to the economic substance of our arrangement with Bramex.  Additionally, our net interest in the oil and gas reserves of the Field will be proportionally reduced to reflect the new ownership structure.  See additional information on this matter in Note 12 of the Notes to Consolidated Financial Statements.

 

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.  However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in 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.  Changes in prices and cost levels, as well as the timing of future development costs, may

 

17

 

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 provided by new legislation which came into effect in 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 were not successful in negotiating a production contract on acceptable terms, it would 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 years ended December 31, 2003 and 2002, we capitalized $4.2 million and $1.3 million, respectively, of interest costs, which reduced our reported net interest expense to $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, 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

 

Effective January 1, 2003, Transmeridian adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations (“SFAS No. 143”) using a cumulative effect approach to recognize transition amounts for asset retirement obligations, asset retirement costs and accumulated depreciation.  SFAS No. 143 requires liability recognition for retirement obligations associated with tangible long-lived assets, such as producing well sites, offshore production platforms, and natural gas processing plants.  The obligations included within the scope of SFAS No. 143 are those for which a company faces a legal obligation.  The initial measurement of the asset retirement obligation is to record a separate liability at its fair value with an offsetting asset retirement cost recorded as an increase to the related property and equipment on the balance sheet.  The asset retirement cost is depreciated using a systematic and rational method similar to that used for the associated property and equipment.  Based on operations completed as of December 31, 2003, the estimated future dismantlement, restoration and abandonment obligation related to the South Alibek Field was $186,000 and there was no cumulative effect upon adoption of SFAS No. 143.

 

In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (“FIN 46R”) which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity.  FIN 46R replaces FASB Interpretation No. 46, Consolidation of Variable Interest Entities, which was issued in January 2003.  Transmeridian will be required to apply FIN 46R to variable interests in variable interest entities (“VIEs”) created after December 31, 2003.  For variable interests in VIEs created before January 1, 2004, FIN 46R will be applied beginning on January 1, 2005.  For any VIEs that must be consolidated under FIN 46R that were created before January 1, 2004, the assets, liabilities and noncontrolling interests of the VIE initially would be measured at their carrying amounts with any difference between the net amount added to the consolidated balance

 

18

 

sheet and any previously recognized interest being recognized as the cumulative effect of a change in accounting principle.  If determining the carrying amounts is not practicable, fair value at the date FIN 46R first applies may be used to measure the assets, liabilities and noncontrolling interest of the VIE.  FIN 46R is not expected to affect our consolidated financial statements.

 

SFAS Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity, (“SFAS No. 150”) was issued in May 2003.  SFAS No. 150 establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity.  SFAS No. 150 also includes required disclosures for financial instruments within its scope.  SFAS No. 150 was effective for instruments entered into or modified after May 31, 2003 and otherwise will be effective as of January 1, 2004, except for mandatory redeemable financial instruments.  For certain mandatory redeemable financial instruments, SFAS No. 150 will be effective on January 1, 2005.  The effective date has been deferred indefinitely for certain other types of mandatory redeemable financial instruments.  SFAS No. 150 is not expected to affect our consolidated financial statements.

 

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

 

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.  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.  All of our sales of crude oil have been based on prevailing current market prices at the time of sale.  As of December 31, 2003 we have not entered into any long-term sales arrangements or financial hedging activities with respect to projected oil production and we do not anticipate entering into any such arrangements at this time.  We may consider long-term sales arrangements or hedging at some point in the future.

 

Interest Rate Risk

 

At December 31, 2003, Transmeridian had long-term debt outstanding of $24.6 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.

 

19

 

 

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.

 

20

Item 8.  Financial Statements

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

Report of Independent Certified Public Accountants
Consolidated Balance Sheets as of December 31, 2003 and 2002
Consolidated Statements of Operations for the Years Ended December 31, 2003, 2002 and 2001 With Cumulative Total from Inception to December 31, 2003
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2003, 2002 and 2001
Consolidated Statements of Cash Flows for the Years Ended December 31, 2003, 2002 and 2001 With Cumulative Total from Inception to December 31, 2003
Notes to Consolidated Financial Statements

 

21

 

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 (a development stage company) as of December 31, 2003 and 2002, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years ended December 31, 2003, 2002 and 2001 and for the period from inception to December 31, 2003.  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 auditing standards generally accepted in the 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, 2003 and 2002 and the consolidated results of their operations and cash flows for each of the years ended December 31, 2003, 2002 and 2001 and for the period from inception to December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

 

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern.  As shown in the financial statements, the Company has incurred cumulative net losses totaling $12,061,436 through December 31, 2003, and, as of that date, the Company’s current liabilities exceeded its current assets by $29,850,854.  These factors, among others, including the Company’s ability to develop its proved reserves, as discussed in Note 2 to the consolidated financial statements, raise substantial doubt about the Company’s ability to continue as a going concern.  Management’s plans in regard to these matters are also described in Note 2.  The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

 

/s/	John A. Braden & Company, P.C.
John A. Braden & Company, P.C.
Houston, Texas
March 22, 2004

 

22

 

Transmeridian Exploration, Inc. and Subsidiaries
(A Development Stage Company)
Consolidated Balance Sheets
As of December 31, 2003 and 2002

 

		2003			2002
ASSETS
Current assets:
Cash and cash equivalents		$	1,321,514		$	624,807
Receivables		143,135			5,527
Crude oil inventory		509,156			—
Prepaid expenses		93,999			183,391
Total current assets		2,067,804			813,725
Property and equipment:
Oil and gas properties, successful efforts method		48,800,256			18,167,880
Drilling rig and equipment		6,484,983			6,040,818
Transportation equipment		239,821			222,844
Office and technology equipment		253,351			170,847
Total property and equipment		55,778,411			24,602,389
Less accumulated depreciation		1,217,836			205,790
Net property and equipment		54,560,575			24,396,599
Other assets		470,693			1,061,090
Total assets		$	57,099,072		$	26,271,414
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$	3,268,552		$	1,419,004
Current maturities of long-term debt		20,176,205			3,842,992
Redeemable common stock		2,000,000			2,000,000
Deferred revenue		509,156			—
Interest payable		5,716,720			1,127,106
Notes payable to related parties		248,025			248,025
Total current liabilities		31,918,658			8,637,127
Long-term debt, net of current maturities		24,488,196			13,752,304
Other long term liabilities		186,000			—
Stockholders’ equity:
Preferred stock, 5,000,000 shares authorized		—			2
Common stock, $0.0006 par value per share,  200,000,000 shares authorized		42,404			35,488
Additional paid-in capital		12,525,250			10,201,625
Deficit accumulated during development stage		(12,061,436		)	(6,355,132		)
Total stockholders’ equity		506,218			3,881,983
Total liabilities and stockholders’ equity		$	57,099,072		$	26,271,414

 

The accompanying notes are an integral part of these statements.

 

23

 

Transmeridian Exploration, Inc. and Subsidiaries
(A Development Stage Company)
Consolidated Statements of Operations
For the years ended December 31, 2003, 2002 and 2001

 

											Cumulative Total from Inception to December 31, 2003
		For the years ended December 31,
		2003			2002			2001
Oil revenues		$	797,411		$	—		$	51,289		$	848,700
Operating and administrative expenses		5,712,440			2,936,603			1,975,534			10,811,717
Operating loss		(4,915,029		)	(2,936,603		)	(1,924,245		)	(9,963,017		)
Other income (expense):
Gain on sale of working interest		—			—			—			414,146
Interest income		870			3,929			—			4,799
Start-up costs		—			—			—			(246,484		)
Interest expense, net of capitalized interest		(772,409		)	(338,229		)	(188,645		)	(2,090,353		)
Total other income (expense)		(771,539		)	(334,300		)	(188,645		)	(1,917,892		)
Net loss		(5,686,568		)	(3,270,903		)	(2,112,890		)	(11,880,909		)
Preferred dividends		(19,736		)	(37,520		)	(123,271		)	(180,527		)
Net loss attributable to common stockholders		$	(5,706,304	)	$	(3,308,423	)	$	(2,236,161	)	$	(12,061,436	)
Basic and diluted loss per share		$	(0.09	)	$	(0.06	)	$	(0.04	)
Weighted average common shares outstanding		64,573,627			58,142,461			59,621,255

 

The accompanying notes are an integral part of these statements.

 

24

 

Transmeridian Exploration, Inc. and Subsidiaries
(A Development Stage Company)
Consolidated Statements of Stockholders’ Equity
For the years ended December 31, 2003, 2002 and 2001

 

		Preferred shares		Preferred stock			Common shares		Common stock			Additional paid-in capital			Accumulated deficit			Treasury stock			Total
							(in 000’s)
Balances at December 31, 2000		3,000		$	2		57,797		$	34,678		$	4,172,329		$	(810,548	)	$	—		$	3,396,461
Proceeds from the sale of common stock, net of offering costs		—		—			2,824		1,694			1,633,319			—			—			1,635,013
Preferred stock exchanged for working interest		100,000		60			—		—			1,499,940			—			—			1,500,000
Common stock issued for services		—		—			126		76			153,424			—			—			153,500
Purchase of treasury stock		—		—			—		—			—			—			(1,320		)	(1,320		)
Proceeds from the sale of treasury stock, net of offering costs		—		—			—		—			1,540,000			—			1,320			1,541,320
Beneficial conversion feature on convertible preferred stock		—		—			—		—			52,969			(52,969		)	—			—
Accrued dividends on convertible preferred stock		—		—			—		—			—			(70,302		)	—			(70,302		)
Retirement of common stock		—		—			(5,000	)	(3,000		)	—			—			—			(3,000		)
Net loss		—		—			—		—			—			(2,112,890		)	—			(2,112,890		)
Balances at December 31, 2001		103,000		$	62		55,747		$	33,448		$	9,051,981		$	(3,046,709	)	$	—		$	6,038,782
Conversion of preferred stock		(100,000	)	(60		)	1,500		900			(840		)	—			—			—
Common stock issued for services		—		—			4,100		2,460			767,540			—			—			770,000
Proceeds from the sale of common stock, net of offering costs		—		—			500		300			99,900			—			—			100,200
Common stock used to retire deferred financing obligation		—		—			4,000		2,400			197,600			—			—			200,000
Beneficial conversion feature on convertible debentures		—		—			—		—			35,924			—			—			35,924
Issuance of warrants in connection with convertible debentures		—		—			—		—			20,000			—			—			20,000
Capital contributed by stockholder		—		—			—		—			25,500			—			—			25,500
Accrued dividends on convertible preferred stock		—		—			—		—			—			(37,520		)	—			(37,520		)
Retirement of common stock		—		—			(6,700	)	(4,020		)	4,020			—			—			—
Net loss		—		—			—		—			—			(3,270,903		)	—			(3,270,903		)
Balances at 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
Accrued dividends on convertible preferred stock		—		—			—		—			—			(19,736		)	—			(19,736		)
Net loss		—		—			—		—			—			(5,686,568		)	—			(5,686,568		)
Balances at December 31, 2003		—		$	—		70,673		$	42,404		$	12,525,250		$	(12,061,436	)	$	—		$	506,218

 

The accompanying notes are an integral part of these statements.

 

25

 

Transmeridian Exploration, Inc. and Subsidiaries
(A Development Stage Company)
Consolidated Statements of Cash Flows
For the years ended December 31, 2003, 2002 and 2001

 

											Cumulative Total from Inception to December 31, 2003
		For the years ended December 31,
		2003			2002			2001
Cash flows from operating activities:
Net loss		$	(5,686,568	)	$	(3,270,903	)	$	(2,112,890	)	$	(11,880,909	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization		245,712			51,859			9,481			308,002
Amortization of debt financing costs		184,166			126,390			—			310,556
Amortization of prepaid contracts		411,355			306,250			—			717,605
Stock based compensation expense		122,800			—			—			122,800
Exploration expense		277,012			—			—			277,012
Stock issued for services		285,299			35,000			153,500			1,020,199
Increase in interest payable		424,920			—			—			424,920
Imputed interest expense		—			35,924			—			35,924
Gain on sale of working interest		—			—			—			(414,146		)
Decrease (increase) in receivables		(49,465		)	9,753			(270,112		)	(309,824		)
Increase in prepaid expenses		89,392			(157,891		)	—			(118,059		)
Increase in accounts payable and accrued liabilities		40,687			807,321			339,724			1,419,171
Net cash used in operating activities		(3,654,690		)	(2,056,297		)	(1,880,297		)	(8,086,749		)
Cash flows from investing activities:
Capital expenditures		(31,176,022		)	(11,486,100		)	(1,813,713		)	(47,743,010		)
Non-cash portion of capital expenditures		6,835,378			1,127,106			—			7,962,484
Capitalized Depreciation		766,333			143,501			—			909,834
Increase in other assets		(65,997		)	(83,898		)	—			(149,895		)
Proceeds from the sale of working interest		—			—			—			614,146
Net cash used in investing activities		(23,640,308		)	(10,299,391		)	(1,813,713		)	(38,406,441		)
Cash flows from financing activities:
Proceeds from long-term debt		28,807,214			14,672,759			1,710,103			45,690,234
Repayments of long-term debt		(1,515,509		)	(1,877,463		)	(210,103		)	(3,603,075		)
Increase in notes payable to related parties		—			248,025			—			248,025
Payment of deferred financing costs		(300,000		)	(200,000		)	—			(500,000		)
Payment of dividends on preferred stock		—			(70,302		)	—			(70,302		)
Purchase of treasury stock		—			—			(1,320		)	(1,320		)
Proceeds from sale of treasury stock, net		—			—			1,541,320			1,541,320
Proceeds from sale of common stock, net		1,000,000			100,200			1,635,013			5,895,664
Repayment of amounts due to third parties		—			—			(1,385,842		)	(1,385,842		)
Net cash provided by financing activities		27,991,705			12,873,219			3,289,171			47,814,704
Net increase (decrease) in cash and cash equivalents		696,707			517,531			(404,839		)	1,321,514
Cash and cash equivalents, beginning of period		624,807			107,276			512,115			—
Cash and cash equivalents, end of period		$	1,321,514		$	624,807		$	107,276		$	1,321,514

 

The accompanying notes are an integral part of these statements.

 

26

 

Transmeridian Exploration, Inc. and Subsidiaries
(A Development Stage Company)
Consolidated Statements of Cash Flows – Supplemental Information
For the years ended December 31, 2003, 2002 and 2001

 

											Cumulative Total from Inception to December 31, 2003
		For the years ended December 31,
		2003			2002			2001
Amounts paid for:
Interest		$	187,613		$	393,452		$	174,534		$	1,546,668
Interest capitalized (non-cash)		(4,164,694		)	(1,285,994		)	—			(6,997,356		)
Income taxes		—			—			—			—
Non-cash transactions:
Common stock issued for services		$	833,267		$	770,000		$	153,500		$	2,303,167
Issuance of common stock to settle deferred financing obligation		—			200,000			—			200,000
Accrued and unpaid dividends on convertible preferred stock		19,736			37,520			70,302			107,822
Capital contribution by stockholder for investor relations services		—			25,500			—			25,500
Issuance of warrants in connection with services		21,000			—			—			21,000
Issuance of warrants in connection with convertible debentures		—			20,000			—			20,000
Asset retirement obligation		186,000			—			—			186,000
Retirement of common stock		—			4,020			3,000			7,020
Exchange of convertible preferred stock for common stock		2			60			—			62
Acquisition of drilling rig for debt and redeemable common stock		—			—			5,300,000			5,300,000
Issuance of preferred stock in exchange for working interest		—			—			1,500,000			1,500,000
Deferred financing costs incurred but not paid in cash		—			—			400,000			400,000
Acquisition of oil and gas properties for debt		—			—			—			1,385,842
Conversion of debt to preferred stock		—			—			—			300,158
Conversion of debt to common stock		296,217			—			—			296,217
Issuance of common stock in exchange for dividends payable on preferred stock		57,255			—			—			57,255

 

The accompanying notes are an integral part of these financial statements

 

27

 

Transmeridian Exploration, Inc. and Subsidiaries

(A Development Stage Company)

Notes to Consolidated Financial Statements

December 31, 2003

 

Note 1 – Organization and Summary of Significant Accounting Policies

 

Transmeridian Exploration, Inc. (the “Company”) was incorporated in the State of Delaware in April 2000.  The Company’s primary operations are conducted in the Republic of Kazakhstan, through its wholly owned subsidiary, Caspi Neft TME (“Caspi Neft”), which is a Kazakhstan Subsidiary Open Joint Stock Company.

 

Risk Factors

 

The Company is a development stage entity organized to acquire and develop oil and gas properties.  Its primary asset is License 1557 and the related Exploration Contract for the development of the South Alibek Field (the “Field”) in Kazakhstan.  The Company’s primary emphasis since its formation in 2000 has been the exploration and development of the Field.

 

The Company’s operations are subject to various risks inherent in foreign operations.  These risks may include loss of revenue, property or commercial rights as a result of government action or other hazards, such as war or civil unrest.  The Company’s business is also subject to all the operating risks normally associated with the exploration and development of oil and gas properties.

 

Principles of Consolidation

 

Our consolidated financial statements include all of our consolidated subsidiaries.  Our most significant wholly-owned 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.

 

In February 2002, we granted Bramex Management, Inc. (“Bramex”), the successor to Kazstroiproekt, Ltd. (“KSP”), a two-year option to acquire a 50% equity interest in Caspi Neft, the subsidiary which holds the rights to the South Alibek Field.  In order to exercise the option, Bramex was required to provide $50.0 million in commercial financing to Caspi Neft in two tranches of $20.0 million and $30.0 million, respectively.  After this financing had been provided, Bramex could exercise the option by the payment of $15.0 million, the proceeds of which were to be dedicated to the retirement of part of Caspi Neft’s debt.  Bramex completed all terms and funding necessary to exercise the option on February 4, 2004.  As a result of the option exercise by Bramex, we may no longer be eligible to fully consolidate Caspi Neft after February 4, 2004, which would materially affect the presentation of our financial statements.  The resulting accounting treatment would be dependent on the degree of management control we retain over Caspi Neft and other factors related to the economic substance of our arrangement with Bramex.  Additionally, our net interest in the oil and gas reserves of the Field will be proportionally reduced to reflect the new ownership structure.  See additional information on this matter in Note 12.

 

Use of Estimates

 

To prepare financial statements in conformity with U.S. generally accepted accounting principles, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Actual results may differ materially from those estimates.

 

28

 

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.

 

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 dismantlement, restoration and abandonment costs, net of salvage values, are included in the calculation of costs to be amortized.  Under Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations”, which the Company is required to implement effective January 1, 2003, the discounted present value of future dismantlement, restoration and abandonment costs will be recognized as a liability on the balance sheet with the offsetting entry recorded as part of the cost of the asset.  The accretion of the discounted liability will be recognized as an operating expense.  Based on the operations completed as of December 31, 2003, the estimated future dismantlement, restoration and abandonment costs related to the South Alibek Field are estimated to be $186,000.

 

Periodically, or when circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future 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 for use in the development of the South Alibek Field.  The rig was placed in service in October 2002 and is being depreciated on the straight-line method over an estimated useful life of 10 years.  Depreciation of the rig, as well as depreciation of other support equipment used in exploration and development activities, is capitalized under the successful efforts method as part of the cost of oil and gas properties.

 

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

 

29

 

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 a part of the cost of unproved 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, 2003 and 2002 totaled $4.2 million and $1.3 million, respectively.  There was no interest capitalized during 2001.

 

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 carryforwards 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.

 

Start-up Costs

 

Start-up costs, including organizational expenses, are expensed as incurred.

 

Debt Financing Costs

 

In April 2001, the Company entered into an agreement to pay a business and financial consulting firm $400,000 for assistance in obtaining $20.0 million in financing for the development of the South Alibek Field.  The consultant was successful in arranging the financing package, which closed in February 2002.  Under the terms of the agreement, one half of the debt placement fee was to be paid in cash.  The balance of $200,000 could be retired with the issuance of 4,000,000 shares of common stock or paid in cash at the Company’s option.  The Company paid one half of the obligation in cash in 2002 and elected to retire the balance with the issuance of common stock.  The deferred debt financing costs are being amortized over the three year term of the financing.

 

In August 2002, in connection with the issuance of $200,000 in convertible debentures, the Company issued 200,000 warrants at $0.42 per share to the lender.  These warrants were valued at $20,000 using the Black-Scholes model and are being amortized as deferred financing costs over the two year term of the convertible debentures.  The unamortized portion of these costs was charged to expense upon the early retirement of the convertible debentures.

 

In June 2003, in connection with the new $30.0 million credit facility, the Company was obligated to pay a commitment fee of $300,000.  Such amount is being amortized over the five year term of the 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 the periods presented because the effects of potentially dilutive securities are antidilutive.

 

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

 

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Revenue Recognition

 

The Company sells its Kazakhstan production in the 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 which is offset by deferred revenue.  Such oil inventory and deferred revenues are valued at the price of the last oil sold.

 

Foreign Exchange Transactions

 

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 statements of operations at the time of each transaction.  Translation differences, if any, are considered to be immaterial.

 

Stock-Based Compensation

 

The Company accounts for employee stock-based compensation using the fair value method as prescribed in SFAS No. 123.  Under this method, the Company records the fair value attributable to stock options granted, 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.  See Note 6 for discussion of long-term debt.

 

Reclassifications and Adjustments

 

Certain prior period amounts have been reclassified to conform to the presentation in the consolidated financial statements as of December 31, 2003.

 

Note 2 – Going Concern

 

The Company is a development stage company and is in the early stages of establishing production and revenues from the development of its primary property in Kazakhstan.  The ability of the Company to realize the carrying value of its assets in the ordinary course of business is dependent on being able to produce and sell significant quantities of oil from the South Alibek Field.  The Company’s primary emphasis since inception has been the exploration and development of the Field, and the Company has invested approximately $55.8 million in property and equipment through December 31, 2003.  This amount includes the initial costs of acquiring the Field, workover and drilling costs, and the costs of support facilities, including a drilling rig dedicated to the Field.  The Field has four wells which have proved reserves and one is currently producing approximately 1,000 Bopd on a test basis.  The Company has drilled and is currently testing the second and third wells in the field.  These wells and subsequent wells will delineate the extent and reserve potential of the Field.  The economic success of the Field is dependent on finding and developing sufficient reserves and rates of production to generate positive cash flow and provide an economic rate of return on the investment in the Field.  In order to sell significant quantities of oil from the Field over the long-term, the Company must obtain a production contract from the government of Kazakhstan.

 

The Company’s financial statements have been presented on the basis that it is a going concern, which contemplates the realization of assets and satisfaction of liabilities in the normal course of business.  The Company has accumulated losses totaling $12.1 million and has incurred a significant amount of debt in the development phase of its operations.  As of December 31, 2003, current liabilities exceed current assets by $29.9 million.  Additionally, to fully develop the area covered by the Field, the Company will

 

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require additional funding and such amounts may be substantial.  Recoverability of a major portion of the recorded asset amounts shown in the accompanying consolidated balance sheet is dependent upon continued operations of the Company.  Continued operations are dependent upon the Company’s ability to meet its financial obligations and to secure additional funding.  The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts and classification of liabilities which might be necessary should the Company be unable to continue as a going concern.

 

Management has taken steps and has the following plans which it believes will be sufficient to enable the Company to continue in existence:

 

1)               Subsequent to December 31, 2003, the Company made a private placement of common stock in the amount of $4.4 million.  The primary use of proceeds for this placement was the retirement of $2.9 million in debt owed to the bank in Kazakhstan, which was originally due in August 2003.  As a result of this debt repayment, both Caspi Neft and Transmeridian are fully in compliance with all terms of the debt agreements relating to the Field.

 

2)               After completion of the $4.4 million private placement and repayment of the debt discussed above, the Company had sufficient cash reserves to fund its US operations for a period in excess of one year, assuming a reasonable continuation of current expenditure levels.

 

3)               In February 2002, as more fully described in Note 6, the Company obtained $20.0 million in debt financing from a bank in Kazakhstan.  The available capacity under this facility was fully utilized during April 2003.  In June 2003, as more fully described in Note 6, the Company obtained an additional $30.0 million in debt financing from the same bank in Kazakhstan.  The available capacity under this facility was approximately $7.0 million at December 31, 2003.

 

4)               The Company is dependent on additional funding to continue development of the South Alibek Field in accordance with its current development plans, which envision the continuous use of two drilling rigs.  The Company currently estimates the funding requirements for 2004 related to its 50% interest in Caspi Neft to be between $5.0 million and $10.0 million.  The Company may seek to restructure the existing debt, raise capital in excess of this amount to allow it to fund new initiatives, further accelerate development of the Field and provide greater assurance of its ability to meet its future financial commitments.  The minimum amount of funding required is highly dependent on the amount and timing of cash flows from the existing and future wells drilled on the property.  The Company’s near-term goal is to develop sufficient revenues from production to fund continuing capital expenditures and meet its minimum debt service requirements.  The amount of capital needed is also dependent on many factors outside the control of the Company, including the costs and results of drilling operations, the ability to effectively bring its future crude oil production to market and future world oil prices.  If the Company is not able to secure such additional funding, it may be necessary to delay certain capital expenditures, including drilling costs.  Such actions could result in delays in the timing of future cash flows and could adversely affect the financial position of the Company.  The Company believes that it will be able to secure the necessary funding to continue development of the Field in accordance with its current development plans.  However, the Company cannot provide assurance that it will be successful as many of the factors required to execute its plans are outside the control of the Company.

 

Note 3 – Property and Equipment

 

Oil and Gas Properties

 

License 1557 (the “License”), covering the South Alibek Field, was granted by the Republic of Kazakhstan on April 29, 1999.  The original License 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 license area.  In November 2001, the Company’s application was approved and the License was expanded to cover an area of

 

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14,111 acres.  Through Caspi Neft, the Company owns 100% of the working interest in the Field, subject to a 10% carried working interest and an option agreement under which Bramex may acquire 50% of the stock of Caspi Neft.  This option was exercised by Bramex subsequent to December 31, 2003.

 

The Exploration Contract (the “Exploration Contract”) associated with the License has a six-year term which expires in April 2005.  The Contract requires capital expenditures during this period of approximately $18.0 million.  As of December 31, 2003, the cumulative capital expenditures which are creditable to our obligation under the Contract have exceeded the minimum Contract commitment.  The Contract may be extended by mutual agreement for two extension periods of two years each.  During the primary term, the Company can produce wells under a test program and pay a royalty of 2%.  Any extension periods would need to be renegotiated with the government and would require additional capital commitments and could potentially include other changes in terms.  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.  The Production Contract, when executed, will contain the final terms for recovery of these costs.

 

If the Company is successful in establishing commercial production from the Field, an application will be made for a Production Contract (the “Production Contract”).  The Company has the exclusive right to negotiate this contract for the Field, and the government is required to conduct these negotiations under the 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.  A Production Contract will typically require a bonus payment upon execution, the amount of which is subject to negotiation.  If satisfactory terms cannot be negotiated, the Company has the right to produce and sell oil under the Law of Petroleum for the term of its existing Exploration Contract through April 2005 at a royalty rate of 2%.  The royalty rate under production contracts is determined on a sliding scale based on annual production.  The rates range from 2% to 6%.

 

Kornerstone Investment Group Ltd. (“Kornerstone”) was originally engaged by the founders of the Company to identify and assist in the acquisition of oil and gas properties in Kazakhstan and the Caspian Sea region.  The agreement with Kornerstone provided for compensation to Kornerstone in the form of a 10% carried working interest.  Under the terms of this carried interest, the Company is required to pay all acquisition, exploration, development and operating costs attributable to the 10% carried interest.  The Company is also entitled to receive all revenues attributable to the 10% carried interest until the Company’s costs are recovered.  Thereafter, Kornerstone will participate as a 10% working interest owner.

 

During 2002, the Company spent $33,484 to acquire leasehold interests for the development of two natural gas wells in South Texas.  In July 2003, the Company conducted an operation on one of the properties.  A downhole obstruction was encountered which prevented a successful test of the target formation and the property was abandoned.  We recorded a charge to exploration expense of $118,893 for this unsuccessful completion attempt.

 

Drilling Rig and Equipment

 

In December 2001, the Company purchased a drilling rig for $5.3 million in total consideration, including a note payable for $3.3 million and $2.0 million in common stock, which is redeemable for cash at the option of the seller of the rig.  See Notes 6 and 7 for further discussion of the terms of the note payable and redeemable common stock.

 

The rig was acquired for drilling operations in the South Alibek Field.  At the time the Company purchased the drilling rig, it was in storage in South America.  In early 2002, the Company arranged to have the rig transported to Kazakhstan via marine cargo vessel.  In addition, the Company undertook various refurbishments and modifications to the rig to make it suitable for use in the Company’s operations.  The Company contracted with a firm experienced in international drilling to operate the rig and provide expatriate drilling personnel.  The rig began drilling operations in October 2002.

 

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As more fully discussed in Note 10, there is a legal dispute between the Company, the seller of the rig and the holder of an apparent first lien on the drilling rig.

 

Note 4 – Other Assets

 

Other assets consist of the following:

 

		2003			2002
Debt financing costs, net of amortization		$	409,443		$	293,610
Prepaid investment advisory contract		61,250			428,750
Advances to Emba Trans Ltd.		—			338,730
		$	470,693		$	1,061,090

 

See Note 1 (Debt Financing Costs) for discussion of debt financing costs and Note 8 (Common Stock Issued for Services) for discussion of prepaid investment advisory contract.

 

As of December 31, 2002, the Company had made cumulative advances of $338,730 to Emba Trans Ltd.  These advances were used to fund the purchase of the Emba terminal, a facility for storing and loading crude oil for shipment by rail, which is intended to be used as an alternate transportation route for the Company’s production from the South Alibek Field.  At that time, ownership of Emba Trans Ltd. had not been legally transferred to the Company.  During 2003, title was transferred and the entity is now owned 75% by Caspi Neft and 25% by Transmeridian.  As of December 31, 2003, all costs related to Emba Trans Ltd and the Emba terminal are included in oil and gas properties, as this asset will be used as a support facility for production from the South Alibek Field.

 

Note 5 – Notes Payable to Related Parties

 

In a series of notes issued between June 2002 and November 2002, certain shareholders and related parties, including the Chief Executive Officer of the Company, loaned the Company $248,025.  These notes bear interest at 17% and are due on September 30, 2004.

 

Note 6 – Long-Term Debt

 

Long-term debt consists of the following:

 

		2003			2002
$20 million credit facility with a Kazakhstan bank		$	20,000,000		$	14,253,000
$30 million credit facility with a Kazakhstan bank		23,007,613			—
Note payable secured by drilling rig		1,656,788			3,142,296
Convertible debentures		—			200,000
Total debt (1)		44,664,401			17,595,296
Less current maturities		20,176,205			3,842,992
Long-term debt		$	24,488,196		$	13,752,304

 

Future maturities of long-term debt at December 31, 2003, are as follows:

 

 

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(1)          Does not include $2 million redeemable common stock due February 4, 2004.  See Note 7.

(2)          See Note 12 for discussion of debt payments subsequent to December 31, 2003.

 

Management believes the fair value of debt at December 31, 2003 and 2002 approximates its book value.

 

$20 Million Credit Facility

 

In February 2002, Caspi Neft entered into a credit facility with a Kazakhstan bank (the “$20 Million Facility”).  The Facility provides for borrowings totaling $20.0 million through July 1, 2003 for development of the South Alibek Field and is secured by the Field, the stock of certain subsidiaries, and the stock and other assets of Caspi Neft.  The $20 Million Facility carries an interest rate of 15% and a fee of 0.5% on the unutilized portion of the commitment.  The parent company, Transmeridian Exploration, Inc. has provided a corporate guarantee of $7.0 million.  Under the terms of the $20 Million Facility, the parent company was required to repay principal of $2.23 million and accrued interest in August 2003.  During late 2003, the Company was attempting to negotiate a one-year extension of this payment date and the bank had indicated its willingness to consider such an extension and had not declared this amount to be in default.  This amount was paid by the Company subsequent to December 31, 2003 with the proceeds from a private placement of common stock.

 

In connection with this financing, the Company granted an option to Bramex to acquire 50% of the common stock of Caspi Neft.  In order to exercise the option, Bramex was required to (1) arrange an additional $30.0 million of financing for Caspi Neft at market rates and (2) make a cash contribution to Caspi Neft of $15.0 million, the proceeds of which would be used to repay part of the $20 Million Facility.  As discussed in Note 12, this option was exercised by Bramex in February 2004.

 

Under the terms of the $20 Million Facility, the accrued interest balance is payable in February 2004 and the remaining principal balance at such date is payable in 12 monthly installments from March 2004 through February 2005.  See further discussion of these payment terms and amounts in Note 12.

 

$30 Million Credit Facility

 

In June 2003, Caspi Neft entered into a new $30.0 million credit facility with the same Kazakhstan Bank (the “$30 Million Facility”).  This facility provides for borrowings up to $30.0 million through May 31, 2005.  The amount outstanding as of May 31, 2005 is scheduled to be repaid over 36 equal monthly installments beginning June 2005 through the final maturity date of May 31, 2008.  The $30 Million Facility carries an interest rate of 15% and a commitment fee of 0.5% per annum on the unutilized portion.  Interest accrued during the first 24 months is payable on May 31, 2005; thereafter, interest is payable monthly.  Upon execution of the $30 Million Facility, Caspi Neft paid the bank an arrangement fee of $300,000, which has been capitalized as a deferred financing cost and will be amortized over the five-year life of the facility.

 

Both credit facilities contain certain restrictive covenants, including restrictions on disposing of material assets, paying dividends, use of crude oil sales and incurring additional indebtedness.  The Company is required to provide audited financial statements of Caspi Neft to the bank within 90 days of the end of the fiscal year.  The Company may not meet this requirement, but such non-compliance has been waived by the bank in prior years.  Both credit facilities are secured by substantially all of the assets of Caspi Neft, including the South Alibek License, and the stock of Caspi Neft.  The Company’s wholly-owned British Virgin Islands subsidiary has also guaranteed the loan.  Both facilities contain certain restrictive covenants, including restrictions on disposing of material assets, paying dividends and incurring additional indebtedness.

 

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 redeemable common stock of $2.0 million.  In July 2003, the Company was notified by the holder of an apparent first lien on the rig (the “First Lien Holder”) that the Seller was in default under its note payable obligation to the First Lien Holder.  The Company was not informed of the

 

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existence of the First Lien Holder in the Asset Purchase Agreement related to the acquisition of the drilling rig.  The note payable is now in dispute as a result of the Seller’s apparent default to the First Lien Holder.  The Company has 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.  See further discussion of this matter in Note 10.

 

Convertible Debentures

 

On August 5, 2002, the Company issued $200,000 in convertible debentures to Private Capital Group (“PCG”).  The debentures carried an interest rate of 7% and were due in August 2004.  PCG had the right to convert the debentures and accrued interest into shares of common stock of the Company.  The number of shares upon conversion was computed based upon a conversion ratio equal to the lesser of (i) $0.36 per common share or (ii) 85% of the average of the three lowest closing bid prices of the Company’s common stock during the twenty trading days immediately preceding the date that notice of conversion is given.

 

The 15% discount contained in the conversion terms represents a beneficial conversion feature as addressed in EITF 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios.”  The amount attributable to the beneficial conversion feature was $35,924.  This amount is recorded as additional paid-in capital and is recognized as additional interest expense over the period ending with the earliest conversion date.  Since the debentures were immediately convertible, the Company recognized the additional interest expense during 2002.

 

Additionally, PCG was granted warrants to purchase 200,000 shares of Company common stock at $0.42 per share, which expire in August 2005.  The warrants were valued at $20,000 using the Black-Scholes model.  This amount has been recorded as additional paid-in capital and deferred financing costs which will be amortized to interest expense over the two-year term of the convertible debentures.

 

In March 2003, PCG filed suit against the Company, which suit alleged that the Company had failed to comply with certain terms of the debentures.  In June 2003, the Company reached a Settlement Agreement with PCG.  Pursuant to the terms of the Settlement Agreement, the convertible debentures, accrued interest and $35,000 in litigation settlement costs were subsequently retired through the issuance of 1,081,865 shares of common stock and the payment of $30,000 in cash.  In connection with the settlement agreement, the Company expensed $10,833 in unamortized deferred financing costs associated with the convertible debentures.

 

Note 7 – Redeemable Common Stock

 

During December 2001, the Company purchased a drilling rig for use in its Kazakhstan operations.  Part of the consideration for the purchase was 1.0 million shares of common stock.  Under the terms of the purchase agreement, these shares were redeemable, at the option of the seller, for $2.00 per share, or $2.0 million in the aggregate, by the end of 2002.  This obligation was renegotiated on December 28, 2002 and now requires the redemption of the stock, at the option of the holder, on February 1, 2004.  The revised agreement also provides interest at 10% on the unpaid balance of the redemption amount.  In the event the seller sells any of the shares prior to February 1, 2004, the proceeds of such sales would reduce the redemption obligation of the Company.

 

As more fully discussed in Note 10, there is a legal dispute between the Company, the seller of the rig and the holder of an apparent first lien on the drilling rig.

 

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Note 8 – Stockholders’ Equity

 

12.5% Convertible Preferred

 

During 2000, the Company borrowed $300,158 from a third party, which carried interest at 12.5%.  The Company also issued warrants to purchase 1.2 million common shares at an exercise price of $1.00 per share.  The Company entered into a credit conversion agreement on August 23, 2000 under which the notes were exchanged for $300,158 of convertible preferred stock, consisting of 3,000 shares, with a par value of $0.0006 per share and a preference value of $100 per share.  The convertible preferred stock accrues dividends at 12.5%.  At the Company’s option, the preferred shares may be converted to common stock or redeemed in cash.  The conversion rate is 85% of the average bid price for the five previous consecutive trading days prior to the conversion date.  In connection with this credit conversion agreement, the Company issued 1.2 million shares of common stock in exchange for cancellation of the 1.2 million warrants outstanding.

 

The 15% discount contained in the conversion terms represents a beneficial conversion feature as addressed in EITF 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios.”  The amount attributable to the beneficial conversion feature was $52,969.  This amount is treated as additional paid-in capital and is recognized as an additional preferred stock dividend charged to retained earnings over the period ending with the earliest conversion date.  Since the preferred shares were immediately convertible, the Company recognized the additional preferred stock dividends during 2001.

 

In July 2003, the holders of all 3,000 shares of the outstanding 12.5% convertible preferred stock elected to convert their shares to common stock.  The $300,158 stated value of the preferred stock plus accrued dividends totaling $57,256 were converted into 1,545,910 shares of common stock, in accordance with the terms of the preferred stock agreement.  At the time of conversion, the convertible preferred stock was owned in equal amounts by the Chief Executive Officer of the Company and the operations manager of the Kazakhstan operations of Caspi Neft.

 

2001 Convertible Preferred

 

In connection with the acquisition of a 5% working interest in the South Alibek Field in April 2001, the Company issued 100,000 shares of convertible preferred stock.  This convertible preferred stock had no dividend obligation and was convertible into 1.5 million shares of the Company’s common stock.  In March 2002, the preferred stock was converted to common stock.

 

Common Stock Reserved for Issuance

 

There are 200,000,000 common shares authorized by the Company’s Amended and Restated Certificate of Incorporation and 70,673,207, 59,147,129 and 55,747,029 common shares were issued and outstanding as of December 31, 2003, 2002 and 2001, respectively.  These share totals exclude redeemable common stock.  Shares of common stock reserved for issuance at December 31, 2003 are summarized as follows:

 

 

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Common Stock Issued for Products and Services

 

The Company has entered into several agreements to exchange common stock for products and services, including investment advisory services, financial consulting and other services and products related to the operations of the Company.  The stock has been valued based on the fair market value of the stock at the time of the agreements or the value of the services rendered, whichever was more clearly evident.  During the years ended December 31, 2003, 2002 and 2001, the Company issued 5.3 million, 4.1 million and 126,000, common shares, respectively, for products and services.  Certain of the larger transactions which comprise these totals are discussed below.

 

In January 2003, 1.5 million shares, valued at $180,000, were issued to settle all remaining obligations in connection with the April 2002 resignation of the former Chairman of the Company, including obligations related to a consulting contract.  During 2003, the Company issued a total of 2.25 million shares of common stock, valued at $323,000, in exchange for drill pipe for use in its operations.  During 2003, the Company also issued 1.1 million shares to financial consultants, valued at $208,000, in exchange for work performed to improve financial reporting procedures and internal controls and other financial management services.

 

During 2002, 4.0 million shares were issued as compensation for investment advisory services, which was recorded as a prepaid expense of $735,000.  The agreement covers a two year period ending in February 2004 and the prepaid amount is being amortized to expense over its term.

 

Retirement of Common Stock

 

On several occasions, the founders and major shareholders of the Company have contributed common shares back to the Company, which were then retired.  Such share contributions were generally made to mitigate the dilutive effects of other share issuances by the Company.  During the years ended December 31, 2002 and 2001, the founders returned 6.7 million and 5.0 million common shares, respectively.  Additionally, in 2001, the Company purchased 2.2 million shares of treasury stock from the founders at par value.  These shares were subsequently sold in a private placement.  There were no such transactions in 2003.

 

Capital Contributed by Stockholder

 

In December 2002, the Chief Executive Officer of the Company transferred, from his personal holdings, 150,000 shares of the Company’s common stock as compensation for a contract with an investor relations firm.  The common stock was valued at $0.17 per share, or $25,500 in the aggregate, and has been recorded as contributed capital and a prepaid expense.  The cost of the services will be charged to expense over the term of the contract.

 

Warrants

 

In connection with the issuance of $200,000 of convertible debentures in August 2002, the Company issued warrants to purchase 200,000 shares of the Company’s common stock at $0.42 per share.  These warrants expire in August 2005.  The value of the warrants, calculated in accordance with the Black-Scholes model, was $20,000 and will be recognized as additional interest expense over the two year term of the debentures.

 

During 2003, the Company issued warrants to purchase 300,000 shares of common stock in connection with investor relations services.  Of such warrants, 150,000 carry an exercise price of $0.25 per share and are exercisable at any time prior to December 5, 2004.  The remaining 150,000 warrants carry an exercise price of $0.40 per share and are exercisable at any time prior to March 5, 2005.  The value of the warrants, calculated in accordance with the Black-Scholes model, was $21,000 on the date of issuance.  This amount will be amortized to expense over the term of the contract.

 

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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 had a term of five years.  The vesting period is determined by the Board of Directors at the date of grant.  As of December 31, 2003, options to purchase 1.74 million shares had been granted and 3.26 million options were available for future grants under the Plan.

 

No stock options were granted under the Plan prior to December 31, 2002.  The following table reflects additional information about options granted under the Plan during the year ended December 31, 2003.

 

		Options Outstanding					Options Exercisable
		Number Outstanding		Weighted Average Exercise Price			Number Exercisable		Weighted Average Exercise Price
		(In thousands)					(in thousands)
Options granted in 2003		1,740		$	0.253		75		$	0.240
Options exercised		—		—			—		—
Options forfeited		—		—			—		—
Balance at December 31, 2003		1,740		$	0.253		75		$	0.240

 

The aggregate fair value of options granted during 2003 was $243,575, which is being amortized to expense over the vesting period in accordance with FASB 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 4.5-5.0%; expected lives between 1 and 3 years; and volatility of the price of the underlying common stock of 41-100%.  Of such aggregate fair value amount, $117,383 was charged to expense during the year ended December 31, 2003.

 

The following table summarizes additional information about the Company’s stock options outstanding, and those which were exercisable, as of December 31, 2003:

 

		Options Outstanding							Options Exercisable
Range of Exercise Prices		Number Outstanding		Weighted Average Remaining Life		Weighted Average Exercise Price			Number Exercisable		Weighted Average Exercise Price
		(In thousands)							(In thousands)
$  0.215 - $0.240		1,630		4.58 Yrs		$	0.231		75		$	0.240
$  0.570 - $0.600		110		5.00 Yrs		$	0.597		—		—
Total at December 31, 2003		1,740		4.79 Yrs		$	0.253		75		$	0.240

 

2003 Stock Compensation Plan

 

In May 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.  Under the terms of the plan, such stock may be issued in lieu of cash to compensate officers, employees, directors and third-party consultants, all of whom must be individuals, for bona fide services rendered.  During the year

 

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ended December 31, 2003, 1.23 million shares of the 2.50 million shares described above were issued under the Form S-8 and 1.27 million shares were reserved for future issuance under the 2003 Stock Compensation Plan.

 

Note 9 – Income Taxes

 

Income before income taxes is composed of the following:

 

		Years Ended December 31,
		2003			2002			2001
United States		$	(2,939,691	)	$	(2,064,614	)	$	(135,320	)
International		(2,766,613		)	(1,206,289		)	(1,977,570		)
		$	(5,706,304	)	$	(3,270,903	)	$	(2,112,890	)

 

A reconciliation of the federal statutory income tax amounts to the effective amounts is shown below:

 

		Years Ended December 31,
		2003			2002			2001
Income tax benefit computed at statutory rates		$	(1,940,143	)	$	(1,112,107	)	$	(718,383	)
Adjustment to valuation allowance		1,940,143			1,112,107			718,383
		$	—		$	—		$	—

 

At December 31, 2002 and 2001 the components of the Company’s deferred tax assets and liabilities were as follows:

 

		As of December 31,
		2003			2002			2001
Capitalized interest		$	(1,853,000	)	$	(437,000	)	$	—
Net operating loss carryforwards		5,866,000			2,543,000			990,000
Valuation allowance		(4,013,000		)	(2,106,000		)	(990,000		)
		$	—		$	—		$	—

 

As of December 31, 2003, the Company has estimated net operating loss carryforwards of $6.2 million in the U.S. and $11.1 million in Kazakhstan.  The net operating loss carryforwards include the deduction of $5.5 million in interest which has been capitalized for book purposes.  If they are not utilized prior to these dates, the U.S. net operating losses will expire between 2020 and 2022, while the Kazakhstan net operating losses will expire in 2009 and 2010.

 

The Company has not recorded any deferred tax assets or income tax benefits from the net operating losses for the years ended December 31, 2003, 2002 and 2001.  The Company has placed a 100% valuation allowance against the deferred tax asset because future realization of the net operating losses is not assured.

 

Note 10 – Commitments and Contingencies

 

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 3, 6 and 7.  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

 

40

 

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 increasing 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.

 

Threatened Claims

 

In early 2003, an attorney for the former Chief Financial Officer of the Company sent a demand letter asserting claims relating to his separation of service from the Company and threatening further legal action.

 

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, 2003, the cumulative capital expenditures which are creditable to our obligation under the Contract have exceeded the minimum Contract commitment.

 

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

 

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 $930,698, $378,000 and $178,000 in 2003, 2002 and 2001, respectively.

 

The Company leases office facilities in Houston and Kazakhstan under leases greater than one year.  Future minimum lease commitments under long-term non-cancelable operating leases are as follows:

 

 

41

 

Note 11 – Business Segment Information

 

The Company’s business activities relate solely to oil and gas exploration and production.  The primary emphasis since its formation in 2000 has been the development of the South Alibek Field.  In 2002, the Company made an initial investment in U.S. properties.  The drilling rig purchased in 2001 is used to support the Company’s development activities in Kazakhstan.  At December 31, 2003, 2002 and 2001, substantially all of the Company’s assets were located in Kazakhstan.  For each of the three years ended December 31, 2003, substantially all of the Company’s results of operations were general and administrative, operating and other start-up costs associated with its operations in Kazakhstan.

 

For the year ended December 31, 2003, 100% of the oil sold from the South Alibek Field was purchased by a single company.

 

Note 12 – Subsequent Events

 

On January 9, 2004, Transmeridian sold 7.3 million shares of common stock in a private placement for net cash proceeds totaling $4.4 million.  The shares were purchased primarily by European individual investors.  The terms of the transaction include certain registration rights which may be exercised no earlier than May 2004.  The proceeds from the offering will be used for repayment of debt and other corporate purposes.  There were no warrants or other dilutive securities issued in connection with this transaction.

 

On February 4, 2004, Bramex Management, Inc. exercised the option which had been granted to it in February 2002 in connection with the arrangement of $50.0 million in total credit facilities for Caspi Neft.  In order to exercise the option, Bramex was required to pay $15.0 million to Caspi Neft, the proceeds of which were to be used to retire part of the outstanding debt of Caspi Neft.  On February 4, 2004, Bramex paid Caspi Neft $15.0 million, of which $11.7 million was applied to principal outstanding under the $20.0 million credit facility and $3.3 million was applied to accrued interest.

 

Also in February 2004, the Company paid $2.98 million which it had been required to pay under the original terms of the $20.0 million credit facility.  Of such amount, $2.23 million was applied to principal and $.75 million was applied to accrued interest.  This payment was made from the proceeds of the private placement of common stock on January 9, 2004.

 

After the above payments were made, the remaining principal balance under the $20.0 million credit facility was $6.1 million.  This amount, plus interest at 15%, is payable in 12 monthly installments from March 2004 through February 2005.

 

During late January 2004, the SA-2 well reached its planned total depth, was logged and production casing was run to undertake completion operations.  As this well had not reached total depth and had not been logged as of December 31, 2003, it could not be included in the proved reserves of the Company at that date.  However, Ryder Scott Company attributed proved reserves to this well in an evaluation subsequent to the end of the year.

 

The following table presents information about the net proved oil reserves and standardized measure of discounted future net cash flows as of December 31, 2003, on a pro forma basis, as if (1) the Bramex option had been exercised as of that date and (2) the SA-2 well had been completed and logged as of that date.  This pro forma information is provided to give readers of the financial statements the most current information available about the Company’s proved reserves and standardized measure of discounted future net cash flows.

 

42

 

Pro Forma Net Proved Crude Oil Reserves and Future Net Revenues

(Reflecting the Bramex Option Exercise and Results of SA-2)

Pro Forma as of December 31, 2003

(Quantities in Barrels)

 

 

The Company has historically consolidated the operations of its 100% owned Caspi Neft subsidiary.  As of the date of the Bramex option exercise, the Company may no longer be eligible to fully consolidate Caspi Neft.  The table below presents summarized balance sheets and results of operations as of December 31, 2003 and for the twelve month period then ended (a) for Transmeridian and its other subsidiaries, excluding Caspi Neft, and (b) for Caspi Neft on a stand-alone basis:

 

		Transmeridian and Other Subsidiaries			Caspi Neft(2)			Eliminations			Consolidated
Balance Sheets As of December 31, 2003
Current assets		$	812,176		$	1,323,025		$	(67,397	)	$	2,067,804
Property and equipment, net		5,496,282			48,376,937			687,356			54,560,575
Investment in Caspi Neft		4,793,393			—			(4,793,393		)	—
Other assets		61,250			409,443			—			470,693
Total assets		$	11,163,101		$	50,109,405		$	(4,173,434	)	$	57,099,072
Current liabilities(1)		$	7,515,098		$	24,403,540		$	—		$	31,918,658
Long-term debt, net		—			24,488,196			—			24,488,196
Other long-term liabilities		—			186,000			—			186,000
Stockholders’ equity		3,648,003			1,031,669			(4,173,434		)	506,218
Total liabilities and equity		$	11,163,101		$	50,109,405		$	(4,173,434	)	$	57,099,072
Statements of Operations for the For the Year Ended December 31, 2003
Revenues		$	—		$	797,411		$	—		$	797,411
Operating and administrative  expenses		(2,267,270		)	(3,445,170		)	—			(5,712,440		)
Other income(expense)		(652,685		)	(118,854		)	—			(771,539		)
Net loss		(2,919,955		)	(2,766,613		)	—			(5,686,568		)
Preferred dividends		(19,736		)	—			—			(19,736		)
Net loss attributable to  common stockholders		$	(2,939,691	)	$	(2,766,613	)	$	—		$	(5,706,304	)

 

(1)               Transmeridian is obligated to repay $2.233 million of the Caspi Neft debt, plus accrued totaling $745,000.  Accordingly, these amounts are recorded by both Transmeridian and Caspi Neft and are eliminated in consolidation.  See Notes 6 and elsewhere in this footnote for further discussion of this obligation.

 

(2)               As reflected in the above table, the majority of the total debt of the Company is recorded on the books of Caspi Neft.  As a result of the exercise of the option by Bramex, the Company may no longer be able to fully consolidate Caspi Neft and would not include the assets and liabilities of Caspi Neft, including its long-term debt, in the consolidated financial statements of the Company.  Accordingly, the Company’s effective net interest in the assets and liabilities of Caspi Neft, including its long term debt, has been reduced by 50%.

 

 

43

 

Note 13 – Supplemental Oil and Gas Disclosures

 

Costs Incurred

 

Cost 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 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, $741,000 and $5.3 million in 2003, 2002 and 2001, respectively.

 

		Kazakhstan			United States			Total
Year ended December 31, 2003
Acquisition costs of properties:
Proved		$	—		$	—		$	—
Unproved		—			—			—
Exploration costs		26,292,534			118,893			26,411,427
Development costs		56,256			—			56,256
Capitalized interest		4,164,693			—			4,164,693
Total		$	30,513,483		$	118,893		$	30,632,376
Year ended December 31, 2002:
Acquisition costs of properties:
Proved		$	—		$	—		$	—
Unproved		7,915			28,463			36,378
Exploration costs		8,944,425			—			8,944,425
Development costs		355,998			5,021			361,019
Capitalized interest		1,060,495			—			1,060,495
Total		$	10,368,833		$	33,484		$	10,402,317
Year ended December 31, 2001:
Acquisition costs of properties:
Proved		$	1,653,023		$	—		$	1,653,023
Unproved		—			—			—
Exploration costs		—			—			—
Development costs		1,667,090			—			1,667,090
Capitalized interest		—			—			—
Total		$	3,320,113		$	—		$	3,320,113

 

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 $6.5 million, $6.0 million and $5.3 million at December 31, 2003, 2002 and 2001, respectively.

 

		Kazakhstan			United States			Total
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
As of December 31, 2002
Proved properties		$	7,765,565		$	—		$	7,765,565
Unproved properties		10,368,831			33,484			10,402,315
Total oil and gas properties		18,134,396			33,484			18,167,880
Accumulated DD&A		—			—			—
Net oil and gas properties		$	18,134,396		$	33,484		$	18,167,880
As of December 31, 2001
Proved properties		$	7,765,565		$	—		$	7,765,565
Unproved properties		—			—			—
Total oil and gas properties		7,765,565			—			7,765,565
Accumulated DD&A		—			—			—
Net oil and gas properties		$	7,765,565		$	—		$	7,765,565

 

44

 

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 represent 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, 2003, 2002 and 2001.  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, 2003, the Company owned a 100% working interest in the South Alibek Field, subject to government royalties and a 10% carried working interest after recovery of costs.  The effect of this carried interest is reflected in the calculation of the Company’s net proved reserves and future net cash flows.  See Note 12 for discussion of Subsequent Events which reduce our net interest in the Field and one well, the SA-2, which was completed and evaluated subsequent to the end of the year.

 

The Company is operating under an Exploration Contract with the government of Kazakhstan which ends in April 2005.  At such time as the Company is successful in establishing commercial production from the Field, an application will be made for an exploration and production contract.  The Company has the exclusive right to negotiate this contract for the Field, and the government is required to conduct these negotiations under the Law of Petroleum.  However, the Company is not guaranteed the right to a production contract.  Such contracts are customarily awarded for a period of 25 years 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.  If satisfactory terms cannot be negotiated, the Company has the right to produce and sell oil under the Law of Petroleum for the term of its existing Exploration Contract through April 2005 at a royalty rate of 2%.  The royalty rate under production contracts is subject to negotiation and varies in accordance with estimated reserve and production volumes.  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.  The Company’s oil and gas reserve data and future net cash flows have been prepared assuming a commercial production contract is obtained which will allow production for the expected 25 year term of the production contract.

 

The proved reserves as of December 31, 2002 represented the reserves that were estimated to be recovered from one well, A-29, and two development offsets not yet drilled.  Subsequent to December 31, 2002, the Company made a decision to redrill the A-29 as this is believed to be the most cost-effective way to recover these reserves and should allow the Company to achieve greater productivity and may potentially access additional reserves.  As of December 31, 2003, the Company had two new wells, the SA-1, which is producing, and the SA-4, which was being prepared for testing.  The Ryder Scott reserve estimate as of December 31, 2003 included these two wells as proved developed, and also reflected ten undeveloped well locations which include the redrill of the A-29 and development offsets for A-29, SA-1 and SA-4. As discussed in Note 12, the SA-2, which was in progress at year end, is not included in proved reserves as of December 31, 2003.

 

45

 

As a result of a number of technical factors, many of which are subject to varying professional interpretation, Ryder Scott's updated reserve report as of December 31, 2003 reflected a reduction in the estimated reserves recoverable from A-29 while substantially increasing the total reserve estimates for the Field.  This reduction in the proved reserves attributable to A-29 was based on changes in reserve engineering assumptions and was not the result of well performance or production issues, nor was it affected by the decision to redrill the A-29.  Certain of the reserves previously attributed to the A-29 have been reclassified by Ryder Scott Company into reserve categories other than proved until such time as they can be reevaluated as proved reserves under SEC guidelines.  This reevaluation would be based on additional technical data obtained during the development of the field, including in-fill drilling and the extended production testing of the existing wells.

 

 

Estimated Quantities of Net Proved Crude Oil Reserves

(Quantities in Barrels)

 

		Years ended December 31,
		2003		2002		2001
Net proved crude oil reserves:
Beginning of year		17,110,741		17,645,418		17,213,772
Revisions of previous estimates		(5,079,386	)	(534,677	)	431,646
Extensions, discoveries and other additions		33,830,809		—		—
Production		(117,376	)	—		—
End of year		45,744,788		17,110,741		17,645,418
Net proved developed reserves:
Beginning of year		5,695,613		5,808,683		5,675,781
End of year		7,815,861		5,695,613		5,808,683

 

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, 2003, 2002 and 2001 were $12.44, $23.99 and $15.37 per barrel, respectively.  The December 31, 2003 price was based on the last sales price received for December 2003. The December 2002 and 2001, prices were based on North Sea Brent crude prices, less a discount for transportation and quality differentials as actual oil sales had not yet occured.  The sales prices used in 2002 and 2001 were based on the prices expected to be received upon full development of the Field.  However, under SEC guidelines, we are required to value the 2003 reserves based on prices received at the end of the year.  This situation can sometimes limit comparison between periods.  As of December 31, 2003, the Company was in the very early stages of selling limited quantities of test production into the local market, primarily by truck.  The Company does not believe the prices it received for this production at the end of December 2003 are representative of what it would expect to receive when the field is fully developed.

 

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 2003, 2002 and 2001 were as follows:

 

46

 

Standardized Measure of Discounted Future Net Cash Flows

(Amounts in Thousands)

 

December 31, 2003:
Future cash inflows		$	569,065
Future production and development costs		(151,096		)
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
December 31, 2002:
Future cash inflows		$	410,487
Future production and development costs		(36,575		)
Undiscounted future net cash flows before income tax		373,912
10% discount for estimated timing of cash flows		(169,595		)
Present value of future net cash flows before income tax		204,317
Future income tax expense, discounted at 10%		(60,318		)
Standardized measure of discounted future net cash flows		$	143,999
December 31, 2001:
Future cash inflows		$	271,298
Future production and development costs		(37,889		)
Undiscounted future net cash flows before income tax		233,409
10% discount for estimated timing of cash flows		(104,492		)
Present value of future net cash flows before income tax		128,917
Future income tax expense, discounted at 10%		(39,511		)
Standardized measure of discounted future net cash flows		$	89,406

 

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)

 

		Years ended December 31,
		2003			2002			2001
Standardized Measure, beginning of year		$	143,999		$	89,406		$	98,986
Sales and transfers of oil and gas produced, net of production costs		(397		)	—			(51		)
Net changes in prices, development and production costs		(107,366		)	83,980			(24,905		)
Extensions, discoveries and improved  recovery, less related costs		171,513			—			—
Purchase of minerals in place		—			—			—
Development costs incurred and changes during the period		(2,887		)	252			616
Revisions of previous quantity estimates		(30,436		)	(6,630		)	3,274
Increase in present value due to passage of one year		20,431			12,892			14,946
Net changes in production rates and other		(13,824		)	(15,094		)	(14,419		)
Net change in income taxes		(590		)	(20,807		)	10,959
Standardized Measure, end of year		$	180,443		$	143,999		$	89,406

 

47

 

Note 14 – 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, 2003 and 2002.

 

		First Quarter			Second Quarter			Third Quarter			Fourth Quarter
2003
Revenue		$	—		$	—		$	158,764		$	638,647
Expenses		1,083,423			1,293,664			1,752,252			2,354,640
Preferred Dividends		9,252			9,352			1,132			—
Net loss attributable to common shareholders		(1,092,675		)	(1,303,016		)	(1,594,619		)	(1,715,994		)
Basic and diluted loss per share		$	(0.02	)	$	(0.02	)	$	(0.02	)	$	(0.03	)
Weighted average common shares outstanding		60,784,650			61,730,233			62,957,899			64,573,627
2002 (a)
Revenue		$	—		$	—		$	—		$	—
Expenses		567,347			583,924			805,955			1,313,677
Preferred Dividends		9,303			9,303			9,456			9,458
Net loss attributable to common shareholders		(576,650		)	(593,227		)	(815,411		)	(1,323,135		)
Basic and diluted loss per share		$	(0.01	)	$	(0.01	)	$	(0.01	)	$	(0.03	)
Weighted average common shares outstanding		56,063,753			58,666,909			62,957,899			58,142,461

 

(a) The Company made certain adjustments to its financial statements during the fourth quarter of 2002 which affected the other interim periods of 2002.  These adjustments, which include changes to our accounting policies regarding carried working interests and drilling rig operations and adjustments for capitalization of interest on unproved oil and gas properties, depreciation of drilling equipment, amortization of deferred financing costs and others are discussed in Form 8-K dated February 20, 2003 and May 16, 2003.  The above quarterly financial information reflects all of these adjustments.

 

48

 

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

 

Not applicable.

 

Item 9A.  Controls and Procedures

 

Corporate Disclosure Controls

 

During 2002, the Company’s certifying officers conducted a review of the Company’s disclosure controls and procedures and determined that they were in need of improvement.  As a result of this review, we engaged financial consultants with experience in accounting for oil and gas operations and SEC reporting requirements to conduct a review of our financial reporting procedures and disclosure controls.  That review resulted in changes to the Company’s accounting policies and procedures and also resulted in adjustments to the financial statements of the quarterly periods for the year ended December 31, 2002.

 

As disclosed in a Current Report on Form 8-K filed February 20, 2003, we changed our accounting policies with regard to carried working interests and drilling rig operations.  This change in accounting policies resulted in adjustments to the financial statements for the interim periods ended June 30, 2002 and September 30, 2002.  These adjusted financial statements were included in the Form 8-K.

 

Additionally, as reported in a Current Report on Form 8-K dated May 16, 2003, during the fourth quarter of 2002 we made certain other adjustments to our financial statements which also affected the interim periods of 2002.  These adjustments included capitalization of interest on unproved oil and gas properties, adjustments to the depreciation of drilling equipment, amortization of deferred financing costs and certain other adjustments as discussed in the Form 8-K.  The Form 8-K included adjusted financial statements for the interim periods of the year ended December 31, 2002.  There were no adjustments made to any periods prior to the year ended December 31, 2002.

 

As a result of the review, we have implemented new accounting policies and procedures at the corporate level in Houston to improve the accuracy and quality of our financial reporting.  Management believes that such new accounting policies and procedures have been effective in achieving these objectives.

 

Kazakhstan Internal Controls

 

Over the past two fiscal years, the volume and dollar amount of Company’s transactions in Kazakhstan have increased significantly.  We have undertaken improvements in our accounting procedures and personnel in Kazakhstan, including the implementation of a computer-based accounting system, hiring of additional accounting employees, establishment of new procedures, and further training of personnel.  We have detailed policies and procedures relating to the procurement of goods and services for our operations in Kazakhstan and cash disbursements for purchases, and we are confident that these procedures are being consistently followed.  As a result of communication issues between our U.S. and Kazakhstan accounting and operating personnel, we face continuing challenges to improve the timeliness of our accounting and financial reporting and the quality of information reported to the Houston office.  During 2003 and continuing into 2004, we have made several changes in the flow, quality and quantity of information from our accounting department in Kazakhstan.

 

While we are confident that cash basis transactions are being recorded accurately, our financial accounting in Kazakhstan does not fully comply with accrual based accounting.  As a result, our corporate accounting personnel in Houston must perform additional procedures to prepare financial statements in accordance with generally accepted accounting principles.  Our independent auditors have advised management and the audit committee that these additional procedures could cause delays in reporting the Company’s results of operations and represent a deficiency in the financial reporting system.  While we believe that our current procedures are effective in producing financial statements which comply with generally accepted accounting principles, we are aware that further improvements in our accounting procedures are needed and we intend to make further improvements in this area.

 

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Summary and Conclusion

 

During 2003, we made considerable progress in improving our financial reporting and systems of internal control.  The Company recently hired a Chief Financial Officer and a Corporate Controller, both of whom  are certified public accountants and have extensive experience in finance and accounting for international oil and gas operations.  We believe that that these new officer additions and enhanced procedures and controls, including improvements we are undertaking in Kazakhstan, will provide an effective means to insure that we can timely and accurately disclose the information we are required to disclose under applicable laws and regulations.  Based on an evaluation of the Company’s disclosure controls and procedures as of the end of the period covered by this report conducted by the Company’s management, with the participation of the Chief Executive Officer, Chief Financial Officer and Corporate Controller, we believe that these controls and procedures are effective.

 

PART III

 

Item 10.  Directors, Executive Officers, Promoters and Control Persons

 

The 2004 Proxy Statement is hereby incorporated by reference for the purpose of providing information about directors, executive officers, promoters and control persons.

 

Item 11.  Executive Compensation

 

The 2004 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

 

The 2004 Proxy Statement is hereby incorporated by reference for the purpose of providing information about security ownership of certain beneficial owners and management.

 

Item 13.  Certain Relationships and Related Transactions

 

The 2004 Proxy Statement is hereby incorporated by reference for the purpose of providing information about certain relationships and related transactions.

 

Item 14.  Principal Accountant Fees and Services

 

The 2004 Proxy Statement is hereby incorporated by reference for the purpose of providing information about principal accountant fees and services.

 

PART IV

 

Item 15.  Exhibits, Financial Statements and Schedules and Reports on Form 8-K

 

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

 

1.               Consolidated Financial Statements

 

Reference is made to the Index to Consolidated Financial Statements appearing in Item 8 of this report.

 

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2.               Consolidated Financial Statement Schedules

 

All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the consolidated statements or notes thereto.

 

3.               Exhibits

 

Exhibit Number			Description		Incorporation by Reference
3.1			Amended and Restated Certificate of Incorporation of the Company		Form SB-2 filed May 15, 2001
3.2			Bylaws of the Company		Form SB-2 filed May 15, 2001
10.1			License 1557 dated April 29, 1999 from the Republic of Kazakhstan for Oil and Gas Exploration of the South Alibek Field		Form SB-2 filed May 15, 2001
10.2			Exploration Contract dated April 29, 1999 covering the South Alibek Field		Form SB-2 filed May 15, 2001
10.3			Letter from the Kazakhstan Ministry of Energy		Form SB-2/A filed October 3, 2001
10.4			General Loan Agreement dated February 4, 2002 by and among Bank TuranAlem, OJSC Caspi Neft TME, Transmeridian Exploration, Inc. (BVI) and Kazstroiproekt, Ltd.		Form 10-KSB filed May 16, 2002
10.5			Transmeridian Exploration, Inc. 2001 Incentive Stock Option Plan		Form S-8 filed May 28, 2003
10.6			General Loan Agreement dated June 2, 2003 by and among Bank TuranAlem, OJSC Caspi Neft TME, Transmeridian Exploration, Inc. (BVI) and Bramex Management Inc.		Filed Herewith
14.			Code of Ethics		Filed Herewith
21.1			List of Subsidiaries		Filed Herewith
31.1			Rule 13a-14(a) Certification of Chief Executive Officer		Filed Herewith
31.2			Rule 13a-14(a) Certification of Chief Financial Officer		Filed Herewith
32.1			Section 1350 Certification of Chief Executive Officer		Filed Herewith
32.2			Section 1350 Certification of Chief Financial Officer		Filed Herewith

 

(b)          Reports on Form 8-K

 

On October 21, 2003, the Company filed a Current Report on Form 8-K to announce a private placement of common stock.

 

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SIGNATURES

 

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

 

	Transmeridian Exploration, Inc.
	/s/ Lorrie T. Olivier
	Lorrie T. Olivier
	Chairman of the Board of Directors, President and
	Chief Executive Officer

 

 

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.

 

Date		Signature		Title
March 30, 2004		/s/ Lorrie T. Olivier		Chairman of the Board of Directors,
		Lorrie T. Olivier		President and Chief Executive Officer
March 30, 2004		/s/ Randall D. Keys		Chief Financial Officer
		Randall D. Keys
March 30, 2004		/s/ Bruce A. Falkenstein		Vice President of Exploration and Geology
		Bruce A. Falkenstein
March 30, 2004		/s/ Charles J. Campise		Corporate Controller
		Charles J. Campise
March 30, 2004		/s/ Philip J. McCauley		Director
		Philip J. McCauley
March 30, 2004		/s/ Angus G.M.P. Simpson		Director
		Angus G.M.P. Simpson
March 30, 2004		/s/ James H. Dorman		Director
		James H. Dorman
March 30, 2004		/s/ George E. Reese		Director
		George E. Reese

 

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