SB-2/A AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON
November 18, 2002

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM SB-2/A
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

TRANSMERIDIAN EXPLORATION INCORPORATED

(Exact Name of Registrant as Specified in Its Charter)

Delaware
(State or Other Jurisdiction of
Incorporation or Organization) 1311
(Primary Standard
Industrial
Classification Code) 76-0644935
(I.R.S. Employer
Identification Number)

397 N. Sam Houston Pkwy E.
Houston, Texas 77060
(281) 999-9091
(Address, Including Zip Code,
and Telephone Number, Including Area
Code of Registrant’s Executive Offices) Jim W. Tucker
Vice President Finance
397 N. Sam Houston Pkwy E.
Houston, Texas 77060
(281) 999-9091
(Name, Address, Including Zip Code,
and Telephone Number, Including Area
Code, of Agent for Service)

Copies of Correspondence to:
Carter Holmes PLLC
4311 Oak Lawn
Suite 600
Dallas, Texas 75219
214-765-6003

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO PUBLIC: As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are being offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. |X|

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act of 1933, check the following box and list the Securities Act Registration Statement number of the earlier effective Registration Statement for the same offering. |_|

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act of 1933, check the following box and list the Securities Act Registration Statement number of the earlier Registration Statement for the same offering. |_|

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act of 1933, check the following box and list the Securities Act Registration Statement number of the earlier Registration Statement for the same offering. |_|

If delivery of the Prospectus is expected to be made pursuant to Rule 434, please check the following box.|_|

CALCULATION OF REGISTRATION FEE
Title Of Each Class Of Securities To Be Registered	Number Of Shares To Be Register	Proposed Maximum Offering Price Per Share	Proposed Maximum Aggregate	Amount Of Registration Fee
Common Stock, $0.0006 par value
Selling Shareholder (1)(2)	4,444,444	$    0.36	$   1,600,000	$  147.20
Total	4,444,444		$   1,600,000	$  147.20

(1) Calculated in accordance with Rule 457(c) under the Securities Act of 1933.

(2) 400% of 1,111,111 shares issued in convertible debentures (See Exhibits “Convertible Debentures”)

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933, OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING PURSUANT TO SECTION 8(a), MAY DETERMINE.

EXPLANATORY NOTE

We have prepared this prospectus to allow one of our unaffiliated shareholders, The Private Capital Group of New York, N.Y., to sell shares of our common stock which they may acquire upon conversion of an aggregate of $400,000 of convertible debentures ($200,000 of which have been sold and $200,000 of which will be sold upon the effectiveness of this registration statement) and exercise 200,000 warrants previously acquired by them. The warrants are exercisable at $0.42 per share. The registration statement requires us to register up to 400% of the shares of common stock issuable upon conversion of the convertible debentures. Although we have paid the expense of the registration of such shares we will receive no proceeds from the sale of these shares, with the exception of the proceeds from the exercise of the warrants. The Selling Shareholder may sell shares pursuant to this prospectus commencing on a date which is one day from the effective date of this prospectus. The Company has the right to buy this debenture with cash if the market for our stock is below $0.36 per share. If the market is above $0.36 the Selling Shareholder can convert the debenture into shares at $0.36, or 1,111,111 shares.

There is a trading market for our common stock on the Over The Counter Bulletin Board (OTC.BB), with a trades in the range of a high $2.20 and a low of $0.15. We are traded under the ticker symbol TMXN.

The information in this prospectus is not complete and may be changed. We will not issue these securities until the registration statement filed with the Securities and Exchange Commission is declared effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any state where the offer or sale is not permitted.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is September 26, 2002.

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TABLE OF CONTENTS

Prospectus Summary	1
Selling Shareholder	2
Risk Factors	4
Cautionary Note Regarding Forward-Looking Statements	9
Use of Proceeds	9
Dividend Policy	9
Dilution	10
Capitalization	11
Our Business and Properties	11
Management Discussion of Our Plan of Business	24
Directors, Executive Officers and Key Employees	28
Executive Compensation	30
Security Ownership of Certain Beneficial Owners and Management	30
Market For Our Stock	31
Description of Capital Stock	31
Antitakeover Effects of Delaware Law and Amended/Restated Certificate of Incorporation & Bylaws	32
Limitation of Liability and Indemnification Matters	33
Transfer Agent and Registrar	33
Shares Eligible for Future Sale	33
Plan of Distribution	33
Legal Matters	34
Experts	34
Independent Petroleum Engineers	35
Where You Can Find Additional Information	35
Glossary of Oil and Natural Gas Terms	35
Report of Independent Certified Public Accountants	43
Index to Financial Statements	44
Financial Statements	F1-F23
Report of Independent Petroleum Engineers	45
Information Not Required In Prospectus	50
Exhibit 23.1. Consent of Carter Holmes PLLC	53
Exhibit 23.2. Consent of John A. Braden & Company, P.C	55
Exhibit 23.3. Consent of Ryder Scott Company, L.P.	56
Exhibit 23.4(a). 7% Convertible Note	57
Exhibit 23.4(b). Convertible Debenture	61
Exhibit 23.4(c). Registration Rights Agreement	83
Exhibit 23.4(d). Stock Pledge Agreement	93
Exhibit 23.4(e). Stock Purchase Warrant	102
Exhibit 23.4(f). Modification Letter	114

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PROSPECTUS SUMMARY

This summary highlights selected material information from the prospectus. We encourage you to read the entire prospectus, including Risk Factors and our financial statements and the related notes.

Unless the context otherwise requires, references to “Transmeridian”, “TMEI”, “we”, “us” and “our”, refer to Transmeridian Exploration, Inc. References to Selling Shareholder refer to Private Capital Group. We have provided definitions for some oil and natural gas industry terms used in the prospectus in Glossary of Oil and Natural Gas Terms which you may find helpful in reading this prospectus.

Transmeridian Exploration Incorporated

We are an independent energy company established primarily to acquire and develop identified and underdeveloped hydrocarbon reserves in the region of the former Soviet Union known as the Confederation of Independent States (CIS) and more particularly the Caspian Sea region, based in part on our management’s experience and business relationships in the area. Our President & CEO and Vice President of Exploration have a total of 15 years of experience working in the Kazakhstan area. (Refer to their bios in Directors, Executive Officers and Key Employees) We target opportunities with proved and potential oil and natural gas reserves at below international finding cost rates. We currently have one project under development. The project (which is referred to in this prospectus at times as the Kazakhstan Property or the South Alibek Field) is located in the Caspian Region of western Kazakhstan, and is situated near pipelines and railroads and oil field infrastructure. The proximity to existing infrastructure for exportation of oil and gas, which reduces associated costs as well as the time needed to place wells on production, will be an important factor in our acquisition of any additional properties.

Our Corporate and Field Offices

In addition to our corporate headquarters at 397 N. Sam Houston Pkwy, E. Suite 300, Houston, Texas 77060, we have a branch office at Seifullin Street 563, 5th Floor, Almaty, Kazakhstan and a branch office in Aktobe, Kazakhstan, Gaziza Zhubanova Street, 50 A. Our Houston telephone number is (281) 999-9091, and our website is www.tmei.com.

Our Reserves

At December 31, 2001 we had estimated net proved reserves of 17,645,418 barrels of oil and 3.475 MMCF (million cubic feet) with a net present value at 10% (before taxes) of $128,917,482 and a standardized measure of $105,349,000 (after tax) as measured on December 31, 2001. Of these reserves, 5,808,683 barrels of oil and 1,144 MMCF were classified as proved developed non-producing. In April of 2001 we acquired an additional 1,012,516 barrels of net proved reserves as a result of our acquisition of a third party’s interest.

Our Growth Strategy

Our long-term strategy is to develop a continuous stream of commercial production from our Kazakhstan Property. We then will be poised to continue the growth of our assets with the possible acquisition of similar properties in the region. In addition, the company may acquire oil and gas leases in North America as low-risk development of known reserves projects become available. This is not expected to be a core part of the company’s business but will provide additional cash flow and some balance to the company’s international holdings.

We intend to finance this initial development through a financial plan based upon, but not limited to:

• Funds generated from production

• Crude oil forward purchase contracts

• Joint Venture arrangements

• Sale of Equity

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• Bank Loans

The Offering

•	Common stock offered by Selling Shareholder	Up to 4,444,444 shares issuable upon conversion of the convertible debentures at a 15% discount to the market price and 200,000 shares issuable upon the exercise of warrants exercisable at $0.42 per share.
•	Common stock to be outstanding upon completion of the offering assuming all shares have been converted.	63,591,573 shares.
•	Term of offering	The Selling Shareholder may commence offering shares for sale in accordance with this prospectus and may continue to offer for a period of 12 months from the effective date of the prospectus.

Use of Proceeds

Although we have paid the expense of the registration of such shares we will receive no proceeds from the sale of these shares, with the exception of the proceeds from the exercise of the warrants. We intend to apply proceeds from the exercise of warrants, after payment of expenses, for working capital and debt reduction. (See “Use of Proceeds”).

SELLING SHAREHOLDER

This prospectus relates to the offering by the Selling Shareholder of up to 4,444,444 shares of our common stock issuable upon conversion of the convertible debentures and 200,000 warrants. All of the shares of common stock offered by this prospectus are being offered by the Selling Shareholder for its own accounts. Under the terms of the convertible debenture we are required to register 400% of the convertible shares or 4,444,444 shares of our common stock.

The Selling Shareholder, as a condition to our filing of this registration statement has agreed that we will only be obligated to maintain the registration statement of which this prospectus is part, effective for a period of 12 months from the effective date.

The following table sets out the Selling Shareholder and its respective holdings. This table sets forth information with respect to the common stock beneficially owned by the Selling Shareholder as of the date of this prospectus, including shares obtainable under convertible notes and warrants exercisable within 60 days of such date. To our knowledge, the Selling Shareholder has sole voting and investment power over the shares of common stock listed in the table below. The Selling Shareholder has not had a material relationship with us during the last three years, other than as an owner of our common stock or other securities.

Name	Address	Shares Owned	Offered	Owned after Offering
Private Capital Group	545 Madison Ave., Suite 600 New York, NY 10022	Up to 4,444,444	Up to 4,444,444	-0-

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We have assumed the sale of all of the common stock offered under this prospectus will be sold. However, as the Selling Shareholder can offer all, some or none of its shares of common stock, no definitive estimate can be given as to the number of shares that the Selling Shareholder will hold after this offering.

The Selling Shareholder will acquire its shares through the conversion of the convertible debenture. We agreed to register the shares. This prospectus is part of the registration statement intended to satisfy that obligation. We have agreed to maintain the registration statement effective for a period of 12 months from the effective date. The registration may be terminated after 6 months if there is a conflict with the underwriting of new securities. Although we have paid the expenses of the registration of such shares, we will not receive any of the proceeds from the sale of shares by the Selling Shareholder. However we will receive the proceeds from the exercise, if any, of the warrants.

PLAN OF DISTRIBUTION

The Selling Shareholder may, from time to time, sell any or all of its shares of common stock on any stock exchange, market or trading facility on which the shares are traded or in private transactions on negotiated terms and prices. These sales may be at fixed or negotiated prices. The Selling Shareholder may use any one or more of the following methods when selling shares:

• ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

• block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

• purchases by a broker-dealer as principal and resale by the broker-dealer for its account;

• an exchange distribution in accordance with the rules of the applicable exchange;

• privately negotiated transactions;

• short sales;

• broker-dealers may agree with the Selling Shareholder to sell a specified number of such shares at a stipulated price per share;

• a combination of any such method of sale; and

• any other method permitted pursuant to applicable law.

The Selling Shareholder may also sell shares under Rule 144 under the Securities Act, if available, rather than under this prospectus.

The Selling Shareholder may also engage in short sales against the box, puts and calls and other transactions in securities of Transmeridian or derivatives of our securities and may sell or deliver shares in connection with these trades. The Selling Shareholder may pledge its shares to its brokers under the margin provisions of customer agreements. If the Selling Shareholder defaults on a margin loan, the broker may, from time to time, offer and sell pledged shares.

Broker-dealers engaged by the Selling Shareholder may arrange for other brokers-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the Selling Shareholder (or, if any broker-dealer acts as agent for the purchaser of shares, from the purchaser) in amounts to be negotiated. The Selling Shareholder does not expect these commissions and discounts to exceed what is customary in the types of transactions involved.

The Selling Shareholder and any broker-dealers or agents that are involved in selling the shares may be deemed to be underwriters within the meaning of the Securities Act in connection with such sales. In such event, any commissions received by such broker-dealers or agents and any profit on the resale of the shares purchased by them may be deemed to be underwriting commissions or discounts under the Securities Act.

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We are required to pay all fees and expenses incident to the registration of the shares, excluding the fees and disbursements of counsel to the Selling Shareholder. We have agreed to indemnify the Selling Shareholder against certain losses, claims, damages and liabilities, including liabilities under the Securities Act.

RISK FACTORS

You should carefully consider the following risk factors before you make an investment decision regarding the purchase of these shares from the Selling Shareholders. We have separated the risks into three broad categories:

• risks relating to our business, properties and industry

• risks relating to the offering and ownership of our common stock

• risks of war or terrorist acts

Risks Related to Our Business, Properties and Industry

Exploration and exploitation of oil and natural gas properties are high-risk activities with many uncertainties that could harm our business, financial condition or results of operations.

Our future existence and financial stability will depend on the success of our exploration and production activities. Our activities are subject to numerous risks beyond our control, including the risk that drilling for oil and gas will not result in commercially viable oil or natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.

Our reserve estimates are dependent on the successful execution of our Financial Plan.

Our reserve estimates are based upon the assumptions contained in the report by The Ryder Scott Company which in part call for investment of approximately $10,000,000 in order to fully realize the value of these reserves. We plan to raise the required capital through, but not limited to, the sale of stock, bank loans, commercial financing through crude oil forward purchase contracts and joint ventures with other oil and gas operators.

Our reserve estimates are dependent on many assumptions that may ultimately turn out to be inaccurate.

The reserve data presented in this prospectus represents only estimates. There are numerous uncertainties inherent in estimating quantities of oil and natural gas reserves of any category and in projecting future rates of production and timing of development expenditures, which underlie the reserve estimates, including many factors beyond our control. In addition, the estimates of future net cash flows from an independent engineering evaluation of the proved reserves in the field and their present value are based upon various assumptions about future production levels, prices and costs that may prove to be incorrect over time. Any significant variance from the assumptions could result in the actual quantity of our reserves and future net cash flows from them being materially different from the estimates. In addition, estimated reserves may be subject to downward or upward revision based upon production history, results or future exploration and development, prevailing oil and gas prices, operating and development costs and other factors. Please read Our Business and Property — Oil & Natural Gas Reserves for a discussion of our proved oil and gas reserves.

All of our reserves and future estimated production originates from one property. Because of this concentration, any production or delivery problems or inaccuracies in reserve estimates related to this property could impact our potential revenues and cash flow.

The South Alibek Field is the only major field where we have the possibility of establishing significant commercial production. If mechanical problems, storms, work stoppages or any other events occur to curtail a substantial portion of this production, our revenue and cash flow would be affected adversely. One hundred percent of an independent engineering evaluation of the estimated reserves in the field are attributable to this property. If the actual reserves associated with this property are less than our estimated reserves, our business, financial condition or results of operations would be adversely affected.

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Drilling for oil and natural gas is a high-risk activity with many uncertainties that could harm our business, financial condition or results of operations.

Our cost of drilling, completing and operating wells is often uncertain before operations begin. Cost overruns in budgeted expenditures are common risks that can make a particular project uneconomical. Further, many factors may curtail, delay or cancel drilling and production operations, including the following:

• pressure or irregularities in geological formations;

• shortages or delays in obtaining equipment and qualified personnel;

• equipment failures or accidents;

• adverse weather conditions, such as winter snowstorms;

• labor unrest and strikes which prevent transportation of product or the importation of equipment;

• title or licensing problems;

• compliance with governmental requirements and permits;

• limitations in the market for oil and natural gas;

• difficulty in enforcing contracts;

• capital market conditions and availability of financing;

• technical problems; and

• political and economic stability of the countries in which we operate.

Since we have limited financial resources the occurrence of any one or more of these events will place severe strains on our available capital resources.

Producing oil and natural gas is a high-risk activity with many uncertainties that could harm our business, financial condition or results of operations.

Our oil and natural gas exploration and production activities are subject to all the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and shoreline contamination;

• abnormally pressured formations;

• mechanical difficulties, stuck oilfield drilling and service tools and casing collapse;

• fires and explosions;

• personal injuries and death; and

• natural disasters.

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Failure to timely and economically transport our production will adversely affect our ultimate profitability.

Currently our production is trucked to the railroad terminals in the general area of the field. The crude is then loaded on rail tank cars and sold on FOB terms with destinations to Finland, Black Sea ports for export or local refineries within Kazakhstan. Transporting crude by truck is considered a temporary measure until we can establish our own pipeline connections to export routes, which will take additional financing. If we do not establish these connections, we will not be able to fully maximize the potential profit from our production.

Once production is commenced on the Kazakhstan Property, unless we replace our oil and natural gas reserves, the reserves and production will decline, which would adversely affect our cash flows and income.

Unless we conduct successful development, exploitation or exploration activities or acquire properties containing proved reserves, proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally is characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production and therefore, cash flow and income, are highly dependent on success in efficiently developing and exploiting current reserves and economically finding or acquiring additional recoverable reserves. We cannot assure potential investors that we will be able to develop, exploit, find or acquire additional reserves to replace current and future production.

There are risks related to operating oil and natural gas exploration, development and production operations in Kazakhstan.

Adverse economic or political developments in Kazakhstan may adversely affect our business. Kazakhstan has been independent from the Soviet Union for only 10 years. Future changes in the political and economic environment in Kazakhstan may adversely affect our business. As a result there is significant potential for social, political, economic and legal instability. (See “Our Business and Properties”)

Reduction in the price of our crude oil will affect not only our revenues and our profitability, but also the value of our reserves.

Oil and gas prices historically have fluctuated over the years. A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and other financial commitments.

The price we receive for our oil and natural gas production is tied to the price of North Sea Brent Crude. North Sea Brent Crude prices fluctuate depending upon several factors such as world demand. Brent Crude oil prices have risen from a December 31, 2001 price of $20.50 to $26.99 for August 23 of this year. These price fluctuations will heavily influence our revenue, profitability, access to capital and future rate of growth. Oil and natural gas are commodities, and therefore their prices are subject to wide fluctuations in response to relative minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices received for production, and the levels of production, depend on numerous factors beyond our control. These factors include:

• changes in global supply of and demand for oil and natural gas;

• the actions of the Organization of Petroleum Exporting Countries, or OPEC;

• worldwide economic conditions, which affect worldwide demand for energy;

• the price and quantity of foreign imports;

• political conditions, including embargoes on Iran or others, affecting other oil-production countries;

• the level of worldwide exploration and production activity;

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• weather conditions;

• interest rates and the cost of capital

• technological advances affecting energy consumption;

• domestic and foreign government regulation, legislation and policies; and

• the price and availability of alternative fuels.

We may face competition from larger and better-financed companies seeking to acquire properties in our sphere of operation.

The oil and gas industry is highly competitive, and our business could be harmed by competition with other larger and better-financed companies. Because oil and gas are fungible commodities, the principal form of competition is price competition. We will maintain the lowest finding and production costs possible to maximize profits. In addition, as an independent oil and gas company, we frequently compete for reserve acquisitions, exploration leases, licenses, concessions and marketing agreements against companies with financial and other resources substantially larger than ours. Many of our competitors have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek entry.

We do not currently maintain insurance against potential losses and unexpected liabilities.

Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations by requiring us to use our capital for purposes other than the continued development of our properties. We will maintain insurance against material casualty losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that we believe to be prudent. We do not presently have such insurance coverage, and if a loss occurs we will have to fund the cost of the occurrence from funds generated from operations. Failure to fund such losses could result in termination of operations and relinquishment of the License.

Write-downs of the carrying values of oil and natural gas properties may adversely affect our earnings.

We employ the successful-efforts method of determining what costs are capitalized from oil and natural gas investments. Accounting rules require that we review periodically the carrying value of our oil and natural gas properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our oil and natural gas properties. A write-down constitutes a non-cash charge to earnings, which reduces our equity. We may incur impairment charges in the future, which could have a material effect on its results of operations in the period taken.

Risks Related to the Securities Markets and Ownership of Our Stock

Our limited operating history will make it difficult for you to judge our prospects.

We have a limited operating history upon which an evaluation of our current business and our prospects can be based. From inception to September 30, 2002, we incurred operating losses of $5,153,031.

The value and transferability of our shares may be adversely impacted by the penny stock rules.

Holders of our common stock may experience substantial difficulty in selling their securities as a result of the penny stock rules, which restrict the ability of brokers to sell certain securities of companies whose assets or revenues fall below the thresholds established by those rules.

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Securities deemed penny stocks are subject to additional informational requirements in connection with any trades made in the penny stock. Penny stocks generally are equity securities with a price of less than $5.00, other than securities registered on national securities exchanges or quoted on the NASDAQ Stock Market system, provided that current price and volume information with respect to transactions in such securities is provided by the exchange or system. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from those rules, to deliver a standardized risk disclosure document prepared by the SEC, which specifies information about penny stocks and the nature and significance of risks of the penny stock market. The broker-dealer also must provide the customer with bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer’s account. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from those rules the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements, in our opinion, may have the effect of reducing the trading activity in the secondary market for a stock that becomes subject to the penny stock rules.

War and Terrorist Acts

War in the area or terrorist acts could disrupt our daily operations and ability to drill for oil, produce oil and transport our oil to market. They can also make it difficult, if not impossible to obtain insurance to cover the losses incurred as a result thereof. Our License area is located in the Republic of Kazakhstan, which is located in Central Asia. The country of Afghanistan is also located in this region.

Our long-term liquidity and capital resources are uncertain.

We have incurred losses for start-up efforts and may continue to incur losses in the future. We sold 4,979 barrels of test production in April of 2001. Even if we get increased cash flow from Well No. 29, we will still need additional capital to fully develop the property. Our financial plan to raise the required capital is through but not limited to, the sale of stock, bank loans, commercial financing through crude oil forward purchase contracts and joint ventures with other oil and gas operators. If we are unable to generate sufficient operating revenues or raise the required amount of additional capital, our ability to meet our obligations and to continue the expansion of our operations will be adversely affected.

The Company’s Auditors express a Going Concern Opinion.

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. As shown in the financial statements, we incurred a net loss of $2,106,322 during the first nine months ended September 30, 2002, and, as of that date, our current liabilities exceeded our current assets by $710,396. These factors, among others, including our ability to raise additional funds as discussed in Note B to the financial statements, raise substantial doubt about our ability to continue as a going concern. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

We are controlled by our officers, directors and entities affiliated with them.

In the aggregate, ownership of our shares by management represents approximately 40% of our issued and outstanding shares of common stock as of the date of filing. These shareholders, if acting together, will be able to significantly influence all matters requiring approval by our shareholders, including the election of directors and the approval of mergers or other business combination transactions.

Our future performance is dependent on our ability to retain key personnel.

Our performance is dependent on the performance of our senior management and key technical personnel. In particular, our success depends on the continued efforts of our senior management team. The loss of the services of any of our executive officers or other key employees could have a material adverse effect on our business, results of operations and financial condition. We do not have employment agreements in place with all of our senior management or key employees.

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Our future success also depends on our continuing ability to retain and attract highly qualified technical and managerial personnel. We anticipate that the number of our employees will increase in the next 12 months. Wages for managerial and technical employees are increasing and are expected to continue to increase in the foreseeable future due to the competitive nature of this job market. We may experience difficulty from time to time in attracting the personnel necessary to support the growth of our business, and there can be no assurance that we will not experience similar difficulty in the future. The inability to attract and retain the technical and managerial personnel necessary to support the growth of our business could have a material adverse effect upon our business, results of operations and financial condition.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus contains forward-looking statements. Forward-looking statements give our current expectations or forecasts of future events and are based on our management’s beliefs, as well as assumptions made by and information currently available to them. You can identify these statements by the fact that they do not relate strictly to historical or current facts. These statements may include the words “anticipate”, “believe”, “budget”, “estimate”, “expect”, “intend”, “objective”, “plan”, “probable”, “possible”, “potential”, “project” and other words and terms of similar meaning in connection with any discussion of future operating or financial performances.

Any or all of our forward-looking statements in this prospectus may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many of these factors, including the risks outlined under Risk Factors, will be important in determining our actual future results, which may differ materially from those contemplated in any forward-looking statements.

When you consider these forward-looking statements, you should keep in mind these risk factors and other cautionary statements in this prospectus. Our forward-looking statements speak only as of the date made.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. Except as otherwise required by federal securities laws, we are under no duty to update any of the forward looking statements after the date of this prospectus to conform them to actual results or to changes in our expectations. All forward-looking statements attributable to us are expressly qualified in their entirety by the foregoing cautionary statement.

The Private Securities Litigation Reform Act of 1995, which provides a safe harbor for similar forward looking statements by existing public companies, does not apply to our offering.

USE OF PROCEEDS

We will not receive any of the proceeds from the sale of shares of common stock owned by the Selling Shareholder. However we could receive proceeds if all of the warrants which are being registered in this offering are exercised. If the warrants are exercised, we will use the net proceeds, if any, for working capital and general corporate purposes. All proceeds from the sales of the shares of common stock owned by the Selling Shareholder will be for its own accounts. See “Selling Shareholder.”

DIVIDEND POLICY

We have not declared and do not foresee declaring any dividends now or into the foreseeable future. Holders of our common stock are entitled to dividends when and if, declared by our board of directors after payment of all preferred dividends in arrears. We intend to retain earnings, if any, to finance the development and expansion of its business. Future dividend policy will be subject to the discretion of our Board of Directors and will be contingent upon future earnings, if any, our financial condition, capital requirements, general business conditions and other factors. Therefore, there can be no assurance that any dividends of any kind will ever be paid.

9

DILUTION

The difference between the public offering price per share and the pro forma net tangible book value per share of our Common Stock after this offering constitutes the dilution to investors in this offering. Net tangible book value per share is determined by dividing our net tangible book value (total tangible assets less total liabilities) by the number of outstanding shares of common stock. Dilution arises mainly from the arbitrary decision by a company as to the offering price per share. Dilution of the value of the shares purchased by the public in this offering will also be due, in part, to the lower book value of the shares presently outstanding and in part, to expenses incurred in connection with the public offering.

Net tangible book value is the net tangible assets of a company (total assets less total liabilities and intangible assets; please refer to Financial Statements). At September 30, 2002 we had a net tangible book value of $5,467,660 or $0.10 per share.

After giving effect to the sale of the 1,111,111 shares being offered at the lesser of $0.36 per share or 85% of market and after deducting estimated expenses of this offering ($-0-), our adjusted net tangible book value at September 30, 2002 after the offering would have been $5,867,660 or $0.10 per share, representing an immediate increase in net tangible book value of $-0- per share to the existing shareholders and an immediate dilution of $0.25 per share to new investors.

From our inception, we have sold 41,300,000 shares of common stock to our founders at a price of $0.0006, have issued 5,632,000 to consultants and service providers at an average price of $0.155, have sold 270,000 shares to family and friends at an average price of $0.40 and 12,315,000 shares to unaffiliated non-U.S. investors for an average price of $0.37, 3,300,000 to unaffiliated non-U.S. investors at an average price of $0.70, 3,600 shares to the public in our IPO for $2.00, issued 1,000,000 shares for part payment of a drilling rig and consulting service at a value of $2.00 and 4,000,000 shares for payment of an equity interest in Emba Terminal.

CAPITALIZATION

The following table sets forth our Actual capitalization as of September 30, 2002 (unaudited).

CONSOLIDATED

Actual

Shareholders’ equity
Preferred stock	2
Common stock	35,488
Additional paid-in capital	10,585,201
Deficit accumulated during development stage	(5,153,031	)
Total shareholders’ equity	$   5,467,660

(intentionally left blank)

10

OUR BUSINESS AND PROPERTIES

Company Structure

The following chart depicts our current company structure:

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Key Operational Dates:

EVENT	DATE
Transmeridian BVI, formed December 12, 1997	Dormant until 4/19/2000
Transmeridian Exploration, Inc., Delaware formed	4/18/2000
Transmeridian Delaware acquired Transmeridian BVI	4/19/2000
CaspiNeft TME formed	6/7/2000
Transmeridian BVI acquires CaspiNeft TME	6/7/2000
CaspiNeft takes physical possession of the field	7/1/2000
Early startup testing program starts	2/1/2001
Sale of Test production	4/17/2001
Lease expanded from 3,396 acres to 14,111 acres	11/7/2001
Company signed $50 million financing package	12/1/2001
Company purchases Drilling Rig	12/28/2001

OUR PROPERTIES

No.	Company Holding Title	Name	Description	Size		Costs
1	CaspiNeft TME	South Alibek	License 1557 Oil and Gas Lease	14,111 acres		$4,000,000
2	CaspiNeft TME	Emba Trans Oil Terminal	Rail Oil Terminal	75	%	$   250,000
3	Transmeridian Exploration, Inc.	Rig 232	Drilling Rig	2,000 HP		$5,300,000
4	Transmeridian Exploration, Inc.	Emba Trans Oil Terminal	Rail Oil Terminal	25	%	$1,400,000
	OBLIGATIONS:
1	Kazstroiproekt Too (KSP)	Has the right for two years, to convert for 50% of the license.
2	Seaboard Equipment Company	Note	Drilling Rig			$3,300,000
3	Seaboard Equipment Company	Note	Drilling Rig			$2,000,000

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We were incorporated in the state of Delaware on April 18, 2000 as an independent energy company established to develop identified and underdeveloped hydrocarbon reserves in the region of the former Soviet Union known as the Confederation of Independent States (CIS) and more particularly the Caspian Sea region. We target opportunities to purchase proved and potential oil and natural gas reserves at below international finding cost rates such as in distress sales. For example our acquisition cost from a distress sale, based on an independent engineering evaluation of the known producible reserves in South Alibek was about $0.20 per barrel compared with comparable industry sales in the region of about $1.00 per barrel. We also concentrate on properties that are close to existing infrastructure for exportation of oil and gas, which reduces associated costs as well as the time needed to place wells on production. We prefer to invest in projects in which we can have a controlling interest.

We are in the start-up phase of exploiting the one project we currently have available for exploration and production of hydrocarbons. The project is located in the Caspian region of western Kazakhstan. While the South Alibek Field is located near other producing and proved oil fields and near pipelines and railroads, you should note that proximity to such fields and infrastructure does not assure that we will be able to successfully exploit our resources.

For our projects, all exploration and production activities are conducted through wholly owned operating subsidiaries. Transmeridian Exploration, Inc. British Virgin Islands (BVI) is responsible for the management of the South Alibek Field, with Open Joint Stock Company (OJSC) Caspi Neft TME (Caspi Neft TME) established in Kazakhstan to handle all the joint venture operations of that project. The Exploration License 1557 for South Alibek and the related Exploration Contract for the exploration work are registered in the name of the operating company Caspi Neft TME.

Transmeridian Exploration, Inc.(BVI) was formed in December 1997 by one of our directors and founders, Mr. Peter Holstein and Transmeridian Kazakhstan Inc.(BVI) was formed in March 2000. Prior to 2000, neither company had any operations, assets or liabilities. Both are registered in the British Virgin Islands with their registered office at Nerine Chambers, 5 Columbus Centre, Pelican Drive Road Town, Tortola, British Virgin Islands.

Our corporate headquarters comprising 6,725 square feet of rented executive offices at a monthly rental of $9,527 on a five-year lease are, in Houston at 397 N. Sam Houston Pkwy, E. Suite 300, Houston, Texas 77060. The corporate office of Caspi Neft TME is in Almaty, Kazakhstan, Seifullin Street 563, 5th Floor comprising 4500 square feet rented monthly for $5,460 and their branch office in Aktobe, Kazakhstan, is at Gaziza Zhubanova Street, 50 A comprising 1,162 square feet rented monthly at $540. Our Houston telephone number is (281) 999-9091.

Our staff consists of an experienced management team with five professionals in the Houston office plus the support of expert engineering and geoscience consultants as needed and an operations management team and staff in Almaty and Aktobe comprised of 22 in Almaty and 51 in Aktobe and 8 field personnel, as well as contract employees supervised by our expatriate engineers.

Acquisition of Transmeridian Exploration, Inc., (BVI)

Transmeridian Exploration, Inc. was formed on April 18, 2000.

Transmeridian acquired all of the issued and outstanding shares of Transmeridian Exploration, Inc. BVI on April 19, 2000 in exchange for the issuance of 18,900,000 shares to each of Messrs. Peter Holstein and Lorrie Olivier. (See “Certain Relationships and Related Transactions”)

Transmeridian BVI had no assets or liabilities prior to its acquisition and its only commercial activity consisted of a consulting agreement with Kornerstone Investment Group Ltd (Kornerstone). The consulting agreement, signed on May 1, 1999 for the identification of potential property acquisitions in Kazakhstan and the negotiation of the purchase terms, gave them consideration of a 10% carried interest upon consummation of any such property acquisition.

During 2000, Kornerstone identified a potential acquisition. A Share Purchase Agreement dated March 24, 2000 was signed with Alpha Corporation Ltd (Alpha) pursuant to which Transmeridian Exploration, Inc. BVI agreed to acquire license 1557.

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On March 31, 2000 an option Agreement was signed with Tracer Petroleum Corporation (Tracer) pursuant to which Tracer acquired a 4.5% interest in the License 1557 and was granted the right to acquire up to a 50% interest in the License 1557.

None of these agreements required payment by or receipt by Transmeridian Exploration, Inc BVI of any monies on the assignment of or transfer of any rights unless and until the transactions contemplated by the Share Purchase Agreement were consummated. No payments were made or rights transferred until after our acquisition of Transmeridian Exploration, Inc. BVI on April 19, 2000. (See “Acquisition of Caspi Neft and License 1557”)

Acquisition of Caspi Neft TME and License 1557.

Kornerstone identified the South Alibek Field as a potential acquisition. The Share Purchase Agreement provided for a down payment of $100,000, held in trust until the final transaction in April 2000 in exchange for an option period to allow for satisfaction of certain legal conditions required to transfer the License 1557 from Alpha’s operating entity to the newly formed entity Caspi Neft TME. Transmeridian Exploration, Inc.(BVI) would then purchase 100% of the shares of Caspi Neft TME once it was verified that this entity had a certifiable clear title to the License and related Exploration Contract for License 1557. The full purchase price for securing 100% control of the License and stock of the title holding company was $4,000,000.

Prior to our acquisition of Caspi Neft TME, the License was held by another subsidiary of Alpha. There was no activity in this subsidiary nor was there any activity on the oil and gas property related to the license.

On April 19, 2000 the Share Purchase Agreement was initiated by Transmeridian Exploration, Inc.(BVI) with the payment of $614,158 by Tracer to Alpha, for which Alpha initiated the transfer of the License 1557 and Exploration Contract for South Alibek to Caspi Neft TME and assigned 100% of the shares of Caspi Neft TME to Transmeridian Exploration, Inc (BVI).

On June 7, 2000 the License 1557 and Exploration Contract for South Alibek was officially transferred to Caspi Neft TME by Resolution 645 of the Republic of Kazakhstan parliament and Alpha transferred the shares of the corporate entity to Caspi Neft TME. Thus, at this time, Transmeridian through its subsidiaries, now held full title to the South Alibek Field.

In August of 2000 we paid Alpha $500,000 to restructure the Share Purchase Agreement in order to extend the $3,385,842 balance due on the Share Purchase Agreement.

In September of 2000 Tracer elected not to participate on a 50% basis but chose to retain a 4.5% working interest in the property.

In 2001, Transmeridian increased its working interest to 90% by acquiring Tracer’s 4.5% working interest in exchange for 100,000 shares of convertible preferred shares of Transmeridian. Each share of preferred stock is convertible into fifteen shares of our common stock for a five-year period. In addition, Tracer received warrants for the purchase of up to one million shares of our common stock at a price of $1.00 per share for a maximum of two years. In March 2002 Tracer converted all of their Series B Preferred shares to common. As of the date of this prospectus, none of the warrants have been converted or exercised.

The final payment terms for the Share Purchase Agreement were settled on April 20, 2001 by the payment of $385,842 and the issuance of a $1,000,000 note due December 1, 2001, secured by 25% of the stock in Caspi Neft TME, the license holder. This note was paid on December 1, 2001 with funds from our bank financing.

The South Alibek field was discovered in 1996 when the Alibek No. 29 was drilled and tested flowing oil. The Government Operating Company in charge of this exploration drilling was without funds to continue operations and the South Alibek field was offered in a public tender in the government’s privatization program. OJSC Caspi Neft won the tender and began looking for a financial partner for the continued exploration and development of the field. We negotiated to purchase the Company thereby giving us the license rights to the exploration and development of the field. After we acquired the acreage, we conducted geological, petrophysical and engineering studies of the available well data as well as the available seismic over the area. This data supported the Ryder Scott Company reserve study which confirmed and quantified from an independent third-party source our evaluation of the potential of the field. The cost we paid for the license bears no relationship to the value of the reserves that the Ryder Scott Company later determined for the field.

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Description of Transmeridian’s Oil and Gas Property.

The cornerstone of our business and growth strategy was our acquisition of interest in the South Alibek field, located in the Caspian region of western Kazakhstan. The South Alibek Field is located in the northeastern portion of the Caspian Sea Region, in northwestern Kazakhstan within the prolific oil region of Aktobe. It is approximately 380 kilometers (225 miles) northeast of the giant Tengiz oil field. South Alibek lies in a fairway of oil and gas fields that produce from carbonate reservoirs of Middle Carboniferous and Lower Carboniferous age. The trend follows the reef buildup on the margin of an ancient sea in this area. The field is located in the Mugodzhar region of the Aktubinsk Oblast, 240 kilometers (75 miles) south of the city of Aktobe and the license area for the field is 14,111 acres (57.106 sq km).

The project is in very close proximity (10 miles) to two large developed oil fields, Kenkiyak and Zhanazhol Field. The South Alibek project is within an area of good infrastructure, including oil and gas pipelines, electrical transmission connections, all weather roads, small towns and trained oilfield labor. The fields in the region were identified and developed during the time of the former Soviet Union and soon after its breakup all activity on the Alibekmola and South Alibek field stopped due to lack of funds to finance its development. Tenders were held to offer the further exploration and development of these fields to private investors.

The South Alibek field is immediately adjacent to the Alibekmola Field on its western flank and is separated by a known major fault. The oil reservoirs are in the Middle Carboniferous (KT1) and Lower Carboniferous (KT-2) limestones which can be found at an initial depth of 6,500 feet and are generally 7,000 feet thick in the area of the field. The carbonate limestones are the main oil reservoirs for many of the fields in the area. The net pay thickness for Well No. 29 based on evaluation of electric logs and production tests is estimated to be 700 feet. Based on additional wells drilled during the Soviet era, in and on the border of the license, combined with seismic coverage, we are estimating that this amount of net pay extends over most of the area covered by the License 1557. The estimate of average pay intervals through-out the field area is based on seismic, which gives us control on the structural extent of the productive intervals and well logs with extensive petrophysical evaluation which allow for correlation and area control within the field area. We also have well tests over these same intervals which gives us confidence of the productive nature of these intervals.

The wells drilled in South Alibek before and soon after the independence of Kazakhstan were part of the field delineation program of the Soviet-modeled geological association, a company acting on behalf of the government. The Alibekmola and South Alibek Fields are delineated by 31 wells, two of which are within the area covered by License 1557 and a grid of modern 2D seismic. The existence of a downthrown field adjacent to the Alibekmola main structure was discovered in 1994 with the drilling and testing of well Alibekmola No. 29. The South Alibek Field is about 2,000 feet lower than the Alibekmola Field having a different production drive mechanism, deeper oil water contact and generally a higher oil quality.

Oil and Natural Gas Reserves

Extensive geologic and engineering information obtained from 1996 to December of 2000 provides the basis of the technical evaluation and conclusions made by us and third parties. Reserves estimates are based on the available data on South Alibek Field, Alibekmola Field and Zhanazhol Field. The Ryder Scott Company, a US independent engineering company, estimated our net known producible reserves in the South Alibek Field of 18.225 million barrels of oil as corrected for its current 90% interest in the property. These reserves only include the reserves estimated to be recoverable from Well No. 29 and two 80-acre offset units (wells) in the 14,111 acre license area. Larger reserves are anticipated if certain reasonable assumptions based on the nearby analogous fields are proven applicable for South Alibek Field. These reserves estimates are contingent on successful confirmation of the estimates and assumptions made in arriving at those estimates and have the types of risks associated with each category as defined by the SPE/SPEE that are normally associated with oil and gas property estimates. (See “Report of Independent Petroleum Engineers”)

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The Kazakhstan Government on June 5, 2002 issued a notification that the certified reserves of 15 million barrels and 10 BCF of gas were added to the official balance of national  (Kazakh) commercial reserves, designated by them as C1 reserves.  These reserves are calculated to be recovered from the 2 main zones within the KT2 within a 1-kilometer radius (777 acres) surrounding Well No. 29.   Reserves for the combined C1 and C2 reserve categories of 128 million barrels and 88 BCF of gas were also approved for the same zones within a limited mapped area.  This certification of commercial reserves now allows for the issuance of an Exploration and Production Contract to further exploit reserves from the area within License 1557.   The in-country reserves work did not address the reserves potential in the KT1 (upper carbonate reservoir) or the untested deeper reservoirs in the KT2.

Summary of the Work Performed by The Ryder Scott Company

The Ryder Scott Company prepared an estimate of the reserves, future production and income attributable to our certain leasehold interests as of December 31, 2001. The subject property is located in South Alibek Field, License Number 1557, in the Republic of Kazakhstan. The income data were estimated using the Securities and Exchange Commission (SEC) requirements for future price and cost parameters.

The estimated reserves and future income amounts presented in this report are related to hydrocarbon prices. Hydrocarbon prices in effect at December 31, 2001 were used in the preparation of this report as required by SEC rules; however, actual future prices may vary significantly from December 31, 2001 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

The estimates of reserves presented herein were based upon a detailed study of the properties in which we own an interest; however, The Ryder Scott Company has not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist, nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. We have furnished all of the accounts, records, geological and engineering data, and reports and other data required for the Ryder Scott Company investigation. The ownership interests, prices and other factual data were also furnished by us and were accepted without independent verification. The estimates presented in this report were based on data available through December 2001.

The following table presents The Ryder Scott Company’s estimated net proved oil and natural gas reserves and the present value of our reserves at December 31, 2001, based on, and qualified by reference to, the reserve report prepared by them. The present values, discounted at 10% per annum, of estimated future net cash flows before income taxes shown in the table are not intended to represent the current market value of the estimated oil and natural gas reserves we own.

The present value of future net cash flows before income tax as of December 31, 2001 was determined by using the stated sales price offered for field deliveries using the market crude price of Dated Brent as of December 31, 2001 of U.S. $20.50 per barrel less a 25% discount for quality and transportation and handling for a net price of U.S. $15.37 per barrel. The Ryder Scott Company utilized an estimate of 6% for government royalty in the calculations of present value. Royalty rates currently being applied to new production contracts in Kazakhstan range between 6-10%. No value was assigned to gas reserves as currently there is no delivery contract for gas sales. Per The Ryder Scott Company (December 31, 2001) (See “Report of Independent Petroleum Engineers”)

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Future Net Revenue
Category	Oil	Gas	Total	Present Worth
Proved:	Bbls	Mmcf	(Undiscounted Future Net Revenue)	(Discounted Future Net Revenue (10%))
Developed Non Producing	5,808,683	1,144	$  89,308,496	$  32,953,417
Undeveloped	11,836,418	2,331	$181,989,793	$  95,964,065
Total Proved	17,645,101	3,475	$271,298,289	$128,917,482

Summary of Productive Area
South Alibek Field (License 1557)

Total Area	14,111 acres
Proved	240 acres		1 well plus 2 offsets at 80-acre sp
Remaining	13,871 acres		(1)
Interest	90	%	(2)
Wells	1		(3)

(1) We are in the third year of a 6-year exploration period of the License for this property and there are no prior year properties. Commercial production from the field has not commenced as of this filing.

(2) Subsequent to year-end we acquired the 4.5% interest previously owned by Tracer.

(3) Well No. 29 was on test production from February 26, 2001 to April, 2001.

Oil and Gas Producing Activities: (Unaudited)

Total costs incurred in the acquisition of the License 1557 and the formation and development of our wholly owned subsidiary Caspi Neft TME, the owner of the oil and gas exploration activities, all incurred within Kazakhstan, were as follows (in thousands except per barrel information):

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	For the year ended December 31, 2001 (000)	For the year ended December 31, 2000 (000)
Property Acquisition costs
Unproved	$           —	$           —
Proved	$      5,598	$      3,944
Exploration Costs		$           —
Development Costs	$      2,168	$         501
Depreciation, depreciation and amortization per
equivalent barrel of production	$           —	$           —
The aggregate capital costs relative to oil and gas
producing activities are as follows
Unproved oil and gas properties	$           —	$           —
Proved oil and gas properties	$      7,766	$      4,445
Accumulated depreciation, depletion and
amortization	$           —	$           —
Net Capitalized Cost	$      7,766	$      4,445

Estimated Oil and Natural Gas Reserves (Unaudited)

The following information regarding estimates of the Company’s proved oil and gas reserves, all located in Kazakhstan, is based on reports prepared on behalf of the Company by independent petroleum engineers, The Ryder Scott Company.

Because oil and gas reserve estimates are inherently imprecise and require extensive judgments of reservoir engineering data, they are generally less precise than estimates made in conjunction with financial disclosures. The revisions of previous estimates as reflected in the table below result from more precise engineering calculations based upon additional production histories.

Proved developed and undeveloped reserves	Year ended December 31, 2001		Year ended December 31, 2000
	Natural Gas (Mmcf ”s)	Oil (Bbls)	Natural Gas (Mmcf ”s)	Oil (Bbls)
Beginning of period	3,391	17,212,772	-0-	-0-
Revisions of previous year estimates	84	431,646	-0-	-0-
Extensions, discoveries and new additions	-0-	-0-	-0-	-0-
Improved recovery	-0-	-0-	-0-	-0-
Purchase of minerals in place	-0-	-0-	3,391	17,212,772
Sales of minerals in place	-0-	-0-	-0-	-0-
Production	-0-	-0-	-0-	-0-
End of period	3,475	17,644,418	3,391	17,212,772

Standardized Measure of Discounted Future Net Cash Flows from Oil and Gas Operations and Changes Therein.

The standardized measure of discounted future net cash flows was determined based on the economic conditions in effect at the end of the period presented, except in those instances where fixed and determinable gas price escalations are included in contracts. The disclosures below do not purport to present the fair market value of our oil and gas reserves. An estimate of the fair market value would also take into account, among other things, the recovery of reserves of an independent engineering evaluation of the known producible reserves in the field, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and risk inherent in reserve estimates.

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The reserve estimates provided at December 31, 2001 are based on oil prices of approximately $15.38, which approximates 75% of the Dated Brent North Sea Brent Crude price per barrel which related to a commercial offer at that time to purchase crude from the field. No value was assigned to gas reserves as currently there is no delivery contact for gas sales.

	Year ended December 31, 2001 ($000)		Year ended December 31, 2000 ($000)
Future net revenue	271,298		309,830
Future costs
Lease operating expenses	(27,227	)	26,202	)
Development costs	(10,661	)	10,407	)
Future net cash flows before income taxes	233,410		273,221
Discounted at 10% per annum	(104,492	)	(123,765	)
Discounted future net cash flow before income taxes	128,917		149,456
Future income taxes, net of discount at 10% per annum	(38,675	)	(44,107	)
Standardized measure of discounted future net cash flows	90,242		105,349

The following are the principal sources of changes in the standardized measure of discounted future net cash flows:

	Year ended December 31, 2001		Year ended December 31, 2000
	(in thousands)		(in thousands)
Beginning of year	$  105,349		$           —
Accretion of discount	$      6,695		$           —
Revisions to previous quantity estimates	3,298		—
Net changes in prices, net of production costs	(25,100	)	—
Purchase of reserves in place	—		105,349
End of year	$    90,242		$  105,349

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Commencement of Operations and Initial Production Activities

We currently have a ninety percent (90.0%) equity interest in the Kazakhstan property with Kornerstone holding a ten percent (10%) carried interest. Contractually, therefore, we are responsible for 100% of development costs. We pay the 10% interest holder’s portion of expenses until the project reaches a positive cash flow basis. Then we are reimbursed from production for the payments made on behalf of the 10% interest holder, Kornerstone, plus 10% interest.

An administrative office in Almaty, Kazakhstan, was staffed in June 2000 and the physical possession of the field was transferred to Caspi Neft TME in July 2000 by the Kazakhstan authorities. All Kazakhstan operations and administration are coordinated through this representation office in the country’s commercial center. The Almaty office, with a staff of 22, handles all federal government liaisons and contacts as well as serving as our head office in the country. A branch operating office was established in the town of Aktobe, which is the nearest industrial area to the field. This office, with a staff of 51 is to maintain a liaison with the local governmental regulatory agencies and the respective state governor’s office, as well as handling the implementation of all operations of South Alibek Field with the help of the field office, staffed by 8 field personnel as well as contract employees supervised by our expatriate engineers.

An Early Start-up Program (ESP) has been established to evaluate reservoir production characteristics that will be critical in determining the final design of the field development program. Permits and operational plans were filed with the authorities to begin production testing of Well No. 29 in January 2001. The various permits and authorizations required were granted in February 2001. This testing program has been authorized for 18 months, which will allow us to flow and recover production from Well No. 29 during this period.

The initial work program on Well No. 29 includes remedial work to repair mechanical deficiencies as well as evaluation of new zones identified but not tested in the original drilling and testing of the well. This ongoing work began in February 2001 with an extended flow test of the existing well No. 29. Test production from well No. 29 was 180 barrels of oil per day, off and on, for a total of 30 days of production from the 13 feet (4 meters) of open interval in the well intervals that was in condition to flow without any treatment or improvement in well production mechanics. Test production at this rate totaled in excess of 5,000 barrels of oil as of April 30, 2001. Currently the field is capable of producing crude with a high gravity of 39(Degree) API and with a low sulfur content of about 0.8%.

A program to repair well damage and to open additional intervals for production evaluation was completed in June 2001. During this workover, it was discovered that in Well No. 29 only 13 feet (4 meters) of oil pay had been previously opened to production. After repair of well damage, an additional 60 net feet of oil pay intervals were opened by perforations. No other perforations are planned until further logging and test results can be analyzed. The well testing is continuing, with installation of new down hole and surface production facilities. Production engineer modeling by Weatherford Artificial Lift Systems of the new mechanical configuration of the well, pump and surface facilities indicates that the equipment relieves the pressure on the reservoir, allowing the fluid to come into the well bore at a faster rate. The modeling indicates that with 60 net feet of pay and the help of the artificial lift equipment, test production rates of 600 BOPD to 1,500 BOPD can be anticipated with the installation of this additional equipment. Mechanical failures and loss of production equipment in the hole have halted all work on the well until adequate well-service equipment can be contracted to retrieve the lost production equipment and place the well in a mechanical condition to produce.

This testing program will provide well production data and reservoir pressure analysis essential to the design of permanent production facilities. This production also facilitates the estimation of reserves required in the transition to a commercial license and production contract for the exploitation of the field.

This work will be followed this year, with the initiation of the drilling program, with the drilling of two new delineation wells and further improvement of the production facilities and infrastructure (See “Management’s Discussion of Our Plan of Business”)

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Marketing of Test Production

The Mugodzhar region of the Aktubinsk Oblast, in which South Alibek is located, is one of the most highly developed areas for oil field development and production in the Republic of Kazakhstan, with existing roads, railroads, rail oil terminals and oil pipelines.

Companies in the area of South Alibek Field utilize both the KazTrans Oil and Russian Transneft pipeline system to export their oil to regional hub export locations such as Samara, Ukraine and 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 this year with the opening of the Caspian Pipeline Consortium (CPC) pipeline, raising current capacity of 250,000 barrels oil per day (bopd) to 800,000 bopd by year end. Two oil pipelines currently service the producing fields, Kenkiyak and Zhanazhol, 10 miles from South Alibek, with 50,000-barrel-per-day and 93,000-barrel-per-day capacities, with only one pipeline currently being used at about 50% of its capacity. The pipelines transport the oil to the Bestamak rail terminal and the oil refinery in Orsk, which is a transfer point for swaps to western markets. The Alibekmola Field, adjacent to South Alibek, is now beginning development, with pipeline constructed across our license area to connect to the larger capacity pipeline at the Kenkiyak Field. The CPC pipeline is between Atyrau and the Black Sea Port of Novorosiisk, and access could be by rail or the laying of a 280 mile pipeline from Kenkiyak to Atyrau as planned by KazTransOil. The capacity would be about 300,000 bopd and would provide an alternative routing for the project’s production. Our current plans do not rely on entry in the CPC system for its export and sales routes but this facility provides a feasible alternative. All economic estimates assume the utilization of trucking, pipeline and rail facilities located within 35 miles of the field.

Since we do not currently have access to a pipeline, the production is being sold, either at the field or trucked to a local rail terminal to export to local markets depending on market conditions at the time The production from Well No. 29 and the new wells planned for this year is expected to be sold on the export market at world oil prices less deductions for quality, transportation and handling costs. Under the terms of the Exploration and Production Contracts, the Kazakhstan government can require us to sell up to 10% of our production into local markets, but so far they have not done so. The use of the rail system for shipment of crude to Western Europe and China is used by a number of companies, the largest of which was Chevron’s Tengiz operations, shipping about 161,000 barrels per day prior to the completion of the CPC Pipeline. Other operators in the Mugodzhar region including Shell Oil, Maersk Oil & Gas, Veba Oil and the Chinese National Petroleum Company have included rail transport in their marketing of oil. Four oil terminals are present in the area and available for storage and sale to export markets. They include Emba 5, 30 miles from South Alibek, Emba, 35 miles from South Alibek, Shubarkuduk, 94 miles from South Alibek and Bestamak, 120 miles from our field. Trucking crude to the terminals is considered a temporary measure until we can establish our own export facilities or pipeline connections to these or other export routes.

Exploration Contract and Conversion to Exploration and Production Contract

Exploration Contract

Currently we have an Exploration Contract for South Alibek. As long as we operate under the Exploration Contract we can produce the wells under a test program and pay a 2% royalty. The exploration period consists of six (6) successive years from the effective date of the License dated April 29, 1999.

The License may be extended twice as mutually agreed by the parties to the License with each extension period having a term of two years. Therefore the total possible exploration period utilizing the maximum of extension periods allowed by the contract is a term of ten (10) years. For each extension requested of the competent government body, the parties shall determine the part of the Contractual Area for further exploration work and make the appropriate changes in the applicable working program. The Exploration Contract can be converted to terms under a Production Contract at any time that we wish with the requirement that we file an approved reserves report based on the current test production of Well No. 29.

In June of 2002 the Government issued a certification of the commercial reserves surrounding Well No. 29 and the company initiated discussions to expand the current Exploration Contract to an Exploration and Production Contract. This new contract will incorporate all the current tax laws and legal regimes in place when the document is executed later this year. The exploitation period will be 25 years, unless extended, and the commercial terms are expected to be in line with government parameters for other fields of this size.

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Typical Production Contract in Kazakhstan

While the majority of the production contract is defined by the country’s petroleum and tax code, there are some terms open to negotiation, such as royalty rates, production bonus and other production-related assessments. The normal term provided under the Kazakhstan Petroleum Code for the exploitation of a proved oil field under a Production Contract is 25 years unless extended. The typical exploration period is 5 years unless extended. In total, a contractor will have at least 30 years to explore and exploit a contract area unless extended. Generally, with the commercial production of a field, the royalty can be as much as 10%-12% of the net production from the field. A typical commercial production contract would include definitive terms describing the commercial and tax conditions for producing any fields discovered within the License area. We currently favor a contract structured on a Tax / Royalty model as opposed to a Production Sharing Model. Under a Tax/Royalty model we would pay 100% of all development costs and receive 100% of all sales proceeds.

Steps we must take to obtain a Production Contract and preserve our rights

In accordance with the Exploration Contract and the provision of the Kazakhstan Petroleum Code, we will be expected to inform the government within 30 days of the existence of any commercial reserves at which time we will be expected to convert our operations to a Production Contract, which will also cover the entire license area. We believe the present Exploration Contract provides us with a preferential right to receive such a commercial production contract. We have sought and received a letter from the Ministry of Natural Resources as to their preferred treatment of transitioning our existing operating contract to include commercial production. Section 10.4. of the present Exploration Contract grants us the exclusive right to a production contract; it states that a Commercial Discovery entitles the Contractor with the exclusive right for conclusion of a Production Contract provided that provisions of the License and the Contract are met. The letter we received from the Ministry of Energy, Industry and Trade clearly states that we have an exclusive right to be granted the right for hydrocarbon production and we have a right to a Production Contract. When we establish commercial production we expect that we will convert from an Exploration Contract to an Exploration Production Contract, as we will still have an unexpired Exploration term and additional exploration works would be warranted.

The material terms of the letter from the Ministry of Natural Resources

A. That the Agency of the Republic of Kazakhstan for Investments is the competent body for Exploration, Production and Joint Exploration and Production of Natural Resources.

B. Since we have an Exploration contract and in accordance with Regulations on Granting Use of Subsoil Natural Resources Article 3.1, we have an exclusive right to produce the hydrocarbons arising from exploration works and to enter in to a Production Contract with the competent authority for the development of the reserves.

C. At all times, the completion of the Exploration works must be completed in a time-efficient manner.

D. The Ministry of Energy, Industry and Trade is willing to prepare an expert evaluation and approval of the South Alibek field within the time frame prescribe by law.

License Extension

The original area of the South Alibek License was 3,396 acres (13.745 sq. km.) when acquired by us. During 2001 our technical team of specialists studied the feasibility of extending the license area due to the structural continuation of the South Alibek Field’s oil-bearing reservoirs beyond the original license boundary. Our specialists, as well as The Ryder Scott Company, a US independent engineering company, estimated that approximately half of the Field was potentially outside of the original license area. An Application was made to the government authorities and an extension was granted and authorized by government resolution on November 7, 2001. The new license area is 14,111 acres (57.106 sq. km.) and is governed by the existing Exploration Contract and Exploration License, giving us rights to explore and continue our exploitation of the hydrocarbons found within the license.

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Economic and Political Climate in Kazakhstan

Adverse economic or political developments in Kazakhstan may adversely affect our business. Kazakhstan has been independent from the Soviet Union for only 10 years. Future changes in the political and economic environment in Kazakhstan may adversely affect our business. That is why we maintain a Kazakhstan Company in Almaty, staffed by Kazakhstan citizens, which aids in the relations with the local government and helps to keep Houston-based management informed as to the proper protocol and any adverse developments. These developments could include, among other things:

• local currency fluctuations or devaluation;

• civil disturbances;

• exchange controls or restrictions on availability of hard currency;

• changes in crude oil and gas price and transportation regulations;

• changes with respect to taxes, royalty rates, import and export tariffs and withholding taxes on distribution to foreign investors; nationalization or expropriation of property; and

• interruption or blockage of oil exports.

Changes in Kazakhstan laws and regulations and the interpretation of those laws and regulations may also adversely affect our business. Kazakhstan’s foreign investment laws, including petroleum licensing legislation, corporate law, tax law, customs law and currency and banking legislation, are still developing and uncertain. These laws are subject to changing and different interpretations, and they may contain inconsistencies and contradictions; some may be discretionary in application and enforcement. As a result, Kazakhstan laws could have a material adverse effect on our business and financial results of operations. Our interests in exploration and production contracts and other agreements may be susceptible to revision or cancellation, and legal redress may be uncertain, delayed or unavailable. Ensuring our ongoing right to contracts will require a careful monitoring or performance of the terms of the contracts and monitoring of the evolution under the Kazakhstan laws and contract administration practices. That is why we engage law firms in Kazakhstan, Russia and the United States. Together with our Kazakhstan team, the Houston executive team and our legal and accounting advisors, we can react to any situation quickly and protect our interests when needed.

Changes in current policies of the Kazakhstan government may also adversely affect our business. Government policies may affect our ability to market oil and natural gas to export markets where hard currency earnings are available. The government has previously issued regulations limiting export of oil to assure local supplies to source price controlled fuel for the local markets. The government has announced that up to ten percent (10%) of a producer’s production must be reserved for domestic refining. No regulations have been issued and there is no assurance that world oil price can be realized on such reserves destined for local markets.

Environmental Regulations

The environmental regulations to which we are subject may become more numerous and compliance with them may become more expensive. We must comply with Kazakh laws and international requirements that regulate the discharge of materials into the environment. Environmental protection and pollution control could, in the future, become so restrictive as to make production unprofitable. Furthermore, we may be exposed to potential claims and lawsuits involving such environmental matters as soil and water contamination and air pollution. We are currently in compliance with all local and international environmental requirements and are closely monitored by the Kazakh environmental authorities. We have not made any material capital expenditures for environmental control facilities and have no plans to do so in the foreseeable future. Our Environmental Policy is Clean As You Go and therefore our cost to comply with government regulations is included in our daily field operating costs. To date we have not seen nor been made aware of any material effects of government regulations that would adversely impact our business or operations outside the normal course of business. We experience the same government regulations in Kazakhstan as we do here in the United States: taxes, royalty payments, reporting and environmental compliance. If we have an environmental spill, we report it to the Environmental Agency with a recommended clean up procedure and they approve and/or modify and approve and we proceed with our own cleanup under their supervision.

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All costs associated with meeting and operating within the environmental laws of Kazakhstan are included in our normal operating budget. We know of no Kazakhstan environmental law, which will cause a material impact on the viability of our project. Kazakhstan does require that all operating companies establish a reserve to reclaim the industrial areas used during the life of the field and to liquidate all depleted wells at the end of the contract term. Our existing contract requires that a fund equal to 1% of the capital development budget of the project must be funded during the development of the field to cover such costs. We do not estimate that this reclamation fund or the actual cost of reclamation will be a material cost to the project.

MANAGEMENT’S DISCUSSION OF OUR PLAN OF BUSINESS

The following discussion of our plan of operation should be read in conjunction with the consolidated financial statements and the attached notes included elsewhere in this prospectus. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including but not limited to, those set forth under Risk Factors and elsewhere in this prospectus.

We have executed a Share Purchase Agreement with Kazstroiproyekt Ltd (KSP), which, at its option within two years, provides for the possible sale and transfer of 50% interest of OJSC Caspi Neft TME, the company which holds the license to the South Alibek Field. In exchange for this interest, KSP must make available initially a three-year $20 million dollar financing for the development of the field. KSP arranged the $20 million loan through Turan Alem Bank of Kazakhstan. Within twenty-four months of this initial loan, KSP must determine if it wants to continue with the project. If KSP determines that it will continue, KSP will be responsible for the payment of $15 million of the initial loan and make available up to $30 million in additional development financing at commercial rates. The portion of the loan not cancelled by the contribution of KSP will be treated as a corporate cost of OJSC Caspi Neft TME to be retired from proceeds of operations or further financing. If KSP determines, after the option period, that it will not continue in the project, it will relinquish all claims and rights to the 50% interest in Caspi Neft TME. Caspi Neft TME will then be solely responsible for the entire existing loan, having an additional 18 months to cancel the debt. The partnership is governed by a joint shareholders agreement which is based on a typical international joint operating agreement. We will provide for all the engineering and general directorship of the company as operator for at least the first 3 years.

An interim bridge loan for $1.5 million was issued through Turan Alem Bank in December 2001, and the Company paid off the $1 million Al Alpha note on December 1, and a final credit agreement with Turan Alem Bank for the principal loan of $20 million was signed on February 4, 2002. We believe that this financing should be sufficient to bring the field into production and allow the completion of the initial phase of delineation drilling and installation of testing and production facilities to handle production rates of up to 30,000 barrels of oil per day. All production will be treated to allow for the sale of crude by truck transport to local railroad transport terminals of rates up to 10 thousand barrels per day until pipeline connections are made to allow for increased rates of delivery. Additional financing may be required if a larger scale of production is indicated by drilling results.

Financial Plan and Plan of Operation for 2002

Our focus in 2002 will be:

• Financing through the Sale of Stock

• Crude oil forward purchase contracts

• Bank Financing of Future Crude Production

• Development Financing

• Joint Venture Partners

• Commence initial 10-well drilling activities

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• Installation of Testing and Treating Facilities

• Staffing

Financial Plan 2002

Financing through the Sale of Stock

We may file registration statements with the SEC in the near future for the sale of its common stock or other equity/debt instruments to raise $5 million to $10 million in working capital. These funds will allow the company to strengthen its balance sheet, considering the debt being incurred, and allow us to be in a position to act on acquisition opportunities as they arise.

Crude Oil Forward Purchase Contracts

On August 27 2001, Caspi Neft TME executed a Crude Oil Forward Purchase Contract with So Cal Energy Incorporated for the delivery and sale of a minimum 3,000 tons (approximately 21,000 barrels) of crude oil per month at a price tied to Dated North Sea Brent Crude. The price we receive for our oil and natural gas production is tied to the price of North Sea Brent Crude. North Sea Brent Crude prices fluctuate depending upon several factors such as world demand. Brent crude oil prices rose from $25.26 to $25.31 from May 15 2001 to March 26, 2002. The agreement provides for off takes from the rail terminals of 21,000 barrels per month initially but can be increased to 210,000 barrels per month if the field delivery capacity can be increased with new drilling. Pricing is based on Dated North Sea Brent Crude discounted $13 per barrel for transportation and quality. Payment will be in US dollars, with 80% prepayment based on the published price of North Sea Brent crude for the date of shipment. The final payment of 20% is determined by the average of a 15-day quote for Dated Brent crude for the respective shipping date. Caspi Neft TME has the right to sell any volumes of oil greater than 3,000 tons per month to other buyers if more favorable pricing terms are offered or if So Cal Energy Incorporated declines the additional volumes.

Due to mechanical problems making production from the Alibek Well No. 29 impracticable at this time, the company and So Cal suspended the previous sales agreement to handle production from this well.  We maintain contacts with this and other marketing companies in the region in anticipation of beginning test production in the third quarter after the initiation of the current 3-well drilling program.

Bank Financing

We have executed a Share Purchase Agreement with Kazstroiproekt Ltd (KSP), and about $9,300,000 in loan draws have been made as of September 30, 2002 to finance drilling operations, cancel all of the company’s previous debt to Al Alpha as well as allow OJSC Caspi Neft TME to repay some of the loans made by us, its parent company. Both we and KSP have pledged all the shares of Caspi Neft TME, as well as the sub-surface rights related to the License 1557 OIL which includes the South Alibek field. In addition, we have provided a corporate guarantee letter for up to $7,000,000 of liability should Caspi Neft TME default on its loan commitments.

The initial $20 million credit line can be drawn down within the first 9 months of the loan period with simple interest accruing at 15% per annum. There is an interest and principal holiday for the first 18 months of the loan. Thereafter interest and principal payments will begin on a quarterly basis.

Joint Venture Partners

Kazstroiproekt Ltd.‘s (KSP’s) principals are the major shareholders of the Turan Alem Bank group. This group has extensive interest in agriculture, power generation and banking investments. This project is their first major investment in the petroleum sector. The agreement with KSP allows for 100% of the financing requirements to delineate the South Alibek Field as well as the investment required to put the field on production at rates of up to 40-50 thousand barrels per day. In short, we consider that the project is now fully financed with the participation of this new partner under Bank Financing above.

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If KSP exercises its option to participate in the field, our interest in the field will be reduced to a net working interest of 40%, with KSP holding 50% and Kornerstone 10%.

Operation Plan

Commencement of Initial Drilling Activities

The investment program for the next three years will include the drilling and completion of 10 wells and the installation of production facilities and pipeline at a cost of approximately $40,000,000. The development of these wells should prove up additional reserves according to the independent petroleum engineering report from The Ryder Scott Company. The successful delineation of the existing field could prove up total reserves up to 380 million barrels. The first three-well program has been initiated with the drilling commencement of the first well in the 3rd Quarter 2002. Two additional wells will immediately follow, with the second nearing completion in the 4th quarter and the third well completed in the 1st quarter of 2003. The total cost of drilling and testing is estimated at $9,600,000 and the construction of a sales trunk-line to the railroad terminal, construction planned for 2002, at an estimated cost of about $2,000,000. We estimate that each well should cost about $3 million dollars to drill and complete and about $200,000 to test and evaluate. Each well should produce test crude which should generate about $825,000 per month in gross revenue under the existing railroad sales program, which would provide about $10-$11 per barrel net-back to the wellhead to cover operating and testing costs. This program will be initiated by the funds from the bank financing but the majority of the development capital will come from the excess internally generated cash flow from wells in our drilling program and/or advance crude sales based on these production levels. Each commercial well drilled will add to this revenue base. We currently estimate that 44 completed wells will be required in the first phase of the field development program.

Most sales from our area of operation are based on the European market price of North Sea Brent Crude. Initial transportation costs are higher than the anticipated pipeline cost of $5.49 per barrel due to the limited amounts of production and the need to truck the produced crude about 35 miles to the nearest railroad sales terminal. Economies of scale will be realized when production increases and transportation costs can be reduced with installation of pipelines to export or other sales points.

To facilitate a continuous low-cost drilling program, on December 28th, 2001 we purchased a Land Drilling Rig named Rig 232-type National 1320UE from Seaboard Equipment Company, Inc. for a total consideration of $5,300,000 to be paid in cash and common stock. We will use this rig to start our 2002 drilling program. The rig was constructed in the middle 80s by western companies and was refurbished in 1998. The equipment is operated by Dingo Drilling International Ltd.

Improvement of Production Facilities

Production facilities for test production of up to 5,000 barrels of oil per day and field production of up to 30,000 barrels per day have been designed and fabrication will be completed in September 2002 with installation by mid fourth quarter 2002. All tankage, piping and construction should be provided by local construction firms which specialize in installing petroleum-processing facilities. We estimate that approximately $4.0 million will be required for the installation of these permanent production facilities to process production of 30,000 BOPD.

The gas produced in association with the oil production will be separated, treated and utilized in providing fuel for operations, with the balance initially being flared during the testing phase then later sold to local markets through a nearby gas sales line.

Staffing

At the present time, we have a start-up staff of about 73 professionals between the Houston and Kazakhstan field offices. The drilling program will require a team of at least 6 engineers to be employed from the Houston office. Two drilling engineers will supervise the drilling work in Kazakhstan for 30 days and then be relieved by 2 other engineers from the Houston office for 30 days. Two expatriate production engineers will also rotate on a 30-days-on-and-off basis to supervise the crude oil production. Each of these professionals will require approximately 4 Kazakhstan field assistants for fieldwork and language translation, or 12 in-country employees. This increase in activity and payroll will require administrative support, geologists, engineers, accountants, interpreters and drivers both at the Almaty office as well as at the Aktobe office. With the addition of the pipeline and terminal construction and expanded development field operations we expect to increase the number of employees in about 4 years to approximately 120 employees in Kazakhstan and 15 in the Houston office.

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Growth Strategy

Our focus is to rapidly develop our property in Kazakhstan and, once a stable production and sales stream is achieved, our attention will be directed to the acquisition and development of additional properties that have:

• low entry cost as measured on a dollar per barrel for proved and potential reserves;

• ready access to infrastructure allowing for production within a short time period without significant capital commitments;

• ready access to local and export markets without the need for immediate investment in pipeline construction projects; and

• projects where we can control operations and ownership.

Operationally, we expect to finish the year 2002 in the South Alibek Field with a substantial increase in daily production from test production in the field. Two wells on test production could have the capability of providing 4,000 to 6,000 barrels per day with artificial lift. We plan to continue our delineation drilling program, adding a well on the average every 90 days. A second drilling rig could be added during 2003 to double this drilling rate. A pipeline is planned by the government which will transport about 300,000 barrels per day from the region to the Aktau refinery and existing export sales pipeline networks. The combination of the Emba Terminal and the proposed new pipeline provide adequate assurance that there will be a ready transport route to deliver the field’s production to the local and export markets.

We plan to continue with our reserve-purchasing program that will include at least one additional field acquisition in the region, which can all be managed from one core administration and operational team, in each of the next two years.

Legal Proceeding

We are not party to any pending or threatened legal proceeding, nor are any of our properties subject to a pending or threatened legal proceeding.

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DIRECTORS, EXECUTIVE OFFICERS AND KEY EMPLOYEES

Our directors and executive officers and their ages, as of September 30, 2002 are as follows:

Name	Age	Position
Lorrie T. Olivier (1)	51	President & CEO, Chairman of the Board
Bruce A. Falkenstein	44	Vice President Exploration and Geology
Jeff S. Tucker	31	Assistant Secretary
Jim W. Tucker	60	Vice President Finance, Controller
Philip J. McCauley	39	Director
Angus G.P.M. Simpson	37	Director

(1) These Directors were elected and have served since the formation of Transmeridian in 2000.

(2) These Directors were elected by the sitting Board on October 23, 2000.

(3) Retired from the Board on September 8, 2002.

(4) Retired from the Board on September 9, 2002.

They have all acted as directors since October 23, 2000. All directors hold office until the next annual meeting of stockholders and until their successors have been duly elected and qualified. There are no agreements with respect to the election of directors.

The following represents a summary of the business history of each of the named individuals for the last five years:

Lorrie T. Olivier

Mr. Olivier is President, Chief Executive Officer and Chairman of the Board. From February 1, 1991 to March 30, 2000, Mr. Olivier was employed by American International Petroleum Corporation as a Vice President of Operation and President of American International Petroleum Kazakhstan (AIPK), American Eurasia Petroleum and American International Petroleum Holdings. He was the lead manager in developing the company’s interest in the Caspian Sea region with the acquisition of several large properties, the last three years focused on Kazakhstan as well as developing experience and business contacts in Russia and other CIS countries.

Bruce A. Falkenstein

Mr. Falkenstein is Vice President of Exploration and Geology. He served for 20 years with Amoco, and later with BP from February 3, 1994 to August 5, 2000, as Chief Geophysicist and a manager of the Kazakhstan Exploration team. Since 1992 he has been working and managing the identification, technical evaluation and capture of oil fields and operations of licenses in the CIS, with particular focus on the Caspian Sea region, 6 years of that time concentrating on Kazakhstan, developing experience and industry contacts in the region during this time.

Jeff S. Tucker

Mr. Tucker is Manager of Administration, Regulatory Reporting and Assistant Secretary. From October 2000 until December 2001 he served as Contract Manager for BigFatWow, Inc., an interactive computer advertising company in Dallas, Texas. From January of 1990 until October 2000 he was a Vice President, Secretary, Controller and a Director of Crossroads Environmental Corp.

Jim W. Tucker

Mr. Tucker is Vice President of Finance. From 1966 to 1972 he served Texaco Inc. His last position was Vice President of Texaco Nigeria Ltd. From 1976 to 1988 he served with Texas Oil and Gas Corp., holding positions as Assistant Controller, Vice President and assistant to the President. From January 1, 1990 until January 20, 2001 he served as the Vice President of Finance of Crossroads Environmental Corp. and Chairman of the Board.

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Philip J. McCauley

Mr. McCauley is a Director. He is currently the Chairman and Chief Executive Officer of Audio Navigation Ltd. From November 1, 1983 to December 1, 1999 Mr. McCauley was the chief executive officer of TTL Group Ltd.

Angus G.M.P Simpson

Mr. Simpson is a Director. He has been a Director of Glenrand Ltd. since October 1, 1998 and also a Director and Executive Chairman of Glenrand Simpson Ltd. since October 1, 1999. Prior to this Mr. Simpson served as a Director of Crawley Warren & Co. Ltd.

We have not compensated directors for service on the Board of Directors or any committee thereof. As of the date hereof, no director has accrued any expenses or compensation. Officers are appointed annually by the Board of Directors and each executive officer serves at the discretion of the Board of Directors. We do not have any standing committees at this time.

During the past five years none of our directors, executive officers, promoters or control persons was:

(1)  the subject of any bankruptcy petition filed by or against any business of which such person was a general partner or executive officer either at the time of the bankruptcy or within two years prior to that time;

(2)  convicted in a criminal proceeding or subject to a pending criminal proceeding (excluding traffic violations and other minor offenses);

(3)  subject to any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities; or

(4)  found by a court of competent jurisdiction (in a civil action), the Commission or the Commodity Futures Trading Commission to have violated a federal or state securities or commodities law.

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EXECUTIVE COMPENSATION

There was no executive compensation program as of December 31, 2001. This is the first year of operation and there are no historical compensation amounts prior to 2001 to report. The following table sets forth information concerning the compensation of the named executive officers through December 31, 2000.

Annual Compensation					Long-Term Compensation
					Awards		Payouts
Name and Principal Position	Year (b)	Salary ($) (c)	Bonuses ($) (d)	Other Annual Compensation ($) (e)	Restricted Stock Award(s) ($) (f)	Securities Underlying Options /SAR (=) (g)	LTIP Payouts ($) (h)	All other Compensation ($) (i)
L.T. Olivier	2001	200,000	0	0	0	0	0	0
President CEO
Bruce Falkenstein	2001	100,000	0	0	0	0	0	0
V.P.
Jim W. Tucker	2001	94,444	0	0	0	0	0	0
V.P.

An incentive employee stock option plan was approved at the Annual Shareholders meeting held on October 11, 2001 and Lorrie Olivier and Peter Holstein each gave 2,500,000 shares of stock to the Company, which we redeemed, for this plan. We awarded 1,500,000 options and 100,000 shares as of April 12, 2002 at an exercise price of $0.35 per share. There have been no options exercised as of the date of this prospectus.

There are no arrangements pursuant to which any director has been or is currently compensated for any service provided as a director. Directors and/or officers will receive expense reimbursement for expenses reasonably incurred on our behalf.

Certain Relationships and Related Transactions

On April 19, 2000 we issued 18,900,000 shares to each Mr. Peter Holstein and Mr. Lorrie Olivier in exchange for their stock in Transmeridian Exploration, Inc. (BVI) and $.0006 per share.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information, to our best knowledge as of September 30, 2002, with respect to each person known by us to own beneficially more than 5% of our outstanding common stock, each director and officer as a group.

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NAME AND ADDRESS OF BENEFICIAL OWNERS	NUMBER OF SHARES OWNED	PERCENTAGE OF CURRENT ISSUED AND OUTSTANDING		PERCENTAGE OF SHARES OWNED FOLLOWING COMPLETION OF OUR OFFERING BASED UPON THE PERCENTAGE OF THE SHARES WE SELL
				10	%	25	%	50	%	75	%	100	%
Lorrie T. Olivier	7,800,000	13	%	12	%	12	%	11	%	10	%	10	%
JMLC Investments, Inc. (1)	6,300,000	10	%	10	%	10	%	9	%	8	%	8	%
Colamer Ltd. (2)	800,000	1	%	1	%	1	%	1	%	1	%	1	%
Peter L. Holstein	1,110,000	2	%	2	%	2	%	2	%	1	%	1	%
Sovereign Trust (3)	5,300,000	9	%	8	%	8	%	7	%	7	%	6	%
Kornerstone Ltd.	5,000,000	8	%	8	%	8	%	7	%	7	%	6	%
Roger W. Brittain	150,000	0	%	0	%	0	%	0	%	0	%	0	%
Angus Simpson	50,000	0	%	0	%	0	%	0	%	0	%	0	%
Philip J. McCauley	50,000	0	%	0	%	0	%	0	$	0	%	0	%
Zen Trust (4)	500,000	1	%	1	%	1	%	1	%	1	%	1	%
Remaining Officer	2,667,500	4	%	4	%	4	%	4	%	3	%	3	%
All Officers and Directors as a group (7 persons)	29,727,500	49	%	47	%	45	%	42	%	39	%	36	%

(1) Beneficial owner of JMJC Investments Inc. are the children of Mr. Lorrie T. Olivier, who is the President of the Company.

(2) Beneficial owner of Colamer Ltd. is Lorrie T. Olivier

(3) Beneficial owner of the Sovereign Trust is the Holstein family Mr. Peter Holstein is the settler of the Trust.

(4) Beneficial owner of Zen Trust are the children of Mr. Philip McCauley. Mr. McCauley is the settler of the Trust.

MARKET FOR OUR STOCK

There is a trading market for our common stock on the Over The Counter Bulletin Board (OTC.BB), with trades in the range of a high of $2.20 and a low of $0.15. We are traded under the ticker symbol TMXN.

DESCRIPTION OF CAPITAL STOCK

The following description of our securities and various provisions of our Restated Certificate of Incorporation and our bylaws are summaries. The Restated Certificate of Incorporation and bylaws, copies of which have been filed with the Securities and Exchange Commission as exhibits to our registration statement of which this prospectus constitutes a part, and provisions of applicable law. Our authorized capital stock consists of 200,000,000 shares of common stock, $.0006 par value, of which 59,147,129 shares were issued and outstanding as of September 30, 2002, and 5,000,000 shares of preferred stock, $.0006 par value, of which 3,000 shares of Non-Voting Series A Convertible Preferred Stock were issued and outstanding as of September 30, 2002.

Common Stock

Each share of common stock is entitled to share pro rata in dividends and distributions with respect to the common stock when, as and if declared by the board of directors from legally available funds. No holder of any shares of common stock has any preemptive right to subscribe for any of our securities. Upon our dissolution, liquidation or winding up of our corporate affairs, the assets will be divided pro rata on a share-for-share basis among holders of the shares of common stock after any required distribution to the holders of preferred stock, if any. All shares of common stock outstanding are fully paid and non-assessable.

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Each shareholder of common stock is entitled to one vote per share with respect to all matters that are required by law to be submitted to shareholders. The shareholders are not entitled to cumulative voting in the election of directors. Accordingly, the holders of more than 50% of the shares voting in the election of directors will be able to elect all the directors if they choose to do so.

Currently, our bylaws provide that shareholder action may be taken at a meeting of shareholders and may be affected by a consent in writing if such consent is signed by the holders of the majority of outstanding shares, unless Delaware law requires a greater percentage. Our Restated Certificate of Incorporation provides that they may be amended by the affirmative vote of a majority of the shares entitled to vote on such an amendment. These are the only provisions of our bylaws or Restated Certificate of Incorporation that specify the vote required by security holders to take action. Written notice of the annual and each special meeting of stockholders, stating the time, place, and purpose or purposes thereof, shall be given to each stockholder entitled to vote thereat, not less than 10 nor more than 60 days before the meeting. The holders of a majority of the shares of the corporation’s capital stock issued and outstanding and entitled to vote thereat, present in person or represented by proxy, shall constitute a quorum at any meeting of stockholders for the transaction of business, except as otherwise provided by statute or by the Certificate of Incorporation.

Preferred Stock

The board of directors is authorized, without further shareholder approval, to issue from time to time up to an aggregate of 5,000,000 shares of preferred stock. The preferred stock may be issued in one or more series and the board of directors may fix the rights, preferences and designations thereof. There are two series of Preferred Shares, a Series A and B both with a par value of $.0006. There are 3,000 shares of Series A outstanding with a stated value of $100 per share issued to Ratcliff International Ltd. which are convertible at any time by us, after the stock is publicly tradable, at the rate of 85% of the average bid price for our common stock, five days prior to conversion. The total series accrues dividends at 12.5% per annum of the stated value of $300,158 until conversion. The Series A is non-voting.

ANTITAKEOVER EFFECTS OF DELAWARE LAW AND OUR AMENDED AND RESTATED CERTIFICATE OF INCORPORATION AND BYLAWS

Our Restated Certificate of Incorporation permits the issuance of up 5,000,000 shares of preferred stock, having such rights, preferences and privileges as the board of directors may determine. The issuance of preferred stock, while providing desirable flexibility in connection with possible acquisitions and other corporate purposes, could have the effect of making it more difficult for a third party to acquire, or of discouraging a third party from acquiring, a majority of our outstanding voting stock.

Provisions of our bylaws, which are summarized below, may affect potential changes in our control. The board of directors believes that these provisions are in the best interests of shareholders because they will encourage a potential acquirer to negotiate with the board of directors, which will be able to consider the interests of all shareholders in a change in control situation. However, the cumulative effect of these terms may be to make it more difficult to acquire and exercise control over us and to make changes in management more difficult.

The bylaws provide the number of our directors that are to be established by the board of directors, but shall be no less than one. Between shareholder meetings, the board of directors may appoint new directors to fill vacancies or newly created directorships. A director may be removed from office by the affirmative vote of the majority of the combined voting power of the then outstanding shares of stock entitled to vote generally in the election of directors.

As discussed above, our bylaws further provide that shareholder action may be taken at a meeting of shareholders and may be effected by consent in writing if such consent is signed by the holders of the majority of outstanding shares, unless Delaware law requires a greater percentage.

We are not aware of any proposed takeover attempt or any proposed attempt to acquire a large block of our common stock.

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LIMITATION OF LIABILITY AND INDEMNIFICATION MATTERS

Our Restated Certificate of Incorporation limits the liability of directors and officers to the fullest extent permitted by Delaware law. This is intended to allow our directors and officers the benefit of Delaware’s corporation law which provides that directors and officers of Delaware corporations may be relieved of monetary liabilities for breach of their fiduciary duties as directors, except under circumstances which involve acts or omissions which involve intentional misconduct, fraud or a knowing violation of law, or the payment of unlawful distributions.

To the extent possible, we intend to obtain officer and director liability insurance with respect to liabilities arising out of certain matters, including matters arising under the Securities Act of 1933.

Insofar as indemnification for liabilities arising under the Securities Act of 1993 may be permitted to our directors, officers and controlling persons pursuant to the foregoing provisions, or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable.

In the event that a claim for indemnification against such liabilities (other than our payment of expenses incurred or paid by a director, officer or controlling person in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by us is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

TRANSFER AGENT AND REGISTRAR

OTC Stock Transfer Inc. 231 E. 2100 South, Salt Lake City, Utah 84115 is the transfer agent and registrar for our common stock, Series A and B Preferred and for issued and outstanding warrants.

SHARES ELIGIBLE FOR FUTURE SALE

As of the date of this prospectus, 59,147,129 shares of our common stock were outstanding. Of the outstanding shares, 17,418,700 shares of common stock are immediately eligible for sale in the public market without restriction or further registration under the Securities Act of 1933, unless purchased by or issued to any affiliate of ours, as that term is defined in Rule 144 promulgated under the Securities Act of 1933, described below. All other outstanding shares of our common stock are restricted securities as such term is defined under Rule 144, in that such shares were issued in private transactions not involving a public offering and may not be sold in the absence of registration other than in accordance with Rule 144, 144(k) or 701 promulgated under the Securities Act of 1933 or another exemption from registration.

PLAN OF DISTRIBUTION

The Selling Shareholder may, from time to time, sell any or all of its shares of common stock on any stock exchange, market or trading facility on which the shares are traded or in private transactions on negotiated terms and prices. These sales may be at fixed or negotiated prices. The Selling Shareholder may use any one or more of the following methods when selling shares:

• ordinary brokerage transactions and transactions in which the broker-dealer solicits purchasers;

• block trades in which the broker-dealer will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;

• purchases by a broker-dealer as principal and resale by the broker-dealer for its account;

• an exchange distribution in accordance with the rules of the applicable exchange;

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• privately negotiated transactions;

• short sales;

• broker-dealers may agree with the Selling Shareholder to sell a specified number of such shares at a stipulated price per share;

• a combination of any such method of sale; and

• any other method permitted pursuant to applicable law.

The Selling Shareholder may also sell shares under Rule 144 under the Securities Act, if available, rather than under this prospectus.

The Selling Shareholder may also engage in short sales against the box, puts and calls and other transactions in securities of Transmeridian or derivatives of our securities and may sell or deliver shares in connection with these trades. The Selling Shareholder may pledge its shares to its brokers under the margin provisions of customer agreements. If a selling shareholder defaults on a margin loan, the broker may, from time to time, offer and sell pledged shares.

Broker-dealers engaged by the Selling Shareholder may arrange for other brokers-dealers to participate in sales. Broker-dealers may receive commissions or discounts from the Selling Shareholder (or, if any broker-dealer acts as agent for the purchaser of shares, from the purchaser) in amounts to be negotiated. The Selling Shareholder does not expect these commissions and discounts to exceed what is customary in the types of transactions involved.

The Selling Shareholder and any broker-dealers or agents that are involved in selling the shares may be deemed to be underwriters within the meaning of the Securities Act in connection with such sales. In such event, any commissions received by such broker-dealers or agents and any profit on the resale of the shares purchased by them may be deemed to be underwriting commissions or discounts under the Securities Act.

We are required to pay all fees and expenses incident to the registration of the shares, excluding the fees and disbursements of counsel to the Selling Shareholder. We have agreed to indemnify the Selling Shareholder against certain losses, claims, damages and liabilities, including liabilities under the Securities Act.

Expiration of the Offering

This offering will expire 365 days from the date of this prospectus.

LEGAL MATTERS

The validity of the issuance of the common stock offered hereby has been passed upon for us by Carter Holmes PLLC, 4311 Oak Lawn, Suite 600, Dallas, Texas 75219.

EXPERTS

The consolidated financial statements of Transmeridian Exploration, Inc. at December 31, 2001, 2000 and for the period then ended appearing in this prospectus and in the registration statement have been audited by John A. Braden & Company, P.C., independent certified public accountants, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given upon the authority of such firm as experts in auditing and accounting.

The consolidated financial statements of Transmeridian Exploration, Inc. at September 30, 2002 and for the period then ended, appearing in this prospectus and in the registration statement have been reviewed by John A. Braden & Company, P.C. independent certified public accountants, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given upon the authority of such firm as experts in auditing and accounting.

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INDEPENDENT PETROLEUM ENGINEERS

The estimated reserve evaluation and related calculations of The Ryder Scott Company LP, our independent petroleum engineers, have been included in this prospectus on reliance upon the authority of such firm as experts in petroleum engineering.

WHERE YOU CAN FIND ADDITIONAL INFORMATION

We have filed with the Securities and Exchange Commission a registration statement on Form SB-2. This prospectus, which is a part of the registration statement, does not contain all of the information included in the registration statement. Some information is omitted and you should refer to the registration statement and its exhibits. You may review a copy of the registration statement, including exhibits, at the Securities and Exchange Commission’s website www.sec.gov.

The public may view this registration statement and subsequent filings on the Securities and Exchange Commission’s website, www.sec.gov.

We intend to distribute an annual report, including audited financial statements to our shareholders.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and in this Memorandum.

Acquisition cost of properties

Costs incurred to purchase, lease or otherwise acquire a property, — including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs and other costs incurred in acquiring properties.

Bbls or Stock Tank Barrel

Abbreviation for barrels of oil or 42 US gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.

Bcf

Abbreviation for billion cubic feet of gas.

BOPD

Abbreviation for barrels of oil per day.

BOE

Abbreviation for barrel of oil equivalent based on a ratio of ten Mcf of natural gas to one barrel of oil.

Btu

Abbreviation for British Thermal Units. A British Thermal Unit is the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit. There are approximately 1,050 Btu’s in each stated cubic foot of natural gas.

Completion

An indefinite term, but including those steps in attempting to bring a well into production after the well has been drilled to total depth through a prospective pay zone. Such steps include running and cementing a production string of casing, perforating, running tubing, acidizing or fracturing, swabbing, etc.

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Condensate

A hydrocarbon mixture that becomes liquid and separate from natural gas when the gas is produced; similar to crude oil.

Development costs

Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the well head assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

Development Well

A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Discovery Well

An exploratory well that encounters a new and previously untapped oil or gas reservoir; it may open a new field, or a previously unknown reservoir (pool) in an old field.

Dry Well (Hole)

An exploratory or a development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Economic producibility of estimates proved reserves

Economic producibility of estimated proved reserves can be supported to the satisfaction of the Office of Engineering if geological and engineering data demonstrate with reasonable certainty that those reserves can be recovered in future years under existing economic and operating conditions. The relative importance of the many pieces of geological and engineering data which should be evaluated when classifying reserves cannot be identified in advance. In certain instances, proved reserves may be assigned to reservoirs on the basis of a combination of electrical and other type logs and core analyses which indicate the reservoirs are analogous to similar reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. (extracted from SAB-35).

Exploration Costs

Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or G&G costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes or properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

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Exploratory well

A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is a well that is not a development well, a service well, or a stratigraphic test well.

Farm-out/Farm-in

An agreement providing for assignment of a lease. A typical characteristic of a farm-out is an obligation of the assignee to conduct operations on the assigned acreage as a prerequisite to completion of the assignment. The assignor will usually reserve some type of interest in the lease. The transaction is characterized as a farm-out to the assignor and as a farm-in to the assignee.

Field

An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field, which are separated vertically by intervening impervious state, or laterally by local geologic barriers, or by both.

Gross

Gross oil and gas wells or gross acres refers to the total number of wells or acres that we have an ownership interest in without regard to the nature or size of the ownership interest.

MBbls

Abbreviation for thousand barrels of oil.

Mcf

Abbreviation for thousand cubic feet of gas.

MMBbls

Abbreviation for million barrels of oil.

MMBtu

Abbreviation for million Btu.

MMcf

Abbreviation for million cubic feet of gas.

Natural gas liquids (NGLs) or plant products

Butane, propane, ethane, natural gasoline and other liquid hydrocarbons that are extracted from natural gas.

Net

Net oil and gas wells or net acres are determined by multiplying gross wells or acres by our working interest in those wells or acres.

Net present value

When used with respect to oil and gas reserves, the estimated future gross revenue to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date indicated, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.

Net revenue interest

The percentage of production to which the owner of a working interest is entitled. For example, the owner of a 100% working interest in a well burdened only by a landowner’s royalty of 12.5% would have an 87.5% net revenue interest in that well.

Oil and gas producing activities

Such activities include:

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(a) The search for crude oil, including condensate and natural gas liquids, or natural gas in their natural states and original locations.

(b) The acquisition of property rights or properties for the purpose of further exploration and/or for the purpose of removing the oil or gas from existing reservoirs on those properties.

(c) The construction, drilling and production activities necessary to retrieve oil and gas from its natural reservoirs, and the acquisition, construction, installation, and maintenance of field gathering and storage systems-including lifting the oil and gas to the surface and gathering, treating, field processing (as in the case of processing gas to extract liquid hydrocarbons) and field storage.

For purposes of this section, the oil and gas production function shall normally be regarded as terminating at the outlet valve on the lease or field storage tank; if unusual physical or operational circumstances exist it may be appropriate to regard the production functions as terminating at the first point at which oil, gas or gas liquids are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal.

Operator

In a joint venture for the execution of works or as defined in a joint operating agreement, the Operator entity charged with the responsibility for the execution of all works and is normally responsible to authorities for the representation and legal execution of all related agreements and contracts.

Producing Well

A well from which hydrocarbon or non-hydrocarbons in a fluid or gaseous state flow or are extracted on a daily basis.

Production costs

Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(a) Costs of labor to operate the wells and related equipment and facilities.

(b) Repairs and maintenance.

(c) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

(d) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(e) Severance taxes.

Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil or gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs.

Proved (proven) area

The part of a property to which Proved reserves have been specifically attributed.

Proved (proven) properties

Properties with Proved reserves.

Unproved properties

Properties with no Proved reserves.

Proved oil and gas reserves or proved reserved reservoir

Proved reserves is defined by the SEC Regulation S-X Rule 4-10, paragraph (a) and includes the categories Proved Developed and Proved Undeveloped: Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalation based upon future conditions.

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(i) Reservoirs are considered proved if economic producibility is supported by either actual production or a conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of improved recovery techniques (such a fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (b) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (c) crude oil, natural gas, and natural gas liquids, that may occur in un-drilled prospects; and (d) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment, and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as proved developed reserves only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved developed producing oil and gas reserves

In accordance with guidelines adopted by the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC), developed reserves may be sub-categorized as producing or non-producing. Producing: Reserves sub-categorized as producing are expected to be recovered from completion intervals which are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Proved developed non-producing oil and gas reserves

In accordance with guidelines adopted by the Society of Petroleum Engineers (SPE) and the World Petroleum Congress (WPC), developed reserves may be sub-categorized as producing or non-producing. Non-Producing: Reserves sub-categorized as non-producing include shut-in and behind pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shut-in awaiting pipeline connections or as a result of a market interruption, or (3) wells not capable of production for mechanical reasons. Behind pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.

Proved undeveloped reserves

Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on un-drilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on un-drilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other un-drilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves should not be attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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Recompletion

Additional works on a well to revise the existing mechanical or production mode of a well or to add additional intervals to the production of a well.

Reservoir

A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confirmed by impermeable rock or water barriers and is individual and separate from other reservoirs.

Reserves

Reserves are those quantities of petroleum which are anticipated to be commercially recovered from known accumulations from a given date forward. All reserve estimates involve some degree of uncertainty. The uncertainty depends chiefly on the amount of reliable geological and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. It should be noted that SEC Regulation S-K prohibits the disclosure of estimated quantities of probable or possible reserves of oil and gas and any estimated value thereof in any documents publicly filed with the Commission.

Royalty Interest

An interest in an oil and gas property entitling the owner to a share of oil and gas production (or the proceeds of the sale thereof) free of production costs.

SEC

The United States Securities and Exchange Commission.

SEC Definitions

Those terms commonly used in the oil and gas industry and defined in the rules and regulations promulgated by the SEC pursuant to the Securities Act of 1933, as amended and/or the Securities Exchange Act of 1934, as amended.

Standardized Measure

The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves Quantities, as described in a Statement of Financial Accounting Standard No. 69, is a value-based measure of an entity’s proved reserves based on estimates of future cash flows from production of reserves assuming a 10% discount rate and constant future sale prices and costs of production.

Seismic

The use of shock waves generated by controlled explosions of dynamite or other means to ascertain the nature and contour of underground geological structures.

Service well

A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

Spud

To start to drill a well.

Stratigraphic test well

A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not drilled in a proved area, or (ii) development-type, if drilled in a proved area.

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Working Interest

The operating interest under an oil and gas lease which gives the owner the right to drill, produce and conduct operating activities on the property and a share of production subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.

Workover

Remedial operations on a well with the hope of restoring or increasing production from the same zone.

2D Seismic

The term applied to describe the method of acquiring seismic data that results in two-dimensional profiles of the subsurface (x,time). 2D seismic data is usually acquired individually and interpreted within a grid of 2D profiles that allows the interpreter to generate three-dimensional maps of the subsurface.

3D Seismic

The term applied to describe the method of acquiring seismic data that results in a three-dimensional grid of data (x,y,time) of the subsurface. 3D seismic data is usually acquired as a complete grid and interpreted within this specialized grid that allows the interpreter to generate three-dimensional maps of the subsurface.

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TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
(A Development Stage Company)

FINANCIAL STATEMENTS

AND INDEPENDENT AUDITORS’ REPORT

FOR THE YEARS ENDED DECEMBER 31, 2001 AND 2000

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Report of Independent Certified Public Accountants

Board of Directors
Transmeridian Exploration Incorporated and Subsidiaries

        We have audited the accompanying consolidated balance sheet of Transmeridian Exploration Incorporated and Subsidiaries (a development stage company) as of December 31, 2001, and the related consolidated statements of operations, shareholders’ equity and cash flows for the years ended December 31, 2001 and 2000. 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 audit

        We conducted our audit 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 audit provides 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 Incorporated and Subsidiaries at December 31, 2001, and the consolidated results of their operations and cash flows for the years ended December 31, 2001 and 2000, 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 incurred a net loss of $2,112,890 during the year ended December 31, 2001, and, as of that date, the Company’s current liabilities exceeded its current assets by $2,098,281. These factors, among others, including the Company’s ability to raise additional funds, as discussed in Note B to the 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 B. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ John A. Braden & Company, P.C.

Houston, Texas
September 23, 2002

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TRANSMERIDIAN EXPLORATION, INC.

TABLE OF CONTENTS

	Page
FINANCIAL INFORMATION
Consolidated Financial Statements
Consolidated Balance Sheets — For the Years Ended December 31, 2001 and 2000	F-1
Consolidated Statements of Operations — For the Years Ended December 31, 2001 and 2000	F-2
Consolidated Statement Of Shareholders’ Equity	F-3
Consolidated Statements of Cash Flows — For the Years Ended December 31, 2001 and 2000	F-4
Notes to Consolidated Financial Statements	F-5 - F-16
Consolidated Balance Sheets — For the Nine Months period Ended September 30, 2002	F-17
Consolidated Statements of Operations — For the Nine Months period Ended September 30, 2002	F-18
Consolidated Statement Of Shareholders’ Equity	F-19
Consolidated Statements of Cash Flows — For the Nine Months period Ended September 30, 2002	F-20
Notes to Consolidated Financial Statements	F-21 - F23

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Transmeridian Exploration Incorporated and Subsidiaries
(A Development Stage Company)

CONSOLIDATED BALANCE SHEETS
December 31, 2001

	2001
ASSETS
Cash	$      107,276
Receivables	270,112
Prepaid expenses	—
Current assets	377,388
Office property and equipment, net of accumulated
depreciation of $10,431 and $950	40,294
Oil and gas properties (successful efforts method of
Accounting for oil and gas properties)	7,765,565
Drilling Rig	5,300,000
Debt Financing Costs	400,000
Total assets	$ 13,883,247
LIABILITIES AND SHAREHOLDERS’ DEFICIT
Current maturities of long-term debt	$   1,431,204
Unpaid amounts to a third party	—
Accounts payable and accrued liabilities	1,044,465
Total current liabilities	2,475,669
Long-term debt, net of current maturities	3,368,796
Redeemable common stock $.0006 par, 1,000,000 and -0- shares
issued and outstanding	2,000,000
SHAREHOLDERS’ EQUITY
Preferred stock $.0006 par, authorized 5,000,000 shares;
103,000 and 3,000 shares issued and outstanding	62
Common stock $.0006 par; authorized 200,000,000 shares;
57,797,000 shares issued and outstanding	33,448
Additional paid-in capital	9,051,981
Deficit accumulated during development stage	(3,046,709	)
Total shareholders’ equity	6,038,782
Total liabilities and shareholders’ equity	$ 13,883,247

The accompanying notes are an integral part of these statements.

F-1

Transmeridian Exploration Incorporated and Subsidiaries
(A Development Stage Company)

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year ended December 31				Cumulative total from inception to December 31,
	2001		2000		2001
Oil sales	$        51,289		$               —		$        51,289
Cost and expenses
Operating expense	489,373		—		489,373
General and administrative expenses	1,486,161		187,140		1,673,301
Total operating expense	1,975,534		187,140		2,162,674
Operating loss	(1,924,245	)	(187,140	)	(2,111,385	)
Other income (expense)
Gain on sale of working interest	—		414,146		414,146
Start-up costs	—		(246,484	)	(246,484	)
Lease financing cost and interest expense	(188,645	)	(791,070	)	(979,715	)
Total other income (expense)	(188,645	)	(623,408	)	(812,053	)
NET (LOSS) INCOME	(2,112,890	)	(810,548	)	(2,923,438	)
Preferred dividends	123,271		—		123,271
NET (LOSS) INCOME AVAILABLE TO COMMON SHAREHOLDERS	$(2,236,161	)	$    (810,548	)	$(3,046,709	)
Basic loss per share	$           (.04	)	$           (.06	)	$           (.06	)
Weighted average shares outstanding	59,621,255		14,453,691		37,037,473

The accompanying notes are an integral part of these statements.

F-2

Transmeridian Exploration Incorporated and Subsidiaries
(A Development Stage Company)

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
For the years ended December 31, 2001 and 2000

	Preferred shares	Preferred stock	Common shares		Common stock		Additional paid-in capital		Retained deficit		Treasury stock		Total
Balance at January 1, 2000	—	$ —	—		$        —		$             —		$             —		$      —		$             —
Issuance of founders shares	—	—	41,300,000		24,780		—		—		—		24,780
Issuance of stock to third parties for services	—	—	5,152,000		3,091		543,309		—		—		546,400
Conversion of debt to common stock	—	—	800,000		480		199,520		—		—		200,000
Conversion of debt to preferred stock	3,000	2	—		—		300,156		—		—		300,158
Stock issued in private placements	—	—	10,545,000		6,327		3,626,173		—		—		3,632,500
Expenses of private placements	—	—	—		—		(496,829	)	—		—		(496,829	)
Net loss	—	—	—		—		—		(810,548	)	—		(810,548	)
Balance at December 31, 2000	3,000	$  2	57,797,000		$ 34,678		$ 4,172,329		$  (810,548	)	$      —		$ 3,396,461
Stock issued in private placements	—	—	1,720,000		1,032		1,052,968		—		—		1,054,000
Preferred stock issued for working interest	100,000	60	—		—		1,499,940		—		—		1,500,000
Costs of private placements	—	—	—		—		(105,400	)	—		—		(105,400	)
Issuance of stock to third parties for services	—	—	126,429		76		153,424		—		—		153,500
Issuance of common stock	—	—	1,103,600		662		775,218		—		—		775,880
Stock offering costs	—	—	—		—		(89,467	)	—		—		(89,467	)
Purchase of treasury stock	—	—	—		—		—		—		(1,320	)	(1,320	)
Sale of treasury stock	—	—	—		—		1,540,000		—		1,320		1,541,320
Beneficial conversion preferred stock dividend	—	—	—		—		52,969		(52,969	)	—		—
Dividends accrued on convertible preferred stock	—	—	—		—		—		(70,302	)	—		(70,302	)
Retirement of common stock	—	—	(5,000,000	)	(3,000	)	—		—		—		(3,000	)
Net loss	—	—	—		—		—		(2,112,890	)	—		(2,112,890	)
Balance at December 31, 2001	103,000	$62	55,747,029		$ 33,448		$ 9,051,981		$(3,046,709	)	—		$ 6,038,782

The accompanying notes are an integral part of these statements.

F-3

Transmeridian Exploration Incorporated and Subsidiaries
(A Development Stage Company)

CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31, 2001 and 2000

	Year ended December 31,				Cumulative total from inception to December 31,
	2001		2000		2001
Cash flows from operating activities
Net loss	$(2,112,890	)	$  (810,548	)	$(2,923,438	)
Adjustments to reconcile net loss
to net cash used in operating activities
Gain on sale of working interest	—		(414,146	)	(414,146	)
Stock issued for services	153,500		546,400		699,900
Depreciation and amortization	9,481		950		10,431
Increase in receivables	(270,112	)	—		(270,112	)
Increase in prepaid expenses	—		(49,560	)	(49,560	)
Increase in accounts payable and accrued liabilities	289,755		231,439		521,194
Net cash used in operating activities	(1,930,266	)	(495,465	)	(2,425,731	)
Cash flows from investing activities
Proceeds from sale of working interest	—		614,146		614,146
Purchase of office property and equipment	(43,159	)	(7,566	)	(50,725	)
Purchase of oil and gas properties	(1,770,554	)	(3,645,451	)	(2,416,005	)
Net cash used in investing activities	(1,813,713	)	(3,038,871	)	(1,852,584	)
Cash flows from financing activities
Proceeds from long-term debt and notes payable	1,710,103		386,000		1,096,103
Payments on notes payable	(210,103	)	—		(210,103	)
Purchase of treasury stock	(1,320	)	—		(1,320	)
Proceeds from sale of treasury stock	1,541,320		—		1,541,320
Retirement of common stock	(3,000	)	—		(3,000	)
Proceeds from sale of stock, net of offering expenses	1,687,982		3,160,451		4,848,433
Payments of amounts due to third parties	(1,385,842	)	(2,500,000	)	(2,885,842	)
Net cash provided by financing activities	3,339,140		1,046,451		4,385,591
(Decrease) increase in cash and cash equivalents	(404,839	)	512,115		107,276
Cash and cash equivalents at beginning of period	512,115		—		—
Cash and cash equivalents at end of period	$    107,276		$    512,115		$    107,276

The accompanying notes are an integral part of these statements.

F-4

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2001 and 2000

NOTE A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Transmeridian Exploration Incorporated (the Company) purchased 100% of the shares of Open Joint Company Caspi Neft TME, which has as its primary asset the license and related contract for the exploration and an oil and gas lease known as Yuzhny (South) Alibek Field (the License). During 2000, Open Joint Stock Company Caspi Neft TME was formed solely for the purpose of the acquisition of the License. The transaction is hereafter referred to as “the Share Purchase Agreement.” The Company plans to begin development of the property shortly after the completion of future private-placement or public offerings.

Transmeridian Exploration Incorporated was incorporated in Delaware in April 2000. Previously, all activity was conducted by Transmeridian Exploration Inc. (British Virgin Islands). There was no significant activity prior to January 1, 2000.

The Company has been in the development stage since its formation. It is primarily engaged in the exploration, development and production of oil and gas properties.

1. Principles of Consolidation

The consolidated financial statements include the accounts of Transmeridian Exploration Incorporated and its subsidiaries, Transmeridian Exploration Inc. (British Virgin Islands), Transmeridian (Kazakhstan) Incorporated (British Virgin Islands), and Open Joint Company Caspi Neft TME (“Caspi Neft TME”) (Kazakhstan), all wholly-owned. In consolidation, all significant intercompany transactions have been eliminated.

2. Use of Estimates

In preparing the financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and revenues and expenses during the reporting period. Actual results could differ from those estimates.

3. Cash and Cash Equivalents

The Company considers all highly liquid instruments purchased with a maturity of three months or less to be cash equivalents.

F-5

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2001 and 2000

NOTE A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — continued

4. Allowance for Doubtful Accounts

The Company considers all receivables to be fully collectible; accordingly, no allowance for doubtful accounts is required. If amounts become uncollectible, they will be charged to operations when that determination is made.

5. 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. Intangible drilling and development costs related to development wells and successful exploratory wells are capitalized, whereas the costs of exploratory wells which do not find proved reserves are expensed. All geological and geophysical costs not reimbursed are expensed as incurred. Costs of acquiring unproved leases are evaluated for impairment until such time as the leases are proved or abandoned. In addition, unamortized costs at a field level are reduced to fair value if the sum of expected undiscounted future cash flows are less than net book value.

Depreciation and amortization of producing properties is computed using the unit-of-production method based upon estimated proved recoverable reserves. Depreciation of other property and equipment is calculated using the straight-line method based upon estimated useful lives ranging from two to ten years. Maintenance and repairs are charged to expense as incurred. Renewals and betterments are capitalized. When assets are sold, retired or otherwise disposed of, the applicable costs and accumulated depreciation and amortization are removed from the accounts, and the resulting gain or loss is recognized.

6. 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 consequences of temporary differences between tax bases and financial reporting bases of other assets and liabilities. The Company deducts intangible development costs as incurred and deducts statutory depletion when it exceeds cost depletion for federal income tax purposes.

7. Start-up Costs

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

8. Debt Financing Costs

Financing costs are amortized over the life of the related obligation.

F-6

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2001 and 2000

NOTE A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — continued

9. Loss Per Share

Basic loss per common share is calculated by dividing net loss after deducting preferred stock dividends and discount on preferred stock that is accreted directly to the accumulated deficit, by the aggregate weighted average shares outstanding during the period. Diluted loss per common share considers the dilutive effect of the average number of common stock equivalents that are outstanding during the period. Included in the weighted average shares outstanding are the 1,000,000 shares of redeemable common stock.

Diluted loss per share is not presented because the exercise of warrants and the effect of the conversion of the Company’s Preferred Stock into shares of the Company’s common stock are antidilutive.

10. Risks and Uncertainties

The ability of the Company to realize the carrying value of its assets is dependent on being able to develop, transport and market hydrocarbons. Currently, exports from the Republic of Kazakhstan are primarily dependent on transport routes, either via rail, barge or pipeline, through Russian territory. Pipeline capacity has significantly improved in 2001 with the opening of the CPC Pipeline, raising current capacity of 250,000 barrels oil per day (bopd) to 800,000 bopd by year end. Domestic markets in the Republic of Kazakhstan might not permit world market prices to be obtained. Management believes, however, that over the life of the project transportation options will be improved by further increases in the capacity of the CPC and other existing pipelines and the building of new pipelines within the region and prices will remain achievable for hydrocarbons extracted to allow full recovery of the carrying value of its assets.

11. Revenue Recognition

Revenues from the sale of oil and gas are recorded using the sales method. As of December 31, 2001, the Company has had only minimal test production.

12. Foreign Exchange Transactions

The Company’s functional currency is the U.S. dollar, thus the financial statements of the Company’s foreign subsidiaries are measured using the U.S. dollar. Accordingly, transaction gains and losses for foreign subsidiaries are recognized in consolidated operations in the year of occurrence.

F-7

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2001 and 2000

NOTE A — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES — continued

13. Fair Value of Financial Instruments

The carrying amounts of cash, short-term debt and long-term variable rate debt approximate fair value. The Company estimates fair value of its long-term, fixed rate debt generally using discounted cash flow analysis based on the Company’s current borrowing rate for similar debt. The carrying amounts of the Company’s financial instruments generally approximate their fair values at December 31, 2001.

NOTE B – GOING CONCERN

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 incurred losses totaling $2,923,438 and has incurred a significant amount of debt in the start-up phase of the Company, Additionally, to fully develop the area covered by the License, the Company needs substantial additional funding. Finally, the Company must also obtain a commercial production contract with the government of Kazakhstan. Management believes it is legally entitled to receive this commercial production contract and has an exclusive right to negotiate this contract and the government of Kazakhstan is obligated to conduct these negotiations under the Law of Petroleum. If no terms can be negotiated, the Company has a right to produce and sell oil, including export oil, under the Law of Petroleum for the term of its existing contract to the end of 2005.

In view of the matters described in the preceding paragraph, 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, which in turn is dependent upon the Company’s ability to meet its financing requirements on a continuing basis, primarily by the Company’s ability to raise additional funds in private placements or public offerings, to maintain present financing, and to succeed in its future operations. 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 that might be necessary should the Company be unable to continue in existence.

Management has taken the following steps to revise its operating and financial requirements, which it believes are sufficient to provide the Company with the ability to continue in existence.

• The Company plans to continue to raise additional capital, in the equity markets as significant sources of funding the development of the License and for acquisitions of additional properties, foreign and domestic.

• As described in Note F, subsequent to year end, the Company obtained $20,000,000 in financing from a bank in Kazakhstan. The funds obtained through this financing will be used to develop several wells.

F-8

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2001 and 2000

NOTE B — GOING CONCERN – Continued

• The Company is currently negotiating a new Exploration and Production Operating Contract in Kazakhstan. The contract is expected to contain all commercial and operating aspects of exploration and production, including terms for full commercial production. This will replace the existing contract that only covers the Exploration phase of License 1557.

• Development of South Alibek’s proven reserves – South Alibek has approximately 11.5 and 5.7 million barrels of net estimated proven undeveloped and developed non-producing oil reserves, respectively. Based on its expected production capabilities from the expenditures that will be made in future private placement or public offerings, the Company believes that it could generate adequate cash flow. Additional funding requirements may also be necessary before the Company is able to rely solely on the production from the South Alibek Field for the cash flow of the Company.

NOTE C – OIL AND GAS PROPERTIES

The Company’s oil and gas properties primarily include the value of the License and other capitalizable costs under the successful efforts method of accounting. No accumulated depreciation or amortization has been recorded because no significant production has occurred through December 31, 2001.

Oil and gas properties are made up of the following at December 31:

	2001
Leasehold costs	$5,597,850
Intangible development costs	1,600,596
Production facilities	499,619
Wellhead equipment	67,500
	$7,765,565

During 2001, the Company advanced a joint venture approximately $254,000 for the completion of a terminal station. As part of the advance, the Company acquired an option to acquire up to 50% of the joint venture. In 2002, the Company chose not to exercise this option, and expects to receive repayment of the advance in 2002. On April 26, 2002, Transmeridian purchased 25% equity interest in the Emba Terminal for 4,000,000 shares of common stock of the company, and has up to 180 calendar days to purchase another 25% equity interest in the facility at a price to be further negotiated.

F-9

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2001 and 2000

NOTE D — DRILLING RIG

In December 2001, the Company purchased a drilling rig for $5,300,000. In exchange for the rig, the Company signed a $3,300,000 note payable due in 24 months at 10% interest, and issued 1,000,000 shares of common stock to the seller of the rig. The Company agreed to redeem 500,000 shares at $2.00 per share after a holding period of twelve months. The seller’s right to have its stock redeemed expires 10 days after the end of the holding period for each group of shares issued. Stock cannot be issued in more than groups of 500,000 shares each.

NOTE E — LONG-TERM DEBT

Long-term debt consists of the following amounts at December 31, 2001:

Note payable to a Company due in 24 monthly installments of
$152,278 of principle and interest at 10%, secured by a drilling rig	$3,300,000
Note payable to a Kazakhstan bank with all principle and interest
due August 2003, with an interest rate of 15%, secured by all of the
stock of Caspi Neft TME	1,500,000
	4,800,000
Less: current portion	1,431,204
	$3,368,796
Maturities of long-term debt as of December 31, 2001, are as follows:
2002	$1,431,204
2003	3,217,776
2004	151,020
	$4,800,000

The loan agreement signed with the bank in 2001, served as bridge financing for a $20,000,000 loan agreement signed in February 2002. Under the terms of this agreement, the Company is required to repay all accrued interest and principle on the first $2,233,000 of borrowings in August 2003. The remaining accrued interest and principle is due on February 2005. The loan is subject to an annual credit facility fee equal to .5% of the unused portion of the credit facility.

F-10

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2001 and 2000

NOTE E — LONG-TERM DEBT — Continued

A Kazakhstan corporation (Corporation), which is controlled by major shareholders of the bank, has an option to purchase 50% of the stock of Caspi Neft TME. The exercise of the option would require the Corporation to repay $15,000,000 of this loan by February 2004, and to provide an additional $30,000,000 in financing at market rates by March 2004. In consideration for this option, the Corporation paid the Company approximately $65,000 in 2001, which is refundable should they not exercise the option. The bank holds all of the stock of Caspi Neft TME as collateral on the loan.

In 2001, the Company entered into an agreement to pay a consultant $400,000 to locate financing for the development of the License area. This fee, which is recorded in accrued liabilities and will be paid in 2002, will be amortized over the life of the related long-term debt as a yield adjustment.

The Company borrowed $300,158 from a third party, which accrued interest at 12.5%. The Company entered into a credit conversion agreement on August 23, 2000, whereby the $300,158 in notes payable would be converted to convertible or redeemable preferred stock. During December 2000, the debt was converted. The preferred stock accrues dividends at 12.5% until converted or redeemed. Accrued dividends at December 31, 2000 were not significant. At December 31, 2001, the Company has accrued $70,302 in dividends.

These shares are either convertible to common stock or redeemable at the Company’s option. The conversion rate is 85% of the average bid price for the five previous consecutive trading days prior to the conversion date.

The conversion feature of the preferred stock represents a “beneficial conversion feature” as addressed in EITF 98-5, Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios. Under EITF 98-5, a portion of the proceeds received from the preferred stock is allocable to the conversion feature contained herein. The value assigned to the conversion feature is determined as the difference between the market price of the Company’s common stock and the conversion price multiplied times the number of shares to be received upon conversion. The discount assigned to the conversion feature is recorded as additional paid-in capital and amortized to accumulated deficit when the stock becomes publicly tradable. In the fourth quarter of 2001, The Company recorded a discount of $52,969.

As additional consideration for entering into this credit conversion agreement, the Company issued 1,200,000 shares of common stock to the third party.

F-11

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2001 and 2000

NOTE E — LONG-TERM DEBT — Continued

The Company incurred debt totaling $200,000 from a related party. The Company entered into an agreement with the related party that converted the debt into 800,000 shares of common stock in December 2000.

Management believes the fair value of debt at December 31, 2001 is not significantly different than its book value.

NOTE F — STOCK FOR SERVICES RENDERED

The Company entered into several agreements to exchange common stock for services. The stock has been valued based on the fair value of the stock at the time of the agreements. During the year ended December 31, 2001, the Company issued a total of 126,429 shares under these type of agreements. This stock was issued to unrelated third party vendors for software, engineering and geological services.

NOTE G — CONVEYANCE OF WORKING INTERESTS

As consideration for work done in conjunction with the Share Purchase Agreement, the Company assigned a 10% carried working interest to a third party. In addition, the Company issued 1,000,000 shares of common stock to this party for the negotiation of an extension of the payment terms with the previous owners of the License. The value of these additional shares has been recorded as lease financing cost in the statement of operations.

During the year ended December 31, 2000, the Company sold a 4.5% working interest share of the License to another third party. This resulted in the gain on sale of working interest reflected in the financial statements.

In April 2001, the Company re-acquired the 4.5% working interest from the third party. The Company issued 100,000 shares of convertible preferred stock, with no mandatory dividends (convertible to 1,500,000 shares of the Company’s common stock, 1,000,000 warrants for the purchase of common stock at $1.00 per share and forgave approximately $50,000 of joint interest billings as a consideration for the working interest. This transaction was valued at the best available value, the companies accumulated cost at the time of the transaction.

F-12

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – CONTINUED
December 31, 2001 and 2000

NOTE H — INCOME TAXES

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

	2001
Deferred tax assets:
Net operating loss carry forwards	$ 990,000
Valuation allowance	(990,000	)
Deferred tax assets	$          —

Under FASB statement No. 109, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of asset and liabilities for financial reporting purposes and the amount used for income tax purposes. The only significant component of the companies deferred tax asset relates to the excess of depreciation on fixed assets allowed for tax purposes over that recorded in the financial statements. For the periods ending December 31, 2001, this amount was $(4,072).

As of December 31, 2001, the Company has estimated loss carry forwards of approximately $2,905,000 of which $807,000 and $2,098,000, expire in 2020 and 2021.

The Company has not recorded any deferred tax assets or income tax benefits from the net operating losses for the years ended December 31, 2001. The Company has taken a 100% valuation allowance against any resulting deferred tax asset due to such carry forward as realization of the net operating losses are more likely than not.

NOTE I — SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION

Cash paid for interest in 2001 and 2000 was $174,534 and $791,069. No taxes were paid in 2001 or 2000.

During the year ended December 31, 2001, the Company acquired a drilling rig for $3,300,000 note payable and $2,000,000 of redeemable common stock.

During the year ended December 31, 2001, the Company re-acquired a 4.5% interest in the License for $1,500,000 of convertible preferred stock.

At December 31, 2001, the Company has accrued a $400,000 payment to a consultant for assistance in obtaining financing. This fee is treated as a financing cost. Additionally, the Company has accrued $70,302 in dividends payable on its convertible preferred stock.

During the year ended December 31, 2000, the Company converted $200,000 of debt to 800,000 shares of common stock.

F-13

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2001 and 2000

NOTE I — SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION — continued

During the year ended December 31, 2000, the Company converted $300,158 of debt to 3,000 of shares of preferred stock.

During the year ended December 31, 2000, the Company acquired oil and gas properties from a third party in exchange for amounts owed totaling $3,885,842.

NOTE J — NEW ACCOUNTING PRONOUNCEMENTS

On June 29, 2001, SFAS No. 141, Business Combinations was approved by the Financial Accounting Standards Board (FASB). SFAS No. 141 requires that the purchase method of accounting be used or all business combinations initiated after June 30, 2001. The Company was required to implement SFAS No. 141 on January 1, 2002. Management has reviewed SFAS No. 141 and determined that the adoption of this statement will have no effect on the Company’s consolidated financial position, cash flows or results of operations.

On June 29, 2001, SFAS No. 142, Goodwill and Other Intangible Assets was approved by the FASB. SFAS No. 142 changes the accounting for goodwill from an amortization method to impairment –only approach. Amortization of goodwill, including goodwill recorded in past business combination, will cease upon adoption of this statement. The Company was required to implement SFAS No. 142 on January 1, 2002. Management has reviewed SFAS No. 142 and determined that this statement will not have a material effect on its consolidated financial position, cash flows or results of operations.

In June 2001, SFAS No. 143, Accounting for Asset Retirement was approved by the FASB. SFAS No. 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted Management has reviewed SFAS No. 143 and determined that this statement will not have a material effect on its consolidated financial position, cash flows or results of operations.

In August 2001, SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. was approved by the FASB. The new rules supersede SFAS No. 121, Accounting for the Impairment of Lon-Lived Assets and for Long-Lived Assests to be Disposed Of. The new rules retain many of the fundamental recognition and measurement provisions, but significantly change the criteria for classifying an asset as held-for-sale. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. Management has reviewed SFAS No. 144 and determined that this statement will not have a material effect on its consolidated financial position, cash flows or results of operations

F-14

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2001 and 2000

NOTE K — SUPPLEMENTAL RESERVE INFORMATION (Unaudited)

Oil and Natural Gas Reserves (Unaudited)

Extensive geologic and engineering information was obtained from 1996 to December of 2000 and provides the basis of the technical evaluation and conclusions made by management and third parties. Reserves estimates are based on the available data on South Alibek Field, Alibekmola Field and Zhanazhol Field. The Ryder Scott Company, a US independent engineering company, estimated the Company’s net known producible reserves in the South Alibek Field of 18.225 million barrels of oil as corrected for its current 90% interest in the property. These reserves only include the reserves estimated to be recoverable from Well No. 29 and two 80 acre offset units (wells) in the 14,111 acre license area. Larger reserves are anticipated if certain reasonable assumptions based on the nearby analogous fields are proven applicable for South Alibek Field. These reserves estimates are contingent on successful confirmation of the estimates and assumptions made in arriving at those estimates, and have the types of risks associated with each category as defined by the SPE/SPEE that are normally associated with oil and gas property estimates.

The Kazakhstan Government on June 5, 2002 issued a notification that the certified reserves of 15 million barrels and 10 BCF of gas were added to the official balance of national  (Kazakh) commercial reserves, designated by them as C1 reserves.  These reserves are calculated to be recovered from the 2 main zones within the KT2 within a 1 kilometer radius (777 acres) surrounding Well No. 29.   Reserves for the combined C1 and C2 reserve categories of 128 million barrels and 88 BCF of gas were also approved for the same zones within a limited mapped area.  This certification of commercial reserves now allows for the issuance of a Exploration and Production Contract to further exploit reserves from the area within License 1557.   The in-country reserves work did not address the reserves potential in the KT1 (upper carbonate reservoir) or the untested deeper reservoirs in the KT2.

Oil and Gas Producing Activities: (Unaudited)

Total costs incurred in the acquisition of the License 1557 and the formation and development of our wholly owned subsidiary Caspi Neft TME, the owner of the oil and gas exploration activities, all incurred within Kazakhstan, were as follows (in thousands except per barrel information):

F-15

Transmeridian Exploration Incorporated and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — CONTINUED
December 31, 2001 and 2000

NOTE K — SUPPLEMENTAL RESERVE INFORMATION (Unaudited) - continued

	For the year ended December 31, 2001 (000)	For the year ended December 31, 2000 (000)
Property Acquisition costs
Unproved	$           —	$           —
Proved	$      5,598	$      3,944
Exploration Costs		$           —
Development Costs	$      2,168	$         501
Depreciation, depreciation and amortization per
equivalent barrel of production	$           —	$           —
The aggregate capital costs relative to oil and gas
producing activities are as follows
Unproved oil and gas properties	$           —	$           —
Proved oil and gas properties	$      7,766	$      4,445
Accumulated depreciation, depletion and
amortization	$           —	$           —
Net Capitalized Cost	$      7,766	$      4,445

Estimated Oil and Natural Gas Reserves (Unaudited)

The following information regarding estimates of the Company’s proved oil and gas reserves, all located in Kazakhstan, is based on reports prepared on behalf of the Company by independent petroleum engineers, The Ryder Scott Company.

Because oil and gas reserve estimates are inherently imprecise and require extensive judgments of reservoir engineering data, they are generally less precise than estimates made in conjunction with financial disclosures. The revisions of previous estimates as reflected in the table below result from more precise engineering calculations based upon additional production histories.

Proved developed and undeveloped reserves	Year ended December 31, 2001		Year ended December 31, 2000
	Natural Gas (Mmcf ”s)	Oil (Bbls)	Natural Gas (Mmcf ”s)	Oil (Bbls)
Beginning of period	3,391	17,212,772	-0-	-0-
Revisions of previous year estimates	84	431,646	-0-	-0-
Extensions, discoveries and new additions	-0-	-0-	-0-	-0-
Improved recovery	-0-	-0-	-0-	-0-
Purchase of minerals in place	-0-	-0-	3,391	17,212,772
Sales of minerals in place	-0-	-0-	-0-	-0-
Production	-0-	-0-	-0-	-0-
End of period	3,475	17,644,418	3,391	17,212,772

F-16

Transmeridian Exploration Incorporated and Subsidiaries
(A Development Stage Company)
CONSOLIDATED BALANCE SHEETS
For the nine months ended September 30, 2002 and
for the year ended December 31, 2001

	September 30, 2002		December 31, 2001
	(unaudited)
ASSETS
Cash	$      258,031		$      107,276
Receivables	1,013,506		270,112
Due from related party	272,700
Prepaid expenses	738,000		—
Current assets	2,282,237		377,388
Office equipment	66,945		22,159
Technology equipment	67,318		20,244
Automobiles	167,200		8,321
Oil and gas properties, (successful efforts method
of accounting for oil and gas properties)	12,925,356		7,765,565
Drilling Rig	5,598,943		5,300,000
Investment in Terminal JV	1,670,368		—
Accumulated depreciation	(424,309	)	(10,430	)
Debt financing costs	400,000		400,000
Total assets	$ 22,754,058		$ 13,883,247
LIABILITIES AND STOCKHOLDERS’ DEFICIT
Current maturities of long-term debt	621,940		$   1,431,204
Accounts payable and accrued liabilities	1,687,319		$   1,044,465
Other current liabilities	197,974		—
Total current liabilities	2,507,233		2,475,669
Long-term debt, net of current maturities	12,293,765		3,368,796
Redeemable common stock $.0006 par, 1,000,000 and
1,000,000 shares issued and outstanding	2,000,000		2,000,000
Total long-term liabilities	14,293,765		5,368,796
STOCKHOLDERS’ EQUITY
Preferred stock $.0006 par, authorized 5,000,000 shares;
103,000 and 3,000 shares issued and outstanding	2		62
Common stock $.0006 par; authorized 200,000,000 shares;
59,147,129 and 55,747,029 shares issued and outstanding	35,488		33,448
Additional paid-in capital	10,585,201		9,051,981
Deficit accumulated during development stage	(4,667,631	)	(3,046,709	)
Total stockholders’ equity	5,953,060		6,038,782
Total liabilities and stockholders’ equity	$ 22,754,058		$ 13,883,247

The accompanying notes are an integral part of these statements.

F-17

Transmeridian Exploration Incorporated and Subsidiaries
(A Development Stage Company)
CONSOLIDATED STATEMENTS OF OPERATIONS
For the nine months ended September 30, 2002 and 2001 and
for the years ended December 31, 2000 and 2001

	Nine months ended September 30,				Years ended December 31,				Cumulative total from inception to September 30,
	2002		2001		2001		2000		2002
	(unaudited)		(unaudited)						(unaudited)
Revenues
Oil sales	$              —		$      51,335		$      51,289		$             —		$       51,289
Rig rental income	$  2,086,200		$             —		$             —		$             —		$  2,086,200
Cost and expenses
Operating expenses	58,797		279,039		489,373		—		$     548,170
Transportation expenses	876,330								$     876,330
General and administrative expense	2,747,844		989,618		1,486,161		187,140		$  4,421,145
Total operating expense	3,682,971		1,268,657		1,975,534		187,140		$  5,845,645
Operating loss	$(1,596,771	)	$(1,217,322	)	$(1,924,245	)	$    (187,140	)	$(3,708,156	)
Other income (expense)
Gain on sale of working interest	—		—		—		414,146		$     414,146
Interest income	3,911		—		—		—		$         3,911
Start-up costs	—		—		—		(246,484	)	$    (246,484	)
Lease financing cost and interest      expense	—		(113,715	)	(188,645	)	(791,070	)	$    (979,715	)
Total other income (expense)	3,911		(113,715	)	(188,645	)	(623,408	)	$    (808,142	)
NET (LOSS) INCOME	$(1,592,860	)	$(1,331,037	)	$(2,112,890	)	$    (810,548	)	$ (4,516,298	)
Preferred dividends	28,062		71,016		123,271		—		$      151,333
NET (LOSS) INCOME AVAILABLE TO COMMON SHAREHOLDERS	$(1,620,922	)	$(1,402,053	)	$(2,236,161	)	$    (810,548	)	$(4,667,631	)
Basic loss per share	(0.03	)	(0.02	)	(0.04	)	(0.06	)	(0.08	)
Weighted average shares outstanding	58,652,564		60,617,000		59,621,255		14,453,691		59,647,129

The accompanying notes are an integral part of these statements.

F-18

Transmeridian Exploration Incorporated and Subsidiaries
(A Development Stage Company)
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
For the nine months ended September 30, 2002 and
for the years ended December 31, 2000 and 2001

	Preferred shares		Preferred stock		Common shares		Common stock		Additional paid-in capital		Retained deficit		Treasury stock		Total
Balance at January 1, 2000	—		$ —		—		$        —		$               —		$             —		$             —		$             —
Issuance of founders shares	—		—		41,300,000		24,780		—		—		—		24,780
Issuance of stock to third parties for services	—		—		5,152,000		3,091		543,309		—		—		546,400
Conversion of debt to common stock	—		—		800,000		480		199,520		—		—		200,000
Conversion of debt to preferred stock	3,000		2		—		—		300,156		—		—		300,158
Stock issued in private placements	—		—		10,545,000		6,327		3,626,173		—		—		3,632,500
Expenses of private placements	—		—		—		—		(496,829	)	—		—		(496,829	)
Net loss	—		—		—		—		—		(810,548	)	—		(810,548	)
Balance at December 31, 2000	3,000		$   2		57,797,000		$ 34,678		$   4,172,329		$  (810,548	)	$             —		$ 3,396,461
Stock issued in private placements	—		—		1,720,000		1,032		1,052,968		—		—		1,054,000
Preferred stock issued for working interest	100,000		60		—		—		1,499,940		—		—		1,500,000
Costs of private placements	—		—		—		—		(105,400	)	—		—		(105,400	)
Issuance of stock to third parties for services	—		—		126,429		76		153,424		—		—		153,500
Issuance of common stock	—		—		1,103,600		662		775,218		—		—		775,880
Stock offering costs	—		—		—		—		(89,467	)	—		—		(89,467	)
Purchase of treasury stock	—		—		—		—		—		—		(1,320	)	(1,320	)
Sale of treasury stock	—		—		—		—		1,540,000		—		1,320		1,541,320
Beneficial conversion preferred stock dividend	—		—		—		—		52,969		(52,969	)	—		—
Dividends accrued on convertible preferred stock	—		—		—		—		—		(70,302	)	—		(70,302	)
Retirement of common stock	—		—		(5,000,000	)	(3,000	)	—		—		—		(3,000	)
Net loss	—		—		—		—		—		(2,112,890	)	—		(2,112,890	)
Balance at December 31, 2001	103,000		$ 62		55,747,029		$ 33,448		$   9,051,981		$(3,046,709	)	—		$ 6,038,782
Stock issued in private placements (unaudited)	—		—		—		—		—		—		—		—
Conversion of preferred stock (unaudited)	(100,000	)	(60	)	1,500,000		900		(840	)	—		—		—
Preferred stock issued for working interest (unaudited)	—		—		—		—		—		—		—		—
Costs of private placements (unaudited)	—		—		—		—		—		—		—		—
Issuance of stock to third parties for services (unaudited)	—		—		—		—		—		—		—		—
Issuance of common stock (unaudited)	—		—		600,100		360		134,840		—		—		135,200
Stock offering costs (unaudited)	—		—		—		—		—		—		—		—
Purchase of treasury stock (unaudited)	—		—		—		—		—		—		—		—
Sale of treasury stock (unaudited)	—		—		—		—		—		—		—		—
Stock issued for properties (unaudited)	—		—		4,000,000		2,400		1,397,600				—		1,400,000
Beneficial conversion preferred stock dividend (unaudited)	—		—		—		—		—		—		—
Dividends accrued on convertible preferred stock (unaudited)	—		—		—		—		—		(28,062	)	—		(28,062	)
Retirement of common stock (unaudited)	—		—		(2,700,000	)	(1,620	)	1,620		—		—		—
Net loss (unaudited)	—		—		—		—		—		(1,592,860	)	—		(1,592,860	)
Balance at September 30, 2002 (unaudited)	3,000		$   2		59,147,129		$ 35,488		$ 10,585,201		$(4,667,631	)	—		$ 5,953,060

The accompanying notes are an integral part of this statement.

F-19

Transmeridian Exploration Incorporated and Subsidiaries
(A Development Stage Company) CONSOLIDATED STATEMENTS OF CASH FLOWS
For the nine months ended September 30, 2002 and 2001 and
for the years ended December 31, 2000 and 2001

	Nine months ended September 30,				Years ended December 31,				Cumulative total from inception to September 30,
	2002		2001		2001		2000		2001
	(unaudited)		(unaudited)						(unaudited)
Cash flows from operating activities
Net loss	$(1,592,860	)	$(1,331,037	)	$(2,112,890	)	$  (810,548	)	$(4,516,298	)
Adjustments to reconcile net loss to net cash used in operating activities
Gain on sale of working interest	—		—		—		(414,146	)	(414,146	)
Stock issued for services			76,750		153,500		546,400		699,900
Depreciation and amortization	413,877		6,423		9,481		950		424,308
Increase in receivables	(743,394	)	(135,056	)	(270,112	)	—		(1,013,506	)
Increase in due from related party	(272,700	)	—						(272,700	)
Increase in prepaid expenses	(738,000	)	(8,350	)	—		(49,560	)	(787,560	)
Increase in unpaid amounts to third party	(197,974	)	—		—		1,385,842		1,187,868
Increase in accounts payable and accrued      liabilities	(642,854	)	120,103		289,755		231,439		(121,660	)
Increase in unearned revenue	—		—		—		—		—
Net cash used in operating activities	(3,773,905	)	(1,271,167	)	(1,930,266	)	890,377		(4,813,794	)
Cash flows from investing activities
Proceeds from sale of working interest	—		—		—		614,146		614,146
Investment in subsidary	(15,536	)	—						(15,536	)
Purchase of drilling rig equipment	(298,943	)	—						(298,943	)
Purchase of office property and equipment	(250,738	)	(35,184	)	(43,159	)	(7,566	)	(301,463	)
Purchase of oil and gas properties	(3,252,681	)	(1,181,880	)	(1,770,554	)	(4,531,293	)	(9,554,528	)
Net cash used in investing activities	(3,817,898	)	(1,217,064	)	(1,813,713	)	(3,924,713	)	(9,556,324	)
Cash flows from financing activities
Proceeds from long-term debt and notes      payable	9,765,840		462,603		710,103		386,000		10,861,943
Payments on notes payable	(2,154,462	)	(105,052	)	(210,103	)	—		(2,364,565	)
Purchase of treasury stock	(2,400	)	(660	)	(1,320	)	—		(3,720	)
Proceeds from sale of treasury stock	—		770,660		1,541,320		—		1,541,320
Retirement of common stock	(1,620	)	(1,500	)	(3,000	)	—		(4,620	)
Proceeds from sale of stock, net of      offering expenses	135,200		1,318,291		1,687,982		3,160,451		4,983,633
Payments of amounts due to third parties	—		(385,842	)	(385,842	)	—		(385,842	)
Net cash provided by financing activities	7,742,558		2,058,500		3,339,140		3,546,451		14,628,149
(Decrease) increase in cash and cash equivalents	$    150,755		$  (429,731	)	$  (404,839	)	$    512,115		$      258,031
Cash and cash equivalents at beginning of period	107,276		512,115		512,115		—		619,391
Cash and cash equivalents at end of period	$    258,031		$      82,384		$    107,276		$    512,115		$      877,422

The accompanying notes are an integral part of these statements.

F-20

TRANSMERIDIAN EXPLORATION INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

NOTE 1 — SUMMARY OF ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

Organization

Transmeridian Exploration, Inc. is an independent oil company engaged in the exploration, development, exploitation and acquisition of foreign natural gas and oil properties. The Company’s operations are currently being focused onshore in the Caspian Sea region of The Republic of Kazakhstan.

Principles of Consolidation

The consolidated financial statements include the accounts of Transmeridian Exploration Incorporated and its subsidiaries, Transmeridian Exploration Inc.(British Virgin Islands), Transmeridian (Kazakhstan) Incorporated (British Virgin Islands), Open Joint Stock Company Caspi Neft TME (Kazakhstan) and TMEI Operating, Inc. all wholly owned. In consolidation, all significant intercompany transactions have been eliminated.

Interim Financial Statements

The balance sheet of the Company at September 30, 2002 and the statements of operations and cash flows for the periods indicated herein have been prepared by the Company without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted, although the Company believes that the disclosures contained herein are adequate to make the information presented not misleading. The balance sheet at December 31, 2001 is derived from the December 31, 2001 audited financial statements but does not include all disclosures required by accounting principles generally accepted in the United States of America. The Interim Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes thereto included in the Company’s Annual Report included in the 10KSB/A.

In the opinion of management, all estimates and adjustments, consisting of normal recurring accruals, necessary to present fairly the information in the accompanying financial statements have been included. The results of operations for such interim periods are not necessarily indicative of the results for the full year.

RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS.

On June 29, 2001, SFAS No. 141, “Business Combinations” was approved by the Financial Accounting Standards Board. SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated after June 30, 2001. The Company was required to implement SFAS No. 141 on January 1, 2002. Management expects that the adoption of this statement will have no effect on the Company’s consolidated financial position, cash flows or results of operations.

On June 29, 2001, SFAS No. 142, “Goodwill and Other Intangible Assets,” was approved by the Financial Accounting Standards Board (“FASB”). SFAS No. 142 changes the accounting for goodwill from an amortization method to an impairment-only approach. Amortization of goodwill, including goodwill recorded in past business combinations, will cease upon adoption of this statement. The Company was required to implement SFAS No. 142 on January 1, 2002. Management has reviewed SFAS No. 142 and determined that this statement will not have a material effect on its consolidated financial position, cash flows or results of operation.

In June 2001 the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 provides the accounting requirements for retirement obligations associated with tangible long-lived assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002, and early adoption is permitted. Management has adopted SFAS No. 143 and determined that this statement will not have a material effect on its consolidated financial position, cash flows or results of operation.

F-21

TRANSMERIDIAN EXPLORATION INC.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

In August 2001 the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The new rules supersede SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of.” The new rules retain many of the fundamental recognition and measurement provisions but significantly change the criteria for classifying an asset as held-for-sale. SFAS No. 144 is effective for fiscal years beginning after December 15, 2001. Management has adopted SFAS No. 144 and determined that this statement will not have a material effect on its consolidated financial position, cash flows or results of operation.

NOTE 2 — LONG-TERM DEBT AND NOTES

Credit Facility

Present Activities

The following discussion of our plan of operation should be read in conjunction with the consolidated financial statements and the attached notes included elsewhere in this report. This discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors.

The company has executed a Share Purchase Agreement which includes a two-year option with Kazstroiproect Ltd (KSP), which provides, if they elect and comply with other financial conditions, for the sale and transfer of 50% interest of OJSC Caspi Neft TME, the company which holds the license to the South Alibek Field. In exchange for this interest, KSP must make available initially a three-year $20 million financing for the development of the field. KSP arranged the $20 million loan through Turan Alem Bank of Kazakhstan. Within twenty-four months of this initial loan (by February 4, 2004), KSP must determine if it wants to continue with the project. If KSP determines that it will continue, KSP will be responsible for the repayment of $15 million of the initial loan and make available up to $30 million in additional development financing at commercial rates. The portion of the loan not cancelled by the contribution of KSP will be treated as a corporate cost of OJSC Caspi Neft TME to be retired from proceeds of operations or further financing. If KSP determines by February 4, 2004 that it will not continue in the project it will relinquish all claims and rights to the 50% interest in Caspi Neft TME and Caspi Neft TME will be solely responsible for the entire loan, having an additional 12 months to pay back the debt. The partnership is governed by a joint shareholders agreement which was based on a typical international joint operating agreement. TMEI will provide for all the engineering and general directorship of the company for at least the first 3 years.

An interim bridge loan for $1.5 million was issued through Turan Alem Bank in December 2001, and the Company paid off the final installment of $1 million to the prior owner of the License, Al Alpha on December 1, 2001. A final credit agreement with Turan Alem Bank for the principal loan of $20 million was signed on February 26, 2002. The company believes that this financing should be sufficient to bring the field into production and allow the completion of the initial phase of delineation drilling and installation of testing and production facilities to handle production rates of up to 30,000 barrels of oil per day. All production will be treated to allow for the sale of crude by truck transport to local railroad transport terminals.

Asset Purchase

On April 26, 2002 the company entered into an agreement with Emba Trans Ltd. for the purchase of a 25% interest in the Emba Trans crude oil rail terminal. The 25% interest was purchased in exchange for 4,000,000 shares of the company’s restricted common stock. The terminal has an existing capacity of about 19,000 barrels per day but requires equipment upgrades to handle the anticipated capacity of 30,000 barrels per day. TMEI will provide engineering and operating personnel for the operation of the terminal. The terminal is about 40 miles by road from the South Alibek Field. For the first year crude deliveries will be made by tank truck until a crude pipeline can be installed to pipe crude from the field to the terminal.

F-22

(intentionally left blank)

F-23

TRANSMERIDIAN EXPLORATION, INC.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

(SEC Case)

As of

December 31, 2001

45

February 1, 2002

Transmeridian Exploration, Inc.
397 N. Sam Houston Pkwy. E., Suite 300
Houston, Texas 77060

Gentlemen:

        The estimated reserves and future income amounts presented in this report are related to hydrocarbon prices. Hydrocarbon prices in effect at December 31, 2001 were used in the preparation of this report as required by SEC rules; however, actual future prices may vary significantly from December 31, 2001 prices. Therefore, volumes of reserves actually recovered and amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold Interests of
Transmeridian Exploration, Inc.
As of December 31, 2001

	Proved
	Developed Non-Producing	Undeveloped	Total Proved
Net Remaining Reserves
Oil/Condensate - Barrels	5,808,683	11,836,735	17,645,418
Gas - MMCF	1,144	2,331	3,475
Income Data
Future Gross Revenue	$89,308,496	$181,989,793	$271,298,289
Deductions	13,726,691	24,161,877	37,888,568
Future Net Income (FNI)	$75,581,805	$157,827,916	$233,409,721
Discounted FNI @ 10%	$32,953,417	$  95,964,065	$128,917,482

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are sales gas expressed in millions of cubic feet (MMCF) at the official temperature and pressure base of the area in which the gas reserves are located.

46

        The future gross revenue is after the deduction of the normal direct costs of operating the wells, recompletion costs, and development costs. The future net income is before the deduction of Kazakhstan income tax and excess profit tax. No gas pipeline is in place nor is there a contract in place for sale of gas, therefore no income is included for the gas that will be produced. Liquid hydrocarbon reserves account for all of the total future gross revenue from proved reserves.

        The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown on each estimated projection of future production and income presented in a later section of this report and in summary form below.

	Discounted Future Net Income As of December 31, 2001
Discount Rate Percent	Total Proved
8	$142,374,028
12	$117,607,233
15	$103,712,251
20	$  86,301,191

        The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

        The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulation S-X Part 210.4-10 (a) as clarified by subsequent Commission Staff Accounting Bulletins. The definition of proved reserves are included under the tab “Reserve Definitions” in this report.

        Because of the direct relationship between volumes of proved undeveloped reserves and development plans, we include in the proved undeveloped category only reserves assigned to undeveloped locations that we have been assured will definitely be drilled.

        Transmeridian has additional interests in this concession that may contain substantial hydrocarbon potential not included herein. Transmeridian has stated that they have an active exploratory and development drilling program that may result in the discovery or reclassification of significant additional volumes.

        The various reserve status categories are defined under the tab “Reserve Definitions” in this report. The developed non-producing reserves included herein are comprised of the shut in category.

Estimates of Reserves

        All reserves included in this report were estimated using volumetric methods.

        The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues there from and the actual costs related thereto could be more or less than the estimated amounts. Moreover, estimates of reserves may increase or decrease as a result of future operations.

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Future Production Rates

        Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. Future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Transmeridian.

        Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates of their future production rates.

Hydrocarbon Prices

        Transmeridian furnished us with hydrocarbon prices in effect at December 31, 2001 and with its forecasts of future prices which take into account SEC and Financial Accounting Standards Board (FASB) rules, current market prices, contract prices, and fixed and determinable price escalations where applicable.

In accordance with FASB Statement No. 69, December 31, 2001 market prices were determined using the daily oil price or daily gas sales price (“spot price”) adjusted for oilfield or gas gathering hub and wellhead price differences (e.g. grade, transportation, gravity, sulfur and BS&W) as appropriate. Also in accordance with SEC and FASB specifications, changes in market prices subsequent to December 31, 2001 were not considered in this report.

        For hydrocarbon products sold under contract, the contract price including fixed and determinable escalations, exclusive of inflation adjustments, was used until expiration of the contract. Upon contract expiration, the price was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves.

        The effects of derivative instruments designated as price hedges of oil and gas quantities are generally not reflected in our individual property evaluations.

Costs

        Operating costs for the leases and wells in this report were supplied by Transmeridian and include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. No deduction was made for indirect costs such as general administration and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells.

        Development costs were furnished to us by Transmeridian and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. At the request of Transmeridian, their estimate of zero abandonment costs after salvage value for onshore properties was used in this report. We have not performed a detailed study of the abandonment costs or the salvage value and makes no warranty for Transmeridian’s estimate.

        Current costs were held constant throughout the life of the properties.

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General

        Table A presents a one line summary of proved reserve and income data for each of the subject properties which are ranked according to their future net income discounted at 10 percent per year. Table B presents a one line summary of gross and net reserves and income data for each of the subject properties. Table C presents a one line summary of initial basic data for each of the subject properties. Tables 1 through 12 present our estimated projection of production and income by years beginning January 1, 2002, by lease or well.

        While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may also increase or decrease from existing levels, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

        The estimates of reserves presented herein were based upon a detailed study of the properties in which Transmeridian owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices. Transmeridian has informed us that they have furnished us all of the accounts, records, geological and engineering data, and reports and other data required for this investigation. The ownership interests, prices, and other factual data furnished by Transmeridian were accepted without independent verification. The estimates presented in this report are based on data available through December 2001.

        Transmeridian has assured us of their intent and ability to proceed with the development activities included in this report, and that they are not aware of any legal, regulatory or political obstacles that would significantly alter their plans.

        Neither we nor any of our employees have any interest in the subject properties and neither the employment to make this study nor the compensation is contingent on our estimates of reserves and future income for the subject properties.

This report was prepared for the exclusive use and sole benefit of Transmeridian Exploration, Inc. The data, work papers, and maps used in this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

THE RYDER SCOTT COMPANY, L.P.



L. B. Branum, P.E.
Vice President

LBB/plk

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INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 24. Indemnification of Officers and Directors.

The only statute, charter provision, by-law, contract, or other arrangement under which any controlling person, director or officers of the Registrant is insured or indemnified in any manner against any liability which he may incur in his capacity as such, is as follows:

Our Amended and Restated Certificate of Incorporation and our By-laws require us to indemnify officers and directors to the fullest extent permitted by the Delaware Business Corporation Law (OBCA). Transmeridian has also entered into agreements to indemnify its directors and executive officers to provide the maximum indemnification permitted by Delaware law. These agreements, among other provisions, provide indemnification for certain expenses (including attorney fees), judgments, fines and settlement amounts incurred in any action or proceeding, including any action by or in our right.

Our By-laws require us to indemnify our directors, officers, employees and agent to the maximum extent permitted by the OBCA. Section 317 of the OBCA provides that a corporation has the power to indemnify and hold harmless a director, officer, employer or agent of the corporation who is or is made a party or is threatened to be made a party to any threatened action, suit or proceeding, whether civil, criminal, administrative or investigative, against all expense, liability and loss actually and reasonably incurred by such person in connection with such a proceeding if he or she acted in good faith and in a manner he or she reasonably believed to be in the best interest of the corporation, and, with respect to any criminal proceeding, had no reasonable cause to believe that the conduct was unlawful. If it is determined that the conduct of such person meets these standards, such person may be indemnified for expenses incurred and amounts paid in such proceeding if actually and reasonably in connection therewith.

The indemnification rights provided in Section 317 of the OBCA are not exclusive of additional rights to indemnification for breach of duty to the corporation and its shareholders to the extent additional rights are authorized in the corporation’s articles of incorporation and are not exclusive of any other rights to indemnification under any by-law, agreement, vote of shareholders or disinterested directors or otherwise, with as to action in his or her office and as to action in another capacity which holding such office.

ITEM 25. Other Expenses of Issuance and Distribution.

The following table sets forth an itemization of various expenses, all of which we will pay, in connection with the sale and distribution of the securities being registered for the Selling Shareholder. All of the amounts shown are estimates, except the Securities and Exchange Commission registration fee.

Securities and Exchange Commission Registration Fee	$     155
Accounting Fees and Expenses	-0-
Transfer Agent Fees	-0-
Printing Costs	-0-
Filing Related Fees	1,000
Legal Fees and Expenses	5,000
State Offering Fees	-0-
Commissions	-0-
TOTAL	$  6,155

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ITEM 26. Recent Sales of Unregistered Securities.

Set forth in chronological order is information regarding shares of common and preferred stock issued from December 31, 2001 to the date of this prospectus. Also included is the consideration, if any, received by us for such securities and information relating to the section of the Securities Act of 1933 (the Securities Act), or rule of the Securities and Exchange Commission under which exemption from registration was claimed.

Title of Class	Number of Shares	Price per Share	Consideration	Commission	Date
Common	1,500,000	$1.00	Conversion of Preferred Stock		March 13, 2002
Common	100,000	$0.35	ISOP		April 12, 2002
Common	4,000,000	$0.35	Emba Terminal	—	April 26, 2002
Common	1,000,000	$2.00	Drilling Rig	—	December 28, 2001
Warrants	200,000	$0.36		—	August 6, 2002
Convertible Debentures	Up to 4,444,444		$ 400,000	—	August 6, 2002
Common	500,000	$0.20	$ 100,000		September 30, 2002

ITEM 27. Exhibits and Financial Statement Schedules.

(A)  EXHIBITS

The following Exhibits are either attached hereto incorporated herein by reference or will be filed by amendment:

EXHIBIT NUMBER	DESCRIPTION OF EXHIBIT AND FILING REFERENCE
23.1	Consent of Carter Holmes, PLLC
23.2	Consent of John A. Braden & Company, P.C.
23.3	Consent of Ryder Scott Company, L.P.
23.4(a)	7% Convertible Note
23.4(b)	Convertible Debenture
23.4(c)	Registration Rights Agreement
23.4(d)	Stock Pledge Agreement
23.4(e)	Stock Purchase Warrant
23.4(f)	Modification Letter

The following Exhibits are referred to by reference and can be found in our prior SEC filings :

EXHIBIT NUMBER	DESCRIPTION OF EXHIBIT AND FILING REFERENCE	FILING  FORM	FILING DATE
3.1 (a)	Articles of Incorporation	SB-2	05/15/2001
3.1 (b)	Certificate of Amendment to the
	Articles of Incorporation	SB-2	05/15/2001
3.2	Bylaws	SB-2	05/15/2001
10.1	License 1557	SB-2	05/15/2001
10.2	Exploration Contract	SB-2	05/15/2001
10.3	SPA (Agreement for the Purchase
	and Sale of Shares)	SB-2	05/15/2001
10.10	Bank Loan Agreement	SB-2A	09/06/2001
24.1	Power of Attorney (Included on
	on Signature Page)	SB-2	05/15/2001

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(B)  FINANCIAL STATEMENT SCHEDULES

Financial Statement Schedules omitted because the information is included in the Financial Statements and Notes thereto.

ITEM 28. Undertakings.

A.  The undersigned registrant hereby undertakes:

(1)  To file, during any period in which offers or sales are being made, a post-effective amendment to this Registration Statement:

(i)  To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

(ii)  To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually, or in the aggregate, represent a fundamental change in the information set forth in the registration statement; notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) (230.424(b) of this Chapter) if, in the aggregate, the changes in volume and price represent no more than a 20% change in the maximum aggregate offering price set forth in the Calculation of Registration Fee table in the effective Registration Statement; and

(iii)  To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the Registration Statement.

(2)  That, for the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment shall be deemed to be a new Registration Statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3)  To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the Offering.

Rider re undertakings

(5) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the provisions described under Item 24 above, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

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