Item 1. Description of Business
Transmeridian Exploration, Inc. (the “Company” or “Transmeridian”) was incorporated in the State of Delaware in April 2000. We are engaged in the business of development and production of oil and gas properties. Our activities are primarily focused on the Caspian Sea region of the former Soviet Union and our primary oil and gas property is License 1557 and the related Exploration Contract for the development of the South Alibek Field (“South Alibek” or the “Field”) in the Republic of Kazakhstan. We conduct our operations in Kazakhstan through a 50% owned subsidiary, Caspi Neft TME (“Caspi Neft”). Caspi Neft is an Open Joint Stock Company (“OJSC”) organized under the laws of Kazakhstan. The remaining 50% of Caspi Neft is owned by Bramex Management, Inc. (“Bramex”), the successor to Kazstroiproekt, Ltd.
At December 31, 2004, the Company’s 50% share of Caspi Neft’s estimated total proved reserves were 26,813,736 barrels of oil (“Bbls”). All of these reserves are attributable to the South Alibek Field. The present value of estimated future net revenues before income taxes, discounted at 10% per annum, based on prices being received at the end of the year, with assumptions held constant throughout the estimated producing life of the reserves (“10% Present Value”) was $219,996,017. After deducting estimated future taxes, the Company’s share of the net present value of such reserves was $176,841,559. The total proved reserve estimates and the net present value before income tax have been prepared by Ryder Scott Company, an independent petroleum engineering company, in accordance with SEC guidelines.
We are in the early stages of developing the South Alibek Field. As of December 31, 2004, only 4,476,364 Bbls, or 17% of Caspi Neft’s proved reserves were classified as proved developed reserves. The balance of our estimated reserves are classified as proved undeveloped and will require the drilling of future wells to produce these reserves. We have an active development program in the Field, including plans to drill wells which are not currently included within the boundaries of our proved reserves. See Item 2, “Properties: Proved Reserves” and Note 12 of the Notes to Consolidated Financial Statements for further information about our estimated proved reserves.
In February 2004, Bramex exercised its option to acquire 50% of the common stock of Caspi Neft. Thus, our equity ownership of Caspi Neft was reduced to 50%, which reduced our effective net interest in the proved reserves in the Field to 50%.
Availability of Reports
Transmeridian makes available free of charge on its internet website, www.tmei.com, its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13 (a) or 15 (a) of the Securities Act of 1934 as soon as reasonably practicable after it electronically files or furnishes them to the Securities and Exchange Commission. Such filings and reports are also available from the Securities and Exchange Commission at its website at www.sec.gov.
Strategy
Our business strategy is to build reserves, production and cash flow through (a) the acquisition and development of oil and gas reserves, (b) exploring for new reserves, and (c) optimizing production and value from the existing reserve base. We prefer to target oil and gas properties with proved or probable reserves and avoid significant exploration risk. Through the contacts, technical knowledge and experience of our management team, we believe we can successfully identify and acquire additional properties in Kazakhstan and the Caspian Sea region. The execution of our business strategy is largely dependent on the successful development of the South Alibek Field, which is intended to provide a base of production, operations and cash flow to enable us to exploit future opportunities.
Drilling Activity
During 2004, we drilled and placed on extended production testing four wells, the South Alibek #2 (SA-2), South Alibek #4 (SA-4), South Alibek #5 (SA-5) and South Alibek #17 (SA-17) and began drilling of one additional well, the South Alibek #14 (SA-14). The SA-14 is the sixth well of an initial seven well drilling program in the South
Alibek Field. The SA-5 and SA-17 are in-field development wells. As of December 31, 2004, SA-14 was within 3,300 feet of its programmed depth. All wells are planned to drill the same KT1 and KT2 carbonate reservoirs of the South Alibek Field. Production casing has been set on all completed wells for the well testing program. With the exception of SA-4, all completed wells have been producing oil on an extended production testing program. In late November, a workover program was initiated to prepare the wells for long-term commercial production and includes reservoir stimulation and installation of production tubing and packers with the aim to increase the field’s oil production.
The following table shows the number of wells drilled:
Customers
We began selling oil from our first well, the SA-1, during the second quarter of 2003. In 2004 we sold 100% of our production into the domestic market, to six different purchasers. Until the pipeline transfer connections and handling facilities are complete, we are producing our oil into the central production facility where it is temporarily stored until being transferred to the buyer. See Item 2:
Item 2. Properties
Petroleum Industry in Kazakhstan
Until 1991, Kazakhstan was one of 15 independent republics which comprised the former Soviet Union. It has chosen to align with Russia and 10 of the former republics in the Confederation of Independent States (“CIS”), a union of economic and political cooperation. Kazakhstan is an area of significant investment activity for the international oil and gas industry. Based upon publicly available information, its proved reserves rank among the top 15 countries in the world, with over 180 producing oil fields and 20 billion barrels of proved reserves. Its current production is approximately 1.25 million barrels of oil per day (“Bopd”), of which approximately 85% is exported.
Regulation of the oil industry in Kazakhstan has been codified with the development of the Law of Petroleum which sets out the conduct of the oil and gas industry and the roles of participants, both private and governmental. The industry is regulated by the Ministry of Energy and Natural Resources, which administers all contracts, licenses and investment programs. The national oil company, Kazmunaigas, has been through several stages of consolidation since the country’s independence in 1991. The government has been merging the various regional governmental companies which previously handled the extraction and transportation sectors of the industry into one consolidated entity to eliminate redundant bureaucracy and provide for a more efficient management of the country’s natural resources. This entity maintains a direct ownership on behalf of the state in most large oil field development projects as well as sole ownership and operation of many of the interconnecting oil and gas pipeline systems. It is responsible for about 25% of Kazakhstan’s oil production and for 80% of oil transportation, contributing $850 million to the state budget in 2004. However, governmental ownership or participation in exploration and development projects is not required and the government has no ownership interest in the South Alibek Field.
Acquisition of the South Alibek Field
In May 1999, prior to the official formation of the Company, Transmeridian signed a consulting agreement with Kornerstone Investment Group Ltd. (“Kornerstone”). The controlling shareholder in Kornerstone is a citizen of Kazakhstan who is involved in oil and gas production and other business endeavors. He is also employed on a part-time basis as a consultant and manager of Caspi Neft, handling governmental matters and contract negotiations with governmental entities. Under this agreement, we engaged Kornerstone to identify and assist in the acquisition of oil and gas properties in Kazakhstan and the Caspian Sea region. Since we had not received any significant funding for the Company at that time, the agreement with Kornerstone provided that its compensation would be in the form of a 10% carried working interest in all properties shown to the Company in which the Company acquired an interest. The agreement required us to pay all costs of acquisition, development and operations attributable to the 10% carried working interest. We are entitled to recover all of our costs related to the carried interest from the production revenues attributable to this interest. After these costs have been fully recovered, Kornerstone will participate as a 10% working interest owner in all development and operating costs incurred subsequent to that point.
In early 2000, Kornerstone identified an opportunity in Kazakhstan known as the South Alibek License 1557, which covered what is now known as the South Alibek Field. The Alibekmola Field had been discovered in 1980 by a regional exploration unit of the Ministry of Geology of the former Soviet Union. A total of 31 wells were drilled in the Alibekmola Field to delineate the oil bearing reservoirs and structure of the field. This delineation work continued following the breakup of the Soviet Union. The South Alibek field was initially identified by an Alibekmola Field delineation well drilled by the Kazakh successors of the Soviet Ministry of Geology, Alibekmola 29 (A-29). It was identified to be in a separate fault block adjacent to the Alibekmola Field, and from testing in 1996 produced flowing oil from several intervals in the KT2 during well testing. Three of the initial delineation wells are within the area covered by our License The successor to the Ministry of Geology did not have sufficient funding to begin delineation drilling around A-29, and the license area was offered in a public tender in
Kazakhstan’s privatization program. The subsequent work by us has resulted in this license area being designated as the South Alibek Field.
The license and related exploration contract were initially acquired in the tender by a subsidiary of AIL Alpha Corporation, Ltd. (“Alpha”). License 1557 was granted by the Republic of Kazakhstan on April 29, 1999. On March 24, 2000, we signed a Share Purchase Agreement with Alpha to acquire the subsidiary which held the title to License 1557.
License and Exploration Contract
Our Exploration Contract (the “Exploration Contract”), entered into with the government of Kazakhstan in March 2000, has a six-year term expiring in April 2005 and requires total capital expenditures during this period of approximately $18.0 million. As of December 31, 2004, the cumulative capital expenditures which are creditable to our obligations under the Exploration Contract have exceeded the minimum commitment. Under the terms of the Contract, we can produce wells under a test program subject to royalty payments of 2% of production. The Exploration Contract may be extended by mutual agreement for two extension periods of two years each. In 2003 the Company requested an extension and in April 2004, we were granted the first of these two-year extensions through April 2007. In connection with such extension, we also agreed to an additional work program commitment of $30.5 million. As of December 31, 2004, $15 million of this additional minimum commitment has been made through the cumulative capital expenditures creditable to our obligations under the Exploration Contract. Future extension periods require negotiation with and approval by the government and may require additional capital commitments and other changes to the terms.
We have commenced negotiations for a production contract (“Production Contract”) and we anticipate that these negotiations will be concluded and a Production Contract in place by the end of 2005. We have the exclusive right to negotiate for a Production Contract for the Field, and the government is required to conduct these negotiations under the Law of Petroleum. However, we are not guaranteed the right to a Production Contract. Such contracts are customarily awarded upon determination that the field is capable of commercial rates of production and that the applicant has complied with the other terms of its license and Exploration Contract. A Production Contract will typically require a bonus payment upon execution, the amount of which is predetermined based upon the reserves approved by the State Committee of Reserves (“SRC”). If satisfactory terms cannot be negotiated, we have the right to produce and sell oil under the Law of Petroleum for the term of our existing Exploration Contract through April 2007, or as extended, at a royalty rate of 2%. The royalty rate under production contracts is on a sliding scale, based on production. The royalty rate ranges from 2% to 6%. The Exploration Contract contains a provision which will allow the government to recover, from future revenues, approximately $4.9 million of exploration costs which were incurred prior to privatization, usually over a 10 year period beginning one year following the approval of the Production Contract. The Production Contract, when executed, will contain the final terms for recovery of these costs.
In December 2004, The State Committee of Reserves (“SCR”) of the Republic of Kazakhstan approved the commercial reserves for development and exploitation of the South Alibek Field. This approval provides the Company with the basis to finalize the terms of a Production Contract relating to this portion of the Field with the Ministry of Energy and Mineral Resources. The Government has assessed a commercial bonus of $1.2 million based on the SCR reserves audit as provided under the country’s Petroleum Code.
The reserve audit covered by the SCR approval defines an initial production area of about 3,500 acres, about 25% of the total area under license. This area can be extended based on the drilling of additional exploration wells pursuant to the Company’s current Exploration Contract, which was recently extended for another 2 years until 2007
There are two general forms of production contracts in Kazakhstan, production sharing contracts and tax and royalty based contracts. We favor a tax and royalty based contract and will seek to negotiate and expect to operate under this structure. Under this financial arrangement, we will pay 100% of the development and operating costs and will be entitled to receive 100% of the revenues from the Field. In addition to an up-front bonus payment and recovery of certain costs incurred prior to conveyance of the Field, the government will be entitled to a royalty based on production from the Field and corporate income taxes. Corporate income taxes in Kazakhstan vary from 30% to 40%. Additionally, there is an excess profit tax on oil and gas production which can vary from 15% to 60% based on the ratio of net income to deductions. These taxes can significantly affect the economics of the project. The
Company is requesting an Exploration and Production Contract to allow for continued exploration while developing the known reserves. This type of contract should allow for maintaining the pre-January 2004 tax regime.
The government may also require that a percentage of our production, which we do not expect to exceed 10%, be sold into domestic markets at local prices. We would expect these prices to be lower than prices which we could receive in the export market. However, our transportation costs would likely be lower as well. Most of the smaller producers in the region are not currently being required to sell into the domestic market.
Overview of Regional Geology
The South Alibek Field is located in a fairway of large producing fields in the oil region of Aktobe in northwestern Kazakhstan. The largest city in the Aktubinsk Oblast is Aktobe, approximately 125 miles north of the Field. Within this fairway, the South Alibek Field is among a set of fields which are formed from a carbonate platform and which produce from carbonate reservoirs of Upper and Middle Carboniferous age. The trend follows the carbonate shelf which was deposited in the shallow waters of an ancient sea in what is now the margins of the Pre-Caspian Basin. Prolific oil field trends are established in the southern and northern margins of the basin, as well as in the southeastern margins where the South Alibek Field is located. The carbonate fields found along the margins of the Pre-Caspian Basin account for approximately 75% of Kazakhstan’s oil reserves and production. The fields in the trend are projected to ultimately contain over 40.0 billion barrels of recoverable reserves, including the super-giant Tengiz Field, which is estimated to hold 9.0 billion barrels of recoverable reserves and the Kashagan Field that is estimated to have 13.0 billion barrels of recoverable reserves.
South Alibek Field is located within 40 miles of two large developed fields, Kenkiyak and Zhanazhol, which contain ultimate recoverable reserves of 200 and 900 million barrels of oil, respectively, including cumulative oil produced and estimated remaining reserves. South Alibek is immediately adjacent to the producing Alibekmola Field, from which it is separated by a large fault. The South Alibek Field is about 1,000 feet lower than the Alibekmola Field and has a lower oil water contact. Production from the Zhanazhol Field is estimated to be in excess of 100,000 Bopd and the Alibekmola Field, still in the early phase of development, reports production to be over 25,000 Bopd.
This region contains good infrastructure for oil and gas development and production, including oil and gas pipelines, electrical transmission connections, all-weather roads, small towns and trained oilfield labor. This improves our development logistics and lowers our costs compared to drilling in a more remote location.
Field Geology
The primary oil reservoirs in the South Alibek and Alibekmola Fields are in the Upper - Middle Carboniferous (KT1) and Middle-Lower Carboniferous (KT-2) limestones, which are the main reservoirs for many of the fields throughout the Southeastern margin of the Pre-Caspian Basin. The tops of these formations are found at an initial depth of 6,500 feet and they have a combined gross thickness of as much as 5,000 feet in the area. The thickness of net productive intervals can be several hundred feet.
We have conducted an extensive evaluation of the information available for the Field and adjacent fields. This information consists of log data from the 31 wells drilled prior to privatization, the five new wells we have drilled under our License, recent vintage 2D seismic data and use of the results of 3D seismic for which we have rights to. Based on the evaluation of this data, we believe that the oil-bearing reservoirs within the KT-1 and KT-2 carbonates may be present over a substantial part of the area covered by our License.
Proved Reserves
Our estimated proved oil and gas reserve quantities were prepared by Ryder Scott Company, independent petroleum engineers. There are numerous uncertainties in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. These uncertainties are greater for properties which are undeveloped or have a limited production history, such as the South Alibek Field. They are only estimates and actual reserves may vary substantially from these estimates. All of our proved reserves are in the South Alibek Field in Kazakhstan. Our net quantities of proved developed and undeveloped reserves of crude oil and standardized measure of future net cash flows are reflected in the table below. See further information about the basis of presentation of these amounts in Note 12 of the Notes to Consolidated Financial Statements.
As of December 31, 2004, we own a 50% working interest in the South Alibek Field, subject to government royalties and a 10% carried working interest after recovery of costs. The effect of the carried interest is reflected in the calculation of our net proved reserves. Our proved reserves have been prepared under the assumption that we obtain a commercial production contract which will allow production for the expected 25-year term of the contract, as more fully discussed above in “License and Production Contract”, above. In February 2004, Bramex exercised its option to acquire 50% of the common stock of Caspi Neft. Thus, our equity ownership of Caspi Neft was reduced to 50%, which reduces our effective net interest in the proved reserves in the Field to 50%. This 50% working interest is also subject to government royalties. Based on forecast production volumes, the average royalty over the term of the production contract is expected to be 6% or less under current law.
Net Proved Crude Oil Reserves and Future Net Cash Flows
As of December 31, 2004
(Quantities in Barrels)
The following table shows the number of developed and undeveloped acres in the South Alibek Field as of the dates indicated:
Transportation and Marketing
Companies in the area of the South Alibek Field utilize both the KazTrans Oil and Russian Transneft pipeline systems to export crude oil to regional hub locations such as Samara, Ukraine, the Port of Odessa on the Black Sea and European locations such as Poland, Hungry, Lithuania, Germany and Finland. Pipeline capacity in the area has significantly improved with the opening of the Caspian Pipeline Consortium (“CPC”) pipeline, which ultimately will increase capacity from 250,000 Bopd to an expected 800,000 Bopd. Two Soviet era oil pipelines, with capacities of 50,000 Bopd and 93,000 Bopd, respectively, service nearby producing fields. One of the pipelines is operating at less than full capacity. These pipelines transport oil to the Bestamak rail terminal and the oil refinery in Orsk, which is a transfer point for swaps to Western markets. The nearest rail terminal for export is approximately 30 miles from the South Alibek Field at Zhem, and is utilized by local producers for domestic and export oil sales by rail. The Kenkiyak-Atyrau pipeline became operational in 2003 with an initial capacity of 120,000 Bopd. This pipeline originates at the Kenkiyak Field and provides a link to the CPC pipeline for the producers in the region. The Alibekmola Field, adjacent to South Alibek, has begun commercial production, and KazTrans Oil has commissioned a 20” pipeline across our license to connect Alibekmola production to the Kenkiyak-Atyrau pipeline for export markets via the CPC pipeline. A pump station has been installed about 1.5 kilometers from our central production facility. We expect to have access to this pipeline, subject to possible capacity limitations, after we make certain required processing and delivery investments. Our goal for the South Alibek Field is to complete the installation of crude oil treating facilities, pipeline connections and handling equipment so that we can secure a pipeline allotment and export quotas for the Field. Prior to this, our production will be transported by truck for sale into the local market or for rail shipment to export markets, depending on the best pricing available at the time.
In 2002, we acquired the Emba Terminal, which is located 35 miles from the Field. The Emba Terminal is a facility for storing and loading crude oil for shipment by rail. The facility has not been operational for several years and will require capital improvements to make it suitable for use. As of December 31, 2004 , we have advanced
approximately $1.465 million to Emba Trans Ltd. which was used to acquire the Emba Terminal, fund the engineering study and begin construction and refurbishment of the facilities. We may also use the terminal to ship crude oil for third parties if we do not require all of the capacity. The Emba Terminal is intended primarily for use as an interim solution to sell our production prior to the completion of pipeline and processing facilities. However, it will also serve as an alternative transportation outlet if our pipeline capacity is constrained. Caspi Neft owns 75% of Emba Trans Ltd., with the balance of 25% owned by Transmeridian.
Another operator in the immediate area of the Field is in the planning stages of extending the rail line from Zhem to its field. The planned construction of this extension will cross our Field, thereby giving us another alternative for transporting our crude oil and making it available to the export market.
Drilling Rig
On December 28, 2001, we purchased a land drilling rig for $5.3 million in total consideration, including a note payable for $3.3 million and the issuance by the Company of $2.0 million in redeemable common stock. The rig was acquired for drilling operations in the South Alibek Field. The rig is a diesel and electric powered National 1320UE, with 2,000 horsepower rating. It has a depth rating of approximately 20,000 feet and has a 320 ton rating on the draw works. At the time of the purchase, the rig was in storage in South America. During 2002, we moved the rig by marine transport vessel to Kazakhstan and undertook various refurbishments and modifications to the rig to make it suitable for use in our operations. We entered into a contract with a firm experienced with international drilling to oversee the operation of the rig and provide expatriate drilling personnel.
As more fully discussed in Item 3
Item 3. Legal Proceedings
Drilling Rig Dispute
In December 2001, the Company purchased a drilling rig for $5.3 million by the issuance, to the seller, of a note payable for $3.3 million and redeemable common stock of $2.0 million. Further discussion of this transaction can be found in Notes 2, 5 and 9 of the Notes to Consolidated Financial Statements. In July 2003, the Company was notified by the holder of an apparent first lien on the drilling rig (the “First Lien Holder”) that the seller of the rig was in default under its note payable obligation to the First Lien Holder. The Company was not informed of the existence of the First Lien Holder in the Asset Purchase Agreement related to the acquisition of the drilling rig. The note payable and the redeemable common stock are now in dispute as a result of the Seller’s default to the First Lien Holder. During 2003, the Company held discussions with the First Lien Holder with the intent to resolve the Seller’s default by making certain payments directly to the First Lien Holder. During the year ended December 31, 2003, the Company made installment payments to the First Lien Holder totaling $688,400.
Discussions with the seller of the rig became increasingly adversarial during late 2003 and on December 15, 2003, the seller filed suit in District Court, Harris County, Texas, 334th Judicial District relating to the Company’s alleged default under the note payable and redeemable common stock agreements with the seller. At this time, the Company ceased installment payments to the First Lien Holder as it had not been able to successfully negotiate a settlement agreement with both the seller and the First Lien Holder. On February 27, 2004, the First Lien Holder filed suit in United States District Court, Southern District of Texas, against the seller and named the Company and two of its affiliates as additional defendants. This action seeks payment of debts owed to the First Lien Holder by the seller related to the drilling rig.
In April 2004, the Company filed a Counterclaim and Third-Party Claim against the seller and certain of its affiliates. This action seeks recovery of repair costs incurred by the Company in connection with undisclosed latent defects in the drilling rig, recovery of payments made to the seller, including the redeemable common stock, and recovery of additional costs associated with the drilling rig.
In August 2004, the Company and the seller of the rig entered into a Settlement and Release Agreement whereby the seller of the rig agreed to cancel the promissory note of $1.6 million, plus accrued interest of $700,000, and return 200,000 of the 1.0 million shares of redeemable common stock. Pursuant to the terms of the Settlement and Release Agreement the remaining balance due on the note of $1.6 million, plus accrued interest of $550,000 has been
cancelled and was replaced by assuming the obligation of the seller of the rig to the First Lien Holder. The Company has estimated this liability to be approximately $2.9 million including accrued and unpaid interest. The Company also agreed to pay $120,000 of the legal fees incurred by the seller of the rig in its lawsuit with the First Lien Holder. In December 2004, the Company began making the seller’s payment obligation to the First Lien Holder of $137,680 per month.
Former Chief Financial Officer
In May 2003, Jim W. Tucker (the “Plaintiff”), the former Chief Financial Officer of the Company, filed suit in the 359th District Court, Montgomery County, Texas, against Transmeridian Exploration, Inc., in connection with his separation from service with the Company on January 3, 2003. The suit alleges breach of an oral employment agreement. The Company was never served with notice and had no knowledge of this suit. Counsel for the Plaintiff claimed they were unable to serve the Company’s registered agent with notice of this suit. Based on these representations, the Court awarded the Plaintiff a Default Judgment on November 25, 2003, in the amount of $922,275.61. The Company was notified of a Writ of Garnishment and Writ of Execution on March 29, 2004 and April 6, 2004, respectively.
On April 5, 2004, the Company filed a Petition for Bill of Review and a Motion to Vacate the Writ of Garnishment. A hearing was held on the Motion to Vacate the Writ of Garnishment on April 8, 2004. On May 11, 2004, the court granted the Motion to Vacate the Writ of Garnishment, but has not issued a ruling on the Petition for Bill of Review. In February 2005, the court granted the Motion to Vacate the Default Judgment and the Company withdrew its Petition for a Change of Venue. The case going forward will be reinstated and will begin as if the Company had just been served notice. The Company intends to vigorously contest this matter and pursue all legal remedies available to it.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of security holders during the quarter ended December 31, 2004.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity and Related Stockholder Matters
Common Stock
Our common stock, par value $0.0006 per share, began trading publicly on February 26, 2002 and is traded on the OTC Bulletin Board under the symbol “TMXN”. There are 200,000,000 shares authorized by our Amended and Restated Certificate of Incorporation. As of December 31, 2004, we had 79,829,062 shares issued and outstanding, which were held by an estimated 1,850 beneficial owners. The following table presents the high and low closing prices per share for our common shares, as reported by the OTC Bulletin Board. Such over-the-counter market prices reflect inter-dealer prices, without retail markup, markdown or commissions:
Preferred Stock
We are authorized by our Amended and Restated Certificate of Incorporation to issue up to 5,000,000 shares of preferred stock. As of December 31, 2004, we had 1,785.714 shares of Series A Cumulative Convertible Preferred Stock issued and outstanding which are held by an estimated nine beneficial owners.
Dividend Policy on Common Stock
We have never paid cash dividends on our common stock. We intend to retain future earnings, if any, to meet our working capital requirements and to finance the future operations of our business. Therefore, we do not plan to declare or pay cash dividends to the holders of our common stock in the foreseeable future.
Recent Issuance of Unregistered Securities
In November 2004, the Company sold 1,785.714 shares of its Series A Cumulative Convertible Preferred Stock (the “Series A Preferred”) in a private placement at a purchase price of $14,000 per share, and issued warrants to purchase up to 4,464,286 shares of the Company’s common stock at an exercise price equal to $1.55 per share. The aggregate purchase price for the Series A Preferred and the related warrants was cash consideration of $25.0 million. This issuance is more fully discussed in Note 8 of the Notes to Consolidated Financial Statements.
The foregoing issuance of Series A Preferred stock were made in reliance upon the exemption from registration set forth in Section 4(2) of the Securities Act of 1933 for transactions not involving a public offering. No underwriters were engaged in connection with the foregoing issuances of securities. The sales were made without general solicitation or advertising. Each purchaser was an “accredited investor” or a sophisticated investor with access to all relevant information necessary to evaluate the investment who represented to the Company that the sales were being acquired for investment.
Stock Option Plan
During 2003, the Company filed a Form S-8 registration statement with the Securities and Exchange Commission to register 5.0 million shares under its 2001 Incentive Stock Option Plan (the “Option Plan”). The options may be granted to officers, board members, key employees and consultants through December 31, 2010. Under the Option Plan, the exercise price of each option is equal to the fair market value of the Company’s common stock on the date of the grant and all options granted have a term of five years. The vesting period is determined by the Board of Directors on the date of grant. As of December 31, 2004, options to purchase 2,045,000 shares had been granted and options to purchase 2,955,000 shares were available for future grants under the Option Plan.
Stock Compensation Plan
During 2003, the Company filed a Form S-8 registration statement with the Securities and Exchange Commission to register 2.5 million shares under its 2003 Stock Compensation Plan (the “Stock Compensation Plan”). Under the Stock Compensation Plan, such stock can be issued in lieu of cash to compensate officers, employees, directors and third-party consultants for services rendered. As of December 31, 2004, 1,443,327 shares had been issued and 775,000 shares have been granted, but have not yet been earned. There are 281,673 shares available for future grants under the Stock Compensation Plan.
Item 6.
Item 6. Selected Financial Data
The following selected financial information (which is not covered by the independent auditors’ report) should be read in conjunction with the consolidated financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.”
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
SEE DISCUSSION OF RISK FACTORS IN ITEM 1 OF THIS ANNUAL REPORT ON FORM 10-K.
Introduction
The following discussion and analysis addresses changes in Transmeridian’s financial condition and results of operations during the three year period 2002 through 2004.
There is limited or no comparability for revenue and operating expense to the comparable periods in 2002 and 2003, as sales and production did not commence until the third quarter of 2003.
Management’s primary goals for 2004 were:
• Continue the development of the Field by operating two drilling rigs;
• Secure additional financing for our 50% share of the 2004 budget;
• Complete Phase I of the production facilities;
• Position the Company for pipeline sales in 2005.
We believe that these primary goals were achieved in 2004. We are currently developing our goals for 2005, which will be finalized in the first quarter of 2005. We anticipate, however, that these goals will include increased production from all the wells in the Field, more efficient drilling and completion programs, improving our price received for oil sales, execution of a Production Contract and securing additional financing for Caspi Neft.
Current Activities
During 2004, we drilled and placed on extended production testing four wells, the South Alibek #2 (SA-2), South Alibek #4 (SA-4), South Alibek #5 (SA-5) and South Alibek #17 (SA-17) and began drilling of one additional well, the South Alibek #14 (SA-14). The SA-14 is the sixth well of an initial seven well drilling program in the South Alibek Field. The SA-5 and SA-17 are in-field development wells. As of December 31, 2004, SA-14 was within 3,300 feet of its programmed depth. All wells are planned to drill the same KT1 and KT2 carbonate reservoirs of the South Alibek Field. Production casing has been set on all completed wells for the well testing program. With the exception of SA-4, all completed wells have been producing oil on an extended production testing program. In late November, a workover program was initiated to prepare the wells for long-term commercial production and includes reservoir stimulation and installation of production tubing and packers with the aim to increase the field’s oil production. The additional perforation and stimulation programs for wells SA-2 and SA-5 have been completed. The wells are being flowed and evaluated to determine their optimum flow potential.
We plan to perform a hydraulic fracture stimulation of well SA-17 during the first quarter of 2005. Logistical challenges in procuring the high strength proppant material and a lack of availability of service company equipment have caused a delay in performing this operation. The service company has mobilized its team to the field and last minute preparations are underway. Once this operation is completed the well will undergo long term testing to evaluate the effectiveness of the hydraulic fracture stimulation for application to the other existing and future wells.
The Central Production Facility is being completed. One of the three oil storage tanks has been commissioned and is currently being used for crude oil storage. We expect the facility to become fully operational during 2005. A de-marcaptane unit is being designed to meet quality specifications required for entry into the regional pipeline system. Our contractors estimate that completion and Field commissioning should occur in the third quarter of 2005.
In July 2004, we established an office in Baku, Azerbaijan to evaluate prospects in that country. We will be allowed to view data from the national oil company’s archives to evaluate the available properties and enter into a Memorandum of Understanding to undertake the study of various plays in the country. We seek properties which meet our objectives of 1) low up-front acquisition costs, 2) identified reserves, 3) significant upside reserve potential, 4) reasonably short payback period and 5) lower than average international finding costs. We are not obligated to purchase or participate in a property and have an indefinite time to review the data.
Results of Operations
Oil production and revenue
For the year ended December 31, 2004, Caspi Neft produced 313,305 barrels (“Bbls”) of crude oil, or an average of 858 Bopd, as compared to 117,376 Bbls, or an average of 641 Bopd for the year ended December 31, 2003. The increase in 2004 when compared to 2003 is due to the Field having three producing wells in 2004 as compared to only one producing well in 2003, and the Field was on production for all of 2004 and only six months of 2003. There is no comparability of production for the years ended December 31, 2003 and 2002, because production from the Field did not commence until July of 2003.
For the year ended December 31, 2004, we sold (by physical delivery to the purchaser) 336,440 Bbls of crude oil at an average price of $11.87 per Bbl, for net revenues of $3,922,990, as compared to 77,293 Bbls at an average price of $10.52 and net revenue of $797,411 for the year ended December 31, 2003. The increase in 2004 when compared to 2003 is due to the Field having three producing wells in 2004 as compared to only one producing well in 2003, and the Field producing for all of 2004 and only six months of 2003. There is no comparability of revenue for the years ended December 31, 2003 and 2002, because sales from the Field did not commence until the third quarter of 2003.
We recognize revenue from the sale of oil when the purchaser takes delivery of the oil at the Field. As of December 31, 2004, the Company had 16,576 Bbls in inventory for which it had received payment, but had not recognized the revenue because delivery had not yet been taken by the purchaser. The average price received for these Bbls was $11.61, which will be recognized as revenue in future periods of 2005 upon delivery to the purchaser.
Our crude oil sales in the last eight months of 2004 occurred at the Field and were not subject to transportation costs. Consequently, our net realization improved by approximately $2.00 per Bbl compared to year end 2003. (For additional discussion on transportation, see Transportation Expense, below).
In December, we entered into a new contract for sales of crude oil from South Alibek Field. The arrangement provides for deliveries to take place at the field and a net sales price of approximately $20 per barrel. While the agreement is short-term in nature, it may be extended by mutual agreement of the parties.
Exploration expense
Exploration expense, which includes geological and geophysical expense and the cost of unsuccessful exploratory wells, is recorded as an expense in the period incurred under the successful efforts method of accounting. During 2004 we incurred $130,926 in exploration expense as compared to $592,553 for the comparable period in 2003. The decrease is primarily due to the fact no new geologic data was purchased and interpreted in 2004. In 2004 we expensed the remaining book value of our South Texas properties, $66,844, due to the unsuccessful reentry in the third quarter. During 2003, we incurred $592,553 in exploration expense which was primarily related to the purchase and interpretation costs of geologic data and a charge for the unsuccessful completion attempt on one of our two U. S. properties. For the year ended December 31, 2002, there were no charges to exploration expense.
Depreciation, depletion and amortization
Depreciation, depletion and amortization (“DD&A”) of oil and gas properties is calculated under units of production method, following the successful efforts method of accounting, as described in Note 1 of the Notes to Consolidated Financial Statements. In 2004 we sold 336,440 Bbls of oil resulting in DD&A of $709,496, as compared to 77,293 Bbls of oil sales resulting in DD&A of $189,635 for 2003. This increase is primarily due to increased oil sales in 2004. There is no comparability for DD&A for the years ended December 31, 2003 and 2002, because sales from the Field did not commence until the third quarter of 2003.
Non-oil and gas property DD&A for 2004 was $79,261 and $56,079 for 2003. This increase is primarily due to asset additions in the Kazakhstan operation. For the year ended December 31, 2002 we recorded $28,320, in non-oil and gas property DD&A. The increases in 2003 and 2002 are primarily due to additional transportation and other equipment acquired by Caspi Neft.
Transportation and Expenses
During the second quarter of 2004, the first of three storage tanks at our permanent production facility was commissioned for use. This allowed us to begin oil sales from the Field, resulting in a cost savings of approximately $517,887. For the year ended December 31, 2004, transportation and storage costs were $173,847, or $0.55 per Bbl produced. For the year ended December 31, 2003, we incurred $235,264 or $2.00 per Bbl produced. We are currently negotiating to have a railroad spur built from our production facility to the main rail line. See Item 2. “Properties: Transportation and Marketing.” This will allow for direct shipment of the crude oil to the export terminals located on the railroad. Additionally, when the treating facilities and pipeline pump station discussed in Item 2 are operational, expected during 2005, we should be able to deliver crude oil production directly into the regional pipeline system, which should result in a significant improvement in sales pricing for our crude oil. The prices received for pipeline sales should be much closer to prevailing world oil prices than our current sales arrangements.
Operating and administrative expense - Kazakhstan.
For the year ended December 31, 2004 operating and administrative expense in Kazakhstan was $3.6 million, as compared $2.5 million for the year ended December 31, 2003. This increase is primarily due to increased activity in our exploration, development and production program for the South Alibek Field. In 2002 operating and
administrative cost in Kazakhstan was $1.2 million. The increase of $1.3 million, when comparing 2002 to 2003, is primarily due to increased personnel costs at Caspi Neft, which is a result of increased activity.
General and administrative expense - Houston
For the year ended December 31, 2004 general and administrative expense in Houston was $2.6 million, as compared $2.1 million for the year ended December 31, 2003. This increase is primarily due to increased legal costs associated with the lawsuits explained in Item 3. In 2002 general and administrative expense in Houston was $1.8 million. The increase when comparing 2002 to 2003 is primarily due to legal costs and investor relation cost.
Interest expense
Interest expense, net of the capitalized portion, for the years ended December 31, 2004, 2003 and 2002, was $1,400,227, $772,409 and $338,229, respectively. The increase in interest expense when comparing 2004 to 2003 is primarily due to increased debt levels and expensing of interest that had been capitalized in the prior year. Once a well has been completed and is producing oil, we no longer continue to capitalize interest. The increase in 2003 compared to 2002 is primarily due to capitalizing the interest on our drilling rig in 2002 during the time it was being prepared for its intended use. We expect interest expense to increase in 2005 due to more wells being placed on production. However, if we are successful in securing a new credit facility or renegotiating the current facility at more favorable interest rates, we would expect interest expense to decrease.
Liquidity and Capital Resources
For the years ended December 31, 2004, 2003 and 2002, capital expenditures were $26.1 million, $31.2 and $11.5 million, respectively. The primary sources of funding have been private placements of common and preferred stock, borrowings under our credit facilities with a Kazakhstan bank (as described in more detail below and in Note 5 to the Notes to Consolidated Financial Statements) and loans from the Company and Bramex to Caspi Neft. From inception through December 31, 2004, we have received a total of $12.0 million in net cash proceeds from sales of common stock and $23.4 million in net cash proceeds from the sale of preferred stock. Our cumulative proceeds from all borrowings, net of repayments, have amounted to $34.6 million since inception. These proceeds have been used to conduct remedial work and production tests on SA - 29, drill and complete the SA - 1, SA-2, SA-4, SA-5 and SA-17, the drilling of the SA - 14, the initial construction costs of support and production facilities and the administrative cost of the office in Kazakhstan. The total capitalized cost attributable to the South Alibek Field as of December 31, 2004, was $78.9 million, which includes $10.0 million of capitalized interest.
In February 2002, Caspi Neft obtained a $20.0 million credit facility with a Kazakhstan bank to fund operations in the South Alibek Field. The available capacity under the facility was fully utilized in April 2003 and the bank extended $1.5 million in additional financing as an interim step pending arrangements for an additional facility. Under the terms of the credit facility, a portion of this debt and accrued interest was due in August 2003. This amount was subsequently paid in February 2004 in conjunction with the Bramex option exercise discussed below. See Note 5 to the Notes to Consolidated Financial Statements for further discussion.
In connection with this bank financing, the Company granted an option to Bramex to acquire 50% of the common stock of Caspi Neft. To exercise this option, Bramex made a capital contribution to Caspi Neft of $15.0 million, which was used to repay part of the bank’s credit facility. The option was exercised in February 2004. For additional information, see Note 5 of the Notes to Consolidated Financial Statements.
In September 2003, Caspi Neft entered into a second facility with this bank in the amount of $30.0 million. The funds from this facility were used for the ongoing development of the project. As of December 31, 2004, the total amount available had been fully utilized. The principal balance with accrued interest is payable in 36 monthly installments from June 2005 through May 2008. For additional information, see Note 5 of the Notes to Consolidated Financial Statements.
In February 2005, the Company, through its subsidiary Caspi Neft, entered into an agreement with the bank in Kazakhstan to defer all payments of principal and interest due on both credit facilities for six months or until July 15, 2005. At the expiration of the extension the total amount of principal and interest deferred, $13.7 million will become due and payable. In exchange for this deferral the Company has agreed to advance up to $10.0 million to Caspi Neft to fund 100% of anticipated capital requirements for the first six months of 2005.
In November 2004, the Company sold 1,785.714 shares of its Series A Cumulative Convertible Preferred Stock (the “Series A Preferred”) in a private placement at a purchase price of $14,000 per share, and issued warrants to purchase up to 4,464,286 shares of the Company’s common stock at an exercise price equal to $1.55 per share. The aggregate purchase price for the Series A Preferred and the related warrants was cash consideration of $25.0 million. Proceeds from the private placement of Series A Preferred Stock and Warrants will be used for general corporate purposes, including funding the Company’s development drilling program in the South Alibek field in Kazakhstan, and to pursue growth opportunities.
The Series A Preferred has a liquidation value of $14,000 per share and is convertible at the holders’ option into common stock at a conversion price of $1.40 per share, subject to adjustments in certain circumstances. The holders of the Series A Preferred will be entitled to a quarterly dividend payable at the rate of four and one-half percent (4.5%) per annum, payable in cash. The holders of the Series A Preferred Stock shall have full voting rights and powers (subject to a beneficial ownership cap as described below) equal to the voting rights and powers of the holders of common stock, voting together with the holders of common stock as one class. Each holder of the Series A Preferred shall not, unless it chooses in advance not to be governed by this limitation, convert the Series A Preferred or exercise the Warrant Shares into common stock such that the number of shares of common stock issued after the conversion would exceed, when aggregated with all other shares of common stock owned by such holder at such time, in excess of 4.999% of the then issued and outstanding shares of common stock outstanding of the Company. So long as at least twenty (20%) percent of the Series A Preferred remains outstanding, the Company shall not issue any new securities or financial instruments that rank pari pasu or senior to the Series A Preferred without the approval of at least 75% of the Series A Preferred outstanding. Beginning one year following the effective date of the registration statement to be filed for the underlying shares of common stock, the Series A Preferred shall automatically convert into the common stock of the Company at the conversion price of $1.40 per share (subject to adjustments), if the common stock trades at a price equal to or greater than $4.15 per share for twenty (20) consecutive trading days, subject to the applicable ownership limitations. In the event a holder is prohibited from converting into common stock due to the 4.999% ownership limitation described above, the excess portion of the Series A Preferred shall remain outstanding, but shall cease to accrue a dividend.
We contributed $10.5 million of the Series A preferred Stock proceeds to the working capital of Caspi Neft. The other 50% owner of Caspi Neft has also contributed $10.5 million.
Management expects cash flow from operations to increase throughout 2005 and provide a portion of the funds needed to further develop the field and repay debt. Such cash flow is dependent upon many factors, such as achieving and sustaining adequate production rates, oil prices, and other factors which may be beyond the control of the Company.
By the end of 2005, we expect to drill and complete four new wells, bringing our total number of producing wells to ten, complete the construction of the production facility, tie into the regional pipeline system, and complete negotiation of a Production Contract. We have an approved budget of approximately $36.6 million for capital expenditures and an operating budget (lease operating expense and general and administrative expense) budget of approximately $12.0 million. We currently anticipate that this capital spending plan will result in a cash shortfall of approximately $10.0 - $15.0 million, before including debt service. We are currently discussing new financing alternatives with several financial institutions, but cannot be assured that we will be successful in securing the new financing. If an agreement is not achieved for new financing we will have to reduce or suspend our capital program in order to fund operating expenses and debt service. The Company believes it will be successful in obtaining new financing to continue development of the Field in accordance with its current development plan. However, the Company cannot provide assurance that it will be successful, as many factors required to execute its plans are outside the control of the Company.
The following table presents our future contractual obligations, which consist of long-term debt and lease commitments:
(1) See Note 5 to the Notes to Consolidated Financial Statements.
(2) See Note 9 to the Notes to the Consolidated Financial Statements.
Critical Accounting Policies and Recent Accounting Pronouncements
We have identified the policies below as critical to our business operations and the understanding of our financial statements. The impact of these policies and associated risks are discussed throughout Management’s Discussion and Analysis where such policies affect our reported and expected financial results. A complete discussion of our accounting policies is included in Note 1 of the Notes to Consolidated Financial Statements.
Principles of Consolidation
Our consolidated financial statements include all of our subsidiaries. Our most significant subsidiary is Caspi Neft, which holds License 1557 and the related Exploration Contract for the South Alibek Field. Except for the drilling rig, which is owned by the parent company, the assets and results of operations of Caspi Neft represent substantially all of our consolidated assets and operations at December 31, 2004.
During February 2004, Bramex Management, Inc., successor in interest to Kazstroiproekt, Ltd. (“Bramex”), exercised its option to acquire 50% of the common stock of OJSC Caspi Neft TME (“Caspi Neft”), the Company’s primary operating subsidiary in Kazakhstan and the entity which holds the license and exploration contract covering the South Alibek Field. Accordingly, as of December 31, 2004, the Company owns a 50% equity interest in this subsidiary. Based on the Company’s ability to exercise significant control over Caspi Neft, the Company believes that the most meaningful accounting treatment is to fully consolidate this entity, with the 50% share owned by Bramex reflected as a minority interest.
To exercise its option to acquire 50% of Caspi Neft, Bramex contributed $15 million in cash to Caspi Neft, the proceeds of which were used by Caspi Neft to retire debt. The difference between the $15 million of capital contributed to Caspi Neft and 50% of the book equity of Caspi Neft after such capital contribution represents an excess purchase price paid by Bramex of $6.0 million. This amount has been included in additional paid-in capital on the accompanying consolidated balance sheet.
Oil and Gas Reserve Information
The information regarding our oil and gas reserves, the changes thereto and the estimated future net cash flows are dependent upon engineering, price and other assumptions used in preparing our annual reserve study. A qualified independent petroleum engineer was engaged to prepare the estimates of our oil and gas reserves in accordance with applicable engineering standards and in accordance with Securities and Exchange Commission guidelines. Changes in prices and cost levels, as well as the timing of future development costs, may cause actual results to vary significantly from the data presented. Our oil and gas reserve data represent estimates only and are not intended to be a forecast or fair market value of our assets.
Our oil and gas reserve data and estimated future net cash flows have been prepared assuming we are successful in negotiating a commercial production contract which will allow production for the expected 25-year term of the contract. The current maximum statutory royalty rate of 6%, as dictated by new tax rules which came into effect in
2004, has been used to calculate the government royalty. Production contracts are customarily awarded upon determination that the field is capable of commercial rates of production and that the applicant has complied with the other terms of its license and exploration contract. However, we are not guaranteed the right to a production contract. If we are not successful in negotiating a production contract on acceptable terms, it will materially change our oil and gas reserve data and estimated future net cash flows.
Successful Efforts Method of Accounting
We follow the successful efforts method of accounting for our investments in oil and gas properties, as more fully described in Note 1 of the Notes to Consolidated Financial Statements. This accounting method has a pervasive effect on our reported financial position and results of operations.
Capitalized Interest Costs
We capitalize interest costs on oil and gas projects under development, including the costs of unproved leasehold and property acquisition costs, wells in progress and related facilities. We also capitalized interest on our drilling rig during the time it was being prepared for its intended use. During the year ended December 31, 2004, 2003 and 2002, we capitalized $4.5 million, $4.2 million and $1.3 million, respectively, of interest costs, which reduced our reported net interest expense to $1.4 million, $772,409 and $338,645 respectively. Since a significant portion of our financial resources has been dedicated to the exploration and development of our Kazakhstan property, since 2001, the resulting interest capitalized has been significant. This capitalized interest becomes part of the capitalized costs of our properties which will be amortized as a part of depreciation, depletion and amortization or charged to expense if the results of our drilling should prove unsuccessful.
Recent Accounting Pronouncements
In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 123 (R), Share-Based Payment (“SFAS No. 123 (R)”) that requires compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. This Statement replaces SFAS No. 123 and is effective as of the first interim or annual reporting period that begins after June 15, 2005. The cumulative effect of applying this Statement, if any, is not expected to be material.
In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151, Inventory Costs (“SFAS No. 151”) to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and spoilage. The Statement requires that abnormal expenses be recognized in the period in which they were incurred. The Statement is effective for inventory costs incurred during fiscal years beginning after June 15, 2005. SFAS No. 151 is not expected to effect our consolidated financial statements.
In December 2004, the FASB issued Statement of Financial Accounting Standards No. 153, Exchanges of Nonmonetary Assets (“SFAS No. 153”) to eliminate an exception from fair value measurement in APB Opinion No. 29, for nonmonetary exchanges of similar productive assets. SFAS No. 153 replaces this exception with a general exception from fair value measurement for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 is not expected to effect our consolidated financial statements.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Oil Prices
Our future success is dependent on the Company being able to transport and market its production either within Kazakhstan or preferably through export to international markets. Crude oil prices are subject to significant volatility in response to changes in supply, market uncertainty and a variety of other factors beyond our control. The majority of our sales of crude oil have been based on prevailing current local market prices at the time of sale. In
June 2004, Caspi Neft entered into a contract to sell approximately 157,500 barrels of crude oil to a local purchaser for approximately $11.61 per barrel. As of December 31, 2004, the purchaser has not taken delivery of approximately 39,260 barrels on this contract.
Interest Rate Risk
At December 31, 2003, Transmeridian had long-term debt outstanding of $23.7 million. The total amount bears interest at a fixed rate of 15% per annum.
Foreign Currency Risk
The Company’s functional currency is the U.S. dollar. The financial statements of the Company’s foreign subsidiaries are measured in U.S. dollars. Accordingly, transaction costs for the conversion to various currencies for foreign operations are recognized in the consolidated financial statements at the time of each transaction.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding the Company’s future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements, In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or the negative thereof or variations thereon or similar terminology. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. Important factors that could cause actual results to differ materially from the Company’s expectations (“cautionary statements”) include, but are not limited to, the Company’s assumptions about energy markets, production levels, reserve levels, operating results, competitive conditions, technology, the availability of capital resources, capital expenditure obligations, the supply and demand for oil, natural gas and other products or services, the price of oil, natural gas and other products or services, currency exchange rates, the weather, inflation, the availability of goods and services, drilling risks, future processing volumes and pipeline throughput, general economic conditions, either internationally or nationally or in the jurisdictions in which Transmeridian or its subsidiaries are doing business, legislative or regulatory changes, including changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations, the securities or capital markets and other factors disclosed under, “Item 2. Properties - Proved Reserves and Estimated Future Net Revenue,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosure About Market Risk” and elsewhere in this report. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. The Company assumes no duty to update or revise its forward-looking statements based on changes in internal estimates or expectations or otherwise.
Item 8.
Item 8. Financial Statements
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Certified Public Accountants
Consolidated Balance Sheets as of December 31, 2004 and 2003
Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003 and 2002
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2004, 2003 and 2003
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002
Notes to Consolidated Financial Statements
Report of Independent Certified Public Accountants
Board of Directors
Transmeridian Exploration, Inc. and Subsidiaries
We have audited the accompanying consolidated balance sheets of Transmeridian Exploration, Inc. and Subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, stockholders’ equity and cash flows for each of the years in the three year period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with standards of Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transmeridian Exploration Inc. and Subsidiaries at December 31, 2004 and 2003 and the consolidated results of their operations and cash flows for each of the years in the three year period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.
TRANSMERIDIAN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
The accompanying notes are an integral part of these financial statements.
TRANSMERIDIAN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
The accompanying notes are an integral part of these financial statements.
TRANSMERIDIAN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
The accompanying notes are an integral part of these financial statements.
TRANSMERIDIAN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
The accompanying notes are an integral part of these financial statements.
TRANSMERIDIAN EXPLORATION, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS - SUPPLEMENTAL INFORMATION
The accompanying notes are an integral part of these financial statements
TRANSMERIDIAN EXPLORATION, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Organization and Summary of Significant Accounting Policies
Transmeridian Exploration, Inc. (the “Company”) was incorporated in the State of Delaware in April 2000. We are engaged in the business of development and production of oil and gas properties. Our activities are primarily focused on the Caspian Sea region of the former Soviet Union and our primary oil and gas property is License 1557 and the related Exploration Contract for the development of the South Alibek Field (“South Alibek” or the “Field”) in the Republic of Kazakhstan. We conduct our operations in Kazakhstan through a 50% owned subsidiary, Caspi Neft TME (“Caspi Neft”). The Company was a development stage Company in prior periods.
Principles of Consolidation
Our consolidated financial statements are presented in United States Dollars, are prepared in accordance with generally accepted accounting principles in the United States and include all of our consolidated subsidiaries. Our most significant subsidiary is Caspi Neft, which holds License 1557 and the related Exploration Contract for the South Alibek Field. Except for the drilling rig, which is owned by the parent company, the assets and results of operations of Caspi Neft represent substantially all of our consolidated assets and operations.
During February 2004, Bramex Management, Inc., successor in interest to Kazstroiproekt, Ltd. (“Bramex”), exercised its option to acquire 50% of the common stock of Caspi Neft, the Company’s primary operating subsidiary in Kazakhstan and the entity which holds the license and exploration contract covering the South Alibek Field. Accordingly, as of December 31, 2004, the Company owns a 50% equity interest in this subsidiary. Based on the Company’s ability to exercise significant control over Caspi Neft, the Company believes that the most meaningful accounting treatment is to fully consolidate this entity, with the 50% share owned by Bramex reflected as a minority interest.
To exercise its option to acquire 50% of Caspi Neft, Bramex contributed $15.0 million in cash to Caspi Neft, the proceeds of which were used by Caspi Neft to retire debt. The difference between the $15.0 million of capital contributed to Caspi Neft and 50% of the book equity of Caspi Neft after such capital contribution represents an excess purchase price paid by Bramex of $6.0 million. This amount has been included in additional paid-in capital on the consolidated balance sheet.
Use of Estimates
To prepare financial statements in conformity with U.S. generally accepted accounting principles, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ materially from those estimates.
Cash and Cash Equivalents
The Company considers all highly liquid instruments with an original maturity of three months or less to be cash equivalents. Certain of the Company’s cash balances are maintained in foreign banks which are not covered by deposit insurance. The cash balances in the Company’s U.S. accounts may exceed federally insured limits.
Property and Equipment
The Company follows the “successful efforts” method of accounting for its costs of acquisition, exploration and development of oil and gas properties.
Oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis, and any impairment in value is recognized. Unproved properties with acquisition costs which are not individually significant are aggregated, and the portion of such costs
estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred.
Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. Such costs include seismic expenditures and other geological and geophysical costs. The costs of drilling exploratory wells are capitalized pending determination of whether they have discovered proved commercial reserves. If proved commercial reserves are not discovered, exploratory drilling costs are expensed. Costs to develop proved reserves are capitalized, including the costs of all development wells and related equipment used in the production of crude oil and natural gas.
Depreciation, depletion and amortization of the costs of proved oil and gas properties is computed using the unit-of-production method based upon estimated proved reserves. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the calculation of costs to be amortized. Under Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations”, which the Company was required to implement effective January 1, 2003, the discounted present value of future dismantlement, restoration and abandonment costs are recognized as a liability on the balance sheet with the offsetting amount reflected as part of the cost of the asset. The accretion of the discounted liability is recognized as an operating expense. Based on the operations completed as of December 31, 2004, the estimated future dismantlement, restoration and abandonment costs related to the South Alibek Field are estimated to be $186,000.
Periodically, or when circumstances indicate that an asset may be impaired, the Company compares expected undiscounted future cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on the Company’s estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the unamortized capitalized cost, the capitalized cost is reduced to fair value. Fair value is calculated by discounting the future cash flows at an appropriate risk-adjusted discount rate.
In December 2001, the Company purchased a drilling rig for use in the development of the South Alibek Field. The rig was placed in service in October 2002 and is being depreciated on the straight-line method over an estimated useful life of ten years. Depreciation of the rig, as well as depreciation of other support equipment used in exploration and development activities, is capitalized under the successful efforts method as part of the cost of oil and gas properties.
Transportation equipment and office and technology equipment are depreciated on a straight-line basis over the estimated useful lives of the assets, which range from three to five years.
Maintenance and repairs are charged to expense as incurred. Replacements and expenditures which improve or extend the life of assets are capitalized. When assets are sold, retired or otherwise disposed of, the applicable costs and accumulated depreciation and amortization are removed from the accounts, and the resulting gain or loss is recognized.
Capitalized Interest Costs
Certain interest costs have been capitalized as a part of the cost of unproved oil and gas properties, including property acquisition costs, wells in progress and related facilities. Additionally, interest was capitalized on the drilling rig while it was being readied for its intended use. Total interest costs capitalized during the years ended December 31, 2004, 2003 and 2002 totaled $4.5 million, $4.2 million and $1.3 million, respectively.
Income Taxes
The Company accounts for income taxes using the asset and liability method. The asset and liability method requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of (i) temporary differences between financial statement carrying amounts of assets and liabilities and the basis of these assets and liabilities for tax purposes and (ii) operating loss and tax credit carryforwards for tax purposes. Deferred
tax assets are reduced by a valuation allowance when management concludes that it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.
Debt Financing Costs
Debt financing costs are amortized over the term of the related financing facility.
Loss per Common Share
Basic net loss per common share is calculated by dividing the net loss attributable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted net loss per common share is computed based upon the weighted average number of common shares outstanding plus the common shares which would be issuable upon the conversion or exercise of all potentially dilutive securities. Diluted net loss per share equals basic net loss per share for the periods presented because the effects of potentially dilutive securities are antidilutive.
Net loss attributable to common stockholders is calculated as the net loss after deductions for cumulative preferred stock dividends, whether paid or accrued.
Revenue Recognition
The Company sells its Kazakhstan production in the domestic market on a contract basis. Revenue is recorded when the purchaser takes delivery of the oil. At the end of the period, oil that has been produced but not sold is recorded as inventory which is offset by deferred revenue. Such oil inventory and deferred revenues are valued at the price of the last oil sold.
Foreign Exchange Transactions
The Company’s functional currency is the U.S. dollar. The financial statements of the Company’s foreign subsidiaries are measured in U.S. dollars. Accordingly, transaction costs for the conversion to various currencies for foreign operations are recognized in the consolidated statements of operations at the time of each transaction.
Concentration of Credit Risk
The Company’s concentrations of credit risk consist principally of cash and accounts receivable. Our cash is deposited in high credit quality financial institutions, however amounts on deposit do exceed the maximum amount insured by the Federal Deposit Insurance Corporation.
Stock-Based Compensation
The Company accounts for employee stock-based compensation using the fair value method as prescribed in SFAS No. 123. Under this method, the Company records the fair value attributable to stock options granted, based on the Black-Scholes model, and amortizes that amount to expense over the service period required to vest the options.
Financial Instruments
The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying values of cash and cash equivalents, receivables and accounts payable approximate fair value. See Note 5 for discussion of long-term debt.
Reclassifications and Adjustments
Certain prior period amounts have been reclassified to conform to the presentation in the consolidated financial statements as of December 31, 2004.
Note 2 - Property and Equipment
Oil and Gas Properties
License 1557 (the “License”), covering the South Alibek Field, was granted by the Republic of Kazakhstan on April 29, 1999. The original License covered 3,396 acres. In March 2000, the Company acquired the License from an unrelated third-party for $4.0 million. During 2001, based on its technical review and analysis of the probable productive area of the Field, the Company applied to the Kazakhstan Ministry of Energy and Mineral Resources to expand the area covered by license area. In November 2001, the Company’s application was approved and the License was expanded to cover an area of 14,111 acres. Through Caspi Neft, the Company owns 50% of the working interest in the Field, subject to a 10% carried working interest.
The Exploration Contract associated with the License has a six-year initial term which expires in April 2005 and may be extended by mutual agreement for two additional two-year periods. The Company has been granted the first of these two-year extensions through April 2007. The Exploration Contract required capital expenditures during the initial period of approximately $18.0 million, which has now been satisfied. In connection with the recent two-year extension, the Company has committed to an additional work program of $30.6 million. During the primary term and in the first extension period, the Company can produce wells under a test program and pay a royalty of 2%. Any future extension periods would need to be renegotiated with the government and would require additional capital commitments and could potentially include other changes in terms. The Exploration Contract contains a provision which will allow the government to recover, from future revenues, approximately $4.9 million of exploration costs which were incurred prior to privatization. The Production Contract, when executed, will contain the final terms for recovery of these costs.
If the Company is successful in establishing commercial production from the Field, an application will be made for a Production Contract (the “Production Contract”). The Company has the exclusive right to negotiate this contract for the Field, and the government is required to conduct these negotiations under the Law of Petroleum. Such contracts are customarily awarded upon determination that the field is capable of commercial rates of production and that the applicant has complied with the other terms of its license and exploration contract. However, the Company is not guaranteed the right to a Production Contract. A Production Contract will typically require a bonus payment upon execution, the amount of which is subject to negotiation. If satisfactory terms cannot be negotiated, the Company has the right to produce and sell oil under the Law of Petroleum for the term of its existing Exploration Contract through April 2007 at a royalty rate of 2%. The royalty rate under production contracts is determined on a sliding scale based on annual production. The rates range from 2% to 6%.
Kornerstone Investment Group Ltd. (“Kornerstone”) was originally engaged by the founders of the Company to identify and assist in the acquisition of oil and gas properties in Kazakhstan and the Caspian Sea region. The agreement with Kornerstone provided for compensation to Kornerstone in the form of a 10% carried working interest. Under the terms of this carried interest, the Company is required to pay all acquisition, exploration, development and operating costs attributable to the 10% carried interest. The Company is also entitled to receive all revenues attributable to the 10% carried interest until the Company’s costs are recovered. Thereafter, Kornerstone will participate as a 10% working interest owner.
During 2002, the Company spent $33,484 to acquire leasehold interests for the development of two natural gas wells in South Texas. In July 2003 and in August 2004, the Company conducted operations on these properties. A downhole obstruction was encountered on both properties which prevented a successful test of the target formation and the property was abandoned. We recorded a charge to exploration expense of $66,844 and $118,893 for the years ended December 31, 2004 and 2003, respectively, for this unsuccessful completion attempt.
Drilling Rig and Equipment
In December 2001, the Company purchased a drilling rig for $5.3 million in total consideration, including a note payable for $3.3 million and $2.0 million in common stock, which is redeemable for cash at the option of the seller of the rig. See Notes 5 and 6 for further discussion of the terms of the note payable and redeemable common stock.
The rig was acquired for drilling operations in the South Alibek Field. At the time the Company purchased the drilling rig, it was in storage in South America. In early 2002, the Company arranged to have the rig transported to Kazakhstan via marine cargo vessel. In addition, the Company undertook various refurbishments and modifications to the rig to make it suitable for use in the Company’s operations. The Company contracted with a firm experienced in international drilling to operate the rig and provide expatriate drilling personnel. The rig began drilling operations in October 2002.
As more fully discussed in Note 9, there is a legal dispute between the Company and the holder of an apparent first lien on the drilling rig.
Note 3 - Other Assets
Other assets consist of the following:
See Note 1 (Debt Financing Costs) for discussion of debt financing costs and Note 7 (Common Stock Issued for Products and Services) for discussion of prepaid investment advisory contract.
Note 4 - Notes Payable to Related Parties
In a series of notes issued between June 2002 and November 2002, certain shareholders and related parties, including the Chief Executive Officer of the Company, loaned the Company $248,025. These notes bear interest at 17% and are due on September 30, 2005. As of December 31, 2004, the remaining balance was $50,000.
Note 5 - Long-Term Debt
Long-term debt consists of the following:
Future maturities of long-term debt at December 31, 2004, are as follows:
Management believes the fair value of debt at December 31, 2004 and 2003 approximates its book value.
$20 Million Credit Facility
In February 2002, Caspi Neft entered into a credit facility with a Kazakhstan bank (the “$20 Million Facility”). The $20 Million Facility provided for borrowings totaling $20.0 million through July 1, 2003 for development of the South Alibek Field and is secured by the Field, the stock of certain subsidiaries and the stock and other assets of Caspi Neft. The $20 Million Facility carries an interest rate of 15% and a fee of 0.5% on the unutilized portion of the commitment.
In connection with this financing, the Company granted an option to Bramex to acquire 50% of the common stock of Caspi Neft. In order to exercise the option, Bramex was required to (1) arrange an additional $30.0 million of financing for Caspi Neft at market rates and (2) make a cash contribution to Caspi Neft of $15.0 million, the proceeds of which would be used to repay part of the $20 Million Facility.
In February 2004, Bramex exercised its option and paid Caspi Neft $15.0 million, of which $11.7 million was applied to principal and $3.3 million was applied to accrued interest. Also in February 2004, the Company repaid Caspi Neft $3.0 million, which it had been required to pay under the original terms of the $20 Million Facility. Of such amount, $2.3 million was applied to principal and $744,690 was applied to accrued interest.
In February 2005, the Company renegotiated the terms of this facility which allowed for a six month deferral of all interest and principal payments or until July 15, 2005. See additional information on this matter in Note 11.
$30 Million Credit Facility
In June 2003, Caspi Neft entered into a new $30.0 million credit facility with the same Kazakhstan Bank (the “$30 Million Facility”). This facility provides for borrowings up to $30.0 million through May 31, 2005. The amount outstanding as of May 31, 2005 is scheduled to be repaid over 36 equal monthly installments beginning June 2005 through the final maturity date of May 31, 2008. The $30 Million Facility carries an interest rate of 15% and a commitment fee of 0.5% per annum on the unutilized portion. Interest accrued during the first 24 months is payable on May 31, 2005; thereafter, interest is payable monthly. Upon execution of the $30 Million Facility, Caspi Neft paid the bank an arrangement fee of $300,000, which has been capitalized as a deferred financing cost and will be amortized over the five-year life of the facility.
In February 2005, the Company renegotiated the terms of this facility which allowed for a six month deferral of all interest and principal payments until July 15, 2005. See additional information on this matter in Note 11.
Both credit facilities contain certain restrictive covenants, including restrictions on disposing of material assets, paying dividends and incurring additional indebtedness. The Company is required to provide audited financial statements of Caspi Neft to the bank within 90 days of the end of the fiscal year. In 2004, the Company did not meet this requirement, but such non-compliance has been waived by the bank. Both credit facilities are secured by substantially all of the assets of Caspi Neft, including the South Alibek License, and the stock of Caspi Neft. The Company’s wholly-owned British Virgin Islands subsidiary has also guaranteed the loan. Both facilities contain certain restrictive covenants, including restrictions on disposing of material assets, paying dividends and incurring additional indebtedness.
Note Payable Secured by Drilling Rig
In December 2001, the Company purchased a drilling rig for $5.3 million by the issuance, to the seller, of a note payable for $3.3 million and redeemable common stock of $2.0 million. In July 2003, the Company was notified by the holder of an apparent first lien on the rig (the “First Lien Holder”) that the seller was in default under its note payable obligation to the First Lien Holder. The Company was not informed of the existence of the First Lien Holder in the Asset Purchase Agreement related to the acquisition of the drilling rig. The note payable is now in dispute as a result of the seller’s apparent default to the First Lien Holder. The Company has held discussions with the First Lien Holder with the intent to resolve the seller’s default by making certain payments directly to the First Lien Holder. The Company made installment payments to the First Lien Holder totaling $688,400 during 2003. However, in December 2003 the Company ceased installment payments to the First Lien Holder as it had not been able to reach a settlement agreement with both the seller and the First Lien Holder. In August 2004, the Company
settled its legal dispute with the seller of the drilling rig. Pursuant to the terms of the Settlement and Release Agreement the remaining balance due on the note of $1.6 million, plus accrued interest of $550,000 has been cancelled and was replaced by assuming the obligation of the seller of the rig to the First Lien Holder. The Company has estimated this liability to be approximately $2.9 million, including accrued and unpaid interest. See further discussion of this matter in Notes 6 and 9.
Note 6 - Redeemable Common Stock
During December 2001, the Company purchased a drilling rig for use in its Kazakhstan operations. Part of the consideration for the purchase was 1.0 million shares of common stock. Under the terms of the purchase agreement, these shares were redeemable, at the option of the seller, for $2.00 per share, or $2.0 million in the aggregate, by the end of 2002. This obligation was renegotiated in December 2002, to require the redemption of the stock, at the option of the holder, on February 1, 2004. The revised agreement also provided for interest at 10% on the unpaid balance of the redemption amount.
Pursuant to the Settlement and Release Agreement executed in August 2004, the seller of the drilling rig has returned 200,000 shares to the Company, the remaining 800,000 shares have been retained by the seller of the drilling rig and such shares are no longer redeemable. As a result, the $2.0 million debt has been satisfied. See further discussion of this matter in Note 9.
Note 7 - Stockholders’ Equity
12.5% Convertible Preferred
In July 2003, the holders of all 3,000 shares of the outstanding 12.5% convertible preferred stock elected to convert their shares to common stock. The $300,158 stated value of the preferred stock plus accrued dividends totaling $57,256 were converted into 1,545,910 shares of common stock, in accordance with the terms of the preferred stock agreement. At the time of conversion, the convertible preferred stock was owned in equal amounts by the Chief Executive Officer of the Company and the operations manager of Caspi Neft.
Series A Convertible Preferred Stock
In November 2004, the Company sold 1,785.714 shares of its Series A Cumulative Convertible Preferred Stock (the “Series A Preferred”) in a private placement at a purchase price of $14,000 per share, and issued warrants to purchase up to 4,464,286 shares of the Company’s common stock at an exercise price equal to $1.55 per share. The aggregate proceeds, net of cash offering costs, for the Series A Preferred and the related warrants was $23.4 million. In addition, the Company issued warrants to purchase 1,674,107 shares of common stock at an exercise price equal to $1.55 per share for financial advisory service in connection with the private placement of Series A Preferred Stock. The estimated value of these warrants, $1.0 million has been reflected as a reduction of additional paid-in capital in the accompanying consolidated financial statements. Proceeds from the private placement of Series A Preferred Stock and Warrants will be used for general corporate purposes, including funding the Company’s development drilling program in the South Alibek field in Kazakhstan, and to pursue growth opportunities.
The Series A Preferred has a liquidation value of $14,000 per share and is convertible at the holders’ option into common stock at a conversion price of $1.40 per share, subject to adjustments in certain circumstances. The holders of the Series A Preferred will be entitled to a quarterly dividend payable at the rate of four and one-half percent (4.5%) per annum, payable in cash. The holders of the Series A Preferred Stock shall have full voting rights and powers (subject to a beneficial ownership cap as described below) equal to the voting rights and powers of the holders of common stock, voting together with the holders of common stock as one class. Each holder of the Series A Preferred shall not, unless it chooses in advance not to be governed by this limitation, convert the Series A Preferred or exercise the Warrant Shares into common stock such that the number of shares of common stock issued after the conversion would exceed, when aggregated with all other shares of common stock owned by such holder at such time, in excess of 4.999% of the then issued and outstanding shares of common stock outstanding of the Company. So long as at least twenty (20%) percent of the Series A Preferred remains outstanding, the Company shall not issue any new securities or financial instruments that rank pari pasu or senior to the Series A Preferred without the approval of at least 75% of the Series A Preferred outstanding. Beginning one year following the effective date of the registration statement to be filed for the underlying shares of common stock, the Series A Preferred shall automatically convert into the common stock of the Company at the conversion price of $1.40 per share (subject to adjustments), if the common stock trades at a price equal to or greater than $4.15 per share for
twenty (20) consecutive trading days, subject to the applicable ownership limitations. In the event a holder is prohibited from converting into common stock due to the 4.999% ownership limitation described above, the excess portion of the Series A Preferred shall remain outstanding, but shall cease to accrue a dividend.
Common Stock Reserved for Issuance
There are 200,000,000 common shares authorized by the Company’s Amended and Restated Certificate of Incorporation and 79,829,062, 70,673,207 and 59,147,129 common shares were issued and outstanding as of December 31, 2004, 2003 and 2002, respectively. These share totals exclude redeemable common stock. Shares of common stock reserved for issuance at December 31, 2004 are summarized as follows:
Common Stock Issued for Products and Services
Prior to 2004, the Company entered into several agreements to exchange common stock for products and services, including investment advisory services, financial consulting and other services and products related to the operations of the Company. The stock has been valued based on the fair market value of the stock at the time of the agreements or the value of the services rendered, whichever was more clearly evident. During the years ended December 31, 2003 and 2002, the Company issued 5.3 million and 4.1 million common shares, respectively, for products and services. Certain of the larger transactions which comprise these totals are discussed below.
In January 2003, 1.5 million shares, valued at $180,000, were issued to settle all remaining obligations in connection with the April 2002 resignation of the former Chairman of the Company, including obligations related to a consulting contract. During 2003, the Company issued a total of 2.25 million shares of common stock, valued at $323,000, in exchange for drill pipe for use in its operations. During 2003, the Company also issued 1.1 million shares to financial consultants, valued at $208,000, in exchange for work performed to improve financial reporting procedures and internal controls and other financial management services.
During 2002, 4.0 million shares were issued as compensation for investment advisory services, which was recorded as a prepaid expense of $735,000. The agreement covers a two year period ending in February 2004 and the prepaid amount is being amortized to expense over its term.
Retirement of Common Stock
On several occasions, the founders and major shareholders of the Company have contributed common shares back to the Company, which were then retired. Such share contributions were generally made to mitigate the dilutive effects of other share issuances by the Company. During the year ended December 31, 2002, the founders returned 6.7 million common shares. There were no such transactions for the years ended December 31, 2004 and 2003.
Capital Contributed by Stockholder
In December 2002, the Chief Executive Officer of the Company transferred, from his personal holdings, 150,000 shares of the Company’s common stock as compensation for a contract with an investor relations firm. The common stock was valued at $0.17 per share, or $25,500 in the aggregate, and has been recorded as contributed capital and a prepaid expense. The cost of the services are being charged to expense over the term of the contract.
Warrants
In connection with the issuance of $200,000 of convertible debentures in August 2002, the Company issued warrants to purchase 200,000 shares of the Company’s common stock at $0.42 per share. These warrants expire in August 2005. The value of the warrants, calculated in accordance with the Black-Scholes model, was $20,000 and are being recognized as additional interest expense over the two year term of the debentures.
During 2003, the Company issued warrants to purchase 300,000 shares of common stock in connection with investor relations services. Of such warrants, 150,000 carried an exercise price of $0.25 per share and were exercisable prior to December 5, 2004. The remaining 150,000 warrants carry an exercise price of $0.40 per share and are exercisable at any time prior to March 5, 2005. The value of the warrants, calculated in accordance with the Black-Scholes model, was $21,000 on the date of issuance. This amount is being amortized to expense over the term of the contract.
2001 Incentive Stock Option Plan
The Company has a 2001 Incentive Stock Option Plan (the “Plan”) under which options to purchase 5.0 million shares of common stock may be granted to officers, board members, key employees and consultants through December 31, 2010. Under the Plan, the exercise price of each option is equal to the fair market value of the Company’s common stock on the date of grant and all options granted have a term of five years. The vesting period is determined by the Board of Directors at the date of grant. As of December 31, 2004, options to purchase 1.74 million shares had been granted and 3.26 million options were available for future grants under the Plan.
No stock options were granted under the Plan prior to 2003. The following table reflects additional information about options granted under the Plan during the years ended December 31, 2004 and 2003.
The aggregate fair value of options granted during 2004 and 2003 was $567,900 and $243,575, respectively, which is being amortized to expense over the vesting period in accordance with SFAS No. 123. The fair value of each option grant was estimated on the date of grant using the Black-Scholes option pricing model with the following assumptions: risk-free interest rates of 5%; expected lives between 1.5 and 2.5 years; and volatility of the price of the underlying common stock of 45-75%. Of such aggregate fair value amount, $105,997 and $117,383 was charged to expense during the years ended December 31, 2004 and 2003, respectively.
The following table summarizes additional information about the Company’s stock options outstanding, and those which were exercisable, as of December 31, 2004:
2003 Stock Compensation Plan
In May 2003, the Company filed a Form S-8 registration statement with the Securities and Exchange Commission to register 2.5 million shares under its 2003 Stock Compensation Plan. Under the terms of the plan, such stock may be issued in lieu of cash to compensate officers, employees, directors and third-party consultants, all of whom must be individuals, for bona fide services rendered. During the years ended December 31, 2004 and 2003, 109,280 shares and 1,234,047 shares, respectively, were issued under the 2003 Stock Compensation Plan and 1,156,673 million shares were reserved for future issuance. For the year ended December 31, 2004 and 2003, $114,854 and $283,625, respectively, was charged to expense on the consolidated statement of operations.
Note 8 - Income Taxes
Income before income taxes is composed of the following:
A reconciliation of the federal statutory income tax (34%) amounts to the effective amounts is shown below:
The components of the Company’s deferred tax assets and liabilities were as follows:
As of December 31, 2004, the Company has estimated net operating loss carryforwards of $9.3 million in the U.S. and $16.5 million in Kazakhstan. The net operating loss carryforwards include the deduction of $10.0 million in
interest which has been capitalized for book purposes. If they are not utilized prior to these dates, the U.S. net operating losses will expire between 2020 and 2023, while the Kazakhstan net operating losses will expire in 2009 and 2011.
The Company has not recorded any deferred tax assets or income tax benefits from the net operating losses for the years ended December 31, 2004, 2003 and 2002. The Company has placed a 100% valuation allowance against the deferred tax asset because future realization of the net operating losses is not assured.
Note 9 - Commitments and Contingencies
Drilling Rig Dispute
In December 2001, the Company purchased a drilling rig for $5.3 million by the issuance, to the seller, of a note payable for $3.3 million and redeemable common stock of $2.0 million. Further discussion of this transaction can be found in Notes 4 and 5. In July 2003, the Company was notified by the holder of an apparent first lien on the drilling rig (the “First Lien Holder”) that the seller of the rig was in default under its note payable obligation to the First Lien Holder. The Company was not informed of the existence of the First Lien Holder in the Asset Purchase Agreement related to the acquisition of the drilling rig. The note payable and the redeemable common stock are now in dispute as a result of the Seller’s default to the First Lien Holder. During 2003, the Company held discussions with the First Lien Holder with the intent to resolve the Seller’s default by making certain payments directly to the First Lien Holder. During the year ended December 31, 2003, the Company made installment payments to the First Lien Holder totaling $688,400.
Discussions with the seller of the rig became increasing adversarial during late 2003 and on December 15, 2003, the seller filed suit in District Court, Harris County, Texas, 334th Judicial District relating to the Company’s alleged default under the note payable and redeemable common stock agreements with the seller. At this time, the Company ceased installment payments to the First Lien Holder as it had not been able to successfully negotiate a settlement agreement with both the seller and the First Lien Holder. On February 27, 2004, the First Lien Holder filed suit in United States District Court, Southern District of Texas, against the seller and named the Company and two of its affiliates as additional defendants. This action seeks payment of debts owed to the First Lien Holder by the seller related to the drilling rig.
In April 2004, the Company filed a Counterclaim and Third-Party Claim against the seller and certain of its affiliates. This action seeks recovery of repair costs incurred by the Company in connection with undisclosed latent defects in the drilling rig, recovery of payments made to the seller, including the redeemable common stock, and recovery of additional costs associated with the drilling rig.
In August 2004, the Company and the seller of the rig entered into a Settlement and Release Agreement. Pursuant to the terms of the Settlement and Release Agreement the remaining balance on the note of $1.6 million, plus accrued interest of $550,000 has been cancelled and was replaced by assuming the obligation of the seller of the rig to the First Lien Holder. The seller also was required to return 200,000 of the 1.0 million shares of redeemable common stock.. The Company has estimated this liability to be approximately $2.9 million including accrued and unpaid interest. The Company also agreed to pay $120,000 of the legal fees incurred by the seller of the rig in its lawsuit with the First Lien Holder.
Former Chief Financial Officer
In May 2003, Jim W. Tucker (the “Plaintiff”), the former Chief Financial Officer of the Company, filed suit in the 359th District Court, Montgomery County, Texas, against Transmeridian Exploration, Inc., in connection with his separation from service with the Company on January 3, 2003. The suit alleges breach of an oral employment agreement. The Company was never served with notice and had no knowledge of this suit. Counsel for the Plaintiff claimed they were unable to serve the Company’s registered agent with notice of this suit. Based on these representations, the Court awarded the Plaintiff a Default Judgment on November 25, 2003, in the amount of $922,275.61. The Company was notified of a Writ of Garnishment and Writ of Execution on March 29, 2004 and April 6, 2004, respectively.
On April 5, 2004, the Company filed a Petition for Bill of Review and a Motion to Vacate the Writ of Garnishment. A hearing was held on the Motion to Vacate the Writ of Garnishment on April 8, 2004. On May 11, 2004, the court granted the Motion to Vacate the Writ of Garnishment, but has not issued a ruling on the Petition for Bill of Review. In February 2005, the court granted the Motion to Vacate the Default Judgment and the Company withdrew it’s Petition for a Change of Venue. The case going forward will be reinstated and will begin as if the Company had just been served notice. The Company intends to vigorously contest this matter and pursue all legal remedies available to it.
International Commitments
The Company, through its subsidiary Caspi Neft, is subject to the terms of License 1557 and the related Exploration Contract covering 14,111 acres in the South Alibek field in Kazakhstan. In connection with the Exploration Contract, the Company has committed to spend approximately $18.0 million on development of the Field through 2005. As of December 31, 2004, the cumulative capital expenditures which are creditable to our obligation under the Contract have exceeded the minimum Contract commitment. The two year extension granted on July 8, 2004, the Company committed to spend approximately $30.6 million from 2005 to 2007.
Purchase commitments are made in the ordinary course of business in connection with ongoing operations in the South Alibek Field.
Our operations are subject to various levels of government controls and regulations in the United States and in the Republic of Kazakhstan. We attempt to comply with all legal requirements in the conduct of our operations and employ business practices which we consider to be prudent under the circumstances in which we operate. It is not possible for us to separately calculate the costs of compliance with environmental and other governmental regulations as such costs are an integral part of our operations.
In the Republic of Kazakhstan, legislation affecting the oil and gas industry is under constant review for amendment or expansion. Pursuant to such legislation, various governmental departments and agencies have issued extensive rules and regulations which affect the oil and gas industry, some of which carry substantial penalties for failure to comply. These laws and regulations can have a significant impact on the industry by increasing the cost of doing business and, consequentially, can adversely affect our profitability. Inasmuch as new legislation affecting the industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations.
Environmental
The Company, as an owner and operator of oil and gas properties, is subject to various federal, state, local and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may impose liability on the lessee under an oil and gas lease or concession for the cost of pollution clean-up resulting from operations and also may subject the lessee to liability for pollution damages.
Lease Commitments
The Company has operating leases for office facilities and certain equipment. Net rental expense under all operating leases and rental agreements was $546,639, $930,698 and $378,000 in 2004, 2003 and 2002, respectively. The Company leases office facilities in Houston and Kazakhstan under leases greater than one year. Future minimum lease commitments under long-term non-cancelable operating leases are as follows:
Note 10 - Business Segment Information
The Company’s business activities relate solely to oil and gas exploration and production. The primary emphasis since its formation in 2000 has been the development of the South Alibek Field. In 2002, the Company made an initial investment in U.S. properties. The drilling rig purchased in 2001 is used to support the Company’s development activities in Kazakhstan. At December 31, 2004, 2003 and 2002, substantially all of the Company’s assets were located in Kazakhstan. For each of the three years ended December 31, 2004, substantially all of the Company’s results of operations consisted of revenues, operating, general and administrative, and other costs associated with its operations in Kazakhstan.
For the year ended December 31, 2004, 91% of the oil sold from the South Alibek Field was purchased by three companies. For the year ended December 31, 2003 100% of the oil sold was purchased by a single company.
Note 11 - Subsequent Events
In January 2005, the Company, through its subsidiary Caspi Neft, entered into an agreement with the bank in Kazakhstan to defer all payments of principal and interest due on both credit facilities for six months or until July 15, 2005. At the expiration of the extension the total amount of principal and interest deferred, $13.7 million will become due and payable. In exchange for this deferral the Company has agreed to advance up to $10.0 million to Caspi Neft to fund 100% of anticipated capital requirements for the first six months of 2005.
Note 12 - Supplemental Oil and Gas Disclosures
Costs Incurred
Cost incurred in oil and gas property acquisition, exploration and development activities, whether expensed or capitalized, are reflected in the table below. This schedule does not include the costs of the drilling rig which was purchased and modified for use in the Company’s development activities in Kazakhstan. Costs incurred for the drilling rig were $444,000 and $741,000 in 2003 and 2002, respectively.
Capitalized Costs
The aggregate amount of capitalized costs related to oil and gas producing activities and the aggregate amount of the related accumulated depreciation, depletion and amortization (“DD&A”), including any accumulated valuation allowances, are reflected in the table below. These capitalized costs do not include the drilling rig which was purchased and modified for use in the Company’s development activities in Kazakhstan. Capitalized costs for the drilling rig were $6.5 million, $6.5 million and $6.0 million at December 31, 2004, 2003 and 2002, respectively.
Oil and Gas Reserve Information (Unaudited)
Basis of Presentation
Proved oil and gas reserve quantities are based on estimates prepared by Ryder Scott Company, independent petroleum engineers. The following reserve data represent estimates only and actual reserves may vary substantially from these estimates. All of the Company’s proved reserves were in Kazakhstan as of December 31, 2004, 2003 and 2002. The Company’s net quantities of proved developed and undeveloped reserves of crude oil and changes therein are reflected in the table below.
As of December 31, 2004, the Company owned a 50% working interest in the South Alibek Field, subject to government royalties and a 10% carried working interest after recovery of costs. The effect of this carried interest is reflected in the calculation of the Company’s net proved reserves and future net cash flows.
The Company is operating under an Exploration Contract with the government of Kazakhstan, which was extended in July 2004, for two years and ends in April 2007. We have the exclusive right to negotiate for a production contract for the Field, and the government is required to conduct these negotiations under the Law of Petroleum. However, we are not guaranteed the right to a Production Contract. Such contracts are customarily awarded upon determination that the field is capable of commercial rates of production and that the applicant has complied with the other terms of its license and Exploration Contract. A Production Contract will typically require a bonus payment upon execution, the amount of which is predetermined based upon the reserves approved by the State Committee of Reserves (“SRC”). If satisfactory terms cannot be negotiated, we have the right to produce and sell oil
under the Law of Petroleum for the term of our existing Exploration Contract through April 2007, or as extended, at a royalty rate of 2%. The royalty rate under production contracts is on a sliding scale, based on production. The royalty rate ranges from 2% to 6%. The Company’s oil and gas reserve data and future net cash flows have been prepared assuming a commercial production contract is obtained which will allow production for the expected 25 year term of the production contract.
The proved reserves as of December 31, 2004 represent the reserves that were estimated to be recovered from five wells, SA-1, SA-2, SA-4, SA-5, SA-17 and sixteen development offsets not yet drilled. Subsequent to December 31, 2002, the Company made a decision to redrill the A-29 as SA-17 as this is believed to be the most cost-effective way to recover these reserves and should allow the Company to achieve greater productivity and may potentially access additional reserves. As of December 31, 2004, the Company had two new wells, the SA-5 and SA-2, which were shut-in during a workover program. The Ryder Scott reserve estimate as of December 31, 2004 included these two wells and SA-1 and SA-17 as proved developed, and the SA-4 as undeveloped, which has reservoir damage that prevented placing the well on production during 2004 and sixteen additional offset locations. The SA-14, which was in progress at year end, is not included in proved reserves as of December 31, 2004.
Estimated Quantities of Net Proved Crude Oil Reserves
(Quantities in Barrels)
Standardized Measure of Discounted Future Net Cash Flows (Unaudited)
Basis of Presentation
The standardized measure data includes estimates of oil and gas reserve volumes and forecasts of future production rates over the reserve lives. Estimates of future production expenditures, including taxes and future development costs, are based on management’s best estimate of such costs assuming a continuation of current economic and operating conditions. No provision is included for depletion, depreciation and amortization of property acquisition costs or indirect costs. Income tax expense has been computed using expected future tax rates and giving effect to tax deductions and credits available, under current laws, and which relate to oil and gas producing activities. The sales prices used in the calculation are the year-end prices of crude oil, including condensate and natural gas liquids, which as of December 31, 2004, 2003 and 2002 were $20.09, $12.44 and $23.00 per barrel, respectively. The December 31, 2004 and 2003 prices were based on the last sales price received for December 2004 and 2003, respectively. The December 2002 price was based on North Sea Brent crude prices, less a discount for transportation and quality differentials. No value was assigned to natural gas reserves, as there is not currently an established market or pipeline facilities for gas sales. Changes in prices and cost levels, as well as the timing of future development costs, may cause actual results to vary significantly from the data presented. This information is not intended to represent a forecast or fair market value of the Company’s oil and gas assets, but does present a standardized disclosure of discounted future net cash flows that would result under the assumptions used. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves for 2004, 2003 and 2002 were as follows:
Standardized Measure of Discounted Future Net Cash Flows
(Amounts in Thousands)
The following table presents a reconciliation of changes in the standardized measure of discounted future net cash flows:
Changes in the Standardized Measure of Discounted Future Net Cash Flows
(Amounts in Thousands)
Note 13 - Supplemental Quarterly Information (Unaudited)
The following table reflects a summary of the unaudited interim results of operations for the quarterly periods in the years ended December 31, 2004 and 2003.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A.
Item 9A. Controls and Procedures
Corporate Disclosure Controls
Evaluation of Disclosure Controls and Procedures.
Based on our evaluation during the most recent quarter, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) were effective as of December 31, 2004 to ensure that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.
Changes in Internal Controls.
There have been no significant changes in our internal controls or in other factors that could significantly affect our disclosure controls and procedures subsequent to the date of the previously mentioned evaluation.
Management’s Report on Internal Control over Financial Reporting
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Beginning with this Form 10-K for the year ending December 31, 2004, the SEC’s rules require the Company to include in its annual report both a management report on internal control over financial reporting and a related attestation report of the Company’s registered public accounting firm on the effectiveness of the Company’s internal controls over financial reporting. However, the Company is permitted (pursuant to the SEC’s exemptive order dated November 30, 2004) to file the management’s report and the related attestation report of the Company’s auditor within forty five (45) days after the date on which this Form 10-K is due. Thus, the Company will be filing by an amendment to this Form 10-K, within the time period permitted by such exemptive order, management’s report and the related attestation report of the Company’s auditors.
Item 9B.
Item 9B. Other Information
On November 15, 2004 the Company filed a Current Report on Form 8-K to announce the sale of 1,785.714 shares of its Series A Cumulative Convertible Preferred Stock (the “Series A Preferred”) in a private placement at a purchase price of $14,000 per share, and issued warrants to purchase up to 4,464,286 shares of the Company’s common stock at an exercise price equal to $1.55 per share. The aggregate purchase price for the Series A Preferred and the related warrants was cash consideration of $25,000,000.
PART III
Item 10.
Item 10. Directors, Executive Officers, Promoters and Control Persons
The 2005 Proxy Statement is hereby incorporated by reference for the purpose of providing information about directors, executive officers, promoters and control persons.
Item 11.
Item 11. Executive Compensation
The 2005 Proxy Statement is hereby incorporated by reference for the purpose of providing information about executive compensation.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The 2005 Proxy Statement is hereby incorporated by reference for the purpose of providing information about security ownership of certain beneficial owners and management.
Item 13.
Item 13. Certain Relationships and Related Transactions
The 2005 Proxy Statement is hereby incorporated by reference for the purpose of providing information about certain relationships and related transactions.
Item 14.
Item 14. Principal Accountant Fees and Services
The 2005 Proxy Statement is hereby incorporated by reference for the purpose of providing information about principal accountant fees and services.
PART IV
Item 15.
Item 15. Exhibits, Financial Statements and Schedules and Reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Consolidated Financial Statements
Reference is made to the Index to Consolidated Financial Statements appearing in Item 8 of this report. Consolidated Financial Statement Schedules.
All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the consolidated statements or notes thereto.
2. Exhibits
Exhibit
Number
Description
Incorporation by Reference
3.1
Amended and Restated Certificate of Incorporation of the Company
Form SB-2 filed May 15, 2001
3.2
Bylaws of the Company
Form SB-2 filed May 15, 2001
4.1
Certificate of Designations of Series A Preferred Stock
Form 8-K filed November 15, 2004
10.1
License 1557 dated April 29, 1999 from the Republic of Kazakhstan for Oil and Gas Exploration of the South Alibek Field
Form SB-2 filed May 15, 2001
10.2
Exploration Contract dated April 29, 1999 covering the South Alibek Field
Form SB-2 filed May 15, 2001
10.3
Letter from the Kazakhstan Ministry of Energy
Form SB-2/A filed October 3, 2001
Exhibit
Number
Description
Incorporation by Reference
10.7
Addendums #1-5 to the $20 Million General Loan Agreement dated February 14, 2002 by and among Bank Turan-Alem, OJSC Caspi Neft TME, Transmeridian Exploration, Inc. (BVI) and Bramex Management, Inc., successor to Kazstroiproekt, Ltd.
Form 10-Q filed May 24, 2004
10.8
Shareholders Joint Operating Agreement dated February 14, 2002 by and among Transmeridian Exploration, Inc. (BVI) and Kazstroiproekt, Ltd.
Form 10-Q filed May 24, 2004
10.9
Addendums #1-5 to the Shareholders Joint Operating Agreement dated February 14, 2002 by and among Transmeridian Exploration, Inc. (BVI) and Bramex Management, Inc., successor to Kazstroiproekt, Ltd.
Form 10-Q filed May 24, 2004
10.10
Addendum #6 to the $20 Million General Loan Agreement dated February 14, 2002 by and among Bank Turan-Alem, OJSC Caspi Neft TME, Transmeridian Exploration, Inc. (BVI) and Bramex Management, Inc., successor to Kazstroiproekt, Ltd
Form 8-K filed February 17, 2005
10.11
Addendum #1 to the $30 Million General Loan Agreement dated June 2, 2003 by and among Bank Turan-Alem, OJSC Caspi Neft TME, Transmeridian Exploration, Inc. (BVI) and Bramex Management, Inc., successor to Kazstroiproekt, Ltd
Form 8-K filed February 17, 2005
10.12
Agreement by and among OJSC Caspi Neft TME, Bank Turan-Alem, Transmeridian exploration, Inc. (BVI), and Bramex Management, Inc., successor to Kazstroiproekt, Ltd
Form 8-K filed February 17, 2005
10.13
Preferred Stock and Warrant Purchase Agreement, dated November 12, 2004
Form 8-K filed November 15, 2004
10.14
Investor Rights Agreement
Form 8-K filed November 15, 2004
14.
Code of Ethics
Filed Herewith
21.1
List of Subsidiaries
Filed Herewith
31.1
Rule 13a-14(a) Certification of Chief Executive Officer
Filed Herewith
31.2
Rule 13a-14(a) Certification of Chief Financial Officer
Filed Herewith
32.1
Section 1350 Certification of Chief Executive Officer
Filed Herewith
32.2
Section 1350 Certification of Chief Financial Officer
Filed Herewith
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this annual report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.