Item 1. Business.
Transmeridian Exploration Incorporated is an independent energy company engaged in the business of acquiring, developing and producing oil and natural gas. Our activities are primarily focused on the Caspian Sea region of the former Soviet Union. We currently have projects in Kazakhstan and southern Russia. Our primary oil and gas property is the South Alibek Field (the “Field”) in the Republic of Kazakhstan, covered by License 1557 and the related exploration and production contracts. We conduct our operations in Kazakhstan through our wholly owned subsidiary, JSC Caspi Neft TME, a joint stock company organized under the laws of Kazakhstan. Our interest in both Caspi Neft and the Field is 100%. We were founded in 2000 as a Delaware corporation.
At December 31, 2007, our estimated total net proved reserves were 58,571,296 barrels of oil. All of these reserves are attributable to the Field. The present value of the estimated future net revenues from our proved reserves before income tax, discounted at 10% per annum (“PV-10”), based on prices being received as of December 31, 2007 and with oil pricing assumptions held constant throughout the estimated producing life of the reserves, was approximately $996,618,000. Our standardized measure of discounted future net cash flow as of December 31, 2007 was approximately $672,226,000. Please see Item 2, “Properties-Proved Reserves” for a reconciliation of PV-10 to our standardized measure of discounted future net cash flows and related discussion. The estimates of our proved reserves and the present value of the estimated future net revenues from our proved reserves have been prepared by Ryder Scott Company, independent petroleum engineers, in accordance with SEC guidelines.
We are in the early stages of developing the Field. As of December 31, 2007, 4,826,036 barrels of oil, or approximately 8% of the Field’s estimated net proved reserves, were classified as proved developed reserves. The balance of our estimated proved reserves are classified as proved undeveloped and will require the drilling of future wells to produce these reserves. As of July 1, 2007, we temporarily curtailed production in the Field pending resolution of issues relating to the flaring of associated natural gas produced from the Field and to allow for the initial commissioning of the central production facility and crude export pipeline. We resumed production on September 29, 2007. See Item 2, “Properties-Proved Reserves” below and Note 12 of the Notes to Consolidated Financial Statements for further information about our estimated proved reserves.
As announced on December 31, 2007, we entered into a definitive agreement to be acquired by Trans Meridian International, Inc. (“TMI”), a company formed by our Chairman and Chief Executive Officer. Pursuant to the agreement, TMI will commence a tender offer to purchase all of our outstanding shares of common stock for $3.00 per share, payable net to the seller in cash. The transaction is subject to satisfaction of various conditions precedent. As a result, no prediction can be made as to the timing of the commencement or completion of a tender offer. There can be no assurance that the transaction will be completed. As TMI has not met the financing condition in the definitive agreement within the prescribed time period, which we extended from January 31, 2008 to February 15, 2008, we may terminate the agreement at any time until the condition is satisfied. Our board of directors requested certain detailed information regarding TMI’s financing be provided by March 21, 2008 and, if our board of directors is not satisfied with such information, then we intend to terminate the agreement if the financing condition is not satisfied by March 31, 2008. To date, our board of directors is not satisfied with the information that has been provided.
We will continue to seek proposals from other parties with respect to a potential acquisition of our company. There can be no assurance, however, that these efforts will result in any agreement or transaction. Further, if we do enter into an agreement to be acquired by a party other than TMI, the value to be received by our common stockholders may be substantially less than the $3.00 per share contained in the current agreement with TMI. We are also in preliminary discussions with interested parties regarding an investment of capital into our company. Again, there can be no assurance that such discussions will result in any agreement or transaction, which may be substantially dilutive to our stockholders. Furthermore, any potential transaction would be subject to the
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negotiation and execution of a definitive agreement and other related agreements, as well as to regulatory and other customary approvals and conditions, which may include stockholder approval and other factors including financing, and there can be no assurance that we would be successful in consummating any such transaction.
Strategy
Our strategy is to increase our reserves, production and cash flows by (i) acquiring and developing oil and gas reserves, (ii) exploring for new reserves and (iii) optimizing production and value from our existing reserve base. We prefer to target medium-sized fields with proved or probable reserves, relatively low entry costs and significant upside reserve potential. Through the industry contacts, technical knowledge and experience of our management team, we believe we can successfully identify, obtain financing for and acquire additional properties in the Caspian Sea region.
Customers
In 2007, approximately 17% of our sales were into the local market to multiple purchasers, and 83% were export sales to multiple purchasers. Our oil sales revenues to date are derived solely from our operations in Kazakhstan. Beginning in August 2005, we began export sales by rail in the international markets. The rail terminal is accessed by truck from our field facilities. Pipeline shipments, which are the preferred and most cost effective method of accessing the export markets, began in March 2007, with first sales in April 2007. See Item 2, “Properties-Transportation and Marketing” below for further discussion of our current transportation and marketing arrangements and future plans. See also Item 1A, “Risk Factors-Our business and results of operations depend on our ability to transport our production to viable markets and on the price at which we can sell our production.”
Competition
The oil and gas industry is highly competitive, and our future business plans could be jeopardized by competition from larger and better-financed companies. We compete for reserve acquisitions, exploration leases, licenses, concessions and marketing agreements against companies with financial and other resources substantially greater than ours. Many of our competitors have more established positions and stronger governmental relationships, which may make it more difficult for us to compete effectively with them. In Kazakhstan, as of February 28, 2008, there were more than 100 fields (approximately 44% were under foreign ownership) and we estimate there are 45 non-Kazakh companies operating these fields. We believe Lukoil and Chinese National Petroleum Corporation (“CNPC”) are the largest foreign-owned petroleum companies operating in Kazakhstan, both of which have made recent significant reserve acquisitions. A high level of interest by non-Kazakh companies also exists in most of the other prospective oil and gas areas of the Caspian Sea region. See Item 1A, “Risk Factors-Competition in our industry is intense, and many of our competitors in the Kazakhstan region have greater financial and other resources than we do.”
Government Regulation
Our operations are subject to various levels of government controls and regulations in the United States and in Kazakhstan, including environmental controls and regulations. We attempt to comply with all legal requirements in the conduct of our operations and employ business practices which we consider to be prudent under the circumstances in which we operate. It is not possible for us to separately calculate the costs of compliance with these controls and regulations, as such costs are an integral part of our operations.
In Kazakhstan, legislation affecting the oil and gas industry is under constant review for amendment or expansion. Pursuant to such legislation, various governmental departments and agencies have issued extensive rules and regulations which affect the oil and gas industry, some of which carry substantial penalties for failure to comply. These laws and regulations can have a significant impact on the oil and gas industry by increasing the
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cost of doing business and, consequently can adversely affect our results of operations. Inasmuch as new legislation affecting the industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations.
Offices and Employees
Our corporate headquarters are in Houston, Texas, where we lease 16,580 square feet of office space. As of February 28, 2008, we had eight full-time employees in Houston. We also maintain three offices in Kazakhstan, the first an administrative office in Aktobe, Kazakhstan, where we lease approximately 9,020 square feet of office space and have 59 full-time employees, the second a small administrative office in Almaty, Kazakhstan, where we have seven employees and the third a small administrative office in Astana, Kazakhstan, where we have two employees. Our field operations for the Field have approximately 125 employees.
Availability of Reports
We make available free of charge on our internet website, www.tmei.com, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and any amendments to such reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after we electronically file such reports with, or furnish such reports to, the Securities and Exchange Commission (“SEC”). We also make available free of charge on our internet website other electronic filings that we make with the SEC as well as the Forms 3, 4 and 5 filed by our directors and executive officers with respect to their beneficial ownership of our common stock. These filings and reports are also available on the SEC’s website at www.sec.gov.
Item 1A.
Item 1A. Risk Factors.
Risks Relating to Our Business
We have a history of losses.
We have a history of losses. We incurred net losses of approximately $20.5 million, $53.2 million and $57.7 million for the years ended December 31, 2005, 2006 and 2007, respectively. Our results of operations in the future will depend on many factors, but largely on our ability to execute our exploration and development program and successfully market our current and future production. Our failure to achieve profitability in the future could adversely affect the trading price of our common stock and our ability to raise additional capital and, accordingly, our ability to continue our exploration and development program and grow our business.
Significant capital expenditures are required to execute our development program.
Our development and production activities, including our exploration and production contracts with the government of Kazakhstan, require us to make substantial capital expenditures. Historically, we have funded our capital expenditure requirements through a combination of cash flows from operations, borrowings under bank credit facilities, private placements of our common stock, preferred stock and debt securities and borrowings from our affiliates. Our cash flows from operations are subject to a number of variables, such as the level of production from our wells, the price of oil, and our success in developing and producing our reserves. If our revenues do not increase sufficiently as a result of any of these variables, or our access to capital becomes limited, we may not be able to meet our capital expenditure requirements, which could, in turn, materially and adversely affect our business, financial condition and results of operations.
We could fail to remain a going concern.
At December 31, 2007, we had a net working capital deficit of approximately $50.8 million and a stockholders’ deficit of approximately $14.8 million, and as described above, we have incurred operating losses
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since our inception. These matters raise substantial doubt about our ability to continue as a going concern and our independent registered public accounting firm has included an explanatory paragraph highlighting this concern in its report dated March 28, 2008. Our consolidated financial statements have been prepared on the basis of a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. If we became unable to continue as a going concern, we would have to liquidate our assets and we might receive significantly less than the values at which they are carried on our consolidated financial statements. Any shortfall in the proceeds from the liquidation of our assets would directly reduce the amounts, if any, that holders of our common stock would receive in liquidation.
To date, we have funded our development operations and working capital requirements through a combination of debt and equity proceeds and cash flow from operations. The inclusion of a going concern modification in the report of our independent registered public accounting firm may materially and adversely affect our stock price and our ability to raise new capital.
Our exploration and development activities may not result in economic quantities of oil and gas.
Our success is dependent on finding, developing and producing economic quantities of oil and gas. Our drilling operations may not be successful in finding, developing and producing economic quantities of oil and gas. In addition, we may not be able to sustain production from wells that initially produce.
The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. In addition, technological difficulties encountered in well completion or following the establishment of production may result in reduced or ceased production from a well.
Our efforts will be unprofitable if we drill dry holes or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled, or subject to higher costs as a result of a variety of factors, including:
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unexpected drilling conditions;
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high pressure or irregularities in geological formations;
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equipment failures or accidents;
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adverse weather conditions, such as winter snowstorms; and
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increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and qualified personnel.
Oil and gas operations are hazardous and may expose us to environmental liabilities.
We are subject to the operating risks normally associated with the exploration, development and production of oil and gas, including well blowouts, cratering and explosions, pipe failure, fires, geological formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Moreover, our drilling operations involve risks from high pressures in geological formations and from mechanical difficulties such as stuck pipe, collapsed casing and separated cable. If any of these risks occurs, we could sustain substantial losses as a result of:
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injury or loss of life;
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severe damage to or destruction of property, natural resources or equipment;
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pollution or other environmental damage;
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environmental clean-up responsibilities;
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regulatory investigations and penalties;
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delays in our operations or curtailment of our production; and
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suspension of our operations.
Because in many cases insurance coverage for these risks is either not available or is not available at premium levels that are economically feasible and justify its purchase, we maintain very limited insurance coverage. As a result, the insurance coverage we maintain may not fully compensate us, or compensate us at all, if we incur losses as a result of these risks. Moreover, in the future we may not be able to maintain all or even part of our current insurance coverage at premium levels that justify its purchase.
In addition, as an owner and operator of oil and gas properties, we are subject to various laws and regulations relating to the discharge of materials into, and the protection of, the environment. These laws and regulations may impose liability on us for the cost of environmental cleanup resulting from our operations and could further subject us to liability for environmental damages.
The actual quantities of, and future net revenues from, our proved reserves may prove to be lower than we have estimated.
The information included herein contains estimates of our proved reserves and the estimated future net revenues from our proved reserves. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise.
We engage Ryder Scott Company, independent petroleum engineers, to prepare our estimates of our proved reserves. During 2007, 2006 and 2005, their review covered 100% of the proved reserve value. Estimates of our proved reserves are made using available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data. As of December 31, 2007, there were downward revisions to previous estimates due to drilling results in 2007. There was no new drilling on perimeter undeveloped offset locations which might have resulted in adding new undeveloped reserves to the field. Drilling in 2007 was entirely infield development wells, which included infill wells and three KT2 horizontal wells. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from these estimates. Such variations may be significant and could materially affect the estimated quantities of, and future net revenues from, our proved reserves. In addition, we may adjust estimates of our proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties. In addition, our reserves are contained in carbonate reservoirs, and there is a larger uncertainty inherent in carbonate reservoirs as compared to sandstone reservoirs.
At December 31, 2007, approximately 92% of our estimated net proved reserves (by volume) were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations.
Our estimate of proved reserves at December 31, 2007 assumes that we will make significant capital expenditures to develop these proved reserves, including an estimated $29 million of capital expenditures in 2008. You should be aware that our estimates of such costs may not be accurate, development may not occur as scheduled and our results may not be as estimated.
Index to Financial Statements You should not assume that the present values referred to in the information incorporated by reference herein represent the current market value of our estimated reserves. In accordance with SEC requirements, the estimates of present values are based on prices and costs as of the date of the estimates. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimates. There are currently no economic markets for our natural gas production and our gas reserves have been given no value in the future net cash flow data incorporated by reference herein.
The timing of both the production from our properties and the expenses we incur from the development and production of our properties will affect both the timing of the actual future net cash flows from our proved reserves and their present value. In addition, the 10% discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate discount factor. The effective interest rate at various times and the risks associated with our business or the oil and gas industry in general will affect the accuracy of the 10% discount factor.
If oil and gas prices decrease or our exploration efforts are unsuccessful, we may be required to write down the capitalized cost of individual oil and gas properties.
A writedown of the capitalized cost of individual oil and gas properties could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved oil and gas reserves, increases in our estimates of development costs or nonproductive exploratory drilling results. A writedown could adversely affect the trading price of our common stock.
We use the successful efforts accounting method. All property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending the determination of whether proved reserves are discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed. All geological and geophysical costs on exploratory prospects are expensed as incurred.
The capitalized costs of our oil and gas properties, on a field-by-field basis, may exceed the estimated undiscounted future net cash flows of that field. If so, we record impairment charges to reduce the capitalized costs of each such field to our estimate of the field’s fair market value. Unproved properties are evaluated at the lower of cost or fair market value. These types of charges will reduce our earnings and stockholders’ equity.
We assess our properties for impairment periodically, based on future estimates of proved reserves, oil and gas prices, production rates and operating, development and reclamation costs based on operating budget forecasts. Once incurred, an impairment charge cannot be reversed at a later date even if we experience increases in the price of oil or gas, or both, or increases in the amount of our estimated proved reserves.
All of our operations are conducted in areas with inherent international and governmental risks.
We are subject to risks inherent in international operations, including adverse governmental actions, political risks, expropriation of assets and the risk of civil unrest or war. Our oil and gas properties are located in Kazakhstan, which until 1990 was part of the Soviet Union, and in Dagestan, which is an autonomous region within the Russian Federation. Kazakhstan and Russia retain many of the laws and customs from the former Soviet Union, but have developed and are continuing to develop their own legal, regulatory and financial systems. As the political and regulatory environment changes, we may face uncertainty about the interpretation of the agreements to which we are party and, in the event of dispute, we may have limited recourse within the legal and political system.
Index to Financial Statements We conduct all of our operations internationally and are subject to the Foreign Corrupt Practices Act and similar local laws. A determination that we violated this act or a similar local law may subject us to significant fines and other penalties and damage our reputation and, in turn, materially and adversely affect our business, financial condition and results of operations.
We conduct all of our operations internationally and, as a U.S. corporation, we are subject to the restrictions imposed by the U.S. Foreign Corrupt Practices Act (the “FCPA”). The FCPA generally prohibits U.S. companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business or otherwise obtaining favorable treatment. In particular, we may be held liable for actions taken by our local partners and representatives, even though such partners and representatives are foreign companies and/or non-U.S. citizens that are not subject to the FCPA.
Our policies mandate strict compliance with the FCPA and similar local laws prohibiting improper payments to government officials. Nonetheless, we cannot assure you that our policies will always protect us from reckless or criminal acts committed by our employees or our local partners and representatives that would violate the FCPA and/or a similar local law.
While our management does not have any knowledge of any violation of the FCPA or a similar local law and while we are committed to conducting our business in a legal and ethical manner, we cannot assure you that a yet-undiscovered violation of the FCPA or a similar local law has not occurred previously or that a violation of the FCPA or a similar local law will not occur in the future. Any determination that we have violated the FCPA or a similar local law could subject us to significant fines and other penalties and damage our reputation, which could, in turn, materially and adversely affect our business, financial condition and results of operations.
Our business and results of operations depend on our ability to transport our production to viable markets and on the price at which we can sell our production.
Our future success depends on our ability to transport and market our production either within Kazakhstan or through export to other markets. Our ability to sell our production and, in turn, our revenues could be materially and adversely affected by issues which are outside our control relating to the crude oil transportation infrastructure both within and outside Kazakhstan. The exportation of oil from Kazakhstan depends on access to transportation routes, primarily pipeline systems, which can have limitations.
Prior to March 2007, we exported our oil exclusively by rail. The rail terminal is accessed by truck from our field facilities. While pipeline shipments which began in March 2007 have resulted in higher realized prices for our crude oil than our previous marketing arrangements, unless we maintain access to pipelines to transfer our crude oil out of Kazakhstan, the prices at which we sell our crude oil may be significantly below world market prices.
Oil prices are volatile. A decline in prices could adversely affect our financial position, results of operations, cash flows, access to capital and ability to grow.
Our revenues, results of operations and future growth depend primarily upon the prices we receive for the oil we sell. Historically, the markets for oil have been volatile and they are likely to continue to be volatile. Wide fluctuations in worldwide oil prices may result from relatively minor changes in the supply of and demand for oil, market uncertainty and other factors that are beyond our control, including:
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worldwide supplies of oil and gas;
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weather conditions;
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the level of consumer demand;
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the price and availability of alternative fuels;
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governmental regulations and taxes;
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the ability of the members of the Organization of Petroleum Exporting Countries to agree to, and maintain, oil price and production controls;
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political instability or armed conflict in oil-producing regions; and
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the overall economic environment.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil price movements with any degree of certainty. Declines in oil prices would not only reduce our revenues, but could reduce the amount of oil that we can produce economically and, as a result, could have a material adverse effect on our business, financial condition and results of operations.
Our substantial indebtedness could adversely affect our financial condition, our access to capital and our ability to grow.
We have substantial debt, namely our Senior Secured Notes due 2010 (the “Senior Secured Notes”) and, in turn, substantial debt service requirements, which could limit our ability to execute our development program. In addition, our ability to make payments on our Senior Secured Notes and any future indebtedness we may incur depends on our ability to generate sufficient cash flow. We cannot assure you that:
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our business will generate sufficient cash flow from operations to service our indebtedness;
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future borrowings or proceeds from equity issuances will be available in an amount sufficient to enable us to pay our indebtedness on or before the maturity date of such indebtedness; or
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we will be able to refinance any of our indebtedness on commercially reasonable terms, if at all.
Factors beyond our control may affect our ability to service our indebtedness. These factors include those discussed in this “Risk Factors” section of this prospectus.
If, in the future, we cannot generate sufficient cash flow from our operations to meet our debt service obligations, we may need to refinance our debt, obtain additional financing, issue equity or sell assets, which we may not be able to do on commercially reasonable terms, if at all, and which we may be prohibited from doing under the terms of our indebtedness. Our inability to generate cash flow or obtain funding sufficient to satisfy our debt service obligations could materially and adversely affect our financial condition.
Covenants in the indenture governing our Senior Secured Notes and the certificates of designations governing our 15% Senior Redeemable Convertible Preferred Stock and our 20% Junior Redeemable Convertible Preferred Stock impose significant restrictions on us.
The indenture governing our Senior Secured Notes and the certificates of designations governing our 15% Senior Redeemable Convertible Preferred Stock (the “Senior Preferred Stock”) and our 20% Junior Redeemable Convertible Preferred Stock (the “Junior Preferred Stock”) contain a number of covenants imposing significant restrictions on us. The restrictions these covenants place on us include restrictions on our repurchase of, and payment of dividends on, our capital stock and limitations on our ability to incur additional indebtedness, make investments, engage in transactions with affiliates, sell assets and create liens on our assets. These restrictions may affect our ability to operate our business and may limit our ability to take advantage of potential business opportunities as they arise and, in turn, may materially and adversely affect our business, financial condition and results of operations.
Index to Financial Statements Competition in our industry is intense, and many of our competitors in the Kazakhstan region have greater financial and other resources than we do.
We operate in the highly competitive areas of oil exploration, development and production. We face intense competition from both major and other independent oil and natural gas companies and national oil companies in seeking to acquire:
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desirable producing properties or new leases for future exploration; and
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the equipment, expertise and personnel necessary to develop and operate our properties.
Many of our competitors have financial and other resources substantially greater than ours and, moreover, some of them are fully integrated oil companies with operations in the exploration, development, production, pipeline transportation, refining and marketing sectors of the oil and gas industry. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Many of our competitors have more established positions and stronger governmental relationships as well as direct support from their own governments, which may make it more difficult for us to compete effectively with them. As a U.S. company, we are also subject to various laws and regulations to which some of our competitors may not be subject, such as the FCPA, which could adversely affect our ability to compete with such parties in the Caspian Sea region.
In addition, our ability to develop and exploit our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, evaluate and select suitable properties and successfully consummate transactions, and there can be no assurance that we will be able to do so.
Compliance with governmental regulations could be costly and could adversely affect our competitiveness.
Our operations are subject to various levels of government controls and regulations in the United States, Kazakhstan and Russia, including environmental controls and regulations. It is not possible for us to separately calculate the costs of compliance with these controls and regulations, as such costs are an integral part of our operations.
In Kazakhstan and the Russian Federation, legislation affecting the oil and gas industry is under constant review for amendment or expansion. Pursuant to such legislation, various governmental departments and agencies have issued extensive rules and regulations which affect the oil and gas industry, some of which carry substantial penalties for failure to comply. These laws and regulations can have a significant impact on the oil and gas industry by increasing the cost of doing business and, consequentially, can adversely affect our results of operations. Inasmuch as new legislation affecting the industry is commonplace and existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations.
In 2006, new regulations on gas flaring became effective in Kazakhstan. The regulations stipulate the payment of fines for flaring gas in excess of permitted limits, even if the operator has a gas utilization plan approved by the government. Our gas utilization project approved in 2006 was scheduled for implementation by late 2007 but, the vendor initially contracted to construct the gas handling facilities was unable to perform. As of July 1, 2007, we temporarily curtailed production in the Field pending resolution of issues relating to the flaring of associated natural gas produced from the Field and to allow for the initial commissioning of the central production facility and crude export pipeline. We resumed production on September 29, 2007 after receiving an additional gas flaring permit until November 1, 2007. Subsequently, we received government approval for our modified gas utilization program and approval for additional gas flaring volumes until 2008. This protocol allows us to flare gas within these cumulative volumes without penalty until December 31, 2008, by which time our
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amended gas utilization program must be implemented. If we are not successful in implementing our program, we may incur substantial fines or be subject to production curtailments, either of which could have a material adverse effect on our business, financial condition or results of operations.
The loss of key personnel could have an adverse effect on our business.
Our success is dependent on the performance of our senior management and key technical personnel. The loss of our chief executive officer or other key employees could have a material and adverse effect on our business. We do not carry life insurance covering any of our senior management or key employees.
If we fail to maintain an effective system of internal control over our financial reporting, our ability to meet our reporting obligations and provide timely and accurate financial statements and, in turn, investor confidence in our financial reports and the trading price of our common stock could be adversely affected.
In connection with our management’s assessment of the effectiveness of our internal control over our financial reporting as of December 31, 2005, we concluded that we did not maintain effective internal control over our financial reporting due to a material weakness resulting from our lack of a sufficient number of accounting staff with experience in public company SEC reporting and technical expertise to enable us to maintain adequate controls over our financial accounting and reporting processes regarding our accounting for non-routine and non-systematic transactions. A material weakness is a control deficiency, or a combination of control deficiencies, that results in more than a remote likelihood that a material misstatement in our annual or interim financial statements would not be prevented or detected. This material weakness resulted in us recording certain accounting adjustments prior to the issuance of our consolidated financial statements for the fiscal year ended December 31, 2005.
However, despite the remedial measures that we implemented and our continuing efforts to improve our internal control over financial reporting, we may not be able to implement and maintain effective internal control over financial reporting in the future. Moreover, we have experienced from time to time deficiencies in our internal control over financial reporting that have not risen to the level of a material weakness. Although we have been able to remediate these deficiencies in the past, we cannot assure you that a material weakness will not exist in the future, as additional deficiencies in our internal control over financial reporting may be discovered which may rise to the level of a material weakness.
Any failure to remedy additional deficiencies in our internal control over our financial reporting that may be discovered in the future or to implement new or improved controls, or difficulties encountered in the implementation of such controls, could adversely affect our operating results, cause us to fail to meet our reporting obligations or result in material misstatements in our financial statements. Any such failure could, in turn, affect the future ability of our management to certify that our internal control over financial reporting is effective when it provides an assessment of our internal control over financial reporting and, moreover, affect the results of our independent registered public accounting firm’s attestation report regarding our management’s assessment. Inferior internal control over financial reporting could also subject us to the scrutiny of the SEC, the AMEX (on which our common stock is listed and traded) and other regulatory bodies and could cause investors to lose confidence in our reported financial information, which could have an adverse effect on the trading price of our common stock.
Risks Relating to Our Common Stock
We have not previously paid dividends on our common stock and do not anticipate doing so in the foreseeable future.
The indenture governing our Senior Secured Notes and the terms of our Senior Preferred Stock and Junior Preferred Stock restrict, and any indentures and other financing agreements that we may enter into in the future
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may further limit, our ability to pay cash dividends on our capital stock. Specifically, under the indenture governing our Senior Secured Notes and the certificates of designations governing our Senior Preferred Stock and Junior Preferred Stock, we may pay cash dividends and make other distributions on or in respect of our capital stock, including our common stock, only if certain covenants are met.
Furthermore, under Delaware law, dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then current or the preceding fiscal year. Our ability to pay cash dividends on our capital stock, including our common stock, would require the availability of adequate “surplus,” which is defined as the excess, if any, of our net assets (total assets less total liabilities) over our capital. However, even if adequate surplus is available to pay dividends on our common stock, we may not have sufficient cash to pay dividends on our common stock.
Moreover, we have not in the past paid any dividends on the shares of our common stock and do not anticipate that we will pay any dividends on our common stock in the foreseeable future. In addition to the above restrictions and limitations, our ability to pay dividends on our common stock is conditioned by the terms of our Senior Preferred Stock and our Junior Preferred Stock. Any future decision to pay a dividend on our common stock and the amount of any dividend paid, if permitted, will be made at the discretion of our board of directors.
We have outstanding, and may issue additional shares of, preferred stock that could adversely affect holders of shares of our common stock.
Our board of directors is authorized to issue additional classes or series of shares of our preferred stock without any action on the part of our stockholders, subject to the limitations set forth in the certificates of designations governing our Senior Preferred Stock and Junior Preferred Stock. Our board of directors also has the power, without stockholder approval and subject to the terms of our Senior Preferred Stock and Junior Preferred Stock, to set the terms of any such classes or series of shares of our preferred stock that may be issued, including voting rights, dividend rights, conversion features, preferences over shares of our common stock with respect to dividends or if we liquidate, dissolve or wind up our business and other terms. If we issue shares of our preferred stock in the future that have preference over shares of our common stock with respect to the payment of dividends or upon our liquidation, dissolution or winding up, or if we issue shares of our preferred stock with voting rights that dilute the voting power of shares of our common stock, the rights of holders of shares of our common stock or the trading price of shares of our common stock could be adversely affected. In addition, as of February 28, 2008, we had outstanding 462,219 shares of our Senior Preferred Stock and 674,471 shares of our Junior Preferred Stock, which may be converted into approximately 47,791,533 shares of our common stock and, as a result, dilute the value of our common stock to our then-current common stockholders and, moreover, adversely affect the trading price of our common stock.
The voting power of our common stock would be diluted upon the conversion of shares of our Senior Preferred Stock or Junior Preferred Stock into shares of our common stock, and such dilution would be increased by any downward adjustment in the conversion price of our Senior Preferred Stock or Junior Preferred Stock. The trading price of our common stock could be adversely affected by such actual or potential dilution.
Shares of our common stock issued upon the conversion of our Senior Preferred Stock or Junior Preferred Stock would dilute the voting power of the then-holders of shares of our common stock, and the trading price of our common stock could be adversely affected by such actual or potential dilution. Any downward adjustment of the conversion price of our Senior Preferred Stock or Junior Preferred Stock pursuant to the conversion price adjustment provisions set forth in the certificates of designations (as amended) governing our Senior Preferred Stock or Junior Preferred Stock would increase the number of shares of our common stock issuable upon the conversion of our Senior Preferred Stock or Junior Preferred Stock (as the case may be). Such additional number of shares of our common stock, if issued, would further dilute the voting power of the then-holders of shares of our common stock. Such additional actual or potential dilution could further adversely affect the trading price of
Index to Financial Statements
our common stock. For example, the conversion price of the Junior Preferred Stock was adjusted on November 1, 2007 from $2.25 to $1.90 per share because a change of control had not occurred, or a definitive agreement that would lead to a change of control had not been signed, as of October 31, 2007. As a result, each share of the Junior Preferred Stock was convertible into approximately 53 shares of common stock, whereas prior to such adjustment each share was convertible into approximately 44 shares of common stock.
The holders of shares of our Junior Preferred Stock and Senior Preferred Stock will be entitled, upon the satisfaction of certain conditions or the failure of certain events to occur, to representation on our board of directors including if a change of control has not occurred by June 15, 2008. The trading price of our common stock could be adversely affected by such actual or potential board representation rights.
Upon the receipt of written requests of holders of 66-2/3% of the then-aggregate outstanding shares of our Junior Preferred Stock and any parity stock having similar voting rights, shares of our Senior Preferred Stock and any then outstanding parity stock having similar voting rights will have the right to designate and elect at least one-half of our board of directors. In addition, if a change of control has not occurred, or an agreement has not been entered into that will result in a change of control, by June 15, 2008 (or any such agreement is later terminated without the consummation of the change of control transaction), we will be required to appoint an additional director or obtain the resignation of one director such that the number of directors to be appointed by our Junior Preferred Stock and any then-outstanding parity stock having similar voting rights would constitute a majority of the number of directors then comprising our board of directors. Moreover, if we fail to pay dividends on our Junior Preferred Stock or any then-outstanding parity stock having similar voting rights for two or more years or fail to redeem our Junior Preferred Stock at the holder’s election on March 15, 2012 or in connection with a change of control, the holders of our Junior Preferred Stock will have the right to elect two additional directors. If the dividends on the Senior Preferred Stock or any parity stock are in arrears and unpaid for two or more years, we fail to redeem the shares of our Senior Preferred Stock “put” to us for redemption pursuant to the holders’ redemption option or we fail to redeem the shares of our Senior Preferred Stock “put” to us for redemption in connection with a change of control, the holders of the Senior Preferred Stock, voting as a single class with the holders of any parity stock, will be entitled at our next regular or special meeting of stockholders to elect two additional directors to our board of directors. Such voting rights and the terms of the directors so elected will continue until such time as the dividend arrearage on the Senior Preferred Stock or any such other stock has been paid in full or we have paid the redemption price payable with respect to the shares of our Senior Preferred Stock “put” to us for redemption pursuant to the mandatory redemption provision. Such board representation rights, whether actually exercisable or exercised or merely potential, could also adversely affect the trading price of our common stock.
Our common stock has experienced, and may continue to experience, price volatility. The limited trading volume of our common stock may contribute to this price volatility.
The trading price of our common stock has been, and may continue to be, highly volatile. We believe the volatility of the trading price of our common stock is due to, among other things, the results of our drilling program, current expectations of our future financial performance, prices of oil and natural gas and the volatility of the stock market in general. Moreover, our common stock, which began trading on the AMEX in March 2005, does not have substantial trading volume. During the 12 months ended February 28, 2008, the average daily trading volume of our common stock as reported by the AMEX was approximately 1.1 million shares, which represented approximately 1.0% of our outstanding shares of common stock (as of February 28, 2008). As a result, relatively small trades of our common stock may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock.
Because of the limited trading volume of our common stock and the price volatility of our common stock, you may be unable to sell your shares of our common stock when you desire or at the price you desire. Moreover, the inability to sell your shares of our common stock in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.
Index to Financial Statements The trading price of our common stock could be adversely affected by sales and issuances of our common stock in the public markets.
As of February 28, 2008, our three largest stockholders (which include Mr. Lorrie T. Olivier, our chairman of the board and chief executive officer) beneficially owned approximately 25%, and our directors and executive officers together beneficially owned approximately 16%, of the then-outstanding shares of our common stock.
Sales of our common stock by these stockholders, or the perception that such sales might occur, could have a material adverse effect on the trading price of our common stock, or could impair our ability to obtain capital through future offerings of equity securities. In addition, the trading price of our common stock could decline as a result of issuances by us of additional shares of our common stock pursuant to our existing shelf registration statement or otherwise. The trading price of our common stock could also decline as the result of the perception that such issuances could occur.
Our directors and executive officers control a significant portion of our common stock and, as a result, may be able to significantly influence matters requiring the approval of our stockholders.
As of February 28, 2008, our directors and executive officers beneficially owned approximately 16% of the then-outstanding shares of our common stock, representing approximately 16% of the voting power of our common stock. As a result, our directors and executive officers, acting together, may be able to significantly influence matters requiring the approval of our stockholders.
Provisions in our amended and restated certificate of incorporation, the indenture governing our Senior Secured Notes and provisions under Delaware law may inhibit a takeover of our company.
Under our amended and restated certificate of incorporation, our board of directors is authorized to issue shares of our common or preferred stock without the approval of our stockholders. Issuance of these shares could make it more difficult to acquire our company without the approval of our board of directors as more shares would have to be acquired to gain control. In addition, upon a change of control of our company, each holder of our Senior Secured Notes may require us to purchase all or a portion of such holder’s notes at a purchase price equal to 101% of the aggregate principal amount of such holder’s notes, together with accrued and unpaid interest, if any, to the date of purchase. Also, Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock.
These provisions may deter hostile takeover attempts that could result in an acquisition of us that would have been financially beneficial to our stockholders.
Item 1B.
Item 1B. Unresolved Staff Comments.
None.
Item 2.
Item 2. Properties.
Petroleum Industry in Kazakhstan
Kazakhstan was one of 15 independent republics that comprised the former Soviet Union. After gaining independence in 1991, it joined with Russia and several other former Soviet republics in the Confederation of Independent States, a union of economic and political cooperation. Kazakhstan is an area of significant investment activity for the international oil and gas industry. Based upon publicly available information, as of February 28, 2008, Kazakhstan’s proved reserves rank it among the top 20 countries in the world, with over 30.0 billion barrels of proved reserves. Its current production is approximately 1.3 million barrels of oil per day, of which approximately 75% is exported.
Index to Financial Statements Regulation of the oil and gas industry in Kazakhstan has been codified in the Law of Petroleum, which sets out the conduct of the oil and gas industry and the roles of participants, both private and governmental. The industry is regulated in Kazakhstan by the Ministry of Energy and Mineral Resources (“MEMR”), which administers all contracts, licenses and investment programs.
The national oil company, Kazmunaigas, has been through several stages of consolidation. The Kazakhstan government has been in the process of merging the various regional governmental companies, which previously handled the extraction and transportation sectors of the industry, into one consolidated entity to eliminate redundant bureaucracy and provide for a more efficient management of the country’s natural resources. This consolidated entity maintains a direct ownership interest on behalf of the Kazakhstan government in most of the large oil field development projects in Kazakhstan as well as sole ownership and operation of many of the interconnecting oil and gas pipeline systems. However, governmental ownership or participation in exploration and development projects is not required, and the Kazakhstan government has no ownership interest in the Field.
Acquisition of the South Alibek Field
In May 1999, we engaged Kornerstone Investment Group, Ltd. (“Kornerstone”) to identify and assist in the acquisition of oil and gas properties in Kazakhstan and elsewhere in the Caspian Sea region. Since we had not received any significant funding at that time, the consulting agreement with Kornerstone provided that Kornerstone’s compensation would be in the form of a 10% carried working interest (which we reacquired from Kornerstone in December 2005) in all properties shown to us and in which we acquired an interest. The controlling shareholder of Kornerstone is a citizen of Kazakhstan who is involved in oil and gas production and other business endeavors. This individual is also currently employed on a part-time basis as a consultant and manager of Caspi Neft.
In early 2000, Kornerstone identified an opportunity in Kazakhstan known as the South Alibek License 1557, which covered what is now known as the Field. The adjacent Alibekmola Field had been discovered in 1980 by a regional exploration unit of the Soviet Ministry of Geology. A total of 31 wells had been drilled in the Alibekmola Field to delineate the oil bearing reservoirs and structure of the field. This delineation work continued following the breakup of the Soviet Union.
The Field was first identified by an Alibekmola Field delineation well, known as Alibekmola 29, drilled by a geological association of the Kazakhstan government. It was determined to be in a separate fault block adjacent to the Alibekmola Field, and in 1996 produced flowing oil from several intervals in the Middle-Lower Carboniferous (“KT2”) reservoirs during well testing. Due to lack of funds for further drilling, the area was offered for public tender and was awarded in the tender to a subsidiary of AIL Alpha Corporation, Ltd. License 1557 was granted to the subsidiary in April 1999. In March 2000, we acquired this subsidiary. Subsequent work by us resulted in this license area being designated as the Field.
License and Exploration Contract
License 1557 originally covered 3,396 acres when we acquired it in March 2000. During 2001, based on our technical review and analysis of the probable productive area of the Field, we applied to the MEMR to expand the area covered by the license. In November 2001, our application was approved and the area was expanded to an area of 14,111 acres.
The exploration contract associated with License 1557 had an original six-year term which expired in April 2005 and has been extended through April 2009. The exploration contract required capital expenditures during the initial period of approximately $18.0 million, which was satisfied and $30.5 million during the first two-year extension, which has also been satisfied. The latest two-year extension, which expires in April 2009, requires an additional commitment of $19.7 million, which has also been satisfied. During the primary and extended terms of the exploration contract, we can produce from wells under a test program and pay a 2% royalty to the government.
Index to Financial Statements Production Contract
Under our exploration contract and the Law of Petroleum, we held the exclusive right to negotiate and execute a production contract with the MEMR in the event of a commercial discovery in the area of our License 1557, and the government was required to conduct these negotiations. In December 2004, the State Committee on Reserves (“SCR”) approved commercial reserves for development and exploitation in the Field. On this basis, the MEMR granted us the exclusive right to execute a long-term production contract in June 2005.
In December 2006, the 25-year production contract governing the operations for the development of the Field was signed and became effective. The terms of the production contract establish the royalty and other payments due to the government in connection with our production of oil and gas. A bonus payment of $0.6 million was payable upon execution, based on the SCR reserves audit approving the commercial discovery, which defined the initial production area of 3,500 acres, or about 25% of the total area under license. If additional area is added on the basis of successful exploratory drilling, additional bonus payments would be assessed at a rate of 0.1% of the recoverable reserves added. The contract also allows the government to recover approximately $4.7 million of historical exploration costs incurred before privatization out of future revenues beginning in January 2007 at a rate of approximately $50,000 per quarter. The production contract provides a minimum seven-year work program commitment of $59.6 million for the continued development of the field.
The production contract is tax and royalty based. Under this financial arrangement, we will pay 100% of the development and operating costs and will be entitled to receive 100% of the revenues from the Field, subject to a royalty based on production from the Field and corporate income taxes. The royalty is a “sliding scale” based on annual production, ranging from 2% to 2.5% for production up to approximately 60,000 barrels per day. Corporate income taxes in Kazakhstan vary from 30% to 40%. Additionally, there is an excess profit tax of up to 30% on a sliding scale based on specified levels of internal rate of return ranging from 0% to 30%. These taxes can significantly affect the economics of the project. The production contract also states we should make available 20% of our production to local refineries at domestic market prices. We would expect these prices to be lower than prices we would receive in the export market. However, our transportation costs would likely be lower as well.
Overview of Regional Geology
The Field is located in a fairway of large fields in northwestern Kazakhstan within the prolific Pre-Caspian Basin. Within 20 miles of the Field are three giant producing fields with resources estimated between 500 million to 1 billion barrels each: the Kenkiyak and Zhanazhol Fields and the immediately adjacent Alibekmola Field. Production from the area’s carbonate reservoirs was first established in the 1950s, before the area was limited to military use and closed to oil and gas activity for 20 years. The Zhanazhol Field was the first to be discovered following the release of some of the area to exploration in the 1970s, and is now producing from the Upper-Middle Carboniferous (“KT1”) and KT2 reservoirs. The Alibekmola Field was discovered in the 1980s as additional areas were released, with production tests and reserves in both the KT1 and KT2 reservoirs. South Alibek was identified by the last well drilled during the delineation of Alibekmola following the breakup of the Soviet Union and independence of Kazakhstan. Development of these fields began after 2000.
The KT1 and KT2 reservoirs were deposited throughout the Middle and Late Carboniferous periods and into the Early Permian as a basin-wide and massive carbonate platform in the shallow waters of the ancient Uralian paleo-ocean on the southeastern boundary of the East European Plate. Regional closing of the ocean during the Permian period created a restricted sea that makes up the Pre-Caspian Basin. Prolific oil field trends are established in the southern half and northern margins of this Basin, with the Field located on the southeastern margin of the Basin on the Zharamys Uplift. The carbonate fields lying within the Pre-Caspian Basin, including the Devonian carbonates which were deposited earlier, account for approximately 75% of Kazakhstan’s oil reserves and production.
The tectonic history specific to the Zhanazhol, Alibekmola and South Alibek Fields area was extensively studied by Soviet scientists during the last four decades of the Soviet era. The carbonates were deposited on a
Index to Financial Statements
stable block removed from the influence of the Ural Mountain building processes to the northeast. Soviet geologists speculated the block was significantly closer to Tengiz at that time than it is today. The movement of the block to the northeast, of up to 450 miles, and the later folding and thrust faulting, began in the Middle Permian through the Late Triassic period. This faulting created the northeast-southwest trending enechalon structures that characterize these fields and provides the trap for oil and gas. The main defining thrust faults are generally oriented in a north-south direction, with a pattern of small stress transfer crossfaulting and fracturing that can enhance the fracture characteristics of the carbonate reservoirs. At present day, the platform trends southwest to northeast over an area approximately 125 miles long and 50 miles wide. It is bounded to the north by a major fault which separates this area from the Urals western fold and thrust belt.
Zhanazhol, Alibekmola and South Alibek Fields are ideally situated for favorable migration of hydrocarbons. The source for the oil and gas was provided by three source rocks, Devonian through Carboniferous in age, with the filling of the structures beginning at the end of the Permian with peaks of generation at the end of the Triassic and end of the Jurassic and with one source rock believed to be generating today.
Field Geology
The Field is immediately adjacent to the producing Alibekmola Field. Structurally it has three-way dip closure and is bounded and separated from Alibekmola on the east by a major north-south thrust fault. The Field is up to 1,000 feet lower than the Alibekmola Field and has a lower oil-water contact established from testing of the Alibekmola 29 well. The Zhanazhol Field lies 10 miles along the regional structural trend to the south. The East Zhagabulak Field is on the northwest corner of the South Alibek license area.
The KT1 and KT2 are the primary oil bearing reservoirs in all four fields, all of which have established production in the KT2. The KT1 is produced in the Zhanazhol Field. It has been found productive by testing in the Alibekmola and East Zhagabulak Fields, but has not been developed in those fields or in South Alibek. Evaluation of field data indicates reservoir properties of the KT1 and KT2 are very similar in the Alibekmola and South Alibek Fields. As of February 28, 2007, production from the Zhanazhol and Alibekmola fields is estimated to be approximately 70,000 and 20,000 barrels of oil per day, respectively.
Within the Field, the KT1 and KT2 reservoirs are porous and fractured carbonates of shallow marine-terriginous origin. The porosity is both primary and secondary, by diagenesis to dolomite and by fracturing. Reserve estimates were based only on log derived porosities because of the significantly larger volume of log data as compared to core data. Furthermore, the density and neutron logs were common to all wells and covered all zones of interest, with the porosities from both of these logs in good agreement and the corrected sonic log porosity also agreed with that calculated from the neutron and density logs. The log derived weighted average porosity of the KT2 is`7.4% for the known producing intervals as determined from production logging data and is 7.7% for all KT2 reservoirs. The log derived weighted average porosity for the KT1 is 9.5%. Core derived porosities averaged between 9-10% for both the KT1 and KT2, and is estimated as high as 15% in the KT2 and 20% in the KT1, although from relatively limited core data. Permeability estimates range between 0.01mD to 100mD from core and up to 300mD from log derived permeability.
The KT2 formation is a series of massive stacked platform carbonates totaling more than 3,000 feet thick, with the top at approximately 10,500 feet in depth. The KT2 is subdivided into five stratigraphically defined zones. The shallower KT1 formation is subdivided into three zones; the lowest zone is a series of massive stacked platform carbonates and the shallower zones are more characteristic of the back-stepping progradational nature of the carbonate platform. The top of the KT1 reservoir is at a depth of approximately 7,000 feet, and the formation is about 2,300 feet thick. The net pay thickness of the reservoirs found in the various zones of the KT1 and KT2 vary between 20 to 80 feet.
We have conducted an extensive evaluation of the information available for the Field and adjacent fields, including vintage and recent logging, core, pressure and testing data, and 2D and 3D seismic data to which we
Index to Financial Statements
have rights. Based on our evaluation, we believe that the oil-bearing reservoirs within the KT1 and KT2 may be present over a substantial part of the area covered by License 1557. We continue to update the technical appraisal of our Field and collect and evaluate reservoir and fluid data from our wells. Based on available regional data, the possibility exists that the prospective Devonian carbonates may underlie the KT2 at significantly greater depths, but this possibility remains undefined due to insufficient data at the present time.
Proved Reserves
Our estimated proved oil and gas reserve quantities were prepared by Ryder Scott Company, independent petroleum engineers. There are numerous uncertainties in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. These uncertainties are greater for properties which are undeveloped or have a limited production history, such as the Field. Our actual reserves, future rates of production and timing of development expenditures may vary substantially from these estimates. All of our proved reserves are in the Field. Our net quantities of proved developed and undeveloped reserves of crude oil and standardized measure of future net cash flows are reflected in the table below. See further information about the basis of presentation of these amounts in Note 12 of the Notes to Consolidated Financial Statements.
Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (a) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (b) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (c) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (d) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
As of December 31, 2007, we owned a 100% working interest in the Field, subject to Kazakhstan government royalties and a 3.5% net revenue interest in favor of a third party. The effect of these interest deductions is reflected in the calculation of our net proved reserves. Our proved reserves have been prepared under the assumption that our production contract will allow production for the expected 25-year term of the contract, as more fully discussed above under “Production Contract.” Based on forecast production volumes, the average royalty over the term of the production contract is expected to be 2.2% or less.
Index to Financial Statements Net Proved Crude Oil Reserves and Future Net Cash Flows
As of December 31, 2007
(Quantities in barrels)
(In thousands)
The difference between our PV-10 as of December 31, 2007 and our standardized measure of discounted future net cash flows as of December 31, 2007 is future income tax expense, discounted at 10%, of approximately $324,392,000. Our management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Our management also believes that PV-10 is relevant and useful for evaluating the relative monetary significance of our oil properties. Further, professional analysts and sophisticated investors may use the measure as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. Our management also uses PV-10 when assessing the potential return on investment related to our oil properties and in evaluating acquisition candidates. Because there are many unique factors that can impact an individual company when estimating the future income taxes to be paid, we believe the use of a pretax measure is valuable for evaluating us. PV-10 is not a measure of financial or operating performance under GAAP, and is not intended to represent the current market value of our estimated oil reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
The following table shows the number of developed and undeveloped acres in the Field as of the dates indicated:
The following table shows the number of productive and non-productive exploration and development wells drilled in the Field as of the dates indicated. Productive wells are producing wells and wells capable of production. SA-4, which was damaged during drilling, was converted to a KT2 pilot water injection well in 2007.
For additional information regarding our production from the Field, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” below.
Index to Financial Statements Transportation and Marketing
Oil producers in the area of the 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, the Port of Primorsk on the Baltic Sea and European locations such as Poland, Hungry, Lithuania, Germany and Finland. Pipeline capacity in the area has significantly increased with the opening of the Caspian Pipeline Consortium (“CPC”) pipeline, which ultimately will boost regional export capacity from 250,000 barrels of oil per day to an expected 690,000 barrels of oil per day. These pipelines transport oil to the Bestamak rail terminal and the oil refinery in Orsk via Kenkiyak Field, and can be used as a transfer point for oil exchanges to Western markets. Several rail loading oil terminals are also in the area and can be used for export sales. The nearest is the Zhem terminal, which lies approximately 30 miles from the Field near the city of Emba.
Two important connecting pipelines in the vicinity of the Field became operational in 2003. The Kenkiyak-Atyrau pipeline, with an initial capacity of 120,000 barrels of oil per day, originates at the Kenkiyak Field and provides a link to the CPC pipeline for nearby producing fields, including the Zhanazhol Field. The Alibekmola-Kenkiyak pipeline, operated by KazTransOil, provides direct pipeline access from the Alibekmola Field to the Kenkiyak-Atyrau pipeline for export to western markets via the CPC pipeline. The pump station at the Alibekmola Field is one mile from the site of our central production facilities.
Prior to March 2007, we exported our oil exclusively by rail from various terminals. The rail terminals are accessed by truck from our field facilities. Pipeline shipments, which are the preferred and most cost-effective method of accessing the export market, began in March 2007, with first sales in April 2007. The oil was shipped through the Alibekmola-Kenkiyak pipeline, using the treatment and export facilities of a third party. This arrangement alleviated the logistical problems we had experienced with the trucking/rail export shipping system. We commissioned our permanent central production facility, including a demercaptan unit, in 2007 which allows us to export directly into the pipeline without using third party facilities and incurring a processing fee. A portion of our oil continues to be sold in the local markets. See “Item 1. Business-Customers.”
Item 3.
Item 3. Legal Proceedings.
On July 18, 2007, Canam Services, Inc. (“Canam”), a supplier of tubing products, filed suit in the 151st Judicial District Court of Harris County, Texas asserting a cause of action against us based upon alleged breach of a guaranty agreement covering certain accounts payable of Caspi Neft. Canam seeks recovery from us in the amount of $1,986,633 plus fees and costs. We denied all of Canam’s material allegations and on September 5, 2007, filed an answer denying each and every material allegation contained in the Canam complaint. Subsequently, Canam reduced the recovery amount to $756,727 plus interest, fees and costs. We plan to vigorously defend this claim and have not recorded any reserve above our recorded accounts payable as of December 31, 2007.
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, 2007.
Index to Financial Statements Executive Officers of the Registrant
Certain information as of March 1, 2008 about our executive officers, including their position or office with the company, is set forth in the following table and accompanying text:
Name
Age
Position(s)
Lorrie T. Olivier
Chairman of the Board, President and Chief Executive Officer
Alan W. Halsey
Vice President and Chief Operating Officer
Earl W. McNiel
Vice President and Chief Financial Officer
Edward G. Brantley
Vice President and Chief Accounting Officer
Lorrie T. Olivier has served as President and Chief Executive Officer of the company since its inception in 2000. Mr. Olivier became Chairman of the Board in 2002. From 1991 to 2000, Mr. Olivier was employed by American International Petroleum Corporation (“AIPC”) as Vice President of Operations and President of AIPC Kazakhstan. He was the key executive in charge of developing AIPC’s interests in the Caspian Sea region. Mr. Olivier has devoted his entire career to international oil and gas exploration and production, also having served with Occidental Petroleum in South America and Shell Oil.
Alan W. Halsey joined the company in June 2006 as our Vice President and Chief Operating Officer. Prior to joining the company, Mr. Halsey managed private investments and was an executive with a family-owned construction materials enterprise from April 2002 to June 2006. Mr. Halsey has 31 years experience in the international oil and gas industry, including 28 years with units of Chevron and Texaco. From 2000 until 2002, he served as Chairman and Managing Director of the Texaco Upstream Companies in Nigeria. In this capacity, he was responsible for increasing production and executing Texaco’s shallow and deepwater development plans in Nigeria, where Texaco historically had been a shallow water producer. From 1998 to 2000, he was President of Texaco Petroleum Company, Colombia, and, from 1992 to 1998, he served as Deputy General Manager and then General Manager of Texaco’s Angola operations.
Earl W. McNiel joined the company in July 2004 as our Vice President and Chief Financial Officer. Mr. McNiel has 24 years of experience with public companies, primarily in the energy industry, and has broad experience with corporate finance, M&A and financial reporting. From 1994 until April 2004, Mr. McNiel was a senior officer with Pride International, Inc., an international oilfield services provider and drilling contractor, serving as Chief Financial Officer, Chief Accounting Officer and Vice President of Planning and Corporate Development. Before joining Pride, Mr. McNiel served as Chief Financial Officer of several publicly owned waste management companies and as Manager, Finance with ENSCO International, Inc., an international offshore drilling contractor. He began his career in public accounting with a major international accounting firm.
Edward G. Brantley joined the company in September 2005 as our Vice President and Chief Accounting Officer. Prior to joining the company, Mr. Brantley was employed by Pride International, Inc., an international oilfield services provider and drilling contractor, from 2000 to September 2005, where he served in several capacities, including Treasurer and Vice President and Chief Accounting Officer. Prior to joining Pride, Mr. Brantley was employed by Baker Hughes, Inc., an international oilfield services provider, for 11 years in various positions, including Controller of Baker Hughes Inteq.
Index to Financial Statements PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Common Stock
Our common stock, par value $0.0006 per share, began trading on the American Stock Exchange under the symbol “TMY” on March 21, 2005. There are 200,000,000 shares of common stock authorized by our amended and restated certificate of incorporation. As of February 28, 2008, we had 117,012,229 shares issued and outstanding, which were held by 215 record owners. The following table presents the high and low sales prices per share for our common stock, as reported by the American Stock Exchange.
Preferred Stock
We are authorized by our amended and restated certificate of incorporation to issue up to 5,000,000 shares of preferred stock, par value $0.0006 per share. As of February 28, 2008, we had 462,219 shares of our Senior Preferred Stock and 674,471 shares of our Junior Preferred Stock issued and outstanding. Additionally, as of February 28, 2008, no shares of our Series A Cumulative Convertible Preferred Stock (the “Series A Preferred Stock”) were issued and outstanding.
Dividend Policy on Common Stock
We have never paid cash dividends on our common stock. We intend to retain future earnings, if any, to meet our working capital requirements and to finance the future operations of our business. Therefore, we do not plan to declare or pay cash dividends to the holders of our common stock in the foreseeable future. Moreover, our ability to pay dividends on our common stock is restricted by the terms of our Senior Preferred Stock and Junior Preferred Stock and by the indenture governing our Senior Secured Notes.
Index to Financial Statements The stock performance graph below compares the cumulative total stockholder return on our common stock since January 1, 2003 with the cumulative total return on the S&P 500 Index and the American Stock Exchange Oil Index over the same period (assuming the investment of $100 in our common stock, the S&P 500 Index and the American Stock Exchange Oil Index on January 1, 2003 and reinvestment of all dividends).
Index to Financial Statements
Item 6.
Item 6. Selected Financial Data.
The following selected financial information should be read in conjunction with the consolidated financial statements and the notes thereto included under “Item 8. Financial Statements and Supplementary Data.”
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Overview
As announced on December 31, 2007, we entered into a definitive agreement to be acquired by Trans Meridian International, Inc. (“TMI”), a company formed by our Chairman and Chief Executive Officer. Pursuant to the agreement, TMI will commence a tender offer to purchase all of our outstanding shares of common stock for $3.00 per share, payable net to the seller in cash. The transaction is subject to satisfaction of various conditions precedent. As a result, no prediction can be made as to the timing of the commencement or completion of a tender offer. There can be no assurance that the transaction will be completed. As TMI has not met the financing condition in the definitive agreement within the prescribed time period, which we extended from January 31, 2008 to February 15, 2008, we may terminate the agreement at any time until the condition is satisfied. Our board of directors requested certain detailed information regarding TMI’s financing be provided by March 21, 2008 and, if our board of directors is not satisfied with such information, then we intend to terminate the agreement if the financing condition is not satisfied by March 31, 2008. To date, our board of directors is not satisfied with the information that has been provided.
We will continue to seek proposals from other parties with respect to a potential acquisition of our company. There can be no assurance, however, that these efforts will result in any agreement or transaction. Further, if we do enter into an agreement to be acquired by a party other than TMI, the value to be received by our common stockholders may be substantially less than the $3.00 per share contained in the current agreement with TMI. We
Index to Financial Statements
are also in preliminary discussions with interested parties regarding an investment of capital into our company. Again, there can be no assurance that such discussions will result in any agreement or transaction, which may be substantially dilutive to our stockholders. Furthermore, any potential transaction would be subject to the negotiation and execution of a definitive agreement and other related agreements, as well as to regulatory and other customary approvals and conditions, which may include stockholder approval and other factors including financing, and there can be no assurance that we would be successful in consummating any such transaction.
In the first six months of 2007, we completed four KT2 vertical wells and drilled and completed three KT2 horizontal wells, two of which were sidetracked from existing vertical cased wellbores. Of these wells, all horizontal wells and three of the four vertical wells are currently on production and one vertical well was producing and is temporarily shut in. Of these new wells, only one horizontal well has been acid stimulated, and the rest are awaiting acid stimulation, which has historically been required to optimize a newly completed well’s production. Confirmation of the strategy to continue development of the field with horizontal wells is not possible until these wells can be stimulated and the results evaluated. Further development drilling in 2007 was temporarily put on hold as a result of the review of strategic alternatives. Currently, we have 15 producing wells and five wells temporarily shut-in for work over.
As of July 1, 2007, we temporarily curtailed production in the Field pending resolution of issues relating to the flaring of associated natural gas produced from the Field and to allow for the initial commissioning of the central production facility and crude export pipeline. We resumed production on September 29, 2007 after receiving an additional gas flaring permit until November 1, 2007. Subsequently, we received government approval from the Working Committee of the MEMR for our modified gas utilization program to supply gas to a proprietary brick manufacturing facility currently under construction, and approval for additional gas flaring volumes of 7.074 million cubic meters for November and December 2007 and 23 million cubic meters until the end of 2008. This protocol allows us to flare gas within these cumulative volumes without penalty until December 31, 2008, by which time our amended gas utilization program must be implemented.
We signed a turnkey contract with a third party to construct and operate the brick manufacturing facility and construction is expected to be completed by June 2008. Produced oil is now being processed through our permanent central production facility, including a demercaptan unit. This allows us to utilize our pipeline connection to the regional export system, and has helped to increase the export sales price we receive for our crude oil production.
Results of Operations
The following table presents selected operational and financial data for the years ended December 31, 2007, 2006 and 2005, respectively.
Oil Production and Revenue
Oil production for the year ended December 31, 2007 increased 31,982 barrels (“bbls”), or 4%, over oil production for the year ended December 31, 2006 primarily due to the shut-in of the Field for substantially all of the third quarter of 2007. We had an average of 11.4 producing wells in 2007. Oil production for the year ended December 31, 2006 increased 343,617 barrels (“bbls”), or 86%, over the 400,425 bbls produced in the year ended December 31, 2005. The increase in 2006 was primarily the result of the continuing development of the Field as there were a total of eight wells in 2006 contributing to our total production as compared to five wells in 2005.
Index to Financial Statements For the year ended December 31, 2007, we sold (by physical delivery to the purchaser) 746,190 bbls at an average price of $47.93 per bbl. Although the total volume sold declined in 2007 as compared to 2006, the average sales price per bbl increased $13.39, or approximately 39%. We began export pipeline sales in April 2007, which resulted in receiving a higher price per bbl as compared to export sales via rail where the purchaser is responsible for transportation costs, thus resulting in a higher discount from quoted crude oil prices. Additionally, crude oil prices increased to record levels during 2007, briefly nearing the $100 per bbl mark. We sold 509,724 bbls in the export market, or approximately 68% of total bbls sold, at an average price of $58.21 per bbl during the year ended December 31, 2007. For the 236,465 bbls sold in the domestic market, we realized an average price per bbl of $25.79.
For the year ended December 31, 2006, we sold 752,342 bbls of crude oil at an average price of $34.54 per bbl, for net revenues of $24.7 million. This was a threefold increase in net revenue over 2005 and was driven by the increased volumes available for sale, a higher average sales price per barrel and the mix of export and domestic sales. Beginning in July 2005, we began selling oil in the export market where sales are based upon quoted international market prices for crude oil less applicable discounts for items such as quality, delivery destinations and transportation, in addition to the local domestic market. We continued to emphasize sales in the export market in 2006 and approximately 51%, or 383,016 bbls, of our total barrels sold were in the export market at an average sales price of $42.63 per bbl. We realized an average price of $26.15 per bbl for the 369,325 bbls sold in the domestic market in 2006. During the year ended December 31, 2005, we sold a total of 324,355 bbls of crude oil at an average price of $27.62 per bbl, for net revenues of $8.4 million.
We recognize revenue from the sale of oil when the purchaser takes delivery of the oil. As of December 31, 2007, we had 59,373 bbls of oil in inventory that had not yet been sold, as compared to 54,110 bbls as of December 31, 2006.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization (“DD&A”) of proved oil and gas properties is calculated under the units of production method, following the successful efforts method of accounting. For the year ended December 31, 2007, depletion of our proved oil and gas properties was $18.2 million, or $23.43 per bbl as compared to $14.4 million, or $19.37 per bbl for the year ended December 31, 2006. The increase was primarily due to the increase in capitalized costs for six wells as a result of the increased drilling program begun in late 2006 and an increase in fourth quarter depletion due to lower proved developed reserves per our 2007 reserve report used in depletion calculations. The increase was partially offset due to the Field being shut-in for a substantial portion of the third quarter and, accordingly, having very low production volumes upon which to calculate depletion.
Depletion for the year ended December 31, 2006 increased approximately $12.0 million from the depletion expense of $2.4 million or $6.10 per bbl recorded for the year ended December 31, 2005. The increase is primarily a result of the change in classification of reserves attributable to the KT1 reservoir to “proved undeveloped” from “proved developed behind pipe,”as of December 31, 2005 due to a change in the assumed field development plan. Under the revised plan, separate wells will be drilled to produce reserves in the KT1, rather than “dual-completing” wells to produce from both the KT2 and KT1 reservoirs simultaneously. As a result, beginning in the fourth quarter of 2005, reserves in the KT1 have been excluded from the total reserve base currently being depleted. Costs incurred that are to be depleted are now spread over a substantially smaller number of barrels of proved developed reserves until such time as additional wells are drilled and reserves, in either the KT1 or KT2 reservoirs, are classified as “proved developed.”
Non-oil and gas proved properties DD&A was $1.5 million for the year ended December 31, 2007 as compared to $506,000 and $940,000 for the years ended December 31, 2006 and 2005, respectively. The increase in depreciation expense in 2007 was due primarily to the increase in capitalized costs for our central production facility, the pipeline connection to the regional pipeline system, other Field related assets and the resumption of
Index to Financial Statements
depreciation of our drilling rig that was reclassified from held for sale in July 2007. The decrease in depreciation expense in 2006 as compared to 2005 is due primarily to no depreciation expense being recognized during the year with respect to our drilling rig that was classified as held for sale as of December 31, 2005. The decrease was partially offset by increased depreciation expense due to additions of transportation and other equipment in Kazakhstan.
Transportation Expense
For the year ended December 31, 2007, transportation and storage costs were $3.9 million, or $5.15 per bbl transported. For the year ended December 31, 2006, transportation and storage costs were $1.6 million, or $2.41 per bbl transported. The increase is due to the use of additional oil terminals for shipments of crude oil, increased storage costs due to not having pipeline access for crude shipments until late March 2007 and higher rates charged by the transportation companies. These additional terminals are located farther from the Field; however, some of the terminals have facilities for removing salts and other impurities from the crude. Additionally, with the beginning of export pipeline sales in April 2007, we incurred pipeline charges on the crude transported to the applicable ports of loading. While transportation costs have increased, we have realized higher sales prices per bbl for export pipeline sales.
For the year ended December 31, 2006, transportation expense increased approximately $1.3 million over the year ended December 31, 2005 primarily to having export sales throughout 2006 as compared to only six months in 2005. In July 2005, we began transporting oil to rail terminals for export sale and incurring transportation and storage costs. Prior to the beginning of export sales, all sales were made at the field with the customer being responsible for the transportation costs. For the year ended December 31, 2005, we incurred transportation and storage costs of $321,000, or $1.54 per bbl.
Impairment Loss
In the first quarter of 2006, we reached an agreement to dispose of our drilling rig. An impairment charge writing the value of the rig down to the estimated proceeds and reclassifying the net book value of the rig to a current asset held for sale was recorded as of December 31, 2005. The carrying value of the drilling rig and related equipment was reclassified in June 2007 when the agreement to dispose of the rig was not consummated and is being depreciated over its estimated remaining useful life.
Operating and Administrative Expense-Kazakhstan
For the year ended December 31, 2007, operating and administrative expenses were $16.7 million as compared to $15.7 million for the year ended December 31, 2006. Although production from the Field was shut-in essentially for the third quarter of 2007, expenses increased primarily as a result of a one-time charge for a tax on flaring excess volumes of gas for the first half of 2007, a penalty for non-delivery of crude to a third-party customer due to start-up issues with delivery of crude oil to the regional pipeline system in early 2007, a restocking charge for returned inventory items and expenses incurred with the possible sale of the Company. These increases in expenses were partially offset by decreases in workover costs, rental equipment expenses and field operating expenses related to the general decrease in development activities of the Field.
Operating and administrative expenses for the year ended December 31, 2006 increased $11.7 million from the $3.9 million recognized in 2005. The increase was primarily the result of the accelerated development program undertaken in 2006. As a result of the increased activity levels, production volumes in 2006 increased 86% over 2005 levels. For the years ended December 31, 2006 and 2005, we averaged 6.7 and 3.5 producing wells, respectively. Because of the increases in production and the acceleration of the development program, we added local personnel to both our operational and administrative staffs during 2006. We had 207 local employees in 2006 as compared to 148 in 2005. In 2006, we also incurred costs for additional contract personnel for such services as security, roustabouts and drivers due to the increased activity levels. Additionally, we added several
Index to Financial Statements
expatriate operational and marketing personnel beginning in the second quarter of 2006. Expatriate personnel costs for 2006 were approximately $1.7 million, including $1.2 million for stock-based compensation expense. We did not have any expatriate personnel costs in 2005. In 2006, we incurred approximately $3.2 million related to workovers for wells as compared to $603,000 in 2005.
General and Administrative Expense-Houston
General and administrative expenses in Houston were $13.7 million for the year ended December 31, 2007, as compared to $10.0 million for the year ended December 31, 2006. The increase in 2007 was primarily due to increased legal expenses related to the possible sale of the Company, increased stock-based compensation related to employee stock options and restricted stock grants and stock registration penalties. These increases were partially offset by decreases in bonus expense and regulatory compliance costs.
For the year ended December 31, 2006, general and administrative expenses in Houston were $10.0 million, as compared to $6.6 million for the year ended December 31, 2005. The increases in 2006 related to the addition of new corporate staff, including our Chief Operating Officer, General Counsel, Chief Accounting Officer and Assistant Controller, since the end of the second quarter of 2005, increased costs for stock-based compensation expense related to employee stock options and restricted stock grants and increased costs related to regulatory compliance, including compliance with the Sarbanes-Oxley Act of 2002.
Interest Expense
Interest expense, net of the capitalized portion, for the years ended December 31, 2007, 2006 and 2005 was $37.7 million, $36.9 million and $10.3 million, respectively. Capitalized interest for the years ended December 31, 2007, 2006 and 2005 was $5.6 million, $4.1 million and $2.5 million, respectively. The increase in interest expense in 2007 from 2006 is due to the increased debt level outstanding in 2007 and increases in the amortization of both the capitalized financing costs and the debt discount related to our Senior Secured Notes. The increase in interest expense for 2006 over 2005 is due to the significantly increased average debt levels between the periods, as well as the recognition in interest expense of the amortization of both the capitalized financing costs, approximately $2.7 million, that were incurred and the debt discount, approximately $5.5 million, that was recorded in December 2005 and May 2006 in connection with our initial private placement of Senior Secured Notes and the subsequent issuance of additional Senior Secured Notes, respectively. Approximately $4.4 million of debt discount amortization related to short-term borrowings was recognized in 2005.
Liquidity and Capital Resources
The accompanying consolidated financial statements have been prepared on the basis of accounting principles applicable to a going concern, which contemplate the realization of assets and satisfaction of liabilities in the normal course of business. As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $50.8 million and a stockholders’ deficit of approximately $14.8 million at December 31, 2007. These matters raise substantial doubt about our ability to continue as a going concern. Included in our current liabilities is approximately $17.8 million in returns obligations incurred in connection with the issuance of our Junior Preferred Stock. However, the returns are not payable until the earlier of (i) the occurrence of a change of control of the Company (as defined in the certificate of designations, as amended, governing the Junior Preferred Stock) or (ii) June 18, 2008; provided, however, that if the returns become due and payable on June 18, 2008 in the absence of a change of control transaction, we may elect to satisfy our payment obligations by delivery of shares of our common stock valued at 97% of the common stock’s market value at such time. Additionally, there is approximately $5.2 million in preferred stock dividends that can be satisfied by the issuance of additional preferred shares or common shares subject to certain restrictions. We have incurred operating losses since our inception. To date, we have funded our development operations and working capital requirements through a combination of debt and equity proceeds and cash flow from operations.
Index to Financial Statements For the years ended December 31, 2007, 2006 and 2005, our capital expenditures were $86.2 million, $107.3 million and $20.7 million, respectively. Our primary sources of funding have been our private placement of Senior Secured Notes and warrants to purchase shares of common stock in December 2005, the additional debt and shares of our common stock issued in May 2006, private placements of common stock, preferred stock and warrants and the exercise of previously issued warrants. The total capitalized cost attributable to the Field as of December 31, 2007 was $427.6 million, which includes $22.2 million of capitalized interest.
In November 2004, we sold 1,785.714 shares of our Series A Preferred Stock in a private placement at a purchase price of $14,000 per share, and issued warrants to purchase up to 4,464,286 shares of our common stock at an exercise price equal to $1.55 per share. The aggregate purchase price for the Series A Preferred Stock and the related warrants was cash consideration of $25.0 million. Proceeds from the private placement of Series A Preferred Stock and warrants were used for general corporate purposes, including funding our development drilling program in the Field and to pursue growth opportunities.
During the years ended December 31, 2007, 2006 and 2005, 594.804 shares, 952.91 shares and 238 shares of Series A Preferred Stock were converted into 5,948,039, 9,529,100 and 2,380,000 shares of our common stock, respectively. As of December 31, 2007, there were no outstanding shares of Series A Preferred Stock.
In May 2005, we borrowed an aggregate of $2,240,000 from a group of individuals pursuant to unsecured, short-term notes. The notes bore interest at 15% per annum and were repaid along with accrued interest in July and September 2005. In July 2005, we borrowed $1,000,000 from an individual pursuant to an unsecured short-term note, which bore interest at 15% per annum and was repaid with accrued interest in December 2005. In connection with these borrowings, we issued detachable warrants to purchase 420,000 shares of common stock at exercise prices ranging from $2.00 to $2.12 per share. The warrants have a three-year term.
In August 2005, we issued convertible promissory notes (the “Convertible Notes”) in an aggregate principal amount of $22,500,000. The Convertible Notes, which bore interest at 10% per annum, were repaid in full, including accrued interest, in December 2005. We used a portion of the proceeds from our private placement of our Senior Secured Notes and warrants in December 2005 discussed below to repay the Convertible Notes.
In October 2005, one of our wholly-owned subsidiaries, Transmeridian Exploration Inc. (“TEI”), entered into a share sale and purchase agreement with Seeria Alliance Ltd. to purchase 100% of the authorized and issued shares of Bramex, the owner of 50% of Caspi Neft. In December 2005, the transaction was completed and TEI now owns, directly or indirectly, 100% of Caspi Neft. The total purchase price was $168 million, of which approximately $44 million was used to repay the bank credit facilities of Caspi Neft.
In December 2005, we and TEI issued in a private placement 250,000 Units, consisting of in the aggregate (i) $250 million principal amount of Senior Secured Notes of the Issuer (the “Existing Notes”) and (ii) warrants to purchase approximately 17.3 million shares of our common stock. The Units were issued and sold for a purchase price of $1,000 per Unit. Each Unit consists of $1,000 principal amount of Notes and 69.054 warrants to purchase an equal number of shares of our common stock. The Existing Notes, which will mature on December 15, 2010, bear interest at the rate of 12% per annum. Interest on the Existing Notes is payable quarterly on March 15, June 15, September 15 and December 15 of each year and at maturity. The fair value of the warrants of approximately $26,816,000 was recorded as a discount to the face amount of the Existing Notes and will be amortized to interest expense over the life of the Existing Notes. We used the proceeds from the offering of the Units of $237.4 million, after expenses, to fund the acquisition of Bramex and to retire the existing bank credit facility indebtedness of Caspi Neft, to repay $22.5 million of the Convertible Notes and to pre-fund the first year of interest payments on the Existing Notes of $30 million.
In May 2006, we and TEI issued in a private placement $40 million principal amount of additional Senior Secured Notes (the “Additional Notes”) and (ii) 1,818,182 shares (approximately $10 million) of our common stock (the “Shares”). The Additional Notes were issued and sold for an issue price of 97% of the principal
Index to Financial Statements
amount thereof plus accrued interest from March 15, 2006, and the Shares were issued and sold at an issue price of $5.50 per share. The discount was recorded as a reduction of the face amount of the Additional Notes and will be amortized to interest expense over the life of the Additional Notes.
The Additional Notes have terms and conditions identical to, and are fungible for trading and other purposes with, the Existing Notes. The Additional Notes, like the Existing Notes, are fully and unconditionally guaranteed by us and all of our material subsidiaries and are governed by the terms of the Indenture, dated as of December 12, 2005, as supplemented by the First Supplemental Indenture, dated as of December 22, 2005, and the Second Supplemental Indenture, dated as of May 24, 2006, by and among TEI, us, the subsidiary guarantors of the Existing Notes and the Additional Notes and the trustee. The Indenture contains provisions that limit the our ability to enter into transactions with affiliates; pay dividends or make other restricted payments; incur debt; create, incur or assume liens; sell assets; and consolidate, merge or transfer all or substantially all of our assets. We are required to offer to repurchase the Senior Secured Notes in connection with certain specified change of control events. The Senior Secured Notes are subject to redemption, in whole or in part, at our option at any time on or after December 15, 2008 at redemption prices starting at 106% of the principal amount redeemed and declining to 100% by June 15, 2010. Prior to December 15, 2008, we may redeem up to 35% of the Senior Secured Notes with proceeds of certain equity offerings at a specified redemption price.
In July 2006, pursuant to the registration rights agreements entered into in connection with the issuance of the Existing Notes and the Additional Notes, we completed an exchange offer of $290 million aggregate principal amount of TEI’s senior secured notes due 2010 registered under the Securities Act of 1933, as amended (the “Securities Act”) for all of the outstanding Existing Notes and Additional Notes.
The net proceeds, after expenses, from the private placements of the Existing Notes and Additional Notes were used to fund the acquisitions of Bramex and the 10% carried working interest in the Field previously held by Kornerstone, to retire the existing bank credit facility indebtedness of Caspi Neft, to repay other existing indebtedness and related accrued interest, to pre-fund the first year of interest payments on the Existing Notes and Additional Notes, to fund the exploration and development of the Field and for working capital and general corporate purposes.
In December 2006, we sold (i) 370,000 shares of our Senior Preferred Stock in a private offering and (ii) 70,000 shares of Senior Preferred Stock in a concurrent private placement. Purchasers of the Senior Preferred Stock in the private placement included our Chairman of the Board and Chief Executive Officer and our Vice President and Chief Financial Officer, who purchased 41,000 and 5,000 shares, respectively.
The Senior Preferred Stock, which has a liquidation preference of $100 per share, pays cumulative quarterly dividends at an initial rate of 15% per annum, subject to adjustment, payable at our option in additional shares of the Senior Preferred Stock, shares of our common stock (subject to the satisfaction of certain conditions) or cash (if allowed by the terms of our then-existing debt instruments). Dividends are payable on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2007. The sale of the Senior Preferred Stock generated total net proceeds to us of approximately $41.2 million, net of commissions of approximately $2.4 million and other offering expenses totaling approximately $0.4 million. Additionally, we issued to the initial purchaser in the offering 110,000 warrants to purchase shares of our common stock as part of the total fees of the offering. The fair value of the warrants of approximately $304,000 was recorded as a discount to the face amount of the Senior Preferred Stock and is being amortized over the life of the Senior Preferred Stock.
Our Senior Preferred Stock was originally convertible into approximately 9.8 million shares of common stock based on an initial conversion price of $4.50 per share of common stock. Effective July 1, 2007, there was a one-time test for adjustment of the conversion price and the dividend rate based upon the achievement of a specified average production rate prior to June 30, 2007 or a specified average trading price threshold of our common stock during the 15 trading days immediately following June 30, 2007. Neither of these thresholds was
Index to Financial Statements
met and the conversion price and the dividend rate of the Senior Preferred Stock were adjusted to $3.90 per share and 18%, respectively, effective July 1, 2007. Additionally, the conversion price of the Senior Preferred Stock is subject to adjustment pursuant to customary anti-dilution provisions. As a result of the issuance of the Junior Preferred Stock, our March 2007 private placement of warrants to purchase shares of our common stock referenced in Note 7 below and our April 2007 private placement of shares of our common stock also referenced in Note 7 below, the conversion price of the Senior Preferred Stock was further adjusted to $3.76 per share. Additionally, the conversion price of the Senior Preferred Stock may also be adjusted upon the occurrence of a change of control meeting certain conditions. However, in no event will the conversion price of the Senior Preferred Stock be reduced to less than $3.23 per share (subject to adjustment), which was the closing price of our common stock on the American Stock Exchange on the pricing date of the private offering and the concurrent private placement. As of December 31, 2007, there were 442,334 shares of Senior Preferred Stock outstanding that were convertible into approximately 11.8 million shares of common stock.
The Senior Preferred Stock ranks senior to our common stock with respect to dividend rights and rights upon our liquidation, winding-up or dissolution. There are also restrictive covenants related to our ability to incur indebtedness, make certain payments or investments and create restrictions on us and our subsidiaries’ ability to pay dividends, and further provides for preemptive rights in favor of the holders of the Senior Preferred Stock with respect to certain securities offerings that we may make in the future.
On March 15, 2007, we issued in a private placement warrants to purchase an aggregate 8,500,000 shares of our common stock. The warrants were issued for total cash consideration of $8 million. Each warrant, when exercised, will entitle the holder to receive one share of our common stock at an exercise price of $2.00 per share. The warrant agreement governing the warrants provides for customary anti-dilution adjustments with respect to the exercise price and the number of shares of our common stock issuable upon exercise of the warrants. The warrants are exercisable at any time, at the holder’s option, and will expire on March 15, 2012.
Also in March 2007, the holders of warrants to purchase an aggregate of 4,773,214 shares of our common stock notified us of their intention to exercise such warrants upon the expiration of the specified notice period for waiver of beneficial ownership limitations under the warrants. In connection with such notification, the holders paid in advance the exercise price of the warrants, resulting in proceeds to us of $10,359,000. The common shares underlying these warrants were issued in May 2007.
Similarly, in April 2007, the holders of warrants to purchase an aggregate of 1,700,000 shares of our common stock notified us of their intention to exercise such warrants upon the expiration of the specified notice period for waiver of beneficial ownership limitations under the warrants. In connection with such notification, the holders paid in advance the exercise price of the warrants, resulting in proceeds to us of $2,635,000. The common shares underlying these warrants were issued in June 2007. Also in April 2007, the holders of warrants to purchase an aggregate of 193,750 shares of our common stock exercised their warrants resulting in proceeds to us of $400,250.
In April 2007, we sold to various investors an aggregate of 1,655,000 shares of our common stock for cash in a private placement exempt from registration under the Securities Act. In connection therewith, we granted to the purchasers certain registration rights with respect to the resale or other disposition of such shares of common stock. The sales price of the shares sold was $2.70 per share, and the aggregate gross proceeds to us from the sale were approximately $4.5 million.
In May 2007, the holders of warrants to purchase an aggregate of 2,000,000 shares of our common stock notified us of their intention to exercise such warrants upon the expiration of the specified notice period for waiver of beneficial ownership limitations under the warrants. In connection with such notification, the holders paid in advance $1.99 of the $2.00 exercise price of the warrants, resulting in proceeds to us of $3,980,000. As of December 31, 2007, the remainder of the exercise price of the warrants had not been paid and the shares of
Index to Financial Statements
common stock issuable in connection with the pending warrant exercises had not been issued. Accordingly, a liability in the amount of $3,980,000 has been reflected in accrued liabilities at December 31, 2007, representing our obligation to issue the related shares of common stock upon receipt of the remaining exercise price.
In June 2007, we sold 550,000 shares of our Junior Preferred Stock. The Junior Preferred Stock, which has a liquidation preference of $100 per share, will pay cumulative quarterly dividends at a rate of 20% per annum, payable at our option in additional shares of the Junior Preferred Stock, shares of our common stock (subject to the satisfaction of certain conditions) or cash (if allowed by the terms of our then-existing debt instruments or the Senior Preferred Stock.
The Junior Preferred Stock was originally convertible into approximately 24.4 million shares of common stock, based on an initial conversion price of $2.25 per share. The conversion price was adjusted on November 1, 2007 to $1.90 per share because a change of control had not occurred, or a definitive agreement that would lead to a change of control had not been signed as of October 31, 2007. As of December 31, 2007, there were 640,656 shares of Junior Preferred Stock outstanding that were convertible into approximately 33.7 million shares of common stock.
In connection with the issuance of our Junior Preferred Stock, each purchaser of Junior Preferred Stock that was also a beneficial owner of our Senior Preferred Stock had the right to exchange shares of Senior Preferred Stock, on a one-for-one basis, for Junior Preferred Stock, up to the number equal to 40% of the aggregate number of shares of Junior Preferred Stock purchased by such holder. Purchasers of Junior Preferred Stock elected to convert 56,000 shares of Senior Preferred Stock into Junior Preferred Stock in August 2007 and the carrying value of the shares of Senior Preferred Stock was transferred to the Junior Preferred Stock.
The Junior Preferred Stock will be redeemable, at the option of the holder, on March 15, 2012 at the liquidation preference plus all accumulated and unpaid dividends, or upon a change of control at an amount equal to the sum of 125% of the liquidation preference plus all accumulated and unpaid dividends.
We will have the option, upon a change of control, to redeem the Junior Preferred Stock at an amount equal to the sum of 125% of the then-effective conversion price multiplied by the number of shares of common stock into which such shares of Junior Preferred Stock are then convertible plus all accrued and unpaid dividends. After June 15, 2008, the Junior Preferred Stock is redeemable, at our option, at a premium to the liquidation preference, provided the closing price of our common stock equals or exceeds 125% of the then-effective conversion price for at least 20 trading days in any 30 consecutive trading day period.
Of the 550,000 shares of the Junior Preferred Stock issued in the private placement, 100,000 shares of the Junior Preferred Stock were issued, and the net proceeds of approximately $9.5 million were paid to us, in connection with the first closing on June 18, 2007. In connection with the second closing on June 26, 2007, the remaining 450,000 shares of the Junior Preferred Stock were issued and net proceeds of approximately $11.0 million from the sale of 120,000 of the shares were paid to us. The remaining 330,000 shares of the Junior Preferred Stock and the gross proceeds of $33.0 million therefrom were originally placed in escrow pending stockholder approval of the issuance or potential issuance of shares of our common stock under the terms of the Junior Preferred Stock that, in the aggregate, equal or exceed 20% of the currently outstanding shares of our common stock. The escrow proceeds, net of transaction fees, were released to us in July 2007 upon our receipt of the requisite proxies evidencing such stockholder approval.
The private placement of Junior Preferred Stock generated total net proceeds of approximately $51.5 million, after transaction fees and expenses. We used the net proceeds from the first closing to satisfy our interest payment obligation with respect to our Senior Secured Notes and for working capital and general corporate purposes. The net proceeds from the second closing, including the escrowed proceeds were used for working capital and general corporate purposes, including funding ongoing development costs. Additionally, we issued 550,000 warrants to the underwriter to purchase shares of our common stock at $2.25 per share as part of the total fees of the offering. We also agreed to pay a transaction preferred return, in cash, equal to 10% of an
Index to Financial Statements
investors’ commitment and a preferred return, in cash, equal to 25% of the aggregate liquidation preference of the shares of Junior Preferred Stock purchased. However, the returns are not payable until the earlier of (i) the occurrence of a change of control of the Company (as defined in the certificate of designations, as amended, governing the Junior Preferred Stock) or (ii) June 18, 2008; provided, however, that if the returns become due and payable on June 18, 2008 in the absence of a change of control transaction, we may elect to satisfy our payment obligations by delivery of shares of our common stock valued at 97% of the common stock’s market value at such time. Additionally, if a change of control has not occurred by December 31, 2007, the return balances are increased, until paid, at the rate of 10% per annum. The fair value of the warrants of approximately $412,500, along with other offering expenses, and the value of the returns of approximately $17.8 million, were recorded as a discount to the face value of the Junior Preferred Stock and will be accreted over the life of the Junior Preferred Stock. The returns obligations have been recognized as current liabilities as of December 31, 2007.
In addition, holders of the Junior Preferred Stock have the right, upon written request of the holders of two-thirds of the outstanding shares of the Junior Preferred Stock, to designate individuals to constitute one-half of the membership of our board of directors and to require us to take the necessary action to effect such change in our board composition. In addition, we will be obligated to cause the directors designated by the holders of two-thirds of the outstanding shares of the Junior Preferred Stock to constitute a majority of the directors then serving on the special committee of the board of directors overseeing the ongoing process with respect to a possible sale of the Company or the Field. If a change of control of the Company has not occurred, or a definitive agreement that would lead to a change of control of the Company has not been signed, by June 15, 2008, we may be obligated to further alter the composition of the board of directors such that individuals designated by the holders of two-thirds of the outstanding shares of the Junior Preferred Stock would then constitute a majority of the members of the board of directors.
The holders of the Junior Preferred Stock are also entitled to certain registration rights with respect to the Junior Preferred Stock, pursuant to which we are obligated to file and cause to become effective a shelf registration statement covering the resale of the Junior Preferred Stock, the shares of our common stock into which the Junior Preferred Stock is convertible, and the shares of the Junior Preferred Stock and shares of our common stock issued in payment of the quarterly dividends. Pursuant to, and in timely compliance with, our filing obligation, we filed such shelf registration statement on July 18, 2007. On October 16, 2007, a registration default occurred because our Registration Statement on Form S-3 was not declared effective by the SEC within 120 days after the execution date of the Amended and Restated Commitment Letter by and among us and the purchasers of the Junior Preferred Stock. This default is continuing; as a result, while such registration default continues, the holders of the Junior Preferred Stock are entitled to receive additional dividends at a rate of 1.00% per annum for the first 30 days of such registration default and at a rate of 1.50% per annum thereafter, in addition to the dividends otherwise accruing until the default is cured.
As announced on December 31, 2007, we entered into a definitive agreement to be acquired by TMI, a company formed by our Chairman and Chief Executive Officer. Pursuant to the agreement, TMI will commence a tender offer to purchase all of our outstanding shares of common stock for $3.00 per share, payable net to the seller in cash. The transaction is subject to execution of a definitive agreement and satisfaction of various conditions precedent. As a result, no prediction can be made as to the timing of the commencement or completion of a tender offer. There can be no assurance that the transaction will be completed. As TMI has not met the financing condition in the definitive agreement within the prescribed time period, which we extended from January 31, 2008 to February 15, 2008, we may terminate the agreement at any time until the condition is satisfied. Our board of directors requested certain detailed information regarding TMI’s financing be provided by March 21, 2008 and, if our board of directors is not satisfied with such information, then we intend to terminate the agreement if the financing condition is not satisfied by March 31, 2008. To date, our board of directors is not satisfied with the information that has been provided.
We will continue to seek proposals from other parties with respect to a potential acquisition of our company. There can be no assurance, however, that these efforts will result in any agreement or transaction. Further, if we
Index to Financial Statements
do enter into an agreement to be acquired by a party other than TMI, the value to be received by our common stockholders may be substantially less than the $3.00 per share contained in the current agreement with TMI. We are also in preliminary discussions with interested parties regarding an investment of capital into our company. Again, there can be no assurance that such discussions will result in any agreement or transaction, which may be substantially dilutive to our stockholders. Furthermore, any potential transaction would be subject to the negotiation and execution of a definitive agreement and other related agreements, as well as to regulatory and other customary approvals and conditions, which may include stockholder approval and other factors including financing, and there can be no assurance that we would be successful in consummating any such transaction.
As of July 1, 2007, we temporarily curtailed production in the Field pending resolution of issues relating to the flaring of associated natural gas produced from the Field and to allow for the initial commissioning of the central production facility and crude export pipeline. We resumed production on September 29, 2007 after receiving an additional gas flaring permit until November 1, 2007. Subsequently, we received government approval from the Working Committee of the MEMR for our modified gas utilization program to supply gas to a proprietary brick manufacturing facility currently under construction, and approval for additional gas flaring volumes of 7.074 million cubic meters for November and December 2007 and 23 million cubic meters until the end of 2008. This protocol allows us to flare gas within these cumulative volumes without penalty until December 31, 2008, by which time our amended gas utilization program must be implemented. We signed a turnkey contract with a third party to construct and operate the brick manufacturing facility and construction is expected to be completed by June 2008.
Operating cash flow is dependent upon many factors, including production levels, sales volumes, oil prices and other factors that may be beyond our control. World oil prices increased to record levels in 2007, but we have not historically been able to consistently benefit from such prices due primarily to factors related to the lack of consistent access to the regional pipeline system, including the inability to process our own crude oil to remove mercaptans and other contaminants and the lack of our own connection to the regional pipeline system. From time to time we have utilized third-party processing facilities and pipeline connections, but access has been inconsistent and often unavailable. Prior to 2007, we exported our crude oil by rail, but due to transportation and storage costs as well as quality discounts, realized net revenues well below those from pipeline export. In mid-2007, we commissioned our permanent central production facility, including a demercaptan unit, and proprietary connection to the regional export pipeline system. As a result, we are now able to produce and export pipeline quality crude oil on a consistent basis, and receive substantially better prices for the crude oil we export.
The following table presents a summary of our development plan for the Field together with the estimated associated costs (in thousands):
Total production increased only marginally from 2006 to 2007, primarily due to the shut-in of the Field for substantially all of the third quarter of 2007. Average daily production during 2007, prior to the shut-in, increased approximately 33% over production levels in 2006. We utilized much of our excess liquidity during the shut-in period to fund operating costs, overhead, scheduled interest payments and necessary capital expenditures. As a
Index to Financial Statements
result, we do not currently have the necessary resources to allow for continued drilling of exploration and development wells and to meet other working capital obligations. We suspended drilling operations and have instituted cost cutting measures in both Kazakhstan and the U.S., primarily personnel reductions, which are expected to result in cost savings of approximately $2.6 million annually. We have also recently completed four wells that were drilled in 2007. The new wells are currently producing an aggregate of approximately 300 bopd, and are expected to produce substantially more once they have been acid stimulated, currently planned for the second quarter of 2008. While all wells in the Field that have been acid stimulated have shown improved flow rates, results have been inconsistent and we are not able to accurately predict the future performance of these new wells. At current production levels of approximately 2,200 bopd, and at the prices we currently receive, management believes we are able to generate sufficient cash flow to cover our operating costs, overhead and scheduled interest payments on our debt. However, as discussed above, we had a working capital deficit of $50.8 million at December 31, 2007, and do not have sufficient liquidity to carry out the full development program set forth above. Furthermore, no assurance can be given that production from the new wells and the cost cutting measures that have been instituted will result in sufficient additional cash flow to cover the working capital deficit and to fund continued Field development. If we are unable to either complete the pending sale of the Company discussed above or another strategic transaction, or if we are unable to increase production to a sufficient level, we will have to seek additional capital to fund interest payments, operating expenses and continued Field development. If we are unable to secure adequate additional capital, we may not be able to carry out the entire development plan set forth above, in which case our business, financial condition, results of operations and possibly our reported proved reserves would be materially and adversely affected. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should we be unable to continue as a going concern.
The following table presents our future contractual obligations, which consist of long-term debt and lease commitments (in thousands):
(1) See Note 4 to the Notes to Consolidated Financial Statements.
(2) See Note 8 to the Notes to Consolidated Financial Statements.
Critical Accounting Policies and Recent Accounting Pronouncements
We have identified the policies below as critical to our business operations and the understanding of our financial statements. The impact of these policies and associated risks are discussed throughout this 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 2 of the Notes to Consolidated Financial Statements.
Oil and Gas Reserve Information
The information regarding our oil and gas reserves, the changes thereto and the estimated future net cash flows are dependent upon engineering, price and other assumptions used in preparing our annual reserve study. A qualified independent petroleum engineer was engaged to prepare the estimates of our oil and gas reserves in accordance with applicable engineering standards and in accordance with SEC 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.
Index to Financial Statements Our oil and gas reserve data and estimated future net cash flows have been prepared based on a commercial production contract with the Kazakhstan government, which allows production for the 25-year term of the contract. The estimate of the royalty used in this report is a sliding scale based on annual production over the 25-year term, based on the provisions of the production contract. The government royalty rate is between 2.0% to 6.0% based on the forecasted annual production with the royalty rate capped at 6%.
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 2 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, 2007, 2006 and 2005, we capitalized $5.6 million, $4.1 million and $2.5 million, respectively, of interest costs, which reduced our reported net interest expense to $37.7 million, $36.9 million and $10.3 million, respectively. Because 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.
Stock-Based Compensation
We account for employee stock-based compensation using the fair value method as prescribed in Statement of Financial Accounting Standards (“SFAS”) No. 123(R). Under this method, we record the fair value attributable to stock options or stock grants, based on the Black-Scholes model, and amortize that amount to expense over the service period required to vest the options.
Income Taxes
We account for income taxes using the asset and liability method. The asset and liability method requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of (i) temporary differences between financial statement carrying amounts of assets and liabilities and the basis of these assets and liabilities for tax purposes and (ii) operating loss and tax credit carry-forwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when management concludes that it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.
Recent Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”) and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted, provided the company has not yet issued financial statements, including for interim periods, for that year. Consistent with its requirements, we adopted SFAS No. 157 as of January 1, 2008 and it did not have a material impact on our consolidated financial statements.
Index to Financial Statements In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We adopted SFAS No. 159 on January 1, 2008, and we do not expect this standard to have a material impact on our consolidated financial statements.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements (“SFAS No. 160”), which amends Accounting Research Bulletin No. 51, Consolidated Financial Statements, to improve the relevance, comparability, and transparency of the financial information that a reporting entity provides in its consolidated financial statements. SFAS No. 160 requires (i) that noncontrolling (minority) interests be reported as a component of shareholders’ equity, (ii) that net income attributable to the parent and to the noncontrolling interest be separately identified in the consolidated statement of operations, (iii) that changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as equity transactions, (iv) that any retained noncontrolling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value, and (v) that sufficient disclosures are provided that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 is effective for annual periods beginning after December 15, 2008 and should be applied prospectively. However, the presentation and disclosure requirements of the statement shall be applied retrospectively for all periods presented. We do not expect this standard to have a material impact on our consolidated financial statements.
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS No. 141(R)”), which replaces SFAS No. 141, Business Combinations. SFAS No. 141(R) changes the requirements for an acquirer’s recognition and measurement of the assets acquired and the liabilities assumed in a business combination. SFAS No. 141(R) is effective for annual periods beginning on or after December 15, 2008 and should be applied prospectively for all business combinations entered into after the date of adoption.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
Oil Prices
Our future success is dependent on our being able to transport and market our production either through export to international markets or within Kazakhstan. Crude oil prices are subject to significant volatility in response to changes in supply of and demand for oil, market uncertainty and a variety of other factors beyond our control. These factors and the volatility of the energy markets make it extremely difficult to predict future oil price movements with any degree of certainty. Declines in oil prices would not only reduce our revenues, but could reduce the amount of oil that we can produce economically and, as a result, could have a material adverse effect on our business, financial condition and results of operations.
Interest Rate Risk
At December 31, 2007, we had long-term debt outstanding of $273.4 million, net of discount of $16.6 million. The debt bears interest at a fixed rate of 12% per annum.
Foreign Currency Risk
Our functional currency is the U.S. dollar. The financial statements of our foreign subsidiaries are measured in U.S. dollars. Accordingly, transaction costs for the conversion to various currencies for foreign operations are recognized in earnings at the time of each transaction.
Index to Financial Statements DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. All statements other than statements of historical fact included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or the negative thereof or variations thereon or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. Important factors that could cause actual results to differ materially from our expectations (“cautionary statements”) include, but are not limited to, our assumptions about energy markets, production levels, reserve levels, operating results, competitive conditions, technology, the availability of capital resources, capital expenditure obligations, the supply and demand for oil, natural gas and other products or services, the price of oil, natural gas and other products or services, currency exchange rates, the weather, inflation, the availability of goods and services, drilling risks, future processing volumes and pipeline throughput, general economic and political conditions, either internationally or nationally or in the jurisdictions in which we or our subsidiaries are doing business, legislative or regulatory changes, including changes in environmental regulation, environmental risks and liability under federal, state and foreign environmental laws and regulations, the securities or capital markets and other factors disclosed under “Item 2. Properties-Proved Reserves,” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and elsewhere in this report. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.
Index to Financial Statements
Item 8.
Item 8. Financial Statements and Supplementary Data.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Index to Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and
Stockholders of Transmeridian Exploration Incorporated:
We have audited the accompanying consolidated balance sheets of Transmeridian Exploration Incorporated and subsidiaries (the “Company”), as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Transmeridian Exploration Incorporated and subsidiaries at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, the Company had a net working capital deficit of approximately $50.8 million and a total stockholders’ deficit of approximately $14.8 million at December 31, 2007, and has incurred operating losses since its inception. These conditions raise substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters also are described in Note 1. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Transmeridian Exploration Incorporated and subsidiaries’ internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 28, 2008, expressed an unqualified opinion on the effective operation of internal control over financial reporting.
/s/ UHY LLP
Houston, Texas
March 28, 2008
Index to Financial Statements
TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(In thousands, except preferred shares and par value information)
The accompanying notes are an integral part of these financial statements.
Index to Financial Statements
TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share amounts)
The accompanying notes are an integral part of these financial statements.
Index to Financial Statements
TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY (DEFICIT)
(In thousands, except preferred shares)
The accompanying notes are an integral part of these financial statements.
Index to Financial Statements
TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
(In thousands)
The accompanying notes are an integral part of these financial statements.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS-SUPPLEMENTAL INFORMATION
(In thousands)
The accompanying notes are an integral part of these financial statements.
Index to Financial Statements
TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Going Concern
The accompanying consolidated financial statements of Transmeridian Exploration Incorporated (“we”, “our”, “us” or the “Company”) have been prepared on the basis of accounting principles applicable to a going concern, which contemplate the realization of assets and satisfaction of liabilities in the normal course of business. As shown in the accompanying consolidated financial statements, we had a net working capital deficit of approximately $50.8 million and a stockholders’ deficit of approximately $14.8 million at December 31, 2007. These matters raise substantial doubt about our ability to continue as a going concern. Included in our current liabilities is approximately $17.8 million in returns obligations incurred in connection with the issuance of our 20% Junior Redeemable Convertible Preferred Stock (“Junior Preferred Stock”). However, the returns are not payable until the earlier of (i) the occurrence of a change of control of the Company (as defined in the certificate of designations, as amended, governing the Junior Preferred Stock) or (ii) June 18, 2008; provided, however, that if the returns become due and payable on June 18, 2008 in the absence of a change of control transaction, we may elect to satisfy our payment obligations by delivery of shares of our common stock valued at 97% of the common stock’s market value at such time. Additionally, there is approximately $5.2 million in preferred stock dividends that can be satisfied by the issuance of additional preferred shares or common shares subject to certain restrictions. We have incurred operating losses since our inception. To date, we have funded our development operations and working capital requirements through a combination of debt and equity proceeds and cash flow from operations.
As announced on December 31, 2007, we entered into a definitive agreement to be acquired by Trans Meridian International, Inc. (“TMI”), a company formed by our Chairman and Chief Executive Officer. Pursuant to the agreement, TMI will commence a tender offer to purchase all of our outstanding shares of common stock for $3.00 per share, payable net to the seller in cash. The transaction is subject to satisfaction of various conditions precedent. As a result, no prediction can be made as to the timing of the commencement or completion of a tender offer. There can be no assurance that the transaction will be completed. As TMI has not met the financing condition in the definitive agreement within the prescribed time period, which we extended from January 31, 2008 to February 15, 2008, we may terminate the agreement at any time until the condition is satisfied. Our board of directors requested certain detailed information regarding TMI’s financing be provided by March 21, 2008 and, if our board of directors is not satisfied with such information, then we intend to terminate the agreement if the financing condition is not satisfied by March 31, 2008. To date, our board of directors is not satisfied with the information that has been provided.
We will continue to seek proposals from other parties with respect to a potential acquisition of our company. There can be no assurance, however, that these efforts will result in any agreement or transaction. Further, if we do enter into an agreement to be acquired by a party other than TMI, the value to be received by our common stockholders may be substantially less than the $3.00 per share contained in the current agreement with TMI. We are also in preliminary discussions with interested parties regarding an investment of capital into our company. Again, there can be no assurance that such discussions will result in any agreement or transaction, which may be substantially dilutive to our stockholders. Furthermore, any potential transaction would be subject to the negotiation and execution of a definitive agreement and other related agreements, as well as to regulatory and other customary approvals and conditions, which may include stockholder approval and other factors including financing, and there can be no assurance that we would be successful in consummating any such transaction.
As of July 1, 2007, we temporarily curtailed production in the Field pending resolution of issues relating to the flaring of associated natural gas produced from the Field and to allow for the initial commissioning of the central production facility and crude export pipeline. We resumed production on September 29, 2007 after receiving an additional gas flaring permit until November 1, 2007. Subsequently, we received government
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
approval from the Working Committee of the Ministry of Energy and Mineral Resources for our modified gas utilization program to supply gas to a proprietary brick manufacturing facility currently under construction, and approval for additional gas flaring volumes of 7.074 million cubic meters for November and December 2007 and 23 million cubic meters until the end of 2008. This protocol allows us to flare gas within these cumulative volumes without penalty until December 31, 2008, by which time our amended gas utilization program must be implemented. We signed a turnkey contract with a third party to construct and operate the brick manufacturing facility and construction is expected to be completed by June 2008.
Operating cash flow is dependent upon many factors, including production levels, sales volumes, oil prices and other factors that may be beyond our control. World oil prices increased to record levels in 2007, but we have not historically been able to consistently benefit from such prices due primarily to factors related to the lack of consistent access to the regional pipeline system, including the inability to process our own crude oil to remove mercaptans and other contaminants and the lack of our own connection to the regional pipeline system. From time to time we have utilized third-party processing facilities and pipeline connections, but access has been inconsistent and often unavailable. Prior to 2007, we exported our crude oil by rail, but due to transportation and storage costs as well as quality discounts, realized net revenues well below those from pipeline export. In mid-2007, we commissioned our permanent central production facility, including a demercaptan unit, and proprietary connection to the regional export pipeline system. As a result, we are now able to produce and export pipeline quality crude oil on a consistent basis, and receive substantially better prices for the crude oil we export.
Total production increased only marginally from 2006 to 2007, primarily due to the shut-in of the Field for substantially all of the third quarter of 2007. Average daily production during 2007, prior to the shut-in, increased approximately 33% over production levels in 2006. We utilized much of our excess liquidity during the shut-in period to fund operating costs, overhead, scheduled interest payments and necessary capital expenditures. As a result, we do not currently have the necessary resources to allow for continued drilling of exploration and development wells and to meet other working capital obligations. We suspended drilling operations and have instituted cost cutting measures in both Kazakhstan and the U.S., primarily personnel reductions, which are expected to result in cost savings of approximately $2.6 million annually. We have also recently completed four wells that were drilled in 2007. The new wells are currently producing an aggregate of approximately 300 bopd, and are expected to produce substantially more once they have been acid stimulated, currently planned for the second quarter of 2008. While all wells in the Field that have been acid stimulated have shown improved flow rates, results have been inconsistent and we are not able to accurately predict the future performance of these new wells. At current production levels of approximately 2,200 bopd, and at the prices we currently receive, management believes we are able to generate sufficient cash flow to cover our operating costs, overhead and scheduled interest payments on our debt. However, as discussed above, we had a working capital deficit of $50.8 million at December 31, 2007, and do not have sufficient liquidity to carry out the full development program set forth above. Furthermore, no assurance can be given that production from the new wells and the cost cutting measures that have been instituted will result in sufficient additional cash flow to cover the working capital deficit and to fund continued Field development. If we are unable to either complete the pending sale of the Company discussed above or another strategic transaction, or if we are unable to increase production to a sufficient level, we will have to seek additional capital to fund interest payments, operating expenses and continued Field development. If we are unable to secure adequate additional capital, we may not be able to carry out the entire development plan set forth above, in which case our business, financial condition, results of operations and possibly our reported proved reserves would be materially and adversely affected. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should we be unable to continue as a going concern.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Note 2. Organization and Summary of Significant Accounting Policies
We were incorporated in the State of Delaware in April 2000. We are engaged in the business of acquiring, developing and producing oil and gas, with our activities primarily focused on the Caspian Sea region of the former Soviet Union. Our primary oil and gas property is the South Alibek Field (“South Alibek” or the “Field”) in the Republic of Kazakhstan covered by License 1557 (the “License”) and the related exploration and production contracts with the government of Kazakhstan.
Principles of Consolidation and Reporting
The consolidated financial statements include the accounts of us and our majority-owned and controlled subsidiaries and are prepared in accordance with generally accepted accounting principles in the United States. All significant intercompany transactions and balances have been eliminated in consolidation.
We conduct our operations in Kazakhstan through a wholly-owned subsidiary, JSC Caspi Neft TME (“Caspi Neft”), a joint stock company organized under the laws of Kazakhstan. Caspi Neft holds the license, exploration and production contracts covering the Field in Kazakhstan. Prior to February 2004, we owned 100% of Caspi Neft. From February 2004 to December 2005, 50% of Caspi Neft was owned by Bramex Management, Inc. (“Bramex”). We continued to exercise significant control over Caspi Neft after Bramex acquired 50% of Caspi Neft in February 2004 and, accordingly, believe the most meaningful accounting treatment was to fully consolidate Caspi Neft with the 50% share owned by Bramex reflected as a minority interest. In December 2005, we reacquired 100% of Caspi Neft. The results of operations of Caspi Neft represent substantially all of the operations of the Company.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We base our estimates and judgments on historical experience and on other information and assumptions that are believed to be reasonable under the circumstances. Estimates and judgments about future events and their effects cannot be perceived with certainty; accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as our operating environment changes and as new events occur. While it is believed that such estimates are reasonable, actual results could differ materially from those estimates. Estimates are used for, but not limited to, determining the following: inventory valuation, recoverability of long-lived assets, useful lives and oil and gas reserves used in depreciation, depletion, and amortization, income taxes and related valuation allowances and insurance, environmental and legal accruals.
Revenue Recognition
We sell our production both in the export and domestic market on a contract basis. Revenue is recorded when the purchaser takes delivery of the oil and is presented in our consolidated financial statements net of royalties. At the end of the period, oil that has been produced but not sold is recorded as inventory at the lower of cost or market. Cost is determined on a weighted average basis based on production costs.
Cash and Cash Equivalents
We consider all highly liquid instruments with an original maturity of three months or less to be cash equivalents. Certain of our cash balances are maintained in foreign banks which are not covered by deposit insurance. The cash balances in our U.S. accounts may exceed federally insured limits.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Property and Equipment
We follow the “successful efforts” method of accounting for the 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.
We review our oil and gas properties for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the unamortized capitalized cost of the asset. If the future undiscounted cash flows, based on our estimates of anticipated production from proved reserves and 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, we purchased a drilling rig that, beginning in October 2002, was used in the development of the Field. The rig was depreciated on the straight-line method and while being used for development drilling, the depreciation of the rig and related support equipment was capitalized under the successful efforts method as part of the cost of the wells. Subsequent depreciation was expensed when the rig was stacked. In the first quarter of 2006, the Company reached an agreement to dispose of the rig. In accordance with generally accepted accounting principles, an impairment charge writing the value of the rig down to the estimated net proceeds and reclassifying the net book value of the rig to current asset held for sale was recorded. The carrying value of the drilling rig and related equipment was reclassified in June 2007 when the agreement to dispose of the rig was not consummated and is being depreciated over its estimated remaining useful life.
Our central production facility, pipeline and related oil processing equipment, 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 twenty four 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.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Capitalized Interest Costs
Certain interest costs have been capitalized as part of the cost of oil and gas properties under development, 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, 2007, 2006 and 2005 totaled $5.6 million, $4.1 million and $2.5 million, respectively.
Income Taxes
We account for income taxes using the asset and liability method. The asset and liability method requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of (i) temporary differences between financial statement carrying amounts of assets and liabilities and the basis of these assets and liabilities for tax purposes and (ii) operating loss and tax credit carry-forwards for tax purposes. Deferred tax assets are reduced by a valuation allowance when management concludes that it is more likely than not that a portion of the deferred tax assets will not be realized in a future period.
Debt Financing Costs
Costs incurred with debt financings are capitalized and amortized over the term of the related financing facility.
Loss per Common Share
Basic net loss per common share is computed by dividing the net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the applicable period. Net loss attributable to common stockholders is calculated as the net loss after deductions for cumulative preferred stock dividends, whether paid or accrued, and accretion of preferred stock discount. Diluted net loss per common share has been computed based on the weighted average number of shares of common stock and common stock equivalents outstanding during the applicable period, as if all potentially dilutive securities were converted into common stock. Diluted net loss per share equals basic net loss per share for the periods presented because the effects of potentially dilutive securities are anti-dilutive. The calculation of diluted weighted average shares outstanding for the years ended December 31, 2007, 2006 and 2005 excludes 2,199,268, 10,872,553, and 3,926,973 common shares, respectively, issuable pursuant to convertible preferred stock and outstanding stock options and warrants because their effect is anti-dilutive.
Foreign Exchange Transactions
Our functional currency is the U.S. dollar because we primarily contract with customers, finance capital and purchase equipment and services using the U.S. dollar. Certain assets and liabilities are translated at historical exchange rates, revenues and expenses in foreign currency are translated at the average rate of exchange for the period and all translation gains or losses are reflected in the period’s results of operations.
Concentration of Credit Risk
Financial instruments that potentially subject us to concentrations of credit risk consist principally of cash and cash equivalents and accounts receivable. We deposit our cash and cash equivalents in high credit quality financial institutions, however amounts on deposit do exceed the maximum amount insured by the Federal Deposit Insurance Corporation. Although our current crude oil sales are to a limited number of purchasers, all of our customers are involved in the energy industry.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Stock-Based Compensation
We account for employee stock-based compensation using the fair value method as prescribed in Statement of Financial Accounting Standards (“SFAS”) No. 123(R). Under this method, we record the fair value attributable to stock options or stock grants, based on the Black-Scholes model, and amortize that amount to expense over the service period required to vest the options.
Financial Instruments
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and long-term debt. The carrying values of cash and cash equivalents, receivables and accounts payable approximate fair value due to their short-term nature. The carrying value of long-term debt approximates its fair value based on the market interest rate of the debt instrument.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current period presentation.
Recent Accounting Pronouncements
In September 2006, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 157, Fair Value Measurements (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (“GAAP”) and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements but rather eliminates inconsistencies in guidance found in various prior accounting pronouncements. SFAS No. 157 is effective for fiscal years beginning after November 15, 2007, with earlier adoption permitted, provided the company has not yet issued financial statements, including for interim periods, for that year. Consistent with its requirements, we adopted SFAS No. 157 as of January 1, 2008 and it did not have a material impact on our consolidated financial statements.
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We adopted SFAS No. 159 on January 1, 2008, and we do not expect this standard to have a material impact on our consolidated financial statements.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements (“SFAS No. 160”), which amends Accounting Research Bulletin No. 51, Consolidated Financial Statements, to improve the relevance, comparability and transparency of the financial information that a reporting entity provides in its consolidated financial statements. SFAS No. 160 requires (i) that noncontrolling (minority) interests be reported as a component of shareholders’ equity, (ii) that net income attributable to the parent and to the noncontrolling interest be separately identified in the consolidated statement of operations, (iii) that changes in a parent’s ownership interest while the parent retains its controlling interest be accounted for as equity transactions, (iv) that any retained noncontrolling equity investment upon the deconsolidation of a subsidiary be initially measured at fair value, and (v) that sufficient disclosures are provided that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 is effective for annual periods beginning after December 15, 2008 and should be applied prospectively. However, the presentation and disclosure requirements of the statement shall be applied retrospectively for all periods presented. We do not expect this standard to have a material impact on our consolidated financial statements.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
In December 2007, the FASB issued SFAS No. 141(R), Business Combinations (“SFAS No. 141(R)”), which replaces SFAS No. 141, Business Combinations. SFAS No. 141(R) changes the requirements for an acquirer’s recognition and measurement of the assets acquired and the liabilities assumed in a business combination. SFAS No. 141(R) is effective for annual periods beginning on or after December 15, 2008 and should be applied prospectively for all business combinations entered into after the date of adoption.
Note 3. Property and Equipment
Property and Equipment
Property and equipment consisted of the following:
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. During the years ended December 31, 2007 and 2006, we capitalized approximately $5.6 million and $4.1 million, respectively, of interest costs.
Oil and Gas Properties
The License covering the Field was granted by the Republic of Kazakhstan on April 29, 1999 and originally covered 3,396 acres. In March 2000, we 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, we applied to the Kazakhstan Ministry of Energy and Mineral Resources to expand the area covered by the License. In November 2001, our application was approved and the License was expanded to cover an area of 14,111 acres.
The exploration contract associated with the License had an original six-year term which expired in April 2005 and has been extended through April 2009. The exploration contract required capital expenditures during the initial period of approximately $18.0 million, which was satisfied and $30.5 million during the first two-year extension, which has also been satisfied. The latest two-year extension, expiring April 2009, requires an additional commitment of $19.7 million for development of the Field, which has been satisfied. During the primary and extended terms of the exploration contract, we can produce from wells under a test program and pay a 2% royalty to the government.
In December 2006, the 25-year production contract for the Field was signed and officially registered by the governmental authorities in Kazakhstan. The production contract initially covers the approved 3,500 acre commercial area within the 14,111 acre License area. Under our exploration contract, we have the right to continue exploration activities within the License area and increase the size of the commercial area subject to the long-term production contract. The production contract provides, among other things, a minimum seven-year
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
work program commitment of $59.6 million for the continued development of the Field, the recovery by the government of approximately $4.7 million of exploration costs that were incurred prior to privatization, a signature bonus, future commercial discovery bonuses if additional recoverable reserves are found, royalty rates determined using a sliding scale based on annual production levels of crude oil and annual funding of agreed social projects, training programs and an abandonment fund.
Pursuant to the terms of the production contract we may be required to dismantle and remove any facilities and equipment and return the area under the contract to a condition that permits the use of such area for purposes similar to those existing prior to the commencement of operations under the exploration contract. We have an asset retirement obligation of approximately $691,000 as of December 31, 2007 for the assets that have been placed into service as of that date. We will account for future asset retirement obligations as assets are placed into service and changes in existing retirement obligations pursuant to the requirements of SFAS No. 143, Accounting for Asset Retirement Obligations.
Note 4. Debt
Long-Term Debt
Long-term debt consists of the following:
Senior Secured Notes
In December 2005, we and Transmeridian Exploration Inc., our wholly owned subsidiary (“TEI”), issued in a private placement 250,000 Units, consisting of in the aggregate (i) $250 million principal amount of senior secured notes due 2010 of the Issuer (the “Existing Notes”) and (ii) warrants to purchase approximately 17.3 million shares of our common stock. The Units were issued and sold for a purchase price of $1,000 per Unit. Each Unit consists of $1,000 principal amount of Notes and 69.054 Warrants to purchase an equal number of shares of our common stock. The Existing Notes, which will mature on December 15, 2010, bear interest at the rate of 12% per annum. Interest on the Existing Notes is payable quarterly on March 15, June 15, September 15 and December 15 of each year and at maturity. The fair value of the warrants of approximately $26,816,000 was recorded as a discount to the face amount of the Existing Notes and will be amortized to interest expense over the life of the Existing Notes. We used the proceeds from the offering of the Units of $237.4 million, after expenses, to fund the acquisition of Bramex and to retire the existing bank credit facility indebtedness of Caspi Neft, to repay $22.5 million of convertible promissory notes and to pre-fund the first year of interest payments on the Existing Notes of $30 million.
In May 2006, we and TEI issued in a private placement $40 million principal amount of additional senior secured notes due 2010 (the “Additional Notes”) and (ii) 1,818,182 shares (approximately $10 million) of our common stock (the “Shares”). The Additional Notes were issued and sold for an issue price of 97% of the principal amount thereof plus accrued interest from March 15, 2006, and the Shares were issued and sold at an issue price of $5.50 per share. The discount was recorded as a reduction of the face amount of the Additional Notes and will be amortized to interest expense over the life of the Additional Notes.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The Additional Notes have terms and conditions identical to, and are fungible for trading and other purposes with, the Existing Notes. The Additional Notes, like the Existing Notes, are fully and unconditionally guaranteed by us and all of our material subsidiaries and are governed by the terms of the Indenture, dated as of December 12, 2005, as supplemented by the First Supplemental Indenture, dated as of December 22, 2005, and the Second Supplemental Indenture, dated as of May 24, 2006, by and among TEI, us, the subsidiary guarantors of the Existing Notes and the Additional Notes and the trustee. The Indenture contains provisions that limit the our ability to enter into transactions with affiliates; pay dividends or make other restricted payments; incur debt; create, incur or assume liens; sell assets; and consolidate, merge or transfer all or substantially all of our assets. We are required to offer to repurchase the Notes in connection with certain specified change of control events. The Notes are subject to redemption, in whole or in part, at our option at any time on or after December 15, 2008 at redemption prices starting at 106% of the principal amount redeemed and declining to 100% by June 15, 2010. Prior to December 15, 2008, we may redeem up to 35% of the Notes with proceeds of certain equity offerings at a specified redemption price.
In July 2006, pursuant to the registration rights agreements entered into in connection with the issuance of the Existing Notes and the Additional Notes, we completed an exchange offer of $290 million aggregate principal amount of TEI’s senior secured notes due 2010 registered under the Securities Act of 1933 for all of the outstanding Existing Notes and Additional Notes.
Future maturities of long-term debt, exclusive of discount, at December 31, 2007, are as follows:
Management believes the fair value of debt at December 31, 2007 approximates its carrying value based on the market interest rate of the debt instrument.
Note 5. Redeemable Convertible Preferred Stock
Senior Redeemable Convertible Preferred Stock
In December 2006, we sold (i) 370,000 shares of our 15% Senior Redeemable Convertible Preferred Stock (the “Senior Preferred Stock”) in a private offering and (ii) 70,000 shares of Senior Preferred Stock in a concurrent private placement. Purchasers of the Senior Preferred Stock in the private placement included our Chairman and Chief Executive Officer and our Vice President and Chief Financial Officer, who purchased 41,000 and 5,000 shares, respectively.
The Senior Preferred Stock, which has a liquidation preference of $100 per share, pays cumulative quarterly dividends at an initial rate of 15% per annum, subject to adjustment, payable at our option in additional shares of the Senior Preferred Stock, shares of our common stock (subject to the satisfaction of certain conditions) or cash (if allowed by the terms of our then-existing debt instruments). Dividends are payable on January 1, April 1, July 1 and October 1 of each year, commencing April 1, 2007. Additionally, we issued to the initial purchaser in
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
the offering 110,000 warrants to purchase shares of our common stock as part of the total fees of the offering. The fair value of the warrants of approximately $304,000 was recorded as a discount to the face amount of the Senior Preferred Stock and is being amortized over the life of the Senior Preferred Stock.
Our Senior Preferred Stock was originally convertible into approximately 9.8 million shares of common stock based on an initial conversion price of $4.50 per share of common stock. Effective July 1, 2007, there was a one-time test for adjustment of the conversion price and the dividend rate based upon the achievement of a specified average production rate prior to June 30, 2007 or a specified average trading price threshold of our common stock during the 15 trading days immediately following June 30, 2007. Neither of these thresholds was met and the conversion price and the dividend rate of the Senior Preferred Stock were adjusted to $3.90 per share and 18%, respectively, effective July 1, 2007. Additionally, the conversion price of the Senior Preferred Stock is subject to adjustment pursuant to customary anti-dilution provisions. As a result of the issuance of the 20% Junior Redeemable Convertible Preferred Stock (“Junior Preferred Stock”), our March 2007 private placement of warrants to purchase shares of our common stock referenced in Note 7 below and our April 2007 private placement of shares of our common stock also referenced in Note 7 below, the conversion price of the Senior Preferred Stock was further adjusted to $3.76 per share. Additionally, the conversion price of the Senior Preferred Stock may also be adjusted upon the occurrence of a change of control meeting certain conditions. However, in no event will the conversion price of the Preferred Stock be reduced to less than $3.23 per share (subject to adjustment), which was the closing price of our common stock on the American Stock Exchange on the pricing date of the private offering and the concurrent private placement. As of December 31, 2007, there were 442,334 shares of Senior Preferred Stock outstanding that were convertible into approximately 11.8 million shares of common stock.
The Senior Preferred Stock ranks senior to our common stock with respect to dividend rights and rights upon the Company’s liquidation, winding-up or dissolution. There are also restrictive covenants related to our ability to incur indebtedness, make certain payments or investments and create restrictions on us and our subsidiaries’ ability to pay dividends, and further provides for preemptive rights in favor of the holders of the Preferred Stock with respect to certain securities offerings that we may make in the future.
Junior Redeemable Convertible Preferred Stock
In June 2007, we sold 550,000 shares of our Junior Preferred Stock. The Junior Preferred Stock, which has a liquidation preference of $100 per share, will pay cumulative quarterly dividends at a rate of 20% per annum, payable at our option in additional shares of the Junior Preferred Stock, shares of our common stock (subject to the satisfaction of certain conditions) or cash (if allowed by the terms of our then-existing debt instruments or the Senior Preferred Stock).
The Junior Preferred Stock was originally convertible into approximately 24.4 million shares of common stock, based on an initial conversion price of $2.25 per share. The conversion price was adjusted on November 1, 2007 to $1.90 per share because a change of control had not occurred, or a definitive agreement that would lead to a change of control had not been signed as of October 31, 2007. As of December 31, 2007, there were 640,656 shares of Junior Preferred Stock outstanding that were convertible into approximately 33.7 million shares of common stock.
In connection with the issuance of our Junior Preferred Stock, each purchaser of Junior Preferred Stock that was also a beneficial owner of our Senior Preferred Stock had the right to exchange shares of Senior Preferred Stock, on a one-for-one basis, for Junior Preferred Stock, up to the number equal to 40% of the aggregate number of shares of Junior Preferred Stock purchased by such holder (the “Investment Rollover”). Purchasers of Junior Preferred Stock elected to convert 56,000 shares of Senior Preferred Stock into Junior Preferred Stock in August 2007 and the carrying value of the shares of Senior Preferred Stock was transferred to the Junior Preferred Stock.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The Junior Preferred Stock will be redeemable, at the option of the holder, on March 15, 2012 at the liquidation preference plus all accumulated and unpaid dividends, or upon a change of control at an amount equal to the sum of 125% of the liquidation preference plus all accumulated and unpaid dividends.
We will have the option, upon a change of control, to redeem the Junior Preferred Stock at an amount equal to the sum of 125% of the then-effective conversion price multiplied by the number of shares of common stock into which such shares of Junior Preferred Stock are then convertible plus all accrued and unpaid dividends. After June 15, 2008, the Junior Preferred Stock is redeemable, at our option, at a premium to the liquidation preference, provided the closing price of our common stock equals or exceeds 125% of the then-effective conversion price for at least 20 trading days in any 30 consecutive trading day period.
Of the 550,000 shares of the Junior Preferred Stock issued in the private placement, 100,000 shares of the Junior Preferred Stock were issued, and the net proceeds of approximately $9.5 million were paid to us, in connection with the first closing on June 18, 2007. In connection with the second closing on June 26, 2007, the remaining 450,000 shares of the Junior Preferred Stock were issued and net proceeds of approximately $11.0 million from the sale of 120,000 of the shares were paid to us. The remaining 330,000 shares of the Junior Preferred Stock and the gross proceeds of $33.0 million therefrom were originally placed in escrow pending stockholder approval of the issuance or potential issuance of shares of our common stock under the terms of the Junior Preferred Stock that, in the aggregate, equal or exceed 20% of the currently outstanding shares of our common stock. The escrow proceeds, net of transaction fees, were released to us in July 2007 upon our receipt of the requisite proxies evidencing such stockholder approval.
The private placement generated total net proceeds of approximately $51.5 million, after transaction fees and expenses. We used the net proceeds from the first closing to satisfy our interest payment obligation with respect to our senior secured notes due 2010 and for working capital and general corporate purposes. The net proceeds from the second closing, including the escrowed proceeds were used for working capital and general corporate purposes, including funding ongoing development costs. Additionally, we issued 550,000 warrants to the underwriter to purchase shares of our common stock at $2.25 per share as part of the total fees of the offering. We also agreed to pay a transaction preferred return, in cash, equal to 10% of an investors’ commitment and a preferred return, in cash, equal to 25% of the aggregate liquidation preference of the shares of Junior Preferred Stock purchased. However, the returns are not payable until the earlier of (i) the occurrence of a change of control of the Company (as defined in the certificate of designations, as amended, governing the Junior Preferred Stock) or (ii) June 18, 2008; provided, however, that if the returns become due and payable on June 18, 2008 in the absence of a change of control transaction, we may elect to satisfy our payment obligations by delivery of shares of our common stock valued at 97% of the common stock’s market value at such time. Additionally, if a change of control has not occurred by December 31, 2007, the return balances are increased, until paid, at the rate of 10% per annum. The fair value of the warrants of approximately $412,500, along with other offering expenses, and the value of the returns of approximately $17.8 million, were recorded as a discount to the face value of the Junior Preferred Stock and will be accreted over the life of the Junior Preferred Stock. The returns obligations have been recognized as current liabilities as of December 31, 2007.
In addition, holders of the Junior Preferred Stock have the right, upon written request of the holders of two-thirds of the outstanding shares of the Junior Preferred Stock, to designate individuals to constitute one-half of the membership of our board of directors and to require us to take the necessary action to effect such change in our board composition. In addition, we will be obligated to cause the directors designated by the holders of two-thirds of the outstanding shares of the Junior Preferred Stock to constitute a majority of the directors then serving on the special committee of the board of directors overseeing the ongoing process with respect to a possible sale of the Company or the Field. If a change of control of the Company has not occurred, or a definitive
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
agreement that would lead to a change of control of the Company has not been signed, by June 15, 2008, we may be obligated to further alter the composition of the board of directors such that individuals designated by the holders of two-thirds of the outstanding shares of the Junior Preferred Stock would then constitute a majority of the members of the board of directors.
The holders of the Junior Preferred Stock are also entitled to certain registration rights with respect to the Junior Preferred Stock, pursuant to which we are obligated to file and cause to become effective a shelf registration statement covering the resale of the Junior Preferred Stock, the shares of our common stock into which the Junior Preferred Stock is convertible, and the shares of the Junior Preferred Stock and shares of our common stock issued in payment of the quarterly dividends. Pursuant to, and in timely compliance with, our filing obligation, we filed such shelf registration statement on July 18, 2007. On October 16, 2007, a registration default occurred because our Registration Statement on Form S-3 was not declared effective by the SEC within 120 days after the execution date of the Amended and Restated Commitment Letter by and among us and the purchasers of the Junior Preferred Stock. This default is continuing; as a result, while such registration default continues, the holders of the Junior Preferred Stock are entitled to receive additional dividends at a rate of 1.00% per annum for the first 30 days of such registration default and at a rate of 1.50% per annum thereafter, in addition to the dividends otherwise accruing until the default is cured.
Note 6. Stockholders’ Equity
Series A Convertible Preferred Stock
During 2007, the remaining 594.804 shares of Series A Cumulative Convertible Preferred Stock (the “Series A Preferred”) were converted into 5,948,039 shares of our common stock. No Series A Preferred shares were outstanding as of December 31, 2007.
Common Stock Reserved for Issuance
There are 200,000,000 common shares authorized by the Company’s Amended and Restated Certificate of Incorporation and 116,859,838 and 101,245,877 common shares were issued and outstanding as of December 31, 2007 and 2006, respectively. Shares of common stock reserved for issuance are summarized as follows:
Warrants
On March 15, 2007, we issued in a private placement warrants to purchase an aggregate 8,500,000 shares of our common stock. The warrants were issued for total cash consideration of $8 million. Each warrant, when exercised, will entitle the holder to receive one share of our common stock at an exercise price of $2.00 per share. The warrant agreement governing the warrants provides for customary anti-dilution adjustments with respect to the exercise price and the number of shares of our common stock issuable upon exercise of the warrants. The warrants are exercisable at any time, at the holder’s option, and will expire on March 15, 2012.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Also in March 2007, the holders of warrants to purchase an aggregate of 4,773,214 shares of our common stock notified us of their intention to exercise such warrants upon the expiration of the specified notice period for waiver of beneficial ownership limitations under the warrants. In connection with such notification, the holders paid in advance the exercise price of the warrants, resulting in proceeds to us of approximately $10,373,000. The common shares underlying these warrants were issued in May 2007.
Similarly, in April 2007, the holders of warrants to purchase an aggregate of 1,700,000 shares of our common stock notified us of their intention to exercise such warrants upon the expiration of the specified notice period for waiver of beneficial ownership limitations under the warrants. In connection with such notification, the holders paid in advance the exercise price of the warrants, resulting in proceeds to us of $2,635,000. The common shares underlying these warrants were issued in June 2007. Also in April 2007, the holders of warrants to purchase an aggregate of 193,750 shares of our common stock exercised their warrants resulting in proceeds to us of approximately $400,000.
In April 2007, we sold to various investors an aggregate of 1,655,000 shares of our common stock for cash in a private placement exempt from registration under the Securities Act of 1933 (as amended, the “Securities Act”). In connection therewith, we granted to the purchasers certain registration rights with respect to the resale or other disposition of such shares of common stock. The sales price of the shares sold was $2.70 per share, and the aggregate gross proceeds to us from the sale were approximately $4.5 million.
In May 2007, the holders of warrants to purchase an aggregate of 2,000,0000 shares of our common stock notified us of their intention to exercise such warrants upon the expiration of the specified notice period for waiver of beneficial ownership limitations under the warrants. In connection with such notification, the holders paid in advance $1.99 of the $2.00 exercise price of the warrants, resulting in proceeds to us of $3,980,000. As of December 31, 2007, the remainder of the exercise price of the warrants had not been paid and the shares of common stock issuable in connection with the pending warrant exercises had not been issued. Accordingly, a liability in the amount of $3,980,000 has been reflected in accrued liabilities at December 31, 2007, representing our obligation to issue the related shares of common stock upon the expiration of the notice period in July 2007 and receipt of the remaining exercise price.
2006 Incentive Plan
Our 2006 Incentive Plan (the “Plan”), which was approved by our stockholders at our 2006 annual meeting of stockholders in May 2006, is an amendment and restatement of our 2001 Incentive Stock Option Plan. Under the Plan, we may grant to officers, board members, key employees and consultants of the company, through May 30, 2016, options to purchase up to an aggregate of 10% of the total shares of our common stock outstanding from time to time, less the number of shares underlying unexercised options as of the date the Plan was approved by our stockholders at our 2006 annual meeting of stockholders (i.e., May 30, 2006); as of December 31, 2007, options to purchase up to an aggregate 3,645,000 shares of our common stock could be granted under the Plan. The exercise price of each option under the Plan shall generally be no less than the fair market value of our common stock on the date of grant, and all options granted under the Plan shall generally have a term of no greater than 10 years. The vesting period of options granted under the Plan is determined by the Board of Directors on the date of grant.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The following table summarizes activity under the Plan for the last three years.
The aggregate fair value of options granted during 2007, 2006 and 2005 was $5,526,000, $4,365,000 and $970,000, respectively, which is being amortized to expense over the vesting period of the options. 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 2.5 and 10 years; and volatility of the price of the underlying common stock of 45-90%. Compensation expense of $3,967,000, $2,070,000 and $401,000 for stock options was recognized during the years ended December 31, 2007, 2006 and 2005, respectively.
The following table summarizes additional information about the Company’s outstanding and exercisable stock options at December 31, 2007:
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
2003 Stock Compensation Plan
In May 2003, we established the 2003 Stock Compensation Plan with the registration of 2.5 million shares under the plan. The plan was amended in May 2005 to increase the number of shares authorized for issuance to a total of 5,000,000 shares. Under the terms of the plan, such stock may be issued for restricted stock awards, payments of bonuses in stock, payments for services to consultants in the form of stock, employer contributions to a 401(k) plan, stock appreciation rights and warrants. Any shares issued in lieu of cash are recognized as expense based on the fair value of the shares on the date of grant. The fair value of restricted stock awards on the date of grant is amortized ratably over the vesting period. The following table summarizes the shares issued during the years ended December 31:
Compensation expense of $1,871,000, $3,170,000 and $1,689,000 for shares issued or granted was recognized during the years ended December 31, 2007, 2006 and 2005, respectively.
Note 7. Income Taxes
We provide for deferred taxes on temporary differences between the financial statements and tax basis of assets using the enacted tax rates that are expected to apply to taxable income when the temporary differences are expected to reverse. We have not recorded any deferred tax assets or income tax benefits from the net deferred tax assets for the years ended December 31, 2007, 2006 and 2005. We have placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.
Income before income taxes is composed of the following:
A reconciliation of the federal statutory income tax (34%) amounts to the effective amounts is shown below:
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
At December 31, 2007, 2006 and 2005 the components of our deferred tax assets and liabilities were as follows:
As of December 31, 2007, we had estimated domestic net operating loss (“NOL”) carryforwards of $25.0 million which will expire between 2020 and 2027. The 2006 and 2007 NOL for financial reporting purposes has been reduced by $828,000 and $163,000 respectively for the effect of SFAS No. 123(R), as more fully described below.
In December 2004, the FASB issued the revised SFAS No. 123(R), Share-Based Payment. SFAS 123(R) is a revision of SFAS No. 123 and supersedes APB No. 25. We had previously adopted SFAS No. 123, and, the revised provisions of SFAS No. 123(R) were effective January 1, 2006. For companies that have NOL carryforwards, SFAS No. 123(R) affects the manner in which stock-based compensation tax deductions are treated for financial reporting purposes. We may claim stock-based compensation deductions in our federal corporate income tax returns in an amount equal to the related income that is included in our employees’ reported federal taxable income subject to any other applicable limitations. Under SFAS No. 123(R), tax benefits generated in 2006 and subsequent reporting periods related to the excess of tax deductible stock-based compensation over the amount recognized for financial accounting purposes, may not be recorded to additional paid-in-capital for financial reporting purposes until the stock-based compensation deductions actually reduce our cash income tax liability. Any tax benefits attributable to these deductions will not be recorded to additional paid-in-capital for financial reporting purposes until such time as all existing and future NOL carryforwards have been fully utilized. As a result of the provisions of SFAS No. 123(R), at December 31, 2007, we have excluded $991,000 of stock-based compensation deductions from our NOL carryforwards for financial reporting purposes. The tax effect of the stock based compensation is approximately $337,000 at the 34% rate.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Prior to the effective date of SFAS No. 123(R), we were permitted to record the tax benefit associated with the excess of tax deductible stock-based compensation over the amount recognized for financial accounting purposes in our financial statement NOL, subject to SFAS No. 109’s realization criteria. Accordingly, the tax return reporting and financial statement NOL carryforward amounts described above include excess tax benefits recognized in 2005 and prior years related to the exercise of non-qualified employee stock options and vested stock awards. The full amount of the related tax benefits have been offset through our deferred tax asset valuation allowance. The associated excess tax benefits will be charged to equity upon the reversal of the associated valuation allowances in future periods.
The change in valuation allowance is as follows:
Section 382 of the Internal Revenue Code (“Section 382”) imposes limitations on a corporation’s ability to utilize NOLs if it experiences an “ownership change.” In general terms, an ownership change may result from transactions increasing the ownership percentage of certain stockholders in the stock of the corporation by more than 50 percentage points over a three year period. In the event of an ownership change, utilization of our NOLs would be subject to an annual limitation under Section 382 determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate (which is 4.49% for December 2007). Any unused annual limitation may be carried over to later years. The amount of the limitation may, under certain circumstances, be increased by built-in gains held by us at the time of the ownership change that are recognized in the five year period after the change. We are currently assessing ownership changes and the impact, if any, that a potential ownership change may have on limiting the ability of the Company to fully utilize the US NOL carryforward.
We are subject to taxation in the United States and Kazakhstan. Our federal income tax returns in the United States are subject to examination for the tax years ended December 31, 2002 through December 31, 2006. Our subsidiary’s tax return in Kazakhstan is subject to examination for the tax year ended December 31, 2007.
Note 8. Commitments and Contingencies
International Commitments
Through our subsidiary Caspi Neft, we are subject to the terms of License 1557 and the related exploration and production contracts covering 14,111 acres in the Field in Kazakhstan. In connection with the exploration contract, and the extensions of it, we have committed to spend approximately $76.6 million on development of the Field through April 2009. As of December 31, 2006, the cumulative capital expenditures which are creditable to our obligation under the contract have exceeded the minimum contract commitment. The production contract provides, among other things, a minimum seven-year work program commitment of $59.6 million for the continued development of the Field.
Purchase commitments are made in the ordinary course of business in connection with ongoing operations in the Field.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Our operations are subject to various levels of government controls and regulations in the United States, the Republic of Kazakhstan and the Russian Federation. 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 Kazakhstan and the Russian Federation, 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
We as an owner and operator of oil and gas properties, are 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.
Legal
On July 18, 2007, Canam Services, Inc. (“Canam”), a supplier of tubing products, filed suit in the 151st Judicial District Court of Harris County, Texas asserting a cause of action against us based upon alleged breach of a guaranty agreement covering certain accounts payable of Caspi Neft. Canam seeks recovery from us in the amount of $1,986,633 plus fees and costs. We denied all of Canam’s material allegations and on September 5, 2007, filed an answer denying each and every material allegation contained in the Canam complaint. Subsequently, Canam reduced the recovery amount to $756,727 plus interest, fees and costs. We plan to vigorously defend this claim and have not recorded any reserve above our recorded accounts payable as of December 31, 2007.
Lease Commitments
We have operating leases for office facilities and certain equipment. Net rental expense under all operating leases and rental agreements was $2,030,000, $2,192,000, and $570,000 in 2007, 2006 and 2005, respectively. We lease office facilities in Houston and Kazakhstan. Future minimum lease commitments under operating leases are as follows:
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Note 9. Business Segment Information
Our business activities relate solely to oil and gas exploration, development and production. Our primary emphasis since our formation in 2000 has been the development of the Field and substantially all of our assets are located in Kazakhstan. For each of the three years ended December 31, 2007 substantially all of our results of operations consisted of revenues, operating, general and administrative, and other costs associated with our operations in Kazakhstan.
For the year ended December 31, 2007, four customers accounted for approximately 24%, 16%, 14% and 11%, respectively, of consolidated revenue. For the year ended December 31, 2006, three customers accounted for approximately 30%, 28% and 17%, respectively, of consolidated revenue. For the year ended December 31, 2005, two customers accounted for approximately 38% and 37%, respectively, of consolidated revenue.
Note 10. Supplemental Financial Information
Other Assets
Other assets at December 31, 2007, consisted of deferred financing costs of $8,572,000, net of amortization, a note receivable of $500,000 from an unrelated third party and a $275,000 deposit. Other assets at December 31, 2006, consisted of debt financing costs of $11,464,000, net of amortization, and a note receivable of $500,000 from an unrelated third party.
Accrued Liabilities
Accrued liabilities consisted of the following:
Note 11. Subsidiary Guarantors
In December 2005, TEI issued an aggregate of 250,000 Units, consisting of (i) an aggregate $250 million principal amount of senior its secured notes due 2010 and (ii) warrants to purchase approximately 17.3 million shares of the our common stock. We and all of our material subsidiaries fully and unconditionally guaranteed the senior secured notes. Prior to the Units offering, we financed our operations primarily through borrowings from banks in Kazakhstan or other private sources. As previously disclosed in 2005 and prior years, substantially all of our assets are located in Kazakhstan and substantially all of our revenue, operating expenses, general and administrative expenses and other costs were and currently are associated with the operations of our principal
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
subsidiary, Caspi Neft, in Kazakhstan. Accordingly, there was no requirement for condensed consolidating financial information and the results for 2004 are not presented herein due to lack of comparability, because the information is not material for evaluation of the sufficiency of the guarantee and the omission of the information does not cause the financials to be inaccurate in reasonable detail.
The following is condensed consolidating financial information for the company, the Issuer, the subsidiary guarantors and the subsidiary non-guarantors of the senior secured notes for the three years ending December 31, 2007:
Condensed Consolidating Balance Sheet (in thousands)
Condensed Consolidating Statements of Operations (in thousands)
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Condensed Consolidating Statements of Cash Flow (in thousands)
Condensed Consolidating Balance Sheet (in thousands)
Condensed Consolidating Statements of Operations (in thousands)
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Condensed Consolidating Statements of Cash Flow (in thousands)
Condensed Consolidating Statements of Operations (in thousands)
Condensed Consolidating Statements of Cash Flow (in thousands)
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Note 12. Supplemental Oil and Gas Disclosures (Unaudited)
Costs Incurred
Costs incurred in oil and gas property acquisition, exploration and development activities, whether expensed or capitalized, are reflected in the table below. This schedule does not include the costs of acquiring the minority interest in Caspi Neft and the carried working interest of approximately $138,314,000.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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.
Oil and Gas Reserve Information
Basis of Presentation
Proved oil and gas reserve quantities are based on estimates prepared by Ryder Scott Company, independent petroleum engineers. There are numerous uncertainties in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. These uncertainties are greater for properties which are undeveloped or have a limited production history, such as the Field. The following reserve data represents estimates only and actual reserves may vary substantially from these estimates. All of our proved reserves were in Kazakhstan as of December 31, 2006, 2005 and 2004. Our net quantities of proved developed and undeveloped reserves of crude oil and changes therein are reflected in the table below.
As of December 31, 2007, we owned a 100% working interest in the Field, subject to government royalties and an additional 3.5% net revenue interest retained by a third party in connection with our buyout of our former partners to be deducted from the remaining revenue interest. The effect of this overriding revenue interest is reflected in the calculation of the Company’s net proved reserves and future net cash flows.
As of December 31, 2007, we operated under both a production contract and an exploration contract. The exploration contract associated with the License had an original six-year term which expired in April 2005 and
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
has been extended through April 2009, The production contract for the Field was signed by the Kazakhstan government on December 29, 2006 with a term of 25 years, ending on December 29, 2031. The net revenue interests used in this report are calculated from a sliding-scale royalty payment based on gross annual production and made to the Kazakhstan government during the period of the production contract of this license, and an additional 3.5% net revenue interest retained by a third party. Based on the forecast annual production, the government royalty rate is between 2.0% to 2.2% and is capped at 6%.
As of December 31, 2007, we had 12 wells producing, five wells shut-in awaiting work over and three new wells, the K-2H, K-3 and SA-32, which began producing in the first quarter of 2008. Additionally, we were injecting water into SA-4 under a pilot injection program.
The proved reserves as of December 31, 2007 represent the reserves that were estimated to be recovered from 21 wells (South Alibek 1, 2, 3, 4, 5, 11, 12, 13, 14, 15, 16, 17, 21, 23, 27 and in-fill wells 31, 32, 35, K-1, K-2 and K-3), and a total of 45 offset locations not yet drilled. Reserves have been allocated to in-fill wells which may have been previously allocated to existing wells. The redrilling of two wells and the deepening of three wells are also included for the full recovery of the estimated reserves. The redrills include SA-4, which is considered to have reservoir damage that prevented placing the well on production, and SA-5 to capture reserves remaining below the horizontal sidetrack. All direct offset well locations in this report are proved undeveloped and are based on 80 acre drainage patterns unless current developed completions are estimated to drain an area larger than their volumetric assignment. In this case, the reserves of certain offset locations have been reduced. All locations have a scheduled KT1 and a KT2 reservoir completion and each of these reservoir completions includes the cost of drilling a separate wellbore. All reserves included in this report were estimated using either historical performance or volumetric methods. Our future drilling plans may include infill drilling on tighter spacing and horizontal wells; however, the effect of these future plans have not been considered in this SEC report.
The cost of 15 wells has been included in this report for water injection into the KT1 reservoir and the cost of 13 wells has been included for water injection into the KT2 reservoir. The first pilot water injection well started injection in October 2007 using well SA-4. The specific location of the remaining injection wells has not been identified; therefore, the reservoir response to the water injection has not been assigned to specific wells, but a total estimated waterflood recovery from each reservoir is included in the reserve forecasts to represent a waterflood type curve performance and recovery estimate of each reservoir.
A 15% primary recovery factor was assigned to each developed and undeveloped well in the KT1 and KT2 reservoirs. A secondary recovery factor of 15% was assigned to the KT1 waterflood and to the KT2 waterflood. The total primary and secondary recovery of 30% was based on analogy data from other fields.
An estimated annual decline rate (ADR) of 25% was assigned to the primary forecasts of the undeveloped wells. The final decline assigned to the KT1 and KT2 waterflood type curve forecasts were also based on an approximate 25% ADR.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Estimated Quantities of Net Proved Crude Oil Reserves
(Quantities in thousands of barrels)
The downward revision of previous reserves estimates was primarily due to a reduction of the KT2 reserves as a result of a revised correlation of the KT2 zonation and a reassessment of reservoir mapping based on additional log analysis from infill drilling.
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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, 2007, 2006 and 2005 were $73.58, $35.59 and $42.45 per barrel, respectively. The sales prices were based on the last sales price received for December 2007, 2006 and 2005, respectively. No value was assigned to natural gas reserves, as there is not currently an established market or pipeline facilities for gas sales. Changes in prices and cost levels, as well as the timing of future development costs, may cause actual results to vary significantly from the data presented. This information is not intended to represent a forecast or fair market value of the Company’s oil and gas assets, but does present a standardized disclosure of discounted future net cash flows that would result under the assumptions used. The standardized measure of discounted future net cash flows relating to proved oil and gas reserves for 2007, 2006 and 2005 were as follows:
Standardized Measure of Discounted Future Net Cash Flows
(In thousands)
Index to Financial Statements TRANSMERIDIAN EXPLORATION INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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
(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, 2007 and 2006.
Index to Financial Statements
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our management has established and maintains a system of disclosure controls and procedures to provide reasonable assurances 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 the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
We carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 under the Exchange Act as of December 31, 2007. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as of December 31, 2007 were effective in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over our financial reporting as that term is defined in Rule 13a-15(f) of the Exchange Act. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Our control environment is the foundation for our system of internal control over financial reporting and is an integral part of our Code of Business Conduct and Ethics and our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit timely preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
In order to evaluate the effectiveness of our internal control over financial reporting as of December 31, 2007, as required by Section 404 of the Sarbanes-Oxley Act of 2002, our management conducted an assessment, including testing, based on the criteria set forth in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting and, based on that evaluation, concluded that, as of December 31, 2007, our internal control over financial reporting was effective.
Index to Financial Statements UHY LLP, an independent registered public accounting firm, has audited our internal control over financial reporting as of December 31, 2007, as stated in their report which appears herein.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Index to Financial Statements REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and
Stockholders of Transmeridian Exploration Incorporated:
We have audited Transmeridian Exploration Incorporated and subsidiaries’ (the”Company”) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Transmeridian Exploration Incorporated and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Transmeridian Exploration Incorporated and subsidiaries as of December 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2007, and our report dated March 28, 2008, expressed an unqualified opinion on those consolidated financial statements.
/s/ UHY LLP
Houston, Texas
March 28, 2008
Index to Financial Statements
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
Item 10. Directors, Executive Officers and Corporate Governance.
The information required by Item 10 regarding our executive officers appears in a separately captioned heading after Item 4 in Part I of this report. The other information required by Item 10 is incorporated by reference to our definitive proxy statement relating to our 2008 annual meeting of stockholders (the “2008 Proxy Statement”), which proxy statement will be filed pursuant to Regulation 14A within 120 days after the end of the last fiscal year.
Item 11.
Item 11. Executive Compensation.
The 2008 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 and Related Stockholder Matters.
The 2008 Proxy Statement is hereby incorporated by reference for the purpose of providing information about security ownership of certain beneficial owners and management and related stockholder matters.
Equity Compensation Plan Information
The information in the following table is presented as of December 31, 2007 with respect to the shares of our common stock that may be issued upon the exercise of stock options and restricted stock units granted under equity compensation plans that have been approved by our stockholders, namely our 2006 Incentive Plan (which amended and restated our 2001 Incentive Stock Option Plan) and our 2003 Stock Compensation Plan. We have not issued any warrants or other rights under these equity compensation plans to acquire any of our equity securities.
(a) The 2006 Incentive Plan provides for the issuance of up to an aggregate of 10% of the total shares of our common stock outstanding from time to time, less the number of shares underlying unexercised options as of the date the 2006 Incentive Plan was approved by shareholders (i.e., May 30, 2006)
Index to Financial Statements
Item 13.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
The 2008 Proxy Statement is hereby incorporated by reference for the purpose of providing information about certain relationships and related transactions and director independence.
Item 14.
Item 14. Principal Accounting Fees and Services.
The 2008 Proxy Statement is hereby incorporated by reference for the purpose of providing information about principal accounting fees and services.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a)(1) Financial Statements. Reference is made to the Index to Consolidated Financial Statements appearing under Item 8 hereof.
(a)(2), (c) Financial Statement Schedules. All financial statement schedules are omitted because they are not required under the related instructions, are inapplicable or the required information has been included in the consolidated financial statements or the accompanying notes to consolidated financial statements appearing under Item 8 hereof.
(a)(3), (b) Exhibits. Reference is made to the Exhibit Index beginning on page E-1 hereof.
Index to Financial Statements SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TRANSMERIDIAN EXPLORATION INCORPORATED
/s/ LORRIE T. OLIVIER
Lorrie T. Olivier
Chairman of the Board,
President and Chief Executive Officer
Date: March 28, 2008
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.
Index to Financial Statements
EXHIBIT INDEX
E-1
Index to Financial Statements
E-2
Index to Financial Statements
E-3
Index to Financial Statements
E-4
Index to Financial Statements
E-5
Index to Financial Statements
E-6
Index to Financial Statements
 Filed herewith.
E-7