Form 10-K
Table of Contents

                      

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-K

 

 

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number 001-34574

 

 

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

 

 

 

Bermuda   None

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

Akmerkez B Blok Kat 5-6

Nisbetiye Caddesi 34330 Etiler, Istanbul, Turkey

  None
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: +90 212 317 25 00

 

 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Name of each exchange on which registered

Common shares, par value $0.01   NYSE Amex

Securities registered pursuant to Section 12(g) of the Act: None

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  þ    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large accelerated filer   ¨    Accelerated filer   þ
Non-accelerated filer   ¨ (Do not check if a smaller reporting company)    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  þ

The aggregate market value of common shares, par value $0.01, held by nonaffiliates of the registrant, based on the last sale price of the common shares on June 30, 2010 (the last business day of the registrant’s most recently completed second fiscal quarter), was approximately $482.5 million. For purposes of this computation, all officers, directors and 10% beneficial owners of the registrant are deemed to be affiliates. Such determination should not be deemed an admission that such officers, directors or 10% beneficial owners are, in fact, affiliates of the registrant.

As of April 15, 2011, there were 346,234,355 common shares outstanding.

 

 

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2011 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates.

 

 

 


Table of Contents

TRANSATLANTIC PETROLEUM LTD.

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2010

INDEX

 

          Page  

PART I

        1   

Item 1.

   Business      1   

Item 1A.

   Risk Factors      12   

Item 1B.

   Unresolved Staff Comments      24   

Item 2.

   Properties      24   

Item 3.

   Legal Proceedings      41   

Item 4.

   Reserved      41   

PART II

        43   

Item 5.

   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities      43   

Item 6.

   Selected Financial Data      45   

Item 7.

   Management’s Discussion and Analysis of Financial Condition and Results of Operations      45   

Item 7A.

   Quantitative and Qualitative Disclosures about Market Risk      58   

Item 8.

   Financial Statements and Supplementary Data      60   

Item 9.

   Changes in and Disagreements With Accountants on Accounting and Financial Disclosure      60   

Item 9A.

   Controls and Procedures      60   

Item 9B.

   Other Information      62   

PART III

        63   

Item 10.

   Directors, Executive Officers and Corporate Governance      63   

Item 11.

   Executive Compensation      63   

Item 12.

   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters      63   

Item 13.

   Certain Relationships and Related Transactions, and Director Independence      63   

Item 14.

   Principal Accounting Fees and Services      63   

PART IV

        64   

Item 15.

   Exhibits and Financial Statement Schedules      64   

 

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Forward-Looking Statements

Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of applicable U.S. and Canadian securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “plans,” “expects,” “estimates,” “budgets,” “intends,” anticipates,” “believes,” “projects,” “indicates,” “targets,” “objective,” “could,” “should,” “may” or other similar words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: fluctuations in and volatility of the market prices for natural gas, natural gas liquids and oil products; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; global economic conditions, particularly in the countries and provinces in which we carry on business, especially economic slowdowns; actions by governmental authorities including increases in taxes, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; the negotiation and closing of material contracts; future capital requirements and availability of financing; estimates and economic assumptions used in connection with our acquisitions; risks associated with drilling and operating wells; actions of third party co-owners of interests in properties in which we also own an interest; our ability to effectively integrate companies and properties that we acquire; and the other factors discussed in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”) and Canadian securities regulatory authorities. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors; our course of action would depend upon our assessment of the future considering all information then available. In that regard, any statements as to future natural gas or oil production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital program; drilling of new wells; demand for natural gas and oil products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves; dates by which transactions are expected to close; future cash flows; uses of cash flows; collectibility of receivables; availability of trade credit; expected operating costs; changes in any of the foregoing and other statements using forward-looking terminology are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.

Readers should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements.

 

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Glossary of selected oil and natural gas terms

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this Annual Report on Form 10-K.

2D seismic. Geophysical data that depict the subsurface strata in two dimensions.

3D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2D, or two-dimensional, seismic.

Appraisal wells. Wells drilled to convert an area or sub-region from the resource to the reserves category.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas.

Boe. Barrels of oil equivalent. Boe is not included in the DeGolyer and MacNaughton report and is derived by the Company by converting natural gas to oil in the ratio of six Mcf of natural gas to one Bbl of oil. The conversion factor is the current convention used by many oil and gas companies. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Commercial well; commercially productive well. An oil and natural gas well which produces oil and natural gas in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Completion. The installation of permanent equipment for the production of oil or natural gas, or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.

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

Dry hole; dry well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Exploitation. The continuing development of a known producing formation in a previously discovered field. To maximize the ultimate recovery of oil or natural gas from the field by development wells, secondary recovery equipment or other suitable processes and technology.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well.

Farm-in or farm-out. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location, the completion of other work commitments related to that acreage, or some combination thereof.

Formation. A succession of sedimentary beds that were deposited under the same general geologic conditions.

Fracture stimulation. A stimulation treatment involving the fracturing of a reservoir and then injecting water, sand and chemicals, such as proppants, into the fractures under pressure to stimulate hydrocarbon production in low-permeability reservoirs.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Initial production rate. Generally, the maximum 24 hour production volume from a well.

Mbbl. One thousand stock tank barrels.

Mboe. One thousand barrels of oil equivalent.

Mcf. One thousand cubic feet of natural gas.

 

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Mmbbl. One million stock tank barrels.

Mmboe. One million barrels of oil equivalent.

Mmcf. One million cubic feet of natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.

Overriding royalty interest. An interest in an oil or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.

Play. A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and gas reserves.

Present value of estimated future net revenues or PV-10. The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, without giving effect to derivative financial instrument activities, after deducting production and ad valorem taxes, future capital costs, abandonment costs and operating expenses, but before deducting future federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil and natural gas prices and operating and capital costs at the date indicated, at its acquisition date, or as otherwise indicated. We believe that the present value of estimated future net revenues before income taxes, while not a financial measure in accordance with U.S. generally accepted accounting principles, is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially.

Productive well. A productive well is a well that is not a dry well.

Proved developed reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate.

Proved reserves. Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

 

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Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

Recompletion. An operation within an existing well bore to make the well produce oil or gas from a different, separately producible zone other than the zone from which the well had been producing.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

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

Royalty interest. An interest in an oil or natural gas property entitling the owner to a share of oil and natural gas production free of costs of production.

Shale. Fine-grained sedimentary rock composed mostly of consolidated clay or mud. Shale is the most frequently occurring sedimentary rock.

Standardized Measure of discounted future net cash flows or the Standardized Measure. Under the Standardized Measure, future cash flows for the years ended December 31, 2010 and 2009 are estimated by applying the simple average spot prices for the trailing twelve month period using the first day of each month beginning on January 1 and ending on December 1 of each respective year, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end and future plugging and abandonment costs to determine pre-tax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.

Undeveloped acreage. License or lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct activities on the property and a share of production.

 

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PART I

 

Item 1. Business.

In this Annual Report on Form 10-K, references to “we,” “us,” “our,” or “the Company” refer to TransAtlantic Petroleum Ltd. and its subsidiaries on a consolidated basis. Unless stated otherwise, all sums of money stated in this Form 10-K are expressed in U.S. Dollars.

Development of Our Business

We are a vertically integrated, international oil and gas company engaged in the acquisition, exploration, development and production of crude oil and natural gas. We hold interests in developed and undeveloped oil and gas properties in Turkey, Morocco, Bulgaria and Romania. We own our own drilling rigs and oilfield service equipment, which we use to develop our properties in Turkey and Morocco. In addition, our drilling services business provides oilfield services and drilling services to third parties in Turkey and Iraq. As of April 1, 2011, approximately 44.2% of our outstanding common shares are beneficially owned by N. Malone Mitchell, 3rd, the chairman of our board of directors.

Strategic Transformation

In 2008, we changed our operating strategy from a prospect generator to a vertically integrated project developer. To execute this strategy, we entered into the following transactions:

 

   

in December 2008, we acquired Longe Energy Limited (“Longe”) from Longfellow Energy, LP (“Longfellow”) in consideration for the issuance of 39,583,333 common shares and 10,000,000 common share purchase warrants to Longfellow. At the time of the acquisition, Longe’s assets included drilling rigs and equipment as well as interests in the Tselfat and Guercif exploration permits in Morocco. Immediately after the Longe acquisition, we purchased an additional $8.3 million in drilling and service equipment, tubulars and supplies from Viking Drilling, LLC (“Viking Drilling”). Mr. Mitchell, his wife and his children indirectly own 100% of Longfellow. Dalea Partners, LP (“Dalea”) owns 85% of Viking Drilling. Mr. Mitchell and his wife own 100% of Dalea. In addition, Mr. Mitchell is a partner of Dalea and a manager of Dalea Management, LLC, the general partner of Dalea.

 

   

in March 2009, we acquired Incremental Petroleum Limited, now called Incremental Petroleum Pty Ltd (“Incremental”), for total consideration of $54.9 million. The acquisition of Incremental expanded our rig fleet and increased our workforce of field staff, engineers and geologists in Turkey. At the time of the acquisition, Incremental’s Turkish properties included the producing Selmo oil field, a 55% interest in the Edirne gas field and additional exploration acreage.

 

   

in July 2009, we acquired Energy Operations Turkey, LLC, now called Talon Exploration, Ltd. (“Talon”), for total cash consideration of $7.7 million. At the time of the acquisition, Talon’s assets included a 50% interest in the producing Arpatepe oil field and additional exploration acreage, inventory and seismic data.

 

   

in August 2010, we acquired Amity Oil International Pty Ltd (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”) for total cash consideration of $96.5 million. At the time of the acquisition, Amity’s and Petrogas’ Turkish properties included a producing gas field, completed gas wells awaiting connection to a pipeline and additional exploration acreage and equipment.

 

   

in February 2011, we acquired Direct Petroleum Morocco, Inc. (“Direct Morocco”), Anschutz Morocco Corporation (“Anschutz”) and Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”) for cash consideration of $2.0 million and the issuance of 8,924,478 common shares, for total consideration of $30.0 million. At the time of the acquisition, Direct Morocco and Anschutz owned a 50% working interest in the Ouezzane-Tissa and Asilah exploration permits in Morocco and Direct Bulgaria owned 100% of the working interests in the A-Lovech and Aglen exploration permits in Bulgaria.

 

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Drilling Services Business

Beginning with the acquisition of Longe in 2008, we have established a significant and comprehensive drilling services business. As of December 31, 2010, we owned six drilling rigs and four workover and completion rigs in Turkey, and we owned two drilling rigs in Morocco. In addition, we managed one drilling rig in Turkey for Viking Drilling and one drilling rig in Iraq for Maritas A.Ş. (“Maritas”) pursuant to management services agreements. We believe that ownership of our own drilling rigs and service equipment will enable us to lower drilling and operating costs over the long term and control the timing of the development of our properties, thereby providing a competitive advantage.

In 2010, we expanded our drilling services activities, particularly in Turkey, to include products and services used to drill and evaluate oil and natural gas wells. Through our wholly-owned subsidiary, Viking International Limited (“Viking International”), we provide the following oilfield services: wireline, pressure pumping (including fracture stimulation, acid stimulation and cementing), construction (including location building, road building and pipeline construction), rental tools and underbalanced drilling, pulling units, drilling fluids, inventory, yards and trucking, and mudlogging.

Through Viking International, we are able to provide a full range of services and materials to our exploration and production business, reducing costs over the long term and the need to rely on third party service providers. In addition, when our drilling rigs and equipment are not operating on our properties, we can use them to provide drilling and oilfield services to third parties in Turkey and northern Iraq. Viking International is aggressively pursuing third party work to generate additional returns on our capital investment. Viking International is not currently active in Bulgaria or Romania. During 2010, Viking International generated revenues of approximately $7.3 million from providing oilfield services to third parties in Turkey and the Kurdistan region of northern Iraq.

Through our wholly-owned subsidiary, Viking Geophysical Services, Ltd. (“Viking Geophysical”), we operate two seismic data acquisition crews with equipment capable of acquiring 2D, 3D and microseismic data. In 2010, our seismic crews acquired 774 kilometers of 2D seismic data, of which 262 kilometers were acquired for third parties, and 791 square kilometers of 3D seismic data, of which 365 square kilometers were acquired for third parties. During 2010, Viking Geophysical generated revenues of approximately $8.4 million from providing seismic services to third parties in Turkey.

Application of Modern Drilling and Completion Techniques in Turkey

Historically, the oil and gas exploration and production industry in Turkey has not used modern drilling and completion techniques. One of our strategies is to apply these modern techniques to our properties in Turkey. To implement this strategy, we began to drill wells using polycrystalline diamond compact bits and downhole motors and to utilize underbalanced drilling equipment. These technologies increase the speed at which wells can be drilled and in many cases reduce the cost of drilling wells. In addition, we have employed modern acid stimulation techniques and modern fracture stimulation techniques. Generally, acid stimulation removes damage near the wellbore caused by the invasion of drilling fluids and can make certain reservoirs, such as the carbonate reservoirs in the Selmo oil field, more productive. Fracture stimulation involves fracturing the reservoir and pumping proppants into the fractures to increase the flow of oil or natural gas from the wellbore. In North America, many reservoirs are routinely fracture stimulated and would not produce oil or natural gas on a commercial basis without fracture stimulation. In the fourth quarter of 2010, we began the first fracture stimulations of natural gas wells in the Thrace Basin in northwestern Turkey. We plan to continue our fracture stimulation program in the Thrace Basin and are considering the use of fracture stimulation for our wells in Bulgaria and Romania. We anticipate that employing fracture stimulation techniques will result in the commercial development of natural gas reserves that would have not been commercial otherwise.

Recent Developments

During 2010 and the first quarter of 2011, we completed the following material acquisitions, financings and operations:

Commencement of Edirne Gas Sales. On April 8, 2010, we commenced natural gas sales from our Edirne gas field in northwestern Turkey. AKSA Dogolgaz Toptan Satis A.Ş. (“AKSA”), a natural gas distributor in Turkey, purchases all of our natural gas production from the Edirne field at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAŞ Petroleum Pipeline Corporation (“BOTAŞ”), the state-owned crude oil and natural gas pipelines and trading company in Turkey.

 

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TPAO Memorandum of Understanding. On April 9, 2010, we entered into a memorandum of understanding with Turkiye Petrolleri Anonim Ortakligi (“TPAO”), a Turkish government-owned oil and gas company, to explore for unconventional resources in Turkey. In the initial phase of the agreement, we will participate in two licenses, one in the Thrace Basin and one in southeastern Turkey, and will re-enter a total of four wells and drill a total of four wells. These wells will target tight sand and shale formations that do not produce under normal conditions.

Successful Completion of Bakuk-101 Well. During April and May 2010, with our partner and operator, Tiway Turkey, Ltd. (“Tiway”), we drilled a successful natural gas well, the Bakuk-101, with potential production of up to 10.0 Mmcf of natural gas per day. The Bakuk-101 well is located on License 4069, which is located in southeastern Turkey near the Syrian border. In November 2010, we re-entered the Bakuk-2 well, which failed to establish an oil leg in the reservoir. We have completed construction of a 23 kilometer, 6-inch pipeline from the Bakuk-101 well to an existing pipeline to the south and expect to begin limited natural gas sales in the second quarter of 2011. We are now evaluating options for further appraisal of the reservoir. As a result of drilling the Bakuk-101 well, we earned a 50% working interest in the Bakuk licenses.

Dalea Credit Agreement. On June 28, 2010, our wholly-owned subsidiary, TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) entered into a credit agreement with Dalea for the purpose of funding the acquisition of all of the shares of Amity and Petrogas and for general corporate purposes. The amounts due under the credit agreement accrue interest at a rate of three-month LIBOR plus 2.50% per annum. The Company borrowed an aggregate of $73.0 million under the credit agreement and used the proceeds to finance a portion of the purchase price of the shares of Amity and Petrogas.

Short-Term Secured Credit Agreement. On August 25, 2010, TransAtlantic Worldwide, entered into a $30.0 million short-term secured credit agreement with Standard Bank, Plc (“Standard Bank”). We borrowed $30.0 million under the short-term secured credit agreement and used the proceeds to finance a portion of the purchase price for the shares of Amity and Petrogas. See “Liquidity and Capital Resources—Short-Term Secured Credit Agreement.”

Completion of Amity and Petrogas Acquisition. On August 25, 2010, TransAtlantic Worldwide acquired all of the shares of Amity and Petrogas for total cash consideration of $96.5 million. Through the acquisition of Amity and Petrogas, we acquired interests ranging from 50% to 100% of eighteen exploration licenses and one production lease, consisting of approximately 1.3 million gross acres (1.0 million net acres) in the Thrace Basin and 730,000 gross and net acres in central Turkey, and equipment. With the completion of the acquisition, we added approximately 7.0 Mmcf of natural gas production per day in the Thrace Basin and approximately 10.0 Mmcf of natural gas production per day in completed gas wells in the Thrace Basin awaiting connection to a pipeline. We funded $66.5 million of the purchase price from borrowings under our credit agreement with Dalea and $30.0 million of the purchase price from borrowings under our short-term secured credit agreement with Standard Bank.

Sale of Common Shares. From September 30, 2010 through October 8, 2010, we closed a public offering of an aggregate of 30,357,143 common shares at a purchase price of $2.80 per share, raising gross proceeds of $85.0 million. Of the 30,357,143 common shares sold, we offered and sold 1,788,643 common shares to Dalea. The net proceeds from the offering, after deducting the placement agency fee and estimated offering expenses, were approximately $80.6 million. We used $19.0 million of the net proceeds to pay off the principal amount and accrued interest under the loan and security agreement between Viking International and Dalea, and we used the remainder of the net proceeds for general corporate purposes.

Pinnacle Turkey and TBNG Option Agreement. On November 8, 2010, TransAtlantic Worldwide entered into an option agreement with Mustapha Mehmet Corporation (“MMC”) regarding the purchase of all of the shares of Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) and Pinnacle Turkey, Inc. (“Pinnacle”). Pursuant to the option agreement, TransAtlantic Worldwide paid MMC an option fee of $10.0 million and had until February 11, 2011 to exercise the option to acquire all of the shares of TBNG and Pinnacle. On February 10, 2011, TransAtlantic Worldwide exercised its option under the option agreement.

On a combined basis, TBNG and Pinnacle currently produce approximately 25.0 Mmcf of natural gas per day and hold interests in a total of approximately 600,000 net onshore acres in Turkey. TBNG and Pinnacle sell their natural gas production through a wholly-owned pipeline distribution system.

Upon the closing of the transactions contemplated by the option agreement, TransAtlantic Worldwide or its affiliates or assigns would acquire all of the shares of TBNG and Pinnacle in consideration for (i) $100.0 million in cash, (ii) the issuance of 18.5 million of our common shares pursuant to a private placement, and (iii) the transfer of certain overriding royalty interests (ranging from 1% to 2.5% of the working interests owned by TBNG and Pinnacle on specified exploration licenses) to an affiliate of MMC. At closing, the $10.0 million option fee will be credited towards the cash purchase price. According to the terms of the option agreement, TransAtlantic Worldwide has the ability to transfer its rights to acquire all of the shares of TBNG and/or Pinnacle to an affiliate or a newly formed entity that is formed for the purpose of acquiring the shares. The closing of the TBNG and Pinnacle acquisition is subject to regulatory approval, stock exchange approval and customary closing conditions, and there is no assurance the transaction will close.

 

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TransAtlantic Worldwide intends to seek a total of $100.0 million from third party investors to fund the cash portion of the purchase price. At the time of closing, Pinnacle would own a 65% working interest in five onshore exploration licenses in the Thrace Basin and a 25% working interest in three shelf and five offshore licenses in the Sea of Marmara. Pinnacle would also own a 37.5% working interest in five exploration licenses in the Gaziantep area in southeastern Turkey. At the time of closing, TBNG would own the other 35% working interest in the five onshore licenses, 100% of the working interest in four production leases in the Thrace Basin, a 25% working interest in three shelf and five offshore licenses in the Sea of Marmara, drilling rigs and equipment. TBNG would remain the operator of the TBNG and Pinnacle licenses and production leases.

Valeura Energy Letter Agreement. On February 9, 2011, we entered into a letter agreement with Valeura Energy Inc. (“VEI”), whereby VEI offered to acquire 61.54% of the shares of Pinnacle and certain interests from Pinnacle and TBNG in certain exploration licenses and production leases on properties in the Thrace Basin and Gaziantep areas of Turkey, together with associated assets. VEI’s acquisition of these assets would have an effective date of October 1, 2010. Under the letter agreement, VEI would provide approximately $61.5 million in funding to acquire 61.54% of the shares of Pinnacle and certain assets.

Under the letter agreement, the parties agreed to negotiate in good faith the terms of certain definitive agreements, including agreements to transfer 61.54% of the shares of Pinnacle and certain assets, and to use reasonable commercial efforts to finalize the definitive agreements no later than April 25, 2011. If any of the conditions precedent of the letter agreement are not satisfied before closing or if closing has not occurred by July 11, 2011, any party is entitled to terminate its obligations under the letter agreement. If VEI’s acquisition of the interests in Pinnacle does not proceed as a result of a material breach by TransAtlantic Worldwide, us or VEI of the letter agreement, a material breach by TransAtlantic Worldwide of the TBNG option agreement or a material breach by TransAtlantic Worldwide or VEI of certain other agreements entered into in contemplation of the acquisition of TBNG and Pinnacle, the breaching party shall be liable to the non-breaching party for all direct damages, costs and expenses suffered by the non-breaching party as a direct result thereof, up to a maximum of $9.2 million.

Direct Petroleum Acquisition. On February 18, 2011, TransAtlantic Worldwide acquired Direct Morocco and Anschutz, and our wholly-owned subsidiary, TransAtlantic Petroleum Cyprus Limited (“TransAtlantic Cyprus”), acquired Direct Bulgaria. In addition, TransAtlantic Worldwide purchased from the seller, Direct Petroleum Exploration, Inc. (“Direct”), all of Direct’s right, title and interest in the amounts due to Direct by each of Direct Morocco, Anschutz and Direct Bulgaria. As consideration for the acquisition, TransAtlantic Worldwide paid $2.0 million in cash to Direct, and we issued 8,924,478 of our common shares to Direct in a private placement, for total consideration of $30.0 million. In addition, if certain post-closing milestones are achieved, we will issue additional consideration to Direct equal to: (i) $6.0 million worth of our common shares if the GRB-1 well in Morocco is a commercial success; (ii) $10.0 million worth of our common shares if the Deventci-R2 well in Bulgaria is a commercial success; and (iii) $10.0 million worth of our common shares if Direct Bulgaria receives a production concession for a specified area in Turkey.

In connection with the acquisition, we entered into a registration rights agreement whereby Direct is entitled to certain piggyback registration rights for the common shares issued to Direct, including any common shares issued to Direct as part of the additional consideration, for a period of six months following the date of issuance to Direct. The piggyback registration rights permit Direct to elect to have the common shares included in a registration statement filed by us, subject to the limitations and conditions set forth in the registration rights agreement.

At the time of closing, Direct Morocco and Anschutz owned a 50% working interest in the Ouezzane-Tissa and Asilah exploration permits, which cover an aggregate of approximately 2,356,000 acres (9,533 square kilometers) in northern Morocco. As a result of the acquisition, we own 100% of those exploration permits. Direct Bulgaria owns 100% of the working interests in the A-Lovech exploration permit and the Aglen exploration permit, subject to a 3% and a 1% overriding royalty interest, respectively, which cover an aggregate of approximately 600,000 acres (2,288 square kilometers) in northwestern Bulgaria. The A-Lovech permit contains the Deventci-R1 well, which discovered a reservoir in the Jurassic Orzirovo formation at a depth of approximately 4,200 meters. The well is currently producing approximately 250 Mcf of natural gas per day, on a limited test basis. We plan to appraise this discovery by drilling a second well, the Deventci-R2 well, on the A-Lovech exploration permit in 2011.

The A-Lovech exploration permit is also estimated to contain over 300,000 acres prospective for Etropole shale (at a depth of approximately 3,800 meters), which was recently certified as a geologic discovery by the Bulgarian government. We anticipate coring the Etropole shale interval, which will enhance the technical understanding of the potential of this shale play. The third established prospective area is a deep gas field on the Aglen exploration permit that produced approximately 9.0 Bcf of natural gas before being abandoned in the late 1990s.

Exploration, Development and Production

Turkey Exploration and Production. We began 2010 with interests in 25 onshore exploration licenses and one onshore production lease in Turkey. As of April 1, 2011, we held interests in 56 onshore exploration licenses and three onshore production leases covering a total of 6.4 million gross acres (6.0 million net acres) in Turkey.

Thrace Basin. Through the Amity and Petrogas acquisition in August 2010, we acquired a 100% working interest in the Alpullu production lease in the Thrace Basin in northwestern Turkey, a 50% working interest in the Gocerler production lease in the Thrace Basin and additional exploration licenses in the Thrace Basin and in southern Turkey. Zorlu Dogal Gaz Ithalat Ihracat ve Toptan Ticaret A.S. (“Zorlu”), a privately owned natural gas distributor in Turkey, purchases substantially all of our natural gas production from the Alpullu field at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAŞ. At the time of closing, natural gas production from the acquired properties was approximately 7.0 Mmcf per day net to our interest. In addition, there were wells capable of producing an additional 10.0 Mmcf of natural gas per day net to our interest upon connection to a pipeline. We are constructing a 20 kilometer, 10-inch pipeline to carry natural gas from the Alpullu gas field in the Thrace Basin to an existing pipeline. We expect to place all wells in production in the second quarter of 2011.

 

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In April 2010, we commenced natural gas sales from our Edirne gas field, which we acquired through the Incremental acquisition in 2009. AKSA purchases all of our natural gas production from the Edirne field at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAŞ.

For 2010, our net production of natural gas in the Thrace Basin, after royalties, was 1,707 Mmcf. For the fourth quarter of 2010, our net production of natural gas in the Thrace Basin, after royalties, was 887 Mmcf, or approximately 9,642 Mcf per day. We currently have 37 producing wells in the Thrace Basin, and we plan to drill between 30 and 40 new wells on our Thrace Basin licenses in 2011.

Southeastern Turkey. Through the Incremental acquisition in 2009, we acquired a 100% working interest in the Selmo production lease in southeastern Turkey. For 2010, our net production of crude oil in the Selmo field, after royalties, was approximately 631,000 Bbls of crude oil at an average rate of approximately 1,700 Bbls per day. Substantially all of our crude oil production is currently concentrated in the Selmo field. TPAO, a Turkish government-owned oil and gas company, and Türkiye Petrol Rafinerileri A.Ş. (“TUPRAS”), a privately-owned oil refinery in Turkey, purchase all of our crude oil production from the Selmo field. We currently have 39 producing wells in the Selmo field, and we plan to drill and complete at least 24 wells at Selmo in 2011. Production of oil from Selmo for the month of March 2011 averaged 2,833 Bbls per day, before royalties.

Through the Talon acquisition in July 2009, we acquired a 50% working interest in the producing Arpatepe exploration license. For 2010, our net production of crude oil in the Arpatepe field, after royalties, was approximately 58,700 Bbls at an average rate of approximately 160 Bbls per day. We currently have three producing wells in the Arpatepe field, and we plan to drill up to five additional wells at Arpatepe in 2011.

In May 2010, we acquired a 50% working interest in the Bakuk licenses in southeastern Turkey by drilling the Bakuk-101 well. The Bakuk-101 well was successful, with potential production of up to 10.0 Mmcf of natural gas per day. In November 2010, we re-entered the Bakuk-2 well, which failed to establish an oil leg in the reservoir. We have completed construction of a 23 kilometer, 6-inch pipeline from the Bakuk-101 well to an existing pipeline to the south and expect to begin limited natural gas sales in the second quarter of 2011.

Turkey Development. We also have substantial exploration acreage in Turkey. In April 2010, we entered into a memorandum of understanding with TPAO to explore for unconventional resources in Turkey. In the initial phase of the agreement, we will participate in two licenses, one in the Thrace Basin and one in southeastern Turkey, and will re-enter a total of four wells and drill a total of four wells. These wells will target tight sand and shale formations that do not produce under normal conditions.

In March 2010, we entered into a farm-in agreement with TBNG to acquire a 50% interest in five Gaziantep licenses in south-central Turkey. To earn that interest, we will pay 62.5% of total drilling and seismic costs until 12.5% of total drilling and seismic costs paid equals $750,000. Thereafter, we will pay 50% of drilling and seismic costs incurred. We expect to terminate this farm-in agreement upon our acquisition of TBNG, which is expected to occur in the second quarter of 2011.

Through the Incremental acquisition in 2009, we acquired the six Tuz Golu and two Haymana exploration licenses in central Turkey and the four Midyat licenses in southeastern Turkey. We have also expanded our portfolio of properties in Turkey by applying for licenses directly with the Turkish General Directorate for Petroleum Affairs (“GDPA”). In 2009, we were awarded eight Malatya licenses. In 2010, we were awarded the Alpullu exploration license, the Bakuk East license, six Tuz Golu South licenses and thirteen Sivas Basin licenses. Each of these licenses was awarded to us based on an approved work program.

Morocco Exploration and Development. As of April 1, 2011, we owned interests in eight onshore exploration permits in northern Morocco. We are the operator and 100% working interest owner in the Tselfat exploration permit (subject to a 25% participation interest by the national oil company of Morocco, Office of National des Hydrocarbures et des Mines (“ONHYM”) once production is achieved), which was awarded to us in May 2006. As part of our recent extension of the license period, in January 2011 we relinquished 45% of our Tselfat exploration permit acreage. The Tselfat exploration permit covers three existing fields; Haricha, Brou Draa and Tselfat. In 2009, we drilled the HR-33 bis well in the Haricha field to help assess whether there is the opportunity for redevelopment of the previously produced but abandoned Haricha field. We have put the HR-33 bis well on an extended production test to determine its commerciality. We commenced crude oil production in January 2011. The crude oil produced during the test is trucked approximately 200 kilometers to a refinery operated by Société Anonyme Marocaine de I’Industrie de Raffinage (“SAMIR”) in Mohammedia, Morocco. If testing confirms the commerciality of the HR-33 bis well, we plan to delineate the oil field and apply for an exploitation concession. In 2010, we drilled the BTK-1 well and the GUW-1 well, which have both been plugged and abandoned after failing to

 

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discover hydrocarbons in commercial quantities. We plan to drill three exploration wells to a depth of at least 1,500 meters on the Tselfat exploration permit in 2011.

We are the operator and 100% working interest owner in the two Asilah exploration permits (subject to a 25% participation interest by ONHYM once production is achieved). In December 2010, we commenced drilling the GRB-1 well, which reached total depth in March 2011. The GRB-1 well targeted tertiary-aged reservoirs, and in 2011, we plan to test numerous intervals that had gas shows while drilling.

We are the operator and 100% working interest owner in five Ouezzane-Tissa exploration permits. In 2010, we drilled at our cost three wells on the Ouezzane-Tissa exploration permits. The first well, the OZW-1 well, encountered an extremely high pressure water zone near 9,000 feet which we could not drill through and was plugged and abandoned. We drilled the second well, the HKE-1 well, which did not reach target depth and was plugged and abandoned. The third well, the HKE-1 bis well, did not discover hydrocarbons in commercial quantities, and is being plugged and abandoned. We plan to relinquish the Ouezzane-Tissa exploration permits in 2011, and upon ONHYM’s acceptance of our final report, we expect to have $3.0 million in work commitment bank guarantees returned to us.

We were awarded two Guercif exploration permits in January 2008. We are the operator and 80% working owner of the Guercif permits. As part of our Guercif work program, we re-entered, logged and tested the MSD-1 well, which we completed as a dry hole in the fourth quarter of 2008. The logs and test failed to establish the presence of hydrocarbons. In December 2010, we abandoned our interests in the Guercif exploration permits. As part of our agreement with ONHYM for the abandonment of the Guercif exploration permits, we transferred an obligation to drill one well from the Guercif exploration permits to the Tselfat exploration permit. Upon ONHYM’s acceptance of our final report, we expect to have $2.0 million in work commitment bank guarantees returned to us.

Bulgaria Exploration and Development. As of April 1, 2011, we owned interests in two onshore exploration permits in Bulgaria. We have a 100% working interest in the A-Lovech and Aglen exploration permits, subject to 3% and 1% overriding royalty interests, respectively, in northwestern Bulgaria. The A-Lovech permit contains the Deventci-R1 well, which discovered a reservoir in the Jurassic Orzirovo formation at a depth of approximately 4,200 meters. The well is currently producing approximately 250 Mcf of natural gas per day on a limited test basis, which is sold to a compressed natural gas facility adjacent to the Deventci-R1 well. We plan to appraise this discovery by drilling a second well, the Deventci-R2 well, on the A-Lovech permit in 2011. We have submitted an application for a production concession covering approximately 160,000 acres of the A-Lovech permit.

The A-Lovech permit is also estimated to contain over 300,000 acres prospective for Etropole shale (at a depth of approximately 3,800 meters), which was recently certified as a geologic discovery by the Bulgarian government. We anticipate coring the Etropole shale interval, which will enhance the technical understanding of the potential of this shale play.

Romania Exploration and Development. As of April 1, 2011, we owned an interest in an onshore production license in Romania. In June 2009, we entered into an agreement with Sterling Resources Ltd. (“Sterling”) to farm-in to Sterling’s Sud Craiova Block E III-7 in western Romania. In exchange for a 50% working interest, we agreed to drill three exploration wells on the Sud Craiova license, each to a depth of approximately 3,280 feet (1,000 meters). We drilled three wells at our cost on the Sud Craiova license in 2009 and 2010, all of which have been plugged and abandoned for failing to discover hydrocarbons in commercial quantities. We are currently reprocessing seismic data previously shot over the Sud Craiova license and plan to drill an exploration well to test the Silurian-aged shale formations at a depth of approximately 4,200 meters. Sterling is the operator of the Sud Craiova license.

In February 2006, we were awarded the Izvoru, Vanatori and Marsa production licenses. We drilled a total of five wells on these licenses in 2009 and 2010, all of which were plugged and abandoned after failing to discover hydrocarbons in commercial quantities. In December 2010, we relinquished our interests in each of these three licenses.

Drilling Services Business

At December 31, 2010, we owned six drilling rigs and four workover and completion rigs in Turkey, and we owned two drilling rigs in Morocco. In addition, we managed one drilling rig in Turkey for Viking Drilling and one drilling rig in Iraq for Maritas pursuant to management services agreements. We believe that ownership of our own drilling rigs and service equipment will enable us to lower drilling and operating costs over the long term and control the timing of the development of our properties, thereby providing a competitive advantage.

In 2010, we expanded our drilling services activities, particularly in Turkey, to include products and services used to drill and evaluate oil and natural gas wells. Through Viking International, we provide the following oilfield services: wireline,

 

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pressure pumping (including fracture stimulation, acid stimulation and cementing), construction (including location building, road building and pipeline construction), rental tools and underbalanced drilling, pulling units, drilling fluids, inventory, yards and trucking, and mudlogging.

Through Viking International, we are able to provide a full range of services to our exploration and production business, reducing costs and the need to rely on third party service providers. In addition, when our drilling rigs and equipment are not operating on our properties, we can use them to provide drilling and oilfield services to third parties. Viking International is aggressively pursuing third party work to generate additional returns on our capital investment. Viking International is not currently active in Bulgaria or Romania. During 2010, Viking International generated revenues of approximately $7.3 million from providing oilfield services to third parties in Turkey and the Kurdistan region of northern Iraq.

Through Viking Geophysical, we operate two seismic data acquisition crews with equipment capable of acquiring 2D, 3D and microseismic data. In 2010, our seismic crews acquired 774 kilometers of 2D seismic data, of which 262 kilometers were acquired for third parties, and 791 square kilometers of 3D seismic data, of which 365 square kilometers were acquired for third parties. During 2010, Viking Geophysical generated revenues of approximately $8.4 million from providing seismic services to third parties in Turkey.

Planned 2011 Operations

We continue to actively explore and develop our existing oil and gas properties in Turkey, Morocco and Bulgaria and evaluate the opportunities for further activities in Romania. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. In 2011, we are focused on accomplishing the following objectives:

 

   

Increasing Production. Our goal is to achieve a production rate of 10,000 Boe per day in Turkey by the end of 2011. We plan to increase our crude oil and natural gas production in Turkey through continuous drilling in Selmo and the Thrace Basin, the completion of pipelines to bring shut-in gas to market, the application of modern well stimulation techniques such as gelled acidizing and fracture stimulation, and the introduction of directional drilling.

 

   

Securing Partners to Reduce Exploration Risk. We are actively seeking partners for our exploration acreage in Turkey, Morocco, Bulgaria and Romania. Through farm-outs, we expect to reduce our exploration risk and accelerate the exploration and development activities on the farmed-out properties. We have begun consolidating and analyzing well data and seismic data for our properties in Bulgaria and our exploration acreage in Turkey. It is our intention to remain as operator in the properties that we farm out.

 

   

Integrating Acquisitions. We expect to complete the acquisition of TBNG and Pinnacle in the second quarter of 2011, which will bring additional acreage, production, personnel and equipment into our Turkey operations. We will continue to integrate the recent acquisitions of Amity, Petrogas and Direct Bulgaria.

Capital expenditures for 2011 are expected to range between $125.0 million and $150.0 million. Approximately 50% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Approximately 35% of these anticipated expenditures will occur in southeastern Turkey, devoted to developing crude oil production at Selmo and Arpatepe and drilling exploratory wells on various licenses. The balance of the estimated budget is divided between exploration activities in Morocco and Romania. We are seeking a joint venture partner to fund our anticipated capital expenditures in Bulgaria in 2011. If cash on hand, borrowings from our senior secured credit facility and cash flow from operations are not sufficient to fund our capital expenditures, then we will either curtail our discretionary capital expenditures or seek other funding sources. We currently plan to execute the following drilling and exploration activities in 2011:

Turkey. We plan to drill approximately 90-100 wells during 2011, including wells to be drilled on acreage held by TBNG, which we expect to acquire in the second quarter of 2011. If we do not complete the acquisition of TBNG, the number of wells we expect to drill in 2011 may change. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill.

Morocco. On our Tselfat exploration permit, we are currently producing oil from the HR-33 bis well on an extended production test to determine if the well is commercially viable. If testing confirms the HR-33 bis well as a commercial well, we plan to delineate the oil field, apply for an exploitation concession and drill at least one additional well in the Haricha field. We also plan to drill the TKN-1 well to test another 3D seismic prospect that is similar to the Haricha field. If the TKN-1 well is a commercial well, we would likely drill an additional appraisal well. We plan to drill three exploration wells to a depth of at least 1,500 meters on the Tselfat exploration permit in 2011. On our Asilah exploration permit, we are planning to test the recently to completed the GRB-1 well, which had substantial gas shows during drilling. If that well is completed as a commercial well, we would likely drill additional appraisal wells and develop plans to commercialize those wells.

 

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Bulgaria. We plan to drill the Deventci-R2 well on the A-Lovech exploration permit to appraise the Deventci-R1 well gas discovery. While drilling the appraisal well on the A-Lovech permit, we plan to test the productivity of the Etropole shale interval. We may also drill an additional appraisal well on the Aglen exploration permit. If the appraisal well on the Aglen permit is successful, we anticipate planning the construction of a pipeline to connect the Deventci wells to a natural gas pipeline to the south. We are seeking to enter into a joint venture where the joint venture partner would carry us in the capital expenditures incurred in Bulgaria in 2011.

Romania. We plan to drill an exploration well to test the Silurian-aged shale formations present on the Sud Craiova license. We may also drill an exploration well to test the Coyote oil prospect on the southeastern portion of the Sud Craiova license.

Drilling Services Business. We plan to continue to increase drilling services revenues by providing drilling services and seismic acquisition services to third parties in Turkey and northern Iraq.

Principal Capital Expenditures and Divestitures

The following table sets forth our principal capital expenditures during 2010 (in thousands of dollars):

 

Expenditure Type

   Year Ended
December 31,
2010
 

Oil and gas properties

   $ 53,766   

Drilling services and other equipment

     58,817   
        

Subtotal

     112,583   
        

Acquisition of Amity and Petrogas, net of cash received

     96,248   
        

Total capital expenditures

   $ 208,831   
        

There were no capital divestitures during 2010.

Principal Markets

In accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, Segment Reporting (“ASC 280”), we have two reportable operating segments, exploration and production of oil and natural gas (“E&P”) and drilling services, and three reportable geographic segments: Romania, Turkey and Morocco. For financial information about our operating segments and geographic areas, refer to “Note 14—Segment information” to our consolidated financial statements.

Customers

During 2010, substantially all of our crude oil production was concentrated in the Selmo field in Turkey. TPAO, a Turkish government-owned oil and gas company, and TUPRAS, a privately-owned oil refinery in Turkey, purchase all of our crude oil production from the Selmo field. During 2010, we sold $48.0 million of crude oil to TPAO and TUPRAS, representing 56.1% of our total revenues. We sell our crude oil to TPAO and TUPRAS pursuant to two separate agreements.

Our wholly-owned subsidiary, TransAtlantic Exploration Mediterranean International Pty. Ltd. (“TEMI”), entered into a domestic crude oil purchase and sale agreement with TUPRAS, effective as of January 26, 2009. Under the purchase and sale agreement, TUPRAS purchases crude oil produced by TEMI and delivered to TEMI’s BOTAŞ/Batman tanks and to the BOTAŞ/Dörtyol plant. The price of the crude oil delivered pursuant to the purchase and sale agreement is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. The purchase and sale agreement had an initial one year term, which automatically renews thereafter for successive one-year terms unless earlier terminated in writing by either party.

TEMI also entered into a domestic crude oil swap agreement with TPAO, effective as of January 1, 2010. Under the swap agreement, TPAO purchases crude oil produced by TEMI from the Selmo oil field. The swap agreement requires TEMI to deliver oil in-kind for the royalties due to the Republic of Turkey. In addition, the swap agreement required TEMI to pay 3% of the insurance amount paid by TPAO to cover transportation of crude oil. Pricing of the crude oil delivered pursuant to the swap agreement is determined by a pricing formula provided under Petroleum Market Law No. 5015 under the laws of

 

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the Republic of Turkey. The swap agreement had an initial one year term, which automatically renews thereafter for successive one-year terms unless earlier terminated in writing by either party.

During 2010, substantially all of our natural gas production was concentrated in the Edirne and Alpullu gas fields in the Thrace Basin in northwestern Turkey. AKSA, a natural gas distributor in Turkey, purchases all of our natural gas production from the Edirne field at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAŞ. Zorlu, a privately owned natural gas distributor in Turkey, purchases substantially all of our natural gas production from the Alpullu field that we operate at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAŞ.

Competition

Exploration, Development and Production. We operate in the highly competitive areas of oil and gas exploration, development, production and acquisition with a substantial number of other companies, including U.S.-based and international companies doing business in each of the countries in which we operate. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and gas companies in each of the following areas:

 

   

seeking oil and gas exploration licenses and production licenses and leases;

 

   

acquiring desirable producing properties or new leases for future exploration;

 

   

marketing natural gas and oil production;

 

   

integrating new technologies; and

 

   

acquiring the equipment and expertise necessary to develop and operate properties.

Many of our competitors have substantially greater financial, managerial, technological and other resources than we do. These companies are able to pay more for exploratory prospects and productive oil and gas properties than we can. To the extent competitors are able to pay more for properties than we are paying, we will be at a competitive disadvantage. Further, many of our competitors enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

Drilling Services Business. We operate in the competitive area of drilling services in Turkey, with a number of other U.S.-based, international and government owned companies. We face competition from large international companies, including Schlumberger N.V. and Halliburton Company, in providing modern stimulation and completion techniques in Turkey. We also face competition for providing conventional drilling services in Turkey from U.S.-based, international and government owned companies, including TPAO, Aladdin Middle East, Ltd. (“Aladdin”) and Perenco. We face intense competition from other drilling services providers in the areas of technological innovation, the quality of services provided and in price differentiation.

Many of our competitors in drilling services have substantially greater financial, managerial, technological and other resources than we do. These companies are able to pay more for technological innovations and may be able to implement new technologies more rapidly than we can. In addition, these companies may be able to offer a larger variety of services at lower prices. Our ability to provide drilling services in the future will depend upon our ability to successfully implement advanced technologies, provide quality services and offer competitive prices in this competitive environment.

Governmental Regulations

Government Regulation. Our current or future operations, including exploration and development activities on our properties, require permits from various governmental authorities, and such operations are and will be governed by laws and regulations governing exploration, development, production, exports, taxes, labor laws and standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters. Compliance with these requirements

 

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may prove to be difficult and expensive. Due to our international operations, we are subject to the following issues and uncertainties that can affect our operations adversely:

 

   

the risk of expropriation, nationalization, war, revolution, political instability, border disputes, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs;

 

   

the risk of not being able to procure residency and work permits for our expatriate personnel;

 

   

taxation policies, including royalty and tax increases and retroactive tax claims;

 

   

exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over international operations;

 

   

laws and policies of the United States affecting foreign trade, taxation and investment;

 

   

the possibility of being subjected to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and

 

   

the possibility of restrictions on repatriation of earnings or capital from foreign countries.

Permits and Licenses. In order to carry out exploration and development of oil and gas interests or to place these into commercial production, we may require certain licenses and permits from various governmental authorities. There can be no guarantee that we will be able to obtain all necessary licenses and permits that may be required. In addition, such licenses and permits are subject to change and there can be no assurances that any application to renew any existing licenses or permits will be approved. We also store, transport and use explosive materials in certain of our drilling service operations, which are also subject to special controls and regulatory regimes in certain countries in which we conduct our services.

Repatriation of Earnings. Currently, there are no restrictions on the repatriation of earnings or capital to foreign entities from Turkey, Morocco, Bulgaria or Romania. However, there can be no assurance that any such restrictions on repatriation of earnings or capital from the aforementioned countries or any other country where we may invest will not be imposed in the future. We may be liable for payment of taxes upon repatriation of certain earnings from the aforementioned countries.

Environmental. The oil and natural gas industry is subject to extensive and varying environmental regulations in each of the jurisdictions in which we operate. Environmental regulations establish standards respecting health, safety and environmental matters and place restrictions and prohibitions on emissions of various substances produced concurrently with oil and natural gas. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products and waste created by water and air pollution control procedures. These regulations can have an impact on the selection of drilling locations and facilities, potentially resulting in increased capital expenditures. In addition, environmental legislation may require those wells and production facilities to be abandoned and sites reclaimed to the satisfaction of local authorities. Such regulation has increased the cost of planning, designing, drilling, operating and in some instances, abandoning wells. We are committed to complying with environmental and operation legislation wherever we operate.

Such laws and regulations not only expose us to liability for our own negligence, but may also expose us to liability for the conduct of others or for our actions that were in compliance with all applicable laws at the time those actions were taken. We may incur significant costs as a result of environmental accidents, such as oil spills, natural gas leaks, ruptures, or discharges of hazardous materials into the environment, including clean-up costs and fines or penalties. Additionally, we may incur significant costs in order to comply with environmental laws and regulations and may be forced to pay fines or penalties if we do not comply.

Employees

As of April 1, 2011, we employed approximately 826 people and, through a service agreement with Longfellow, Viking Drilling, MedOil Supply, LLC and Riata Management, LLC (“Riata”), contracted for the services of approximately 67 additional people. As of April 1, 2011, approximately 55 of our employees at one of our Turkish subsidiaries are represented by collective bargaining agreements with the Turkish Employers Association of Chemical, Oil and Plastic

 

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Industries (KIPLAS) and the Petroleum, Chemical and Rubber Workers Union of Turkey (PETROL-IS). The collective bargaining agreements expire January 31, 2012. We consider our union and employee relations to be satisfactory.

Formation

We were incorporated under the laws of British Columbia, Canada on October 1, 1985 under the name Profco Resources Ltd. and continued to the jurisdiction of Alberta, Canada under the Business Corporations Act (Alberta) on June 10, 1997. Effective December 2, 1998, we changed our name to TransAtlantic Petroleum Corp. Effective October 1, 2009, we continued to the jurisdiction of Bermuda under the Bermuda Companies Act 1981 under the name TransAtlantic Petroleum Ltd.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our website at www.transatlanticpetroleum.com as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC.

 

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Item 1A. Risk Factors.

Risks Related to Our Business

We will require significant capital to continue our exploration and development activities beyond May 25, 2011.

We may not have sufficient funds to continue our operations beyond May 25, 2011, the maturity date of our short-term secured credit agreement with Standard Bank. If we are unable to finance our operations on acceptable terms or at all, our business, financial condition and results of operations may be materially and adversely affected.

Future cash flows and the availability of debt or equity financing will be subject to a number of variables, such as:

 

   

the success of our prospects in Turkey, Morocco, Bulgaria and Romania;

 

   

success in finding and commercially producing reserves; and

 

   

prices of natural gas and oil.

Debt financing could lead to:

 

   

a substantial portion of operating cash flow being dedicated to the payment of principal and interest;

 

   

our company being more vulnerable to competitive pressures and economic downturns; and

 

   

restrictions on our operations.

If sufficient capital resources are not available, we might be forced to cease operations entirely, curtail developmental and exploratory drilling and other activities or be forced to sell some assets on an untimely or unfavorable basis, which would have a material adverse effect on our business, financial condition and results of operations.

We have a history of losses and may never be profitable.

We have incurred substantial losses in prior years. During 2010, our comprehensive loss was approximately $78.9 million and we used $43.5 million of cash in operating activities. We may suffer significant additional losses in the future and may never be profitable. Even if we do achieve profitability, we may not be able to sustain or increase profitability on a quarterly or annual basis. We expect to incur losses unless and until such time as one or more of our properties generates sufficient revenue to fund our continuing operations.

The future performance of our business will depend upon our ability to identify, acquire and develop additional oil and gas reserves that are economically recoverable. Success will depend upon the ability to acquire working and revenue interests in properties upon which oil and gas reserves are ultimately discovered in commercial quantities, and the ability to develop prospects that contain additional proven oil and gas reserves to the point of production. Without successful acquisition and exploration activities, we will not be able to develop additional oil and gas reserves or generate additional revenues. There are no assurances that additional oil and gas reserves will be identified or acquired on acceptable terms, or that oil and gas reserves will be discovered in sufficient quantities to enable us to recover our exploration and development costs or sustain our business.

The successful acquisition and development of oil and gas properties requires an assessment of recoverable reserves, future oil and gas prices and operating costs, potential environmental and other liabilities, and other factors. Such assessments are inherently uncertain. In addition, no assurance can be given that our exploration and development activities will result in the discovery of any reserves. Operations may be curtailed, delayed or canceled as a result of lack of adequate capital and other factors, such as lack of availability of rigs and other equipment, title problems, weather, compliance with governmental regulations or price controls, mechanical difficulties, or unusual or unexpected formations, pressures and or work interruptions. In addition, the costs of exploration and development may materially exceed our initial estimates.

We need significant amounts of cash to repay our debt. If we are unable to generate sufficient cash to repay our debt, our business, financial condition and results of operations could be adversely affected.

As of December 31, 2010, the outstanding principal amount of our debt was $138.6 million. Of this amount, $30.0 million is due by May 25, 2011 and $73.0 million is due by June 28, 2011. We must generate sufficient amounts of cash to service and repay our debt. Our ability to generate cash will be affected by general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Future borrowings may not be available to us under our senior secured credit facility or from the capital markets in amounts sufficient to pay our obligations as they mature or to fund other liquidity needs. In addition, disruptions in the credit and financial markets can constrain our access to capital and increase its cost. The inability to service, repay or refinance our indebtedness could adversely affect our financial condition and results of operations.

If future financing is not available to us when required, as a result of limited access to the credit or equity markets or otherwise, or is not available on acceptable terms, we may be unable to invest needed capital for our developmental and exploratory drilling and other activities, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our business, financial condition and results of operations.

 

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Difficulties in combining the operations of Amity, Petrogas and Direct Bulgaria with our operations may prevent us from achieving the expected benefits from the acquisitions.

There are significant risks and uncertainties associated with our acquisitions of Amity, Petrogas and Direct Bulgaria. The acquisitions are expected to provide substantial benefits, including among other things, expanding on our presence in the Thrace Basin, creating a presence in Bulgaria and providing additional prospective acreage for shallow gas targets as well as deeper conventional and unconventional gas. Achieving such expected benefits is subject to a number of uncertainties, including:

 

   

whether the operations of Amity, Petrogas and Direct Bulgaria are integrated with us in an efficient and effective manner;

 

   

difficulty transitioning customers and other business relationships to our company;

 

   

problems unifying management of a combined company;

 

   

loss of key employees from our existing or acquired businesses; and

 

   

increased competition from other companies seeking to expand sales and market share during the integration period.

Failure to achieve these benefits could result in increased costs, decreases in the amount of expected revenues and diversion of management’s time and energy from the development and operation of our existing business that could materially and adversely impact our business, financial condition and operating results.

We have identified material weaknesses in our internal control over financial reporting. These material weaknesses, if not corrected, could affect the reliability of our financial statements and have other adverse consequences.

Under Section 404 of the Sarbanes-Oxley Act of 2002, we are required to furnish a report by our management on internal control over financial reporting. This report must contain, among other matters, an assessment of the effectiveness of our internal control over financial reporting, including a statement as to whether or not our internal control over financial reporting is effective. This assessment must include disclosure of any material weaknesses in our internal control over financial reporting identified by our management. In addition, the report must contain a statement that our auditors have issued an attestation report on management’s assessment of such internal control over financial reporting.

We have identified several material weaknesses in our internal control over financial reporting as of December 31, 2010 as disclosed in “Item 9A. Controls and Procedures.” Failure to have effective internal controls could lead to a misstatement of our financial statements. If, as a result of deficiencies in our internal controls, we cannot provide reliable financial statements, our business decision process may be adversely affected, our business and operating results could be harmed, investors could lose confidence in our reported financial information, the price of our common shares could decrease and our ability to obtain additional financing, or additional financing on favorable terms, could be adversely affected. In addition, failure to maintain effective internal control over financial reporting could result in investigations or sanctions by regulatory authorities.

 

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We intend to take further action to remediate the material weaknesses and improve the effectiveness of our internal control over financial reporting. However, we can give no assurances that the measures we may take will remediate the material weaknesses identified or that any additional material weaknesses will not arise in the future due to our failure to implement and maintain adequate internal control over financial reporting. In addition, even if we are successful in strengthening our controls and procedures, those controls and procedures may not be adequate to prevent or identify irregularities or ensure the fair presentation of our financial statements included in our periodic reports filed with the SEC.

Our senior secured credit facility, short-term secured credit agreement and credit agreement contain various covenants that limit our management’s discretion in the operation of our business and can lead to an event of default that may adversely affect our business, financial condition and results of operations.

The operating and financial restrictions and covenants in our senior secured credit facility with Standard Bank and BNP Paribas (Suisse) SA, our short-term secured credit agreement with Standard Bank, or our credit agreement with Dalea may adversely affect our ability to finance future operations or capital needs or to engage in other business activities. Our senior secured credit facility, short-term secured credit agreement and credit agreement with Dalea contain various covenants that restrict our ability to, among other things:

 

   

incur additional debt;

 

   

create liens;

 

   

enter into any hedge agreement for speculative purposes;

 

   

engage in business other than as an oil and gas exploration and production company;

 

   

enter into sale and leaseback transactions;

 

   

enter into any merger, consolidation or amalgamation;

 

   

dispose of all or substantially all of our assets;

 

   

use the amounts borrowed for only certain specified purposes;

 

   

declare or provide for any dividends or other payments or distributions;

 

   

redeem or purchase any shares; or

 

   

guarantee or permit the guarantee of the obligations of any other person.

In addition, the senior secured credit facility requires us to maintain specified financial ratios and tests and to maintain commodity price hedge agreements. Various risks, uncertainties and events beyond our control could affect our ability to comply with the covenants and financial tests and ratios required by the senior secured credit facility and could result in a default under the senior secured credit facility.

An event of default under the senior secured credit facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, including failure to timely deliver to the lenders copies of our 2011 audited annual financial statements without a going concern note or similar qualification, cross default to other indebtedness, our bankruptcy or insolvency, failure to meet the required financial tests and ratios and the occurrence of a material adverse effect. In the event of our bankruptcy or insolvency, all amounts payable under the senior secured credit facility become immediately due and payable. In the event of any other default under our senior secured credit facility, the lenders would be entitled to accelerate the repayment of amounts outstanding. Moreover, in the event of a default we would lose the ability to draw on, and the lenders would have the option to terminate, any obligation to make further extensions of credit under the senior secured credit facility. In addition, in the event of a default under the senior secured credit facility, which is secured by substantially all of the assets of our wholly-owned subsidiaries, DMLP, Ltd. (“DMLP”), TEMI, Talon and TransAtlantic Turkey, Ltd. (“TAT”), the lenders could proceed to foreclose against the assets securing such obligations.

An event of default under the short-term secured credit agreement with Standard Bank includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, our bankruptcy or insolvency, the occurrence of a material adverse effect or a change in control. In the event of our bankruptcy or insolvency, all amounts payable under the short-term secured credit agreement become immediately due and payable. In the event of any other

 

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default under our short-term secured credit agreement, the lenders would be entitled to accelerate the repayment of amounts outstanding. In the event of a default under the short-term secured credit agreement, which is secured by substantially all of the assets of our wholly-owned subsidiaries, Amity and Petrogas, the lenders could proceed to foreclose against the assets securing such obligations.

An event of default under the credit agreement with Dalea includes, among other events, failure to make the payment of principal or interest when due, breach of certain covenants or conditions, the occurrence of an adverse material change in our financial condition, bankruptcy or insolvency, or a change of control. In the event of a default under the credit agreement, the lender can demand all amounts payable under the credit agreement to be immediately due and payable. In the event of bankruptcy or insolvency, all amounts payable under the credit agreement become immediately due and payable.

In the event of a default and acceleration of indebtedness under the senior secured credit facility, the short-term secured credit agreement or the credit agreement with Dalea, our business, financial condition and results of operations may be materially and adversely affected.

The occurrence of a financial crisis, such as the financial crisis in recent years, may impact our ability to obtain equity, debt or bank financing in the future and may adversely impact our operations.

Events in the financial markets in recent years had an adverse impact on the credit markets and, as a result, the availability of equity, debt or bank financing has become more expensive and difficult to obtain. Banks have been adversely affected by the recent financial crisis and have severely curtailed existing liquidity lines, increased pricing and introduced new and tighter borrowing restrictions to corporate borrowers, with extremely limited access to new facilities or for new borrowers. These factors could negatively impact our ability to access liquidity needed for our business in the longer term. These factors may impact our ability to obtain equity, debt or bank financing on terms commercially reasonable to us, if at all. Additionally, these factors, as well as other related factors, may cause decreases in asset values that are deemed to be other than temporary, which may result in impairment losses. The negative impact of these events may also include our inability to expand existing credit facilities or finance the acquisition of assets on favorable terms, if at all, or adversely impacting our operations or the trading price of our securities.

We depend on a limited number of key personnel who would be difficult to replace.

We depend on the performance of Mr. Mitchell, chairman, Matthew McCann, chief executive officer, and Gary Mize, president and chief operating officer. The loss of any of Messrs. Mitchell, McCann or Mize could negatively impact our ability to execute our strategy. We do not maintain key person life insurance policies on Messrs. Mitchell, McCann or Mize.

We may experience difficulty staffing our drilling rigs, seismic equipment and other services equipment.

We have a limited number of employees and will need to staff our drilling rigs, seismic equipment and other services equipment, and to add staff to other departments. We may experience difficulty in finding a sufficient number of experienced crews to work on our drilling rigs, seismic equipment and other services equipment, and in finding experienced staff in other departments to complete the work required.

Our drilling services business will depend on the level of activity in the oil and natural gas exploration and production industry.

Our drilling services business will depend on the level of activity in oil and natural gas exploration and production in our operating markets. Both short-term and long-term trends in oil and natural gas prices affect the level of those activities. Lower oil and natural gas prices may depress oil and natural gas exploration and production activity. In addition, because oil and natural gas prices are volatile, the level of exploration and production activity can also be volatile.

Drilling for and producing natural gas and oil are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our future success depends on the success of our exploration, development and production activities in each of our prospects. These activities are subject to numerous risks beyond our control, including the risk that we will be unable to economically produce our reserves or be able to find commercially productive natural gas or oil reservoirs. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained

 

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through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project unprofitable. Further, many factors may curtail, delay or prevent drilling operations, including:

 

   

unexpected drilling conditions;

 

   

pressure or irregularities in geological formations;

 

   

equipment failures or accidents;

 

   

pipeline and processing interruptions or unavailability;

 

   

title problems;

 

   

adverse weather conditions;

 

   

lack of market demand for natural gas and oil;

 

   

delays imposed by, or resulting from, compliance with environmental and other regulatory requirements; and

 

   

declines in natural gas and oil prices.

Our future drilling activities might not be successful, and drilling success rates overall or within a particular area could decline. We could incur losses by drilling unproductive wells. Shut-in wells, curtailed production and other production interruptions may materially adversely affect our business, financial condition and results of operations.

We have concentrated current production of crude oil.

We derive substantially all of our crude oil production from the Selmo field in southeastern Turkey. TPAO and TUPRAS purchase all of our crude oil production from the Selmo field, which represented 56.1% of our total revenues in 2010. If either of these companies fails to purchase our production, our results of operations could be materially and adversely affected.

We could experience labor disputes that could disrupt our business in the future.

As of April 1, 2011, approximately 55 of our employees at one of our Turkish subsidiaries are represented by collective bargaining agreements with KIPLAS and PETROL-IS. The collective bargaining agreements expire January 31, 2012. Potential work disruptions from labor disputes could disrupt our business and adversely affect our financial condition and results of operations.

Our operations are primarily conducted in Turkey, Morocco, Bulgaria and Romania and we are subject to political, economic and other risks and uncertainties in these countries.

Due to our international operations, we are subject to the following issues and uncertainties that can affect our operations adversely:

 

   

the risk of expropriation, nationalization, war, revolution, political instability, border disputes, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs;

 

   

the risk of not being able to procure residency and work permits for our expatriate personnel;

 

   

taxation policies, including royalty and tax increases and retroactive tax claims;

 

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exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over international operations;

 

   

laws and policies of the United States and of the other countries in which we operate affecting foreign trade, taxation and investment;

 

   

the possibility of being subjected to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and

 

   

the possibility of restrictions on repatriation of earnings or capital from foreign countries.

Acts of violence, terrorist attacks or civil unrest in southeastern Turkey could adversely affect our business.

We currently derive substantially all of our oil revenue from the Selmo oil field in southeastern Turkey. Historically, the southeastern area of Turkey has experienced political, social or economic problems, terrorist attacks, insurgencies or civil unrest. If any of these events or conditions occurs, we may be unable to access the locations where we conduct operations. In those locations where we have employees or operations, we may incur substantial costs to maintain the safety of our personnel and our operations. Despite these precautions, the safety of our personnel and operations in these locations may continue to be at risk, and we may in the future suffer the loss of employees and contractors or our operations could be disrupted, any of which could have a material adverse effect on our business and results of operations.

Acts of violence or civil unrest in Morocco could adversely affect our business.

We currently have operations in Morocco and are evaluating the commerciality of a well drilled on our Tselfat exploration license in Morocco. Recently, areas of Morocco have experienced acts of violence and civil unrest. If any of these events or conditions continue to occur, we may be unable to access the locations where we conduct operations. In those locations where we have employees or operations, we may incur substantial costs to maintain the safety of our personnel and our operations. Despite these precautions, the safety of our personnel and operations in these locations may continue to be at risk, and we may in the future suffer the loss of employees and contractors or our operations could be disrupted, any of which could have a material adverse effect on our business and results of operations.

We could be assessed for Canadian federal tax as a result of our continuance under the Bermuda Companies Act 1981.

For Canadian tax purposes, we were deemed, immediately before the completion of our continuance under the Bermuda Companies Act 1981, to have disposed of each property owned by us for proceeds equal to the fair market value of that property, and will be subject to tax on any resulting net income. In addition, we are required to pay a special “branch tax” equal to 25% of any excess of the fair market value of our property over the “paid-up capital” (as defined in the Income Tax Act (Canada)) of our outstanding common shares and our liabilities. Management, together with its professional advisors, has determined the fair market value of our property and the paid-up capital of our common shares for these purposes. Management does not anticipate that the deemed disposition of our assets at fair market value will result in any material adverse Canadian income tax consequences to us and believes that the paid-up capital of our common shares and our liabilities exceeds the fair market value of our property resulting in no “branch tax” being payable. However, the Canada Revenue Agency (“CRA”) may not accept our determination of the fair market value of our property. In the event that CRA’s determination of fair market value is significantly higher than our valuation and such determination is final, we may be subject to material amounts of tax resulting from the deemed disposition.

We are involved in litigation over the ownership of a portion of the surface rights at the Selmo oil field in Turkey.

A substantial portion of our 2010 revenue was generated from the sale of oil produced from the Selmo oil field in Turkey. Our subsidiary, TEMI, has been involved in litigation with persons who claim ownership of a portion of the surface rights of the Selmo field, which encompasses almost all of our production wells. We and the Turkish government are vigorously defending these cases. Although the litigation does not affect our ownership of the Selmo production license, if this litigation is not resolved in our favor, our operations on the affected portions of the Selmo oil field could be materially disrupted. A material disruption to our operations at Selmo could have a material adverse effect on our business.

 

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Risks Related to the Oil and Gas Industry

Reserve estimates depend on many assumptions that may turn out to be inaccurate.

Any material inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present values of our reserves. The process of estimating natural gas and oil reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves that we may report. In order to prepare these estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves that we may report. In addition, we may adjust estimates of proved, probable and possible reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped, probable and possible reserves will be developed within the periods anticipated. Any significant variance in the assumptions could materially affect the estimated quantity and value of our reserves.

Investors should not assume that the pre-tax net present value of our proved, probable and possible reserves is the current market value of our estimated oil and natural gas reserves. We base the pre-tax net present value of future net cash flows from our proved, probable and possible reserves on prices and costs on the date of the estimate. Actual future prices, costs, and the volume of produced reserves may differ materially from those used in the pre-tax net present value estimate.

We may not correctly evaluate reserve data or the exploitation potential of properties as we engage in our acquisition, development, and exploitation activities.

Our future success will depend on the success of our acquisition, development, and exploitation activities. Our decisions to purchase, develop or otherwise exploit properties or prospects will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic and other information, the results of which are often inconclusive and subject to various interpretations. Our estimates regarding reserves and production resulting from the acquisitions of Incremental, Talon, Amity, Petrogas, Direct Bulgaria, Anschutz and Direct Morocco and our exploration and development activities may prove to be incorrect, which could significantly reduce our income and our ability to generate cash needed to fund our capital program and other working capital requirements in the longer term.

We may be unable to acquire or develop additional reserves, which would reduce our cash flow and income.

In general, production from natural gas and oil properties declines over time as reserves are depleted, with the rate of decline depending on reservoir characteristics. If we are not successful in our exploration and development activities or in acquiring properties containing reserves, our reserves will generally decline as reserves are produced. Our natural gas and oil production is highly dependent upon our ability to economically find, develop or acquire reserves in commercial quantities.

To the extent cash flow from operations is reduced, either by a decrease in prevailing prices for natural gas and oil or an increase in finding and development costs, and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves would be impaired. Even with sufficient available capital, our future exploration and development activities may not result in additional reserves, and we might not be able to drill productive wells at acceptable costs.

A substantial or extended decline in natural gas and oil prices may adversely affect our ability to meet our capital expenditure obligations and financial commitments.

Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, natural gas and oil. Lower natural gas and oil prices may also reduce the amount of natural gas and oil that we can produce economically. Historically, natural gas and oil prices and markets have been volatile, and they are likely to continue to be volatile in the future.

 

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A decrease in natural gas or oil prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable and may result in charges to earnings for impairment of the value of these assets. If natural gas or oil prices decline significantly for extended periods of time in the future, we might not be able to generate sufficient cash flow from operations to meet our obligations and make planned capital expenditures. Natural gas and oil prices are subject to wide fluctuations in response to relatively minor changes in the supply of, and demand for, natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control. Among the factors that could cause fluctuations are:

 

   

change in local and global supply and demand for natural gas and oil;

 

   

levels of production and other activities of the Organization of Petroleum Exporting Countries and other natural gas and oil producing nations;

 

   

market expectations about future prices;

 

   

the level of global natural gas and oil exploration, production activity and inventories;

 

   

political conditions, including embargoes, in or affecting oil production activities; and

 

   

the price and availability of alternative fuels.

Lower natural gas and oil prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of natural gas and oil that we can produce economically. A substantial or extended decline in oil or natural gas prices may have a material adverse effect our business, financial condition and results of operations.

Undeveloped resources are uncertain.

We have undeveloped resources. Undeveloped resources, including undeveloped reserves, by their nature, are significantly less certain than developed resources. The discovery, determination and exploitation of undeveloped resources require significant capital expenditures and successful drilling and exploration programs. We may not be able to raise the additional capital we need to develop these resources. There is no certainty that we will discover additional resources or that resources will be economically viable or technically feasible to produce.

We are subject to operating hazards.

The oil and gas business involves a variety of operating risks, including the risk of fire, explosion, blowout, pipe failure, casing collapse, stuck tools, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, pipeline ruptures and discharges of toxic gases, the occurrence of any of which could result in substantial losses to us due to injury and loss of life, loss of or damage to well bores and/or drilling or production equipment, costs of overcoming downhole problems, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Gathering systems and processing facilities are subject to many of the same hazards and any significant problems related to those facilities could adversely affect our ability to market our production.

Our oil and natural gas operations are subject to extensive and complex laws and government regulation in the jurisdictions in which we operate and compliance with existing and future laws may increase our costs or impair our operations.

Our oil and natural gas operations are subject to numerous federal, state and international laws and regulations, including those related to the environment, employment, immigration, labor, oil and gas exploration and development, payments to foreign officials, taxes and the repatriation of foreign earnings. If we fail to adhere to any applicable federal, state or international laws or regulations, or if such laws or regulations negatively affect the sale of oil and natural gas, our business, prospects, results of operations, financial condition or cash flows may be impaired. We might be required to make significant capital expenditures to comply with federal, state or international laws or regulations. In addition, existing laws or regulation, as currently interpreted or reinterpreted in the future, or future laws or regulations could adversely affect our business or operations, or substantially increase our costs and associated liabilities.

In addition, exploration for, and exploitation, production and sale of, oil and gas in each country in which we operate is subject to extensive national and local laws and regulations requiring various licenses, permits and approvals from various governmental agencies. If these licenses or permits are not issued or unfavorable restrictions or conditions are imposed on our exploration or drilling activities, we might not be able to conduct our operations as planned. Alternatively, failure to comply with these laws and regulations, including the requirements of any licenses or permits, might result in the suspension or termination of operations and subject us to penalties. Our costs to comply with these numerous laws, regulations, licenses and permits are significant.

 

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We do not plan to insure against all potential operating risks. We might incur substantial losses from, and be subject to substantial liability claims for, uninsured or underinsured risks related to our natural gas and oil operations and drilling services business.

We do not intend to insure against all risks. Our natural gas and oil exploration and production activities and drilling services business will be subject to hazards and risks associated with drilling for, producing and transporting natural gas and oil, and storing, transporting and using explosive materials, and any of these risks can cause substantial losses resulting from:

 

   

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

 

   

abnormally pressured formations;

 

   

mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

 

   

fires and explosions;

 

   

personal injuries and death;

 

   

regulatory investigations and penalties; and

 

   

natural disasters.

We might elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. Losses and liabilities arising from uninsured and underinsured events or in amounts in excess of existing insurance coverage could have a material adverse effect on our business, financial condition or results of operations.

We might not be able to identify liabilities associated with properties or obtain protection from sellers against them, which could cause us to incur losses.

Our review and evaluation of prospects and future acquisitions might not necessarily reveal all existing or potential problems. For example, inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, may not be readily identified even when an inspection is undertaken. Even when problems are identified, a seller may be unwilling or unable to provide effective contractual protection against all or part of those problems, and we often assume environmental and other risks and liabilities in connection with acquired properties.

Competition in the oil and gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do, which may adversely affect our ability to compete.

We operate in the highly competitive areas of oil and gas exploration, development, production and acquisition with a substantial number of other companies, including U.S.-based and foreign companies doing business in each of the countries in which we operate. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and gas companies in each of the following areas:

 

   

seeking oil and gas exploration licenses and production licenses;

 

   

acquiring desirable producing properties or new leases for future exploration;

 

   

marketing natural gas and oil production;

 

   

integrating new technologies; and

 

   

acquiring the equipment and expertise necessary to develop and operate properties.

Many of our competitors have substantially greater financial, managerial, technological and other resources than we do. These companies are able to pay more for exploratory prospects and productive oil and gas properties than we can. To the

 

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extent competitors are able to pay more for properties than we are paying, we will be at a competitive disadvantage. Further, many of our competitors enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Our ability to explore for and produce natural gas and oil prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

We also operate in the competitive area of drilling services in Turkey, with a number of other U.S.-based, international and government owned companies. We face competition from large international companies, including Schlumberger N.V. and Halliburton Company, in providing modern stimulation and completion techniques in Turkey. We also face competition for providing conventional drilling services in Turkey from U.S.-based, international and government owned companies including TPAO, Aladdin and Perenco. We face intense competition from other drilling services providers in the areas of technological innovation, the quality of services provided and in price differentiation.

Many of our competitors in drilling services have substantially greater financial, managerial, technological and other resources than we do. These companies are able to pay more for technological innovations and may be able to implement new technologies more rapidly than we can. In addition, these companies may be able to offer a larger variety of services at lower prices. Our ability to provide drilling services in the future will depend upon our ability to successfully implement advanced technologies, provide quality services and offer competitive prices in this competitive environment.

We might not be able to obtain necessary permits, approvals or agreements from one or more government agencies, surface owners, or other third parties, which could hamper our exploration, development or production activities.

There are numerous permits, approvals, and agreements with third parties, which will be necessary in order to enable us to proceed with our exploration, development or production activities and otherwise accomplish our objectives. The government agencies in each country in which we operate have discretion in interpreting various laws, regulations, and policies governing operations under the licenses. Further, we may be required to enter into agreements with private surface owners to obtain access to, and agreements for, the location of surface facilities. In addition, because many of the laws governing oil and gas operations in the international countries in which we operate have been enacted relatively recently, there is only a relatively short history of the government agencies handling and interpreting those laws, including the various regulations and policies relating to those laws. This short history does not provide extensive precedents or the level of certainty that allows us to predict whether such agencies will act favorably toward us. The governments have broad discretion to interpret requirements for the issuance of drilling permits. Our inability to meet any such requirements could have a material adverse effect on our exploration, development or production activities.

We may not be able to complete the exploration, development or production of any, or a significant portion of, the oil and gas interests covered by our leases or licenses before they expire.

Each license or lease under which we operate has a fixed term. We may be unable to complete our exploration, development or production efforts prior to the expiration of licenses or leases. Failure to obtain government approval for a license or lease, an extension of the license or lease, be granted a new exploration license or lease or the failure to obtain a license or lease covering a sufficiently large area would prevent or limit us from continuing to explore, develop or produce a significant portion of the oil and gas interests covered by the license or lease. The determination of the amount of acreage to be covered by the production license or lease is in the discretion of the respective governments.

Political and economic instability or fundamental changes in the leadership or in the structure of the governments in the jurisdictions in which we operate could have a material negative impact on our company.

Our foreign property interests and foreign operations may be affected by political and economic risks. These risks include war and civil disturbances, political instability, currency restrictions and exchange rate fluctuations, labor problems and high rates of inflation. In addition, local, regional and world events could cause the jurisdictions in which we operate to change the petroleum laws, tax laws, foreign investment laws, or to revise their policies in a manner that renders our current and future projects unprofitable. Further, we are subject to risks in the foreign jurisdictions in which we operate of the nationalization of the oil and gas industry, expropriation of property or other restrictions and penalties on foreign-owned entities, which could render our projects unprofitable or could prevent us from selling our assets or operating our business. The occurrence of any such fundamental change could have a material adverse effect on our business, financial condition and results of operations.

 

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Risks Related to Our Common Shares

The interests of our controlling shareholder may not coincide with yours and such controlling shareholder may make decisions with which you may disagree.

As of April 1, 2011, Mr. Mitchell beneficially owned approximately 44.2% of our outstanding common shares. As a result, Mr. Mitchell could control substantially all matters requiring shareholder approval, including the election of directors and approval of significant corporate transactions. In addition, this concentration of ownership may delay or prevent a change in control of our company and make some future transactions more difficult or impossible without the support of Mr. Mitchell. The interests of Mr. Mitchell may not coincide with our interests or the interests of other shareholders.

Offers or availability for sale of a substantial number of common shares by our shareholders may cause the market price of our common shares to decline.

The ability of our shareholders to sell substantial amounts of our common shares in the public market, or upon the expiration of any statutory holding period under Rule 144 under the Securities Act of 1933, as amended (the “Securities Act”), could create a circumstance commonly referred to as an “overhang” and in anticipation of which the market price of our common shares could fall. The existence of an overhang, whether or not sales have occurred or are occurring, could make it more difficult for us to raise additional financing through the sale of equity or equity-related securities in the future at a time and price that we deem reasonable or appropriate.

The value of our common shares might be affected by matters not related to our own operating performance.

The value of our common shares may be affected by matters that are not related to our operating performance and which are outside of our control. These matters include the following:

 

   

general economic conditions in the United States, Turkey, Morocco, Bulgaria, Romania and globally;

 

   

industry conditions, including fluctuations in the price of oil and natural gas;

 

   

governmental regulation of the oil and natural gas industry, including environmental regulation;

 

   

fluctuation in foreign exchange or interest rates;

 

   

liabilities inherent in oil and natural gas operations;

 

   

geological, technical, drilling and processing problems;

 

   

unanticipated operating events which can reduce production or cause production to be shut in or delayed;

 

   

failure to obtain industry partner and other third party consents and approvals, when required;

 

   

stock market volatility and market valuations;

 

   

competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;

 

   

the need to obtain required approvals from regulatory authorities;

 

   

worldwide supplies and prices of, and demand for, natural gas and oil;

 

   

political conditions and developments in each of the countries in which we operate;

 

   

political conditions in natural gas and oil producing regions;

 

   

revenue and operating results failing to meet expectations in any particular period;

 

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investor perception of the oil and natural gas industry;

 

   

limited trading volume of our common shares;

 

   

change in environmental and other governmental regulations;

 

   

announcements relating to our business or the business of our competitors;

 

   

our liquidity; and

 

   

our ability to raise additional funds.

In the past, companies that have experienced volatility in the trading price of their common shares have been the subject of securities class action litigation. We might become involved in securities class action litigation in the future. Such litigation often results in substantial costs and diversion of management’s attention and resources and could have a material adverse effect on our business, financial condition and results of operation.

U.S. shareholders who hold common shares during a period when we are classified as a passive foreign investment company may be subject to certain adverse U.S. federal income tax consequences.

Management believes that we are not currently a passive foreign investment company. However, we may have been a passive foreign investment company during one or more of our prior taxable years and could become a passive foreign investment company in the future. In general, classification of our company as a passive foreign investment company during a period when a U.S. shareholder holds common shares could result in certain adverse U.S. federal income tax consequences to such shareholder.

Certain U.S. shareholders who hold common shares during a period when we are classified as a controlled foreign corporation may be subject to certain adverse U.S. federal income tax rules.

Management believes that we currently are a controlled foreign corporation for U.S. federal income tax purposes and that we will continue to be so treated. Consequently, a U.S. shareholder that owns 10% or more of the total combined voting power of all classes of our stock entitled to vote on the last day of our taxable year may be subject to certain adverse U.S. federal income tax rules with respect to its investment in us.

 

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Item 1B. Unresolved Staff Comments.

Not applicable.

 

Item 2. Properties.

Turkey

General. As of April 1, 2011, we held interests in 56 onshore exploration licenses and three onshore production leases covering a total of approximately 6.4 million gross acres (approximately 6.0 million net acres) in Turkey. We acquired our interests in Turkey through the acquisitions of Incremental, Talon, Amity and Petrogas, as well as through farm-in agreements with existing third-party license holders and through applications submitted to the GDPA.

The following is a map showing our interests in Turkey:

LOGO

 

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Thrace Basin. The following is a map showing our interests in the Thrace Basin in northwestern Turkey:

LOGO

Edirne (Licenses 3839 and 4037). We own a 55% working interest in License 3839 and a 100% working interest in License 4037, which cover an aggregate of approximately 239,000 acres (967 square kilometers). In April 2010, we commenced natural gas sales from the Edirne gas field. AKSA purchases all of our natural gas production from the Edirne field at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAŞ. There are currently 11 producing wells on the Edirne license, and we plan to drill between 15 and 20 wells on the Edirne exploration licenses in 2011. We are the operator of Licenses 3839 and 4037, which expire in October 2011 and March 2011, respectively. We are applying for a three year extension on License 3839 and a two year extension on License 4037.

Alpullu (Production Lease 3599-4794 and License 4861). We own a 100% working interest in Production Lease 3599-4794 and License 4861, which cover 3,158 acres (13 square kilometers) and approximately 117,000 acres (474 square kilometers), respectively. Upon the acquisition of Amity in August 2010, we commenced limited natural gas sales from the Alpullu production lease. Zorlu purchases substantially all of our natural gas production from the Alpullu production lease at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAŞ. We currently have six producing wells on the Alpullu production lease, and we plan to drill between five and eight wells in 2011 to further develop the Alpullu production lease and test structures on the Alpullu exploration license. We are the operator of Production Lease 3599-4794 and License 4861, which expire in September 2028 and December 2014, respectively.

Gocerler (Production Lease 4200 and License 4288). We own a 50% working interest in Production Lease 4200 and License 4288, which cover 3,363 acres (14 square kilometers) and approximately 119,000 acres (483 square kilometers), respectively. Upon the acquisition of Amity in August 2010, we commenced limited natural gas sales from the Gocerler production lease. Zorlu purchases all of our natural gas production from the Gocerler production lease at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAŞ. We currently have three producing wells on the Gocerler production lease. We plan to drill one exploratory well on License 4288 in 2011. TPAO is the operator of Production Lease 4200 and License 4288, which expire in March 2024 and August 2011, respectively. We have applied for a two year extension on License 4288.

Adatepe (License 3648). We own a 50% working interest in License 3648, which covers approximately 121,000 acres (488 square kilometers). Upon the acquisition of Amity in August 2010, we commenced limited natural gas sales from the Adatepe license. Zorlu purchases all of our natural gas production from the Adatepe license at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAŞ. We currently have seven producing wells on the Adatepe license. We plan to drill one development well on License 3648 in 2011. We are the operator of License 3648, which expires in July 2011. We have applied for a production lease over the Adatepe field. If the production lease is granted, we plan to apply for an exploration license over the remaining acreage.

Malkara (Licenses 4094 and 4532). We own a 100% working interest in Licenses 4094 and 4532, which cover an aggregate of approximately 242,000 acres (979 square kilometers). We are the operator of Licenses 4094 and 4532, which expire in September 2011 and January 2013, respectively. We have applied for a two year extension on License 4094.

Banarli (License 3864). We own a 50% working interest in License 3864, which covers approximately 96,000 acres (387 square kilometers). We plan to drill two exploratory wells on License 3864 in 2011. We are the operator of License 3864, which expires in April 2012.

Cayirdere and Velimse (Licenses 3791 and 3792). We own a 50% working interest in Licenses 3791 and 3792, which cover an aggregate of approximately 125,000 acres (504 square kilometers). We plan to drill one exploratory well on License 3792 in 2011. TPAO is the operator of Licenses 3791 and 3792, which expire in January 2013.

 

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Southeastern Turkey. The following is a map showing our interests in southeastern Turkey:

LOGO

Selmo (Production Lease 829). We own a 100% working interest in Production Lease 829, which covers 8,886 acres (36 square kilometers) and includes the Selmo oil field. There are currently 39 producing wells on the Selmo production lease. For 2010, our net production of crude oil in the Selmo field, after royalties, was approximately 631,000 Bbls of crude oil, at an average rate of approximately 1,700 Bbls per day. We sell all of our production from the Selmo oil field to TPAO and TUPRAS. We plan to drill and complete at least 24 wells at Selmo in 2011. We are the operator of Production Lease 829, which expires in June 2015.

Arpatepe (License 3118). We own a 50% working interest in License 3118, which covers approximately 96,000 acres (389 square kilometers) near the city of Diyarbakir. The Arpatepe-1 and Arpatepe-2 wells on License 3118 represent Turkey’s first and second economic discoveries of crude oil from deeper, onshore Paleozoic sandstone formations. For 2010, our net production of crude oil in the Arpatepe field, after royalties, was approximately 58,700 Bbls of crude oil, at an average rate of approximately 160 Bbls per day. We sell all of our production from the Arpatepe oil field to Aladdin. We currently have three producing wells in the Arpatepe field, and we plan to drill up to five additional wells there in 2011. Aladdin is the operator of License 3118, which expires in November 2011. Aladdin has applied for a production lease over the Arpatepe oil field. If the production lease is granted, we expect that Aladdin will apply for an exploration license over the remaining acreage.

Bakuk (Licenses 4069 and 4642). In April and May 2010, with our partner and operator, Tiway, we drilled the Bakuk-101 well to earn a 50% working interest in Licenses 4069 and 4642, which cover an aggregate of approximately 219,000 acres (777 square kilometers) on the Turkish border with Syria. The Bakuk-101 well was successful, with potential production of up to 10.0 Mmcf of natural gas per day. In November 2010, we re-entered the Bakuk-2 well, which failed to establish an oil leg in the reservoir. We have completed construction of a 23 kilometer, 6-inch pipeline from the Bakuk-101 well to an existing pipeline to the south and expect to begin limited natural gas sales in the second quarter of 2011. We are now evaluating options for further appraisal of the reservoir. We plan to drill one well on License 4069 in 2011. We plan to acquire 100 square kilometers of 3D seismic data on License 4642 in 2011. Tiway is the operator of License 4069, which expires in September 2011. We are applying for a two year extension of License 4069. We are the operator of License 4642, which expires in October 2014.

Germav (License 4175). We own a 100% working interest in License 4175, which covers approximately 118,000 acres (476 square kilometers) near the Turkish border with Iraq. The target is a deep sub-thrust play similar to the major Iraqi and Iranian Zagros fields to the south. In 2010, we drilled the Kalatepe-1 well, which is currently undergoing testing and completion. We are the operator of License 4175, which expires in June 2012.

Molla (License 4174). We own a 100% working interest in License 4174, which covers approximately 17,700 acres (71 square kilometers) near the Turkish border with Iraq. Our primary target is an underexplored Paleozoic play at a depth of approximately 9,800 feet. In 2010, we re-entered the Goksu-1 well to test the Hazro and Bedinan sandstone intervals and the Dadas shale intervals, but the re-entry did not discover hydrocarbons in commercial quantities in the Bedinan or Dadas intervals. We plan to test the Hazro sandstone interval later in 2011. We are the operator of License 4174, which expires in June 2012.

 

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Midyat (Licenses 3969, 3970, 3971 and 3972). We own a 100% working interest in Licenses 3969, 3970, 3971 and 3972, which cover an aggregate of approximately 460,000 acres (1,863 square kilometers) near the Turkish border with Iraq. We plan to drill one exploratory well on the Midyat licenses in 2011. We are the operator of the licenses, which expire in November 2012.

Central Basins. Our exploration licenses in central Turkey cover largely unexplored tertiary basins. We are currently seeking partners in each of these exploration licenses. Through farm-outs, we expect to reduce our exploration risk and accelerate the exploration and development activities on the farmed-out properties. We have begun consolidating and analyzing well data and seismic data for our central basins exploration acreage in Turkey. We intend to remain as operator in the properties that we farm-out. The following is a map showing our interests central Turkey:

LOGO

Malatya (Licenses 4572, 4573, 4574, 4575, 4576, 4577, 4659 and 4660). We own a 100% working interest in Licenses 4572, 4573, 4574, 4575, 4576, 4577, 4659 and 4660, which cover an aggregate of approximately 962,000 acres (3,892 square kilometers) in the Malatya area of south-central Turkey. We paid a third party who will be a 10% working interest owner in the Malatya licenses cash consideration and agreed that the party would back-in for its 10% working interest after payout of the first well to be drilled on the Malatya licenses. These licenses are in a large, relatively unexplored tertiary basin. We plan to drill one exploratory well on the Malatya licenses in 2011. We are the operator of the licenses, which expire in April 2013.

Haymana (Licenses 4310 and 4311), We own a 100% working interest, subject to a 2% overriding royalty interest, in Licenses 4310 and 4311, which cover an aggregate of approximately 243,000 acres (985 square kilometers) in the Tuz Golu Basin south of Ankara in central Turkey. These licenses are in a large, relatively unexplored tertiary basin. We plan to relinquish the Haymana licenses in 2011. We are the operator of the licenses, which expire in May 2012.

Tuz Golu (Licenses 4314, 4315, 4316, 4317, 4342 and 4344). We own a 100% working interest, subject to a 2% overriding royalty interest, in Licenses 4314, 4315, 4316, 4317, 4342 and 4344, which cover an aggregate of approximately 627,000 acres (2,536 square kilometers) in the Tuz Golu Basin south of Ankara in central Turkey. These licenses are in a large, relatively unexplored tertiary basin. We plan to drill one exploratory well on the Tuz Golu licenses in 2011. We are the operator of the licenses, which expire in May 2012.

Tuz Golu South (Licenses 4717, 4718, 4719, 4720, 4721 and 4722). We own a 100% working interest in Licenses 4717, 4718, 4719, 4720, 4721 and 4722, which cover an aggregate of approximately 733,000 acres (2,967 square kilometers) in central Turkey. These licenses are in a large, relatively unexplored tertiary basin. We are the operator of the licenses, which expire in December 2014.

Sivas Basin (Licenses 4729, 4730, 4731, 4732, 4733, 4734, 4735, 4736, 4737, 4738, 4739, 4740 and 4741). We own a 100% working interest in Licenses 4729, 4730, 4731, 4732, 4733, 4734, 4735, 4736, 4737, 4738, 4739, 4740 and 4741, which cover an aggregate of approximately 1.6 million acres (6,475 square kilometers) in central Turkey. These licenses are in a large, relatively unexplored tertiary basin. We are the operator of the licenses, which expire in December 2014.

 

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Gurun (License 4325). We own a 90% working interest in License 4325, which covers approximately 122,000 acres (495 square kilometers) in central Turkey. In April 2009, we farmed-in to License 4325 for cash consideration and the obligation to carry a 10% interest in the first well drilled to earn a 90% interest in the license. We plan to drill one exploratory well on License 4325 in 2011. We are the operator of License 4325, which expires in February 2012.

Yuksekkoy (License 4350). We own a 100% working interest in License 4350, which covers approximately 121,000 acres (488 square kilometers) on the Mediterranean coast of Turkey. We are the operator of License 4350, which expires in March 2012.

Gaziantep (Licenses 4607, 4638, 4648, 4649 and 4656). In March 2010, we entered into a farm-in agreement with TBNG to acquire a 50% working interest in Licenses 4607, 4638, 4648, 4649 and 4656, which cover an aggregate of approximately 610,000 acres (6,447 square kilometers) near the Turkish border with Syria. To earn the interest, we will pay 62.5% of total drilling and seismic costs on the licenses until 12.5% of total drilling and seismic costs paid equals $750,000. Thereafter, we will pay 50% of drilling and seismic costs incurred. We expect to terminate this farm-in agreement upon our acquisition of TBNG, which is expected to occur in the second quarter of 2011. TBNG is the operator of these licenses, which expire in October 2013, except License 4607, which expires in August 2013.

We lease an equipment yard in Diyarbakir and own equipment yards at Selmo and Edirne. We currently own six drilling rigs and four workover and completion rigs that are located in Turkey. We also manage one drilling rig in Turkey for Viking Drilling pursuant to a management services agreement.

We had total net proved reserves of 12,936 Mbbl of oil and 22,425 Mmcf of natural gas, net probable reserves of 5,341 Mbbl of oil and 38,312 Mmcf of natural gas and net possible reserves of 12,803 Mbbl of oil and 174,126 Mmcf of natural gas in Turkey as of December 31, 2010.

Commercial Terms. Turkey’s fiscal regime for oil and gas licenses is presently comprised of royalties and income tax. Royalties are at 12.5% and the corporate income tax rate is 20%. The licenses have a four-year term but after the third year, a payment in the form of a bond must be made to extend the license if no new well has been drilled prior to that date. The GDPA, the agency responsible for the regulation of oil and gas activities under the Ministry of Energy and Natural Resources in Turkey, awards a license after it approves the applicant’s work program, which may include obligations such as geological and geophysical work, seismic reprocessing and interpretation and contingent shooting of seismic and drilling of wells.

Licensing Regime. The licensing process in Turkey for oil and gas concessions occurs in three stages: permit, license and lease. Under a permit, the government grants the non-exclusive right to conduct a geological investigation over an area. The size of the area and the term of the permit are subject to the discretion of the GDPA.

A license grants exclusive rights over an area for the exploration for petroleum. A license has a term of four years and requires drilling activities by the third year, but this obligation may be deferred into the fourth year by posting a bond. No single company may own more than eight licenses within a district. Rentals are due annually based on the hectares under the license.

Once a discovery is made, the license holder applies to convert the area, not to exceed 25,000 hectares, to a lease. Under a lease, the lessee may produce oil and gas. The term of a lease is for 20 years. Annual rentals are due based on the hectares comprising the lease.

 

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Morocco

General. As of April 1, 2011, we owned interests in eight onshore exploration permits in northern Morocco. The following is a map showing our interests in Morocco:

LOGO

Tselfat. We own a 100% working interest in the Tselfat exploration permit (subject to a 25% participation interest by ONHYM once production is achieved), which covers approximately 222,000 acres (900 square kilometers) in northern Morocco. As part of our recent extension of the license period, in January 2011 we relinquished 45% of our Tselfat exploration permit acreage. The Tselfat exploration permit covers three existing fields, Haricha, Brou Draa and Tselfat, that produced from the early 1920s to 1970s, with limited production continuing into the 1990s. The Tselfat permit provides several opportunities including redevelopment of the existing fields, extensions of known productive horizons and exploration of higher impact targets at depth.

Since the award of the Tselfat exploration permit in 2006, we have been collecting, collating, digitizing and reviewing all of the existing well, production, seismic and other data. In addition, we shot a 175 square kilometer 3D seismic survey over the Brou Draa and Haricha fields. In 2009, we drilled the HR-33 bis well in the Haricha field to help assess whether there is the opportunity for redevelopment of the previously produced but abandoned Haricha field. We have put the HR-33 bis well on an extended production test to determine if the well is commercially viable. We commenced crude oil production in January 2011. The crude oil produced during the test is trucked approximately 200 kilometers to a refinery operated by SAMIR in Mohammedia, Morocco. If testing confirms the HR-33 bis well as a commercial well, we plan to delineate the oil field and apply for an exploitation concession and drill at least one additional well on the Haricha field. In 2010, we drilled the BTK-1 well and the GUW-1 well, which have both been plugged and abandoned after failing to discover hydrocarbons in commercial quantities. We plan to drill three exploration wells to a depth of at least 1,500 meters on the Tselfat exploration permit in 2011. We are the operator of the Tselfat exploration permit, which expires in June 2012.

Asilah. We own a 100% working interest in the two Asilah exploration permits (subject to a 25% participation interest by ONHYM once production is achieved), which cover an aggregate of approximately 681,000 acres (2,754 square kilometers) in northern Morocco. In July 2008, we entered into an agreement with Direct Morocco and Anschutz to farm-in to the Asilah exploration permits. In February 2011, we acquired all of the working interests in the Asilah exploration permits through our acquisition of Direct Morocco and Anschutz and terminated the agreement in March 2011. We conducted a 2D seismic survey in late 2008 and acquired 290 kilometers of 2D seismic data on the Asilah exploration permits. In December 2010, we commenced drilling the GRB-1 well which reached total depth in March 2011. The GRB-1 well targeted tertiary-aged reservoirs, and in 2011, we plan to test numerous intervals that had gas shows while drilling. We are the operator of the Asilah exploration permits, which expire in May 2012.

Ouezzane-Tissa. We own a 100% working interest in five Ouezzane-Tissa exploration permits, which cover an aggregate of approximately 2.4 million acres (9,533 square kilometers) in northern Morocco. In July 2008, we entered into an agreement with Direct Morocco and Anschutz to farm-in to the Ouezzane-Tissa exploration permits. In February 2011, we acquired all of the working interests in the Ouezzane-Tissa exploration permits through our acquisition of Direct Morocco and Anschutz and terminated the agreement in March 2011. The first well, the OZW-1 well, encountered an extremely high

 

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pressure water zone near 9,000 feet which we could not drill through and was plugged and abandoned. We drilled the second well, the HKE-1 well, which did not reach target depth and was plugged and abandoned. The third well, the HKE-1 bis well, did not discover hydrocarbons in commercial quantities and is being plugged and abandoned. We plan to relinquish the Ouezzane-Tissa exploration permits in 2011, and upon ONHYM’s acceptance of our final report we expect to have $3.0 million in work commitment bank guarantees returned to us. We are the operator of the Ouezzane-Tissa exploration permits.

Guercif. In June 2005, we were awarded the Guercif-Beni Znassen reconnaissance license covering 3.4 million acres (13,750 square kilometers) in northeastern Morocco. In January 2008, we converted a portion of our Guercif-Beni Znassen reconnaissance license into two exploration permits covering a total of 962,000 acres (3,893 square kilometers) in the Guercif area in northeastern Morocco, pursuant to a petroleum agreement with ONHYM. The Guercif exploration permits were for an eight-year term divided into three periods, each with a defined work program. Under the initial three-year work program, we re-entered, logged and tested the MSD-1 well, which we completed as a dry hole in the fourth quarter of 2008. The logs and test failed to establish the presence of hydrocarbons. In December 2010, we abandoned our interests in the Guercif exploration permits. As part of our agreement with ONHYM for the abandonment of the Guercif exploration permits, we transferred an obligation to drill one well from the Guercif exploration permits to the Tselfat exploration permit. Upon ONHYM’s acceptance of our final report, we expect to have $2.0 million in work commitment bank guarantees returned to us.

We lease an equipment yard in Meknes, and we currently have two drilling rigs located in Morocco. There are no reserves associated with our Moroccan properties as of December 31, 2010.

Commercial Terms. During the exploration phase of each exploration permit, we and our partners, if any, will operate and bear 100% of the costs to earn a 75% interest. Our interests are subject to the 25% interest held by ONHYM, which is carried by us and our partners, if any, during the exploration phase, all of which is governed by the applicable petroleum agreement. ONHYM pays its share of costs in the development phase. Once a discovery is made, the area covered by the discovery is converted into an exploitation concession, which is governed by the applicable association contract. Under an exploitation concession, we and our partners, if any, (75%) and ONHYM (25%) will each pay our respective share of costs. Upon conversion to an exploitation concession, we will pay a discovery bonus to ONHYM, and when certain sustained daily production levels are reached, we will pay one-time production bonuses. At Tselfat and Asilah, the discovery bonus at conversion is $500,000 and the one-time production bonuses are as follows: 15,000 Bbls/day—$750,000; 25,000 Bbls/day—$1 million; 35,000 Bbls/day—$2 million and 50,000 Bbls/day—$3 million. These production bonuses are deductible and are treated as development costs for Moroccan tax purposes. There is a ten-year tax holiday on revenues from petroleum production commencing in the year in which production begins. After ten years, the corporate tax rate is 30%. Oil and gas exploration activities are exempt from both value added tax and customs duties.

The royalty paid to the Moroccan government for onshore production is 10% on oil and 5% on gas. In addition, the first approximately 2.1 Mmbbl of oil production and the first approximately 11 billion cubic feet of gas production are exempt from royalty. Once an area is converted into an exploitation concession, we are required to pay annual surface rentals of $2.85 per acre.

Licensing Regime. The licensing process in Morocco for oil and gas concessions occurs in three stages: reconnaissance license, exploration permit and then exploitation concession.

Under a reconnaissance license, the government grants exploration rights for a one-year term to conduct seismic and other exploratory activities, but not drilling. The size may be very large and generally is unexplored or under-explored. The reconnaissance license may be extended for up to one additional year. Interests under a reconnaissance license are not transferable. The recipient of a reconnaissance license commits to a work program and posts a bank guarantee in the amount of the estimated cost for the program. At the end of the term of the reconnaissance license, the license holder must designate one or more areas for conversion to an exploration permit or relinquish all rights.

An exploration permit, which is codified in a petroleum agreement with ONHYM, is for a term of up to eight years and covers an area not to exceed 2,000 square kilometers. Under an exploration permit, exploration and appraisal studies and operations are undertaken in order to establish the existence of oil and gas in commercially exploitable quantities. This generally entails the drilling of exploration wells to establish the presence of oil and/or gas and such additional appraisal wells as may be necessary to determine the limits and the productive capacity of a hydrocarbon deposit to determine whether or not to go forward to develop and produce the prospect. The eight-year term under an exploration permit is divided into three separate terms, each with a duration of two to three years. A distinct work program is negotiated for each separate term and the oil company then must post a bank guarantee to cover the cost of the work program for that term. The interests under an exploration permit are 75% to the oil company and 25% to ONHYM. Interests under an exploration permit are transferable. However, 100% of the costs of all activities under an exploration permit are borne by the oil company.

 

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An exploitation concession is applied for upon the discovery of a commercially exploitable field. The concession size corresponds to the area of the commercial discovery. The maximum duration of an exploitation concession is 25 years. Once an exploitation concession becomes effective, then the costs incurred for the development of the field are to be funded by the parties in proportion to their respective percentage interests, which is 75% to the oil company and 25% to ONHYM. The oil company serves as operator. The oil company and ONHYM enter into an association contract (similar to a joint operating agreement) to govern operations on the concession. Interests under an exploitation concession are transferable. All production is sold at market prices. A bonus (the amount of which is negotiated at the time of negotiation of a petroleum agreement) is paid to the government by the oil company upon conversion to an exploitation concession, and additional production bonuses are also paid when certain production levels from the exploitation concession are achieved. The levels of production and the amount of production bonuses are negotiated as part of a petroleum agreement.

Bulgaria

General. As of April 1, 2011, we owned interests in two onshore exploration permits in Bulgaria. We acquired all of our Bulgarian interests through the purchase of Direct Bulgaria in February 2011. The following is a map showing our interests in Bulgaria and Romania:

LOGO

A-Lovech. We own a 100% working interest, subject to a 3% overriding royalty interest, in the A-Lovech exploration permit, which covers approximately 565,000 acres (2,288 square kilometers) in northwestern Bulgaria. The A-Lovech permit contains the Deventci-R1 well, which discovered a reservoir in the Jurassic Orzirovo formation at a depth of approximately 4,200 meters. The well is currently producing approximately 250 Mcf of natural gas per day on a limited test basis, which is sold to a compressed natural gas facility adjacent to the Deventci-R1 well. We plan to appraise this discovery by drilling a second well, the Deventci-R2, on the A-Lovech permit in 2011. We are the operator of the A-Lovech permit, which expires in November 2011. We have submitted an application for a production concession covering approximately 160,000 acres of the A-Lovech permit.

The A-Lovech permit is also estimated to contain over 300,000 acres prospective for Etropole shale (at a depth of approximately 3,800 meters), which was recently certified as a geologic discovery by the Bulgarian government. We anticipate coring the Etropole shale interval, which will enhance the technical understanding of the potential of this shale play.

Aglen. We own a 100% working interest, subject to a 1% overriding royalty interest, in the Aglen exploration permit, which covers approximately 1,700 acres (7 square kilometers) within the boundaries of the A-Lovech permit. The Aglen permit contains a prospective deep gas field that produced approximately 9.0 billion cubic feet of natural gas before being abandoned in the late 1990s. We are the operator of the Aglen permit, which expires in April 2012.

We do not own any drilling rigs in Bulgaria. There are no reserves associated with our Bulgarian properties as of December 31, 2010.

 

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Commercial Terms. Bulgaria’s current petroleum laws provide a framework for investment and operation that allows foreign investors to retain the proceeds from the sale of petroleum production. The fiscal regime is comprised of royalties and income tax.

The royalty ranges from 2.5% to 30%, based on an “R factor” which is particular to each production concession agreement but is typically calculated by dividing the total cumulative revenues from a production concession by the total cumulative costs incurred for that production concession.

The production concession holder pays Bulgarian corporate income tax, which is assessed at a rate of 10%. All costs incurred in connection with exploration, development and production operations are deductible for corporate income tax purposes. Resident companies which remit dividends outside of Bulgaria are subject to a dividend withholding tax between 10% to 15%, depending on the proportion of the capital owned by the recipient. No customs duty is payable on the export of petroleum, nor is customs duty payable on the import of material necessary for the conduct of petroleum operations. There is also a 19% value added tax. Oil is priced at market while gas is tied to a bundle pricing based in part on the import price and in part on the domestic price.

Licensing Regime. The licensing process in Bulgaria for oil and gas concessions occurs in two stages: exploration permit and then production concession.

Under an exploration permit, the government grants exploration rights for a term of up to five years to conduct seismic and other exploratory activities, including drilling. The recipient of an exploration permit commits to a work program and posts a bank guarantee in the amount of the estimated cost for the program. The area covered by an onshore exploration permit may be as large as 5,000 square kilometers. The exploration permit may be extended for up to two additional two-year terms, subject to fulfillment of minimum work programs, and may be extended for an additional one-year term in order to appraise potential geologic discoveries. Interests under an exploration permit are transferable, subject to government approval. The permit holder is required to pay an annual area fee equal to 30 Bulgarian Leva (approximately $22) per square kilometer, or 45 Bulgarian Leva (approximately $33) per square kilometer in the event the permit term is extended.

Upon the registration of a commercial discovery, an exploration permit holder may apply for a production concession. The production concession size corresponds to the area of the commercial discovery. The duration of a production concession is 35 years and may be extended by a further 15 years subject to the terms and conditions of the production concession agreement. Interests under a production concession are transferable, subject to government approval. No bonus is paid to the government by the oil company upon conversion to a production concession.

Romania

General. As of April 1, 2011, we owned an interest in one onshore production license in Romania, which was acquired through a farm-in agreement with Sterling in June 2009. The map showing our interest in Romania is on the previous page.

Sud Craiova. We own a 50% working interest in Sud Craiova Block E III-7, which covers approximately 1.5 million acres (6,070 square kilometers) in western Romania. In June 2009, we entered into an agreement with Sterling to farm-in to the Sud Craiova license. In exchange for a 50% working interest, we agreed to drill three exploration wells on the Sud Craiova license, each to a depth of approximately 3,280 feet (1,000 meters). We drilled three exploration wells at our cost on the Sud Craiova license in 2009 and 2010, all of which have been plugged and abandoned after failing to discover hydrocarbons in commercial quantities. We are currently reprocessing seismic data previously shot over the Sud Craiova license and plan to drill an exploration well to test the Silurian-aged shale formations at a depth of approximately 4,200 meters. Sterling is the operator of the Sud Craiova license, which expires in December 2013.

Izvoru, Vanatori and Marsa. In February 2006, we were awarded the Izvoru, Vanatori and Marsa production licenses, covering approximately 1,200 acres (5 square kilometers), 780 acres (4 square kilometers) and 188 acres (1 square kilometer), respectively. In 2009 and 2010, we drilled a total of five wells on the licenses, all of which were plugged and abandoned after failing to discover hydrocarbons in commercial quantities. In December 2010, we relinquished our interests in each of these three licenses.

We lease an equipment yard in Izvoru. We do not own any drilling rigs in Romania. There are no reserves associated with our Romanian properties as of December 31, 2010.

 

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Commercial Terms. Romania’s current petroleum laws provide a framework for investment and operation that allows foreign investors to retain the proceeds from the sale of petroleum production. The fiscal regime is comprised of royalties, excise tax and income tax. Two forms of royalty are payable as:

 

   

a percentage of the value of gross production on a field basis, such percentage being fixed on a sliding scale depending on production levels. The production royalty rate varies between 3.5% to 13.5% for crude oil and between 3% to 13% for natural gas production; and

 

   

a fixed percentage of the gross income obtained from the transportation and transit of petroleum through the national pipeline system and from petroleum operations carried out through oil terminals belonging to the state. The royalty rate is currently fixed at 5%.

The license holder pays Romanian corporate income tax, but enjoys a one-year income tax holiday from the first day of production. Corporate income tax is assessed at a rate of 16%. All costs incurred in connection with exploration, development and production operations are deductible for corporate income tax purposes. Excise duty is payable on crude oil and natural gas at the rate of 4 Euro per ton of crude oil and 7.4 Euro per 1,000 cubic meters of natural gas. Excise tax is not payable on crude oil or natural gas delivered as royalty to the Romanian government or on quantities directly exported. Resident companies which remit dividends outside of Romania are subject to a dividend withholding tax at between 10% to 15%, depending on the proportion of the capital owned by the recipient. No customs duty is payable on the export of petroleum, nor is customs duty payable on the import of material necessary for the conduct of petroleum operations. There is also a 19% value added tax. Oil is priced at market while gas is tied to a bundle pricing based in part on the import price and in part on the domestic price.

Licensing Regime. The Ministry of Industry and Resources of Romania has responsibility for petroleum policy and strategy. The National Agency for Mineral Resources (“NAMR”) was set up in 1993 to administer and regulate petroleum operations. When licenses are to be made available, NAMR publishes a list of available blocks for concession in the Official Gazette. Foreign and Romanian companies must register their interest by a specified date and must submit applications by an application deadline. Applicants are required to prove their financial capacity, technical expertise and other requirements as required by NAMR. The licensing rounds are competitive and the winning bid is based on a scoring system.

NAMR negotiates the terms of agreements granting the licenses with the winning licensee and the license agreement is then submitted to the Romanian government for its approval. The date of government approval is the effective date of the license. Blocks which fail to attract a prescribed level of bids are re-offered in a subsequent licensing round. NAMR may issue a prospecting permit or a petroleum concession. A prospecting permit is for the conduct of geological mapping, magnetometry, gravimetry, seismology, geochemistry, remote sensing and drilling of wildcat wells in order to determine the general geological conditions favoring petroleum accumulations. A petroleum concession provides exclusive rights to conduct petroleum exploration and production under a petroleum agreement.

United States

California. Through the Incremental acquisition, we acquired interests in three projects in the San Joaquin Valley in central California: farm-outs on the McFlurrey project and the South East Kettleman North Dome oil field and a small non-operated working interest in the Kettleman Middle Dome Unit.

In February 2010, we entered into a settlement agreement with our partner in the McFlurrey and South East Kettleman North Dome farm-outs to settle certain disagreements between us and our partner. Pursuant to the settlement agreement, we resigned as operator of the farm-outs and transferred ownership of the two McFlurrey wells to the partner, subject to our obligation to plug and abandon the first well at our cost, which we have accomplished. In addition, we paid the partner for our share of the costs of plugging and abandoning, and cleaning up and restoring the surface and well site of the second well. We paid a total of $84,000 to plug, abandon and restore the two wells.

We own a non-operated working interest in the Kettleman Middle Dome Unit located in Kings County, California. This unit produces approximately 150 gross Bbls (approximately 8 net Bbls) of oil per day along with small amounts of associated natural gas. We own a 5% interest in five existing wells on the Kettleman Middle Dome Unit (three are currently producing). On all new projects and well proposals submitted and completed after May 16, 2008, we will own a 10% non-operated working interest. We are currently seeking purchasers for our interest in the Kettleman Middle Dome Unit.

 

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Oklahoma. In Oklahoma, we lease two properties, one in Dewey County (128 net acres) and one in McClain County (29 net acres). We own a 20% non-operated working interest in a well on the Dewey County property that is currently producing a small amount of oil and natural gas.

There are no reserves associated with our U.S. properties as of December 31, 2010.

Summary of Oil and Gas Reserves

All of our net proved, probable and possible reserves are located in Turkey. The following table summarizes our net proved, probable and possible reserves in Turkey at December 31, 2010 in accordance with the rules and regulations of the SEC.

 

     Reserves  

Reserves Category

   Oil and Condensate
(Mbbl)
     Natural Gas
(Mmcf)
     Total
(Mboe)
 

Proved Reserves

        

Proved Developed

     5,588         16,560         8,348   

Proved Undeveloped

     7,348         5,865         8,326   

Probable Reserves

     5,341         38,312         11,726   

Possible Reserves

     12,803         174,126         41,824   

Total

     31,080         234,863         70,224   

Value of Proved Reserves

The following table shows our estimated future net revenue, PV-10 and Standardized Measure as of December 31, 2010:

 

(in thousands)

      

Future net revenue

   $ 817,138   

Total PV-10(1)

   $ 536,282   

Total Standardized Measure

   $ 438,367   

 

(1) Management believes that the presentation of PV-10, while not a financial measure in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”), provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of financial or operating performance under U.S. GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under U.S. GAAP. The Standardized Measure represents the PV-10 after giving effect to income taxes. The following table provides a reconciliation of our PV-10 to our Standardized Measure:

 

(in thousands)

      

Total PV-10

   $ 536,282   

Future income taxes

   $ (143,000

Discount of future income taxes at 10% per annum

   $ 45,085   
        

Standardized Measure

   $ 438,367   
        

Proved Reserves

Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors. See “—Oil and Gas Reserves under U.S. Law.”

 

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At December 31, 2010, our estimated proved reserves were 16,674 Mboe, an increase of 43.1% compared to 11,649 Mboe at December 31, 2009. During 2010, we added estimated proved reserves of 321 Mboe through extensions and discoveries driven by our 2010 drilling activity in Turkey, 2,250 Mboe through the acquisition of Amity and Petrogas and 3,429 Mboe through significant additions in proved undeveloped reserves at the Selmo oil field, which were offset by production volumes of 975 Mboe.

Proved Undeveloped Reserves

At December 31, 2010, our estimated proved undeveloped reserves were 8,326 Mboe, an increase of 60.1% compared to 5,202 Mboe at December 31, 2009. This increase in proved undeveloped reserves is primarily attributable to additions to proved undeveloped reserves at the Selmo oil field and was partially offset by proved undeveloped reserves being converted to proved developed reserves at the Edirne gas field. There were 1,548 Mboe proved undeveloped reserves that were converted to proved developed reserves due to 17 proved undeveloped well locations that were drilled and placed in production in 2010. During 2010, we incurred $19.6 million in capital expenditures to drill and bring on-line these 17 proved undeveloped wells. At December 31, 2010, no material amounts of proved undeveloped reserves remained undeveloped for five years or more after they were initially disclosed as proved undeveloped reserves. We intend to convert the proved undeveloped reserves disclosed as of December 31, 2010 to proved developed reserves within five years of the date they were initially disclosed as proved undeveloped reserves.

Probable Reserves

Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil and gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. See “—Oil and Gas Reserves under U.S. Law.”

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

At December 31, 2010, our estimated probable reserves were 11,726 Mboe. Increases in probable reserves during 2010 were primarily attributable to the acquisition of Amity and Petrogas in August 2011.

Possible Reserves

Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of oil and gas that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. See “—Oil and Gas Reserves under U.S. Law.”

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserve where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir. Possible reserves also include incremental quantities associated with a greater percentage of recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be

 

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assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

At December 31, 2010, our estimated possible reserves were 41,824 Mboe. Increases in possible reserves during 2010 were primarily attributable to the acquisition of Amity and Petrogas in August 2011.

Internal Controls

Management has established, and is responsible for, a number of internal controls designed to provide reasonable assurance that the estimates of proved, probable and possible reserves are computed and reported in accordance with rules and regulations provided by the SEC as well as established industry practices used by independent engineering firms and our peers. These internal controls consist of documented process workflows and qualified professional engineering and geological personnel with specific reservoir experience. We also retain an outside independent engineering firm to prepare estimates of our proved, probable and possible reserves. We work closely with this firm, and management is responsible for providing accurate operating and technical data to it. Our internal audit department has tested the processes and controls regarding our reserves estimates for 2010. Senior management reviews and approves our reserve estimates, whether prepared internally or by third parties. In addition, our audit committee serves as our reserves committee and is composed of three outside directors, all of whom have experience in the review of energy company reserves evaluations. The audit committee reviews the final reserves estimate and also meets with representatives from the outside engineering firm to discuss their process and findings.

Oil and Gas Reserves under U.S. Law

In the United States, we are required to disclose proved reserves, and we are permitted to disclose probable and possible reserves, using the standards contained in Rule 4-10(a) of the SEC’s Regulation S-X. The estimates of proved, probable and possible reserves presented as of December 31, 2010 have been prepared by DeGolyer and MacNaughton, our external engineers. The technical person at DeGolyer and MacNaughton that is primarily responsible for overseeing the preparation of our reserves estimates is a Registered Professional Engineer in the State of Texas and has a Bachelor of Science degree in Mechanical Engineering from Kansas State University. He has over 28 years of experience in oil and gas reservoir studies and evaluations, is a member of the International Society of Petroleum Engineers and meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with DeGolyer and MacNaughton to ensure the integrity, accuracy and timeliness of data furnished to them for the preparation of their reserves estimates. Our internal senior reservoir engineer is the technical person primarily responsible for overseeing the reserve estimation process. He has a Bachelor of Science degree in Petroleum Engineering from the University of Oklahoma. He has over 37 years of experience in the oil and gas industry, including experience in operations, drilling and reservoir engineering, and is a member of multiple professional organizations.

Estimates of oil and natural gas reserves are projections based on a process involving an independent third party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs. We also make assumptions relating to availability of funds and timing of capital expenditures for development of our proved undeveloped, probable and possible reserves. These reports should not be construed as the current market value of our reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the reserves will ultimately be realized. Our actual results could differ materially. See “Note 21—Supplemental oil and natural gas reserves and standard measure information (unaudited)” to our consolidated financial statements for additional information regarding our oil and natural gas reserves.

The technologies and economic data used in the estimation of our proved, probable and possible reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

The estimates of proved, probable and possible reserves prepared by DeGolyer and MacNaughton for the year ended December 31, 2010 included a detailed review of our Selmo, Arpatepe, Bakuk and Thrace Basin properties in Turkey. DeGolyer and MacNaughton determined that our estimates of reserves conform to the guidelines of the SEC, including the

 

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criteria of “reasonable certainty,” as it pertains to expectations about whether reserves are economically producible from a given date forward, under existing economic conditions, operating methods and government regulations, consistent with the definition in Rule 4-10(a)(24) of SEC Regulation S-X.

Oil and Gas Reserves under Canadian Law

As a reporting issuer under Alberta, British Columbia and Ontario securities laws, we are required under Canadian law to comply with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”) implemented by the members of the Canadian Securities Administrators in all of our reserves related disclosures. DeGolyer and MacNaughton evaluated the Company’s reserves as of December 31, 2010 in accordance with the reserves definitions of NI 51-101 and the Canadian Oil and Gas Evaluators Handbook (“COGEH”). Our annual oil and gas reserves disclosures prepared in accordance with NI 51-101 and COGEH and filed in Canada are available at www.sedar.com.

Oil and Gas Production, Production Prices and Production Costs

The following table sets forth our net production of oil and natural gas, after royalties for 2010, 2009 and 2008:

 

     Net Production  

Year

   Oil(1)
(Bbls)
    Natural Gas
(Mcf)
     Total
(Boe)
 

2010

       

Turkey

     689,823 (2)      1,707,421         974,393   

United States

     638        1,437         878   

2009

       

Turkey

     417,071 (2)      —           417,071   

United States

     798        1,429         1,036   

2008

       

Turkey

     —          —           —     

United States

     863        2,029         1,201   

 

  (1) “Oil” volumes include condensate (light oil) and medium crude oil.
  (2) During 2010 and 2009, our net production of crude oil in the Selmo field, after royalties, was 631,149 Bbls and 411,964 Bbls, respectively.

The following table sets forth the average sales price per Bbl of oil and Mcf of natural gas and the average production cost, not including ad valorem and severance taxes, per unit of production for each of 2010, 2009 and 2008:

 

     2010      2009      2008  

Turkey

        

Average Sales Price

        

Oil ($/Bbl)

     80.01         66.05         —     

Natural Gas ($/Mcf)

     7.63         —           —     

Unit Costs

        

Production ($/Boe)

     20.48         23.53         —     

United States

        

Average Sales Price

        

Oil ($/Bbl)

     74.08         54.47         100.98   

Natural Gas ($/Mcf)

     7.44         5.07         11.70   

Unit Costs

        

Production ($/Boe)

     35.91         43.01         60.77   

 

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Drilling Activity

The following table sets forth the number of net productive and dry exploratory wells and net productive and dry development wells we drilled for 2010, 2009 and 2008:

 

     Development Wells      Exploratory Wells  
     Productive      Dry      Productive      Dry  

Turkey

           

2010

     13.75         4.2         2.5         2.5   

2009

     5.1         —           —           —     

2008

     —           —           —           —     

Morocco

           

2010

     —           —           —           3.5   

2009

     —           —           —           1.5   

2008

     —           —           —           —     

Romania

           

2010

     —           2         —           1   

2009

     —           3         —           0.5   

2008

     —           —           —           —     

United States

           

2010

     —           —           —           —     

2009

     —           —           —           1   

2008

     —           —           —           —     

Current Operations

We are in the process of integrating the Amity, Petrogas and Direct Bulgaria properties, equipment and personnel into our operations. We have substantially integrated the Incremental, Talon, Anschutz and Direct Morocco acquisitions and organized our activities in Turkey into a service division consisting of two wholly-owned subsidiaries, Viking International and Viking Geophysical, and into an exploration and production division consisting of six wholly-owned exploration and production subsidiaries: TEMI, TAT, Talon, DMLP, Amity and Petrogas.

As of April 1, 2011, we were producing an aggregate of approximately 2,767 Bbls of oil per day from the Selmo and Arpatepe oil fields and approximately 15.9 Mmcf of natural gas per day in the Thrace Basin and were engaged in the following drilling and exploration activities.

Turkey. We are drilling two wells at Selmo and two wells in the Thrace Basin. In addition, we are completing two wells at Selmo and testing and completing the Kalatepe-1 well on License 4175. We are testing and commissioning the recently completed 23 kilometer, 6-inch pipeline from the Bakuk-101 well to an existing pipeline to the south and expect to begin limited natural gas sales in the second quarter of 2011. We are now evaluating options for further appraisal of the reservoir. We are constructing a 20 kilometer, 10-inch pipeline to carry natural gas from the Alpullu gas field in the Thrace Basin to an existing pipeline. We are conducting a 236 kilometer 2D seismic shoot on License 4350.

Morocco. We have constructed water separation facilities at the HR-33 bis well on the Tselfat exploration permit and are conducting an extended production test on that well.

Bulgaria. We are evaluating potential locations for the planned Deventci-R2 well, which will appraise the Orzirovo formation and core the Etropole shale formation.

Romania. We are evaluating a potential exploration well to test a potential Jurassic oil play and reprocessing seismic data previously shot over the Sud Craiova license.

 

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Planned 2011 Operations

We continue to actively explore and develop our existing oil and gas properties in Turkey, Morocco and Bulgaria and evaluate the opportunities for further activities in Romania. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. In 2011, we are focused on accomplishing the following objectives:

 

   

Increasing Production. Our goal is to achieve a production rate of 10,000 Boe per day in Turkey by the end of 2011. We plan to increase our crude oil and natural gas production in Turkey through continuous drilling in Selmo and the Thrace Basin, the completion of pipelines to bring shut-in gas to market, the application of modern well stimulation techniques such as gelled acidizing and fracture stimulation, and the introduction of directional drilling.

 

   

Securing Partners to Reduce Exploration Risk. We are actively seeking partners for our exploration acreage in Turkey, Morocco, Bulgaria and Romania. Through farm-outs, we expect to reduce our exploration risk and accelerate the exploration and development activities on the farmed-out properties. We have begun consolidating and analyzing well data and seismic data for our properties in Bulgaria and our exploration acreage in Turkey. It is our intention to remain as operator in the properties that we farm-out.

 

   

Integrating Acquisitions. We expect to complete the acquisition of TBNG and Pinnacle in the second quarter of 2011, which will bring additional acreage, production, personnel and equipment into our Turkey operations. We will continue to integrate the recent acquisitions of Amity, Petrogas and Direct Bulgaria.

Capital expenditures for 2011 are expected to range between $125.0 million and $150.0 million. Approximately 50% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Approximately 35% of these anticipated expenditures will occur in southeastern Turkey, devoted to developing crude oil production at Selmo and Arpatepe and drilling exploratory wells on various licenses. The balance of the estimated budget is divided between exploration activities in Morocco and Romania. We are seeking a joint venture partner to fund our anticipated capital expenditures in Bulgaria in 2011. If cash on hand, borrowings from our senior secured credit facility and cash flow from operations are not sufficient to fund our capital expenditures, then we will either curtail our discretionary capital expenditures or seek other funding sources. We currently plan to execute the following drilling and exploration activities in 2011:

Turkey. We plan to drill approximately 90-100 wells during 2011, including wells to be drilled on acreage held by TBNG, which we expect to acquire in the second quarter of 2011. If we do not complete the acquisition of TBNG, the number of wells we expect to drill in 2011 may change. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill.

Morocco. On our Tselfat exploration permit, we are currently producing oil from the HR-33 bis well on an extended production test to determine if the well is commercially viable. If testing confirms the HR-33 bis well as a commercial well, we plan to delineate the oil field, apply for an exploitation concession and drill at least one additional well in the Haricha field. We also plan to drill the TKN-1 well to test another 3D seismic prospect that is similar to the Haricha field. If the TKN-1 well is a commercial well, we would likely drill an additional appraisal well. We plan to drill three exploration wells to a depth of at least 1,500 meters on the Tselfat exploration permit in 2011. On our Asilah exploration permit, we are planning to test the recently completed GRB-1 well, which had substantial gas shows during drilling. If that well is completed as a commercial well we would likely drill additional appraisal wells and develop plans to commercialize those wells.

Bulgaria. We plan to drill the Deventci-R2 well on the A-Lovech exploration permit to appraise the Deventci-R1 well gas discovery. While drilling the appraisal well on the A-Lovech permit, we plan to test the productivity of the Etropole shale interval. We may also drill an additional appraisal well on the Aglen exploration permit. If the appraisal well on the Aglen permit is successful, we anticipate planning the construction of a pipeline to connect the Deventci wells to a natural gas pipeline to the south. We are seeking to enter into a joint venture where the joint venture partner would carry us in the capital expenditures incurred in Bulgaria in 2011.

Romania. We plan to drill an exploration well to test the Silurian-aged shale formations present on the Sud Craiova license. We may also drill an exploration well to test the Coyote oil prospect on the southeastern portion of the Sud Craiova license.

Drilling Services Business. We plan to continue to increase drilling services revenues by providing drilling services and seismic acquisition services to third parties in Turkey and northern Iraq.

 

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Oil and Gas Properties, Wells, Operations and Acreage

Productive Wells. The following table sets forth the number of productive wells (wells that were currently producing oil or natural gas or were capable of production) in which we held a working interest as of December 31, 2010:

 

     Oil      Natural Gas  
     Gross(1)      Net(2)      Gross(1)      Net(2)  

Turkey

     40         38.5         45         26.65   

United States

     —           —           4         0.4   

 

  (1)   “Gross wells” means the wells in which we hold a working interest (operating or non-operating).
  (2)   “Net wells” means the sum of the fractional working interests owned in gross wells.

Developed Acreage. The following table sets forth our total gross and net developed acreage as of December 31, 2010:

 

     Developed (Acres)  
     Gross(1)      Net(2)  

Turkey

     802,080         472,935   

United States

     2,228         131   
                 

Total

     804,308         473,066   
                 

 

  (1)   “Gross” means the total number of acres in which we have a working interest.
  (2)   “Net” means the sum of the fractional working interests owned in gross acres.

Undeveloped Acreage. The following table sets forth our undeveloped land position as of December 31, 2010:

 

     Undeveloped
(Acres)
 
     Gross(1)      Net(2)  

Turkey

     5,583,094         5,504,922   

Morocco

     3,258,525         1,740,435   

Romania

     1,441,854         720,927   

United States

     29         29   
                 

Total

     10,283,502         7,966,313   
                 

 

      (1)     “Gross” means the total number of acres in which we have a working interest.
      (2)     “Net” means the sum of the fractional working interests owned in gross acres.

Undeveloped Acreage Expirations. The following table summarizes by year our undeveloped acreage scheduled to expire in the next five years:

 

As of December 31,

   Undeveloped
(Acres)
     % of Total
Undeveloped
(Acres)
 
     Gross(1)      Net(2)      Net(2)  

2011

     2,475,364         1,297,564         16.3   

2012

     2,707,107         2,354,592         29.6   

2013

     2,534,120         1,808,944         22.7   

2014

     2,566,912         2,505,214         31.4   

2015

     —           —           —     

 

  (1) “Gross” means the total number of acres in which we have a working interest.
  (2) “Net” means the sum of the fractional working interests owned in gross acres.

 

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Item 3. Legal Proceedings.

TEMI has been involved in litigation with persons who claim ownership of a portion of the surface at the Selmo oil field in Turkey. These cases are being vigorously defended by TEMI and Turkish government authorities. We do not have enough information to estimate the potential additional operating costs we could incur in the event the purported surface owners’ claims are ultimately successful.

In 2003, a group of villagers living around the Selmo field applied to the Kozluk Civil Court of First Instance in Turkey with seven title survey certificates dating back to Ottoman times. These villagers were granted title registration certificates, and in 2005, these villagers applied to the Kozluk Civil Court of First Instance to enlarge the areas covered by the certificates to approximately 20 square kilometers. Neither we nor, to our knowledge, any ministry in the Turkish government received notice of this court proceeding. Almost all of our production wells at the Selmo field lie within this enlarged area. In 2009, the Supreme Court overruled the Kozluk Civil Court of First Instance and directed that court to re-examine the case.

The Turkish Forestry Authority has filed a claim in the Kozluk Cadastre Court against the villagers for attempting to register land that is registered with the Turkish government as forest. TEMI has joined the Turkish government as a plaintiff in that case. In February of 2011, the Kozluk Cadastre Court decided to suspend the case until there is a resolution of the underlying litigation in the Kozluk Civil Court of First Instance.

In addition, TEMI is involved as a defendant in two nuisance cases in the Kozluk Cadastre Court and one claim for damages in the Kozluk Civil Court of First Instance. The plaintiffs in each of these cases are the same villagers in the underlying litigation. The Turkish Treasury Department and the Turkish Forestry Authority have joined TEMI as defendants in each of these nuisance cases. Each of the Kozluk Cadastre Court and the Kozluk Civil Court of First Instance has decided to suspend each of these nuisance cases until there is a resolution of the underlying litigation in the Kozluk Civil Court of First Instance.

We do not believe these cases have merit and intend to continue to vigorously defend our interests. The ultimate liability with respect to these claims cannot be determined at this time; however, we do not expect these matters to have a material impact on our financial position, operations or liquidity and we have not taken a reserve for them.

 

Item 4. Reserved.

Executive Officers of the Registrant.

 

Name

   Age   

Positions

Matthew W. McCann

   42    Director and Chief Executive Officer

Gary T. Mize

   58    President and Chief Operating Officer

Scott C. Larsen

   59    Director and Executive Vice President

Hilda D. Kouvelis

   48    Vice President and Chief Financial Officer

Jonathan J. Grider

   40    Vice President, Accounting

Jeffrey S. Mecom

   45    Vice President and Corporate Secretary

Matthew W. McCann has served as our chief executive officer since January 2009 and has served as a director since May 2008. Since April 2007, Mr. McCann has also served as general counsel of Riata Management, LLC, an Oklahoma City-based private oil and gas exploration and production company. From December 2005 to April 2007, Mr. McCann served as vice president, legal and corporate secretary for Sandridge Energy, Inc. (formerly Riata Energy, Inc.), an independent oil and natural gas company concentrating in exploration, development and production activities, and from 2001 to December 2005, Mr. McCann served as general counsel for Riata Energy, Inc.

Gary T. Mize was appointed as our president in June 2010 and has served as our chief operating officer since January 2010. He previously served as our vice president from January 2010 to June 2010. From 1994 through November 2009, Mr. Mize served as executive vice president of Manti Exploration Company, an oil and gas company engaged in exploration, development and production, where he was responsible for coordination of all acquisition, exploration, financial, and operational activities. Prior to joining Manti Exploration Company, Mr. Mize was employed by Exxon Mobil Corporation from 1974 to 1994. At Exxon, Mr. Mize held numerous management positions including operations manager—southeastern division, technical manager—East Texas division and planning manager—natural gas department.

 

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Scott C. Larsen has served as our executive vice president since June 2010 and served as a director since May 2005. He previously served as our president from March 2004 to June 2010, as our chief executive officer from May 2005 to January 2009, and as our vice president — operations from July 2002 to March 2004. He has been involved in our international activities since their inception in 1994. An attorney by training with over 25 years of experience in the oil and gas industry, Mr. Larsen previously served as general counsel for Humble Exploration, an independent exploration company. Additionally, he spent several years as a partner of Vineyard, Drake & Miller, a business litigation law firm and served as general counsel for Summit Partners Management Co., a venture capital and management company.

Hilda D. Kouvelis has served as our chief financial officer since January 2007 and as a vice president since May 2007. She served as our controller from July 2005 to January 2007. From November 2007 to May 2008, Ms. Kouvelis served as chief financial officer of Sky Petroleum Inc. and Southern Star Energy Inc. From 2001 to 2004, Ms. Kouvelis served as controller for Ascent Energy, Inc., an oil and natural gas exploration and development company. She has more than 20 years of industry experience, including 18 years with FINA, Inc., where she held various positions in accounting and finance, including controller and treasurer. From 1998 to 2000, Ms. Kouvelis served as controller for International Operations at PetroFina S.A.’s headquarters in Brussels, Belgium. Ms. Kouvelis will resign as our vice president and chief financial officer the day following the filing of this Annual Report on Form 10-K. She will continue to serve as an employee through a date mutually agreed upon by her and us which is expected to be not later than September 30, 2011.

Jonathan J. Grider has served as a vice president since February 2011. From February 2010 to February 2011, Mr. Grider served as corporate controller for SERVA Group, LLC, an oilfield equipment manufacturer. Mr. Grider served as international controller at Great White Energy Services, LLC, an oilfield equipment service provider and manufacturer, from November 2007 to January 2010. Mr. Grider held various positions, including country controller in Oman, with Wood Group ESP, Inc., an international oilfield services provider, between March 2001 and November 2007.

Jeffrey S. Mecom has served as our corporate secretary since May 2006 and as a vice president since May 2007. Before joining us in April 2006, Mr. Mecom was an attorney in private practice in Dallas. Mr. Mecom served as vice president, legal and corporate secretary with Aleris International, Inc., a former NYSE-listed international metals recycling and processing company, from 1995 until April 2005.

To the best of our knowledge, there are no arrangements or understandings between any officer and any other person, pursuant to which any person referred to above was selected as an officer.

 

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PART II

 

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Canada

Our common shares are traded in Canada on the Toronto Stock Exchange (the “TSX”) under the trading symbol “TNP”. The following table sets forth the quarterly high and low sales prices per common share in Canadian dollars on the TSX for the periods indicated.

 

     High      Low  

2010:

     

First Quarter

   $ 3.80       $ 2.61   

Second Quarter

   $ 4.20       $ 3.03   

Third Quarter

   $ 3.61       $ 2.84   

Fourth Quarter

   $ 3.52       $ 3.00   

2009:

     

First Quarter

   $ 1.49       $ 0.68   

Second Quarter

   $ 2.40       $ 1.20   

Third Quarter

   $ 3.19       $ 1.80   

Fourth Quarter

   $ 3.65       $ 2.37   

United States

On December 8, 2009, our common shares began trading on the NYSE Amex. From April 20, 2009 to December 8, 2009, our common shares traded on the OTC Bulletin Board. Prior to April 20, 2009, no established trading market for our common shares existed in the United States.

The following table sets forth the high and low bid quotations in U.S. dollars for our common shares for the periods indicated, as reported by the OTC Bulletin Board. The quotations reflect inter-dealer prices, without retail markup, markdowns or commissions and may not represent actual transactions.

 

     High      Low  

2009:

     

Second Quarter (from April 20, 2009)

   $ 2.15       $ 1.09   

Third Quarter

   $ 2.91       $ 1.57   

Fourth Quarter (through December 7, 2009)

   $ 3.09       $ 2.27   

The following table sets forth the high and low sales price per common share in U.S. dollars on the NYSE Amex for the periods indicated.

 

     High      Low  

2010:

     

First Quarter

   $ 3.73       $ 2.43   

Second Quarter

   $ 4.10       $ 2.87   

Third Quarter

   $ 3.49       $ 2.68   

Fourth Quarter

   $ 3.50       $ 2.96   

2009:

     

Fourth Quarter (from December 8, 2009)

   $ 3.90       $ 2.64   

Common Shares and Dividends

As of April 15, 2011, 346,234,355 common shares were issued and outstanding and held by approximately 300 record holders, including nominee holders such as banks and brokerage firms who hold shares for beneficial owners.

 

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We have not declared any dividends to date on our common shares. We have no present intention of paying any cash dividends on our common shares in the foreseeable future, as we intend to use cash flow to invest in our business.

Foreign Exchange Control Regulations

We have been designated as a non-resident for Bermuda exchange control purposes by the Bermuda Monetary Authority. Because of this designation, there are no restrictions on our ability to transfer funds in and out of Bermuda.

The transfer of shares between persons regarded as resident outside Bermuda for exchange control purposes and the sale of our common shares to or by such persons may take place without specific consent under the Exchange Control Act 1972. Issuances and transfers of shares involving any person regarded as resident in Bermuda for exchange control purposes require specific approval under the Exchange Control Act 1972.

As an “exempted company,” we are exempt from Bermuda laws which restrict the percentage of share capital that may be held by non-Bermuda residents, but as an exempted company, we may not participate in certain business transactions, including: (1) the acquisition or holding of land in Bermuda (except that required for our business and held by way of lease or tenancy for terms of not more than 50 years) without the express authorization of the Bermuda legislature, (2) the taking of mortgages on land in Bermuda to secure an amount in excess of $50,000 without the consent of the Minister of Finance, (3) the acquisition of any bonds or debentures secured by any land in Bermuda, other than certain types of Bermuda government securities or (4) the carrying on of business of any kind in Bermuda, except in furtherance of our business carried on outside Bermuda.

Bermuda Tax Considerations

The following summarizes some of the material tax consequences applicable to us or to an investment in our common shares under Bermuda laws. Each prospective investor should consult its own tax advisors regarding tax consequences of an investment in our common shares.

In Bermuda there are no taxes on profits, income or dividends, nor is there any capital gains tax, estate duty or death duty. Profits can be accumulated and it is not obligatory for a company to pay dividends. In addition, stamp duty is not chargeable to any shareholder in respect of the incorporation, registration or licensing of an exempted company, nor, subject to certain minor exceptions, on their transactions. No reciprocal tax treaty affecting us exists between Bermuda and the United States.

The Bermuda government has enacted legislation under which the Minister of Finance is authorized to give a tax assurance to an exempted company or a partnership that, in the event of there being enacted in Bermuda any legislation imposing tax computed on profits or income or computed on any capital asset, gain or appreciation, then the imposition of any such tax shall not be applicable to such entities or any of their operations. In addition, there may be included an assurance that any such tax or any tax in the nature of estate duty or inheritance tax shall not be applicable to the share, debentures or other obligations of such entities.

On November 6, 2009, we received such a tax assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act, 1966. Pursuant to the tax assurance, we have been granted an exemption from the imposition of tax under any applicable Bermuda law computed on profits or income or computed on any capital asset, gain or appreciation, or on any tax in the nature of estate, duty or inheritance tax, provided that such exemption shall not prevent the application of any such tax or duty to such persons as are ordinarily resident in Bermuda and shall not prevent the application of any tax payable in accordance with the provisions of the Land Tax Act, 1967 or otherwise payable in relation to land in Bermuda leased to us. This tax exemption expires on March 28, 2016.

 

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Item 6. Selected Financial Data.

The following table summarizes selected consolidated financial information from continuing operations for each of the five years in the period ended December 31, 2010. You should read the information set forth below in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and notes thereto included elsewhere in this Form 10-K.

 

     Year Ended December 31,  
     2010      2009      2008      2007      2006  
     (amounts in thousands, except per share amounts)  

Revenue

   $ 85,563       $ 29,269       $ 111       $ 653       $ 1,613   

Net loss attributable to common shareholders

     71,152         62,146         16,475         6,318         12,285   

Comprehensive loss

     78,941         52,545         16,475         6,318         12,413   

Basic and diluted net loss attributable to common shareholders, per common share

     0.23         0.29         0.25         0.15         0.32   

Cash dividends per common share

   $ —         $ —         $ —         $ —         $ —     

Basic and diluted weighted average number of shares outstanding

     312,488         212,320         66,524         43,047         38,182   
     As of December 31,  
     2010      2009      2008      2007      2006  

Total assets

     472,347         307,083         81,254         5,107         15,136   

Long term liabilities

     62,292         13,341         14         8         1,939   

Shareholders’ equity

     274,630         264,607         74,940         2,070         6,518   

Capital expenditures

     208,831         126,184         10,268         4,126         3,160   

 

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

We are a vertically integrated, international oil and gas company engaged in the acquisition, exploration, development and production of crude oil and natural gas. We hold interests in developed and undeveloped oil and gas properties in Turkey, Morocco, Bulgaria and Romania. We own our own drilling rigs and oilfield service equipment, which we use to develop our properties in Turkey and Morocco. In addition, our drilling services business provides oilfield services and drilling services to third parties in Turkey and Iraq. As of April 1, 2011, approximately 44.2% of our outstanding common shares are beneficially owned by N. Malone Mitchell, 3rd, the chairman of our board of directors.

Financial and Operational Performance Highlights. Highlights of our financial performance and operational performance for 2010 include:

 

   

During 2010, we derived 56.1% of our revenues from the production of oil, 25.6% of our revenues from the production of natural gas and 18.4% of our revenues from oilfield services.

 

   

Total oil and gas revenue increased to $69.8 million for 2010 from $27.7 million realized in 2009. The increase was the result of increased production in the Selmo oil field, additional production in the Arpatepe oil field and new production in the Thrace Basin gas fields. The increase was also due to the increase in the average price received for our oil production in Turkey, which was $80.0 per barrel during the year ended December 31, 2010 as compared to $66.1 per barrel for the year ended December 31, 2009.

 

   

Oilfield services revenue increased to $15.7 million for 2010 from $1.6 million in 2009.

 

   

Production in Turkey increased to 689,823 net Bbls of crude oil and 1,707 Mmcf of natural gas for 2010, compared to 417,071 net Bbls of crude oil and a nominal amount of natural gas for 2009.

 

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In 2010, we incurred $208.8 million in capital expenditures compared to capital expenditures of $126.2 million in 2009. The increase is primarily due to the acquisition of Amity and Petrogas.

 

   

During 2010, we increased our short-term borrowings to $106.7 million, compared to short-term borrowings of $7.5 million in 2009.

Executive Overview

Strategic Transformation. In 2008, we changed our operating strategy from a prospect generator to a vertically integrated project developer. Since 2008, we have entered into a series of transactions to implement this strategy where we acquired drilling rigs, equipment, inventory, seismic data and exploration and production acreage in Turkey, Morocco and Bulgaria. For additional information on our strategic transformation, see “Business—Development of Our Business—Strategic Transformation.”

Drilling Services Business. Beginning with the acquisition of Longe in 2008, we have established a significant drilling services business. We provide oilfield services and drilling services to our exploration and production business and to third parties in Turkey and Iraq. For additional information on our drilling services business, see “Business—Development of Our Business—Drilling Services Business.”

Recent Developments

We have completed a number of material acquisitions, financings and operations during 2010 and the first quarter of 2011. For additional information on our recent developments, see “Business—Recent Developments.”

Current Operations

We are in the process of integrating the Amity, Petrogas and Direct Bulgaria properties, equipment and personnel into our operations. We have substantially integrated the Incremental, Talon, Anschutz and Direct Morocco acquisitions and organized our activities in Turkey into a service division consisting of two wholly-owned subsidiaries, Viking International and Viking Geophysical, and into an exploration and production division consisting of six wholly-owned exploration and production subsidiaries: TEMI, TAT, Talon, DMLP, Amity and Petrogas.

As of April 1, 2011, we were producing an aggregate of approximately 2,767 Bbls oil per day from the Selmo and Arpatepe oil fields and approximately 15.9 Mmcf of natural gas per day in the Thrace Basin and were engaged in the following drilling and exploration activities:

Turkey. We are drilling two wells at Selmo and two wells in the Thrace Basin. In addition, we are completing two wells at Selmo and testing and completing the Kalatepe-1 well on License 4175. We are testing and commissioning a recently completed 23 kilometer, 6-inch pipeline from the Bakuk-101 well to an existing pipeline to the south and expect to begin limited natural gas sales in the second quarter of 2011. We are now evaluating options for further appraisal of the reservoir. We are constructing a 20 kilometer, 10-inch pipeline to carry natural gas from the Alpullu gas field in the Thrace Basin to an existing pipeline. We are conducting a 236 kilometer 2D seismic shoot on License 4350.

Morocco. We have constructed water separation facilities at the HR-33 bis well on the Tselfat exploration permit and are conducting an extended production test on that well.

Bulgaria. We are evaluating potential locations for the planned Deventci-R2 well, to appraise the Orzirovo formation and core the Etropole shale formation.

Romania. We are evaluating a potential exploration well to test a potential Jurassic oil play and reprocessing seismic data previously shot over the Sud Craiova license.

 

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Planned 2011 Operations

We continue to actively explore and develop our existing oil and gas properties in Turkey, Morocco and Bulgaria and evaluate the opportunities for further activities in Romania. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. In 2011, we are focused on accomplishing the following objectives:

 

   

Increasing Production. Our goal is to achieve a production rate of 10,000 Boe per day in Turkey by the end of 2011. We plan to increase our crude oil and natural gas production in Turkey through continuous drilling in Selmo and the Thrace Basin, the completion of pipelines to bring shut-in gas to market, the application of modern well stimulation techniques such as gelled acidizing and fracture stimulation, and the introduction of directional drilling.

 

   

Securing Partners to Reduce Exploration Risk. We are actively seeking partners for our exploration acreage in Turkey, Morocco, Bulgaria and Romania. Through farm-outs, we expect to reduce our exploration risk and accelerate the exploration and development activities on the farmed-out properties. We have begun consolidating and analyzing well data and seismic data for our properties in Bulgaria and our exploration acreage in Turkey. It is our intention to remain as operator in the properties that we farm-out.

 

   

Integrating Acquisitions. We expect to complete the acquisition of TBNG and Pinnacle in the second quarter of 2011, which will bring additional acreage, production, personnel and equipment into our Turkey operations. We will continue to integrate the recent acquisitions of Amity, Petrogas and Direct Bulgaria.

Capital expenditures for 2011 are expected to range between $125.0 million and $150.0 million. Approximately 50% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Approximately 35% of these anticipated expenditures will occur in southeastern Turkey, devoted to developing crude oil production at Selmo and Arpatepe and drilling exploratory wells on various licenses. The balance of the estimated budget is divided between exploration activities in Morocco and Romania. We are seeking a joint venture partner to fund our anticipated capital expenditures in Bulgaria in 2011. If cash on hand, borrowings from our senior secured credit facility and cash flow from operations are not sufficient to fund our capital expenditures, then we will either curtail our discretionary capital expenditures or seek other funding sources. We currently plan to execute the following drilling and exploration activities in 2011:

Turkey. We plan to drill approximately 90-100 wells during 2011, including wells to be drilled on acreage held by TBNG, which we expect to acquire in the second quarter of 2011. If we do not complete the acquisition of TBNG, the number of wells we expect to drill in 2011 may change. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill.

Morocco. On our Tselfat exploration permit, we are currently producing oil from the HR-33 bis well on an extended production test to determine if the well is commercially viable. If testing confirms the HR-33 bis well as a commercial well, we plan to delineate the oil field, apply for an exploitation concession and drill at least one additional well in the Haricha field. We also plan to drill the TKN-1 well to test another 3D seismic prospect that is similar to the Haricha field. If the TKN-1 well is a commercial well, we would likely drill an additional appraisal well. We plan to drill three exploration wells to a depth of at least 1,500 meters on the Tselfat exploration permit in 2011. On our Asilah exploration permit, we are planning to test the recently completed GRB-1 well, which had substantial gas shows during drilling. If that well is completed as a commercial well, we would likely drill additional appraisal wells and develop plans to commercialize those wells.

Bulgaria. We plan to drill the Deventci-R2 well on the A-Lovech exploration permit to appraise the Deventci-R1 well gas discovery. While drilling the appraisal well on the A-Lovech permit, we plan to test the productivity of the Etropole shale interval. We may also drill an additional appraisal well on the Aglen exploration permit. If the appraisal well on the Aglen permit is successful, we anticipate planning the construction of a pipeline to connect the Deventci wells to a natural gas pipeline to the south. We are seeking to enter into a joint venture where the joint venture partner would carry us in the capital expenditures incurred in Bulgaria in 2011.

Romania. We plan to drill an exploration well to test the Silurian-aged shale formations present on the Sud Craiova license. We may also drill an exploration well to test the Coyote oil prospect on the southeastern portion of the Sud Craiova license.

Drilling Services Business. We plan to continue to increase drilling services revenues by providing drilling services and seismic acquisition services to third parties in Turkey and northern Iraq.

 

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Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3—Significant accounting policies” to our consolidated financial statements included in this Annual Report on Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We believe the following critical accounting policies affect the significant judgments and estimates used in the preparation of our consolidated financial statements.

Oil and Gas Properties. In accordance with the successful efforts method of accounting for oil and gas properties, costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. Acquisition costs of proved properties are amortized using the unit-of-production method based on total proved reserves, and exploration well costs and additional development costs are amortized using the unit-of-production method based on proved developed reserves. Proceeds from the sale of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned. Exploration costs, such as exploratory geological and geophysical costs, delay rentals and exploration overhead, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be nonproductive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.

Valuation of Property and Equipment Other than Oil and Gas Properties. We follow the provisions of ASC 360, Property, Plant and Equipment (“ASC 360”). ACS 360 requires that our long-lived assets, including drilling service and other equipment, be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Oil and gas properties are evaluated by field for potential impairment. Other properties are evaluated for impairment on a specific asset basis or in groups of similar assets as applicable. An impairment is recognized when the estimated undiscounted future net cash flows of an asset are less than its carrying value. If an impairment occurs, the carrying value of the impaired asset is reduced to fair value. Pursuant to ASC 932-360-35-11, we have evaluated our long-lived assets and determined that no impairment occurred with respect to our unproved properties in the oil and natural gas segment and the drilling services segment.

Business Combinations. We follow ASC 805, Business Combinations (“ASC 805”), and ASC 810-10-65, Consolidation (“ASC 810-10-65”). ASC 805 requires most identifiable assets, liabilities, non-controlling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under ASC 805, all business combinations will be accounted for by applying the acquisition method. Accordingly, transactions costs related to acquisitions are to be recorded as a reduction of earnings in the period they are incurred and costs related to issuing debt or equity securities that are related to the transaction will continue to be recognized in accordance with other applicable rules under U.S. GAAP. ASC 810-10-65 will require non-controlling interests (previously referred to as minority interests) to be treated as a separate component of equity, not as a liability or other item outside of permanent equity. The statement applies to the accounting for non-controlling interests and transactions with non-controlling interest holders in consolidated financial statements.

 

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Foreign Currency Translation. Effective January 1, 2009, we determined that the functional currency of our corporate entities in Morocco, Turkey, Canada and Romania had changed from the U.S. Dollar to the Moroccan Dirham, Turkish Lira, Canadian Dollar and the Romanian New Leu, respectively. We have entered into contractual obligations and commitments that will result in increasingly significant levels of transactions conducted in these currencies. In recognition of these contractual obligations and commitments combined with the resulting increases in future revenues and expenditures in these countries, we determined the appropriate functional currency was the local currency for each of these subsidiaries.

We follow ASC 830, Foreign Currency Matters (“ASC 830”). ASC 830 requires the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation. Exchange gains or losses from re-measuring transactions and monetary accounts in a currency other than the functional currency are included in earnings. For certain of our controlled entities, translation adjustments result from the process of translating the functional currency of subsidiary financial statements into the U.S. Dollar reporting currency. These translation adjustments are reported separately and accumulated in the balance sheet as a component of accumulated other comprehensive income (loss). The accounting basis of the assets and liabilities affected by the change are adjusted to reflect the difference between the exchange rate when the asset or liability arose and the exchange rate on the date of the change.

Other Recent Accounting Pronouncements and Reporting Rules

In January 2010, the FASB issued Accounting Standards Update No. 2010-06, Improving Disclosures about Fair Value Measurements (“ASU 2010-06”). The update provides amendments to ASC 820, Fair Value Measurements and Disclosures, (“ASC 820”) that require more robust disclosures about: (1) the different classes of assets and liabilities measured at fair value, (2) the valuation techniques and inputs used, (3) the activity in Level 3 fair value measurements, and (4) the transfers between Levels 1, 2, and 3. The new disclosures and clarifications of existing disclosures are effective for interim and annual reporting periods beginning after December 15, 2009. Disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. The adoption of ASU 2010-06 did not have a material impact on our financial statements.

The United States Congress passed the Dodd-Frank Act in 2010. Among other requirements, the law requires companies in the oil and gas industry to disclose payments made to the U.S. federal government and all foreign governments. The SEC was directed to develop the reporting requirements in accordance with the law. The SEC has issued preliminary guidance and is seeking feedback thereon from all interested parties. The preliminary rules indicated that payment disclosures would be required at a project level within the Annual Report on Form 10-K beginning with the year ended December 31, 2012. We cannot predict the final disclosure requirements that will be required by the SEC.

We have reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on current or future earnings or operations.

 

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Results of Operations – Fiscal Year Ended December 31, 2010 Compared to Fiscal Year Ended December 31, 2009

Revenue. Total crude oil and natural gas sales increased to $69.8 million in the year ended December 31, 2010, from $27.7 million realized in 2009. The increase was the result of increased production in the Selmo oil field, additional production in the Arpatepe oil field and new production in the Thrace Basin gas fields. The increase was also due to the increase in the average price received for our oil production. We recorded $15.7 million in oilfield services revenue during 2010, compared to $1.6 million in oilfield services revenue during the same period in 2009. The increase was due to an increase in oilfield drilling services provided to third parties and seismic services provided to third parties in 2010.

Production. We produced 689,823 net Bbls of crude oil in Turkey in 2010 at an average rate of 1,890 Bbls per day. Substantially all of our oil production in 2010 was generated from the Selmo oil field in Turkey. We produced 417,071 net Bbls of crude oil in 2009. We produced approximately 1,707 Mmcf of natural gas in Turkey in 2010 at an average rate of approximately 9,100 Mcf per day. The majority of our natural gas production in 2010 was generated from the Thrace Basin gas fields in Turkey. We produced a nominal amount of natural gas in 2009.

Production Expenses. Production expenses for the year ended December 31, 2010 increased to $20.3 million from $10.2 million in the year ended December 31, 2009. The increase in production expenses was the result of the acquisition of Amity in the third quarter of 2010 and an overall increase in production.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs increased to $32.6 million in the year ended December 31, 2010 compared to $24.8 million for the year ended December 31, 2009. The increase was primarily due to increased abandonment expense in Morocco.

Seismic and Other Exploration. Seismic and other exploration costs increased to $12.3 million for the year ended December 31, 2010, compared to $10.5 million for the year ended December 31, 2009. The increase was due primarily to increased exploration activity in Turkey.

International Oil and Gas Activities. During 2010, we continued significant activities in foreign countries to establish our drilling services and exploration and production support functions, including inventory yards, personnel, transportation and fuel, consulting, legal, accounting, travel and other costs. These expenses are necessary to further our identification and development of business opportunities but are not identifiable to specific capital projects. The following table presents exploration expenditures by country:

 

      For the Year Ended  

(in thousands)

   December 31,
2010
     December 31,
2009
 

Turkey

   $ 18,176       $ 4,594   

Morocco

     4,494         4,485   

Romania

     602         586   

Other and unallocated

     386         2,684   
                 

Total

   $ 23,658       $ 12,349   
                 

General and Administrative Expense. General and administrative expense was $29.7 million for the year ended December 31, 2010, compared to $16.1 million for the year ended December 31, 2009, primarily due to the expansion of our operating activities during 2010. We also recorded $1.7 million in transaction expenses relating to the acquisition of Amity and Petrogas during 2010. In addition, we recorded share-based compensation expense of $2.0 million during 2010, compared to $1.6 million for 2009.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased to $28.2 million for the year ended December 31, 2010, compared to $7.9 million in depreciation, depletion and amortization expense in 2009. The increase was due primarily to drilling services equipment put into service in 2010 and the acquisition of Amity and Petrogas.

 

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Other Comprehensive Loss (Gain). We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. Dollar reporting currency. Foreign currency translation adjustment for 2010 decreased to a $7.8 million loss from a $9.6 million gain for 2009 due to the strengthening of the U.S. Dollar compared to the foreign currencies of the other countries in which we operate.

Comprehensive Loss. The comprehensive loss for the year ended December 31, 2010 was $78.9 million, compared to a comprehensive loss of $52.5 million for the year ended December 31, 2009. The comprehensive loss for 2010 is primarily composed of exploration, abandonment and impairment expense of $32.6 million, general and administrative expense of $29.7 million, depreciation, depletion and amortization expenses of $28.2 million, production expenses of $20.3 million and seismic and other exploration costs of $12.3 million.

Net Loss Attributable to Common Shareholders. Net loss attributable to common shareholders for the year ended December 31, 2010 was $71.2 million, or $0.23 per share (basic and diluted), compared to $62.1 million, or $0.29 per share (basic and diluted), for the year ended December 31, 2009.

Results of Operations – Fiscal Year Ended December 31, 2009 Compared to Fiscal Year Ended December 31, 2008

Revenue. Total crude oil and natural gas sales increased to $27.7 million in the year ended December 31, 2009 from $111,000 realized in 2008. The increase was the result of the acquisition of Incremental in the first quarter of 2009, as substantially all of our revenue in 2009 was derived from the sale of crude oil from the Selmo oil field in Turkey. We recorded $1.6 million in oilfield services revenue during 2009. We had no oilfield services revenue during the same period in 2008.

Production. We produced 417,071 net Bbls of crude oil in Turkey from March 5, 2009, the date of our acquisition of Incremental, through December 31, 2009 at an average rate of 1,402 Bbls per day. Substantially all of our production in 2009 was generated from the Selmo oil field in Turkey. We produced a nominal amount of crude oil in 2008.

Production Expenses. Production expenses for the year ended December 31, 2009 increased to $10.2 million from $73,000 in the year ended December 31, 2008. The increase in production expenses was the result of the acquisition of Incremental and its producing properties in the first quarter of 2009 and the acquisition of Talon and its producing properties in July 2009.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs increased to $24.8 million for the year ended December 31, 2009. The increase was primarily due to the abandonment of the Atesler-1 well in Turkey, the OZW-1 and HR-33 bis wells in Morocco, the Izvoru Beta, Izvoru Delta, Vanatori 227-T, and NG-04 wells in Romania, and two wells in California. We did not record any exploration, abandonment and impairment expense in 2008.

Seismic and Other Exploration. Seismic and other exploration costs increased to $10.5 million for the year ended December 31, 2009 compared to $7.9 million for the year ended December 31, 2008. The increase was due primarily to increased seismic exploration activity.

International Oil and Gas Activities. During 2009, we continued significant activities in foreign countries to establish our drilling services and exploration and production support functions, including inventory yards, personnel, transportation and fuel, consulting, legal, accounting, travel and other costs. These expenses are necessary to further our identification and development of business opportunities but are not identifiable to specific capital projects. The following table presents exploration expenditures by country:

 

      For the Year Ended  

(in thousands)

   December 31, 
2009
     December 31, 
2008
 

Turkey

   $ 4,594       $ 917   

Morocco

     4,485         2,217   

Romania

     586         762   

Other and unallocated

     2,684         1,287   
                 

Total

   $ 12,349       $ 5,183   
                 

General and Administrative Expense. General and administrative expense was $16.1 million for the year ended December 31, 2009 compared to $3.6 million for the year ended December 31, 2008, primarily due to increased corporate staffing and salaries resulting from the acquisitions of Longe and Incremental in the fourth quarter of 2008 and the first quarter of 2009, respectively, and to support increased drilling and exploration activity. We also recorded $817,000 in transaction expenses relating to the Incremental acquisition during 2009. In addition, we recorded share-based compensation of $1.6 million during 2009, compared to $583,000 for 2008.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $7.9 million for the year ended December 31, 2009. We had $53,000 in depreciation, depletion and amortization expense in 2008 due to the

 

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write-down and sale of substantially all of our U.S. properties during 2007. The increase was due to the acquisition of Incremental in the first quarter of 2009 and drilling services equipment put in service during 2009.

Other Comprehensive Loss (Gain). We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. Dollar reporting currency. We recorded a $9.6 million gain for foreign currency translation adjustment in 2009 due to the devaluation of the U.S. Dollar compared to the foreign currencies of the other countries in which we operate. We recorded no foreign currency translation adjustment in 2008 because the functional currency of our foreign subsidiaries was the U.S. Dollar.

Comprehensive Loss. The comprehensive loss for the year ended December 31, 2009 was $52.5 million, compared to a comprehensive loss of $16.5 million for the year ended December 31, 2008. The comprehensive loss for 2009 was primarily composed of exploration, abandonment and impairment expense of $24.8 million, general and administrative expense of $16.1 million, production expenses of $10.2 million, seismic and other exploration costs of $10.5 million, depreciation, depletion and amortization expenses of $7.9 million, loss on derivatives of $1.9 million and foreign exchange loss of $3.4 million, primarily relating to our financing of the acquisition of Incremental in the first quarter of 2009.

Net Loss Attributable to Common Shareholders. Net loss attributable to common shareholders for the year ended December 31, 2009 was $62.1 million, or $0.29 per share (basic and diluted), compared to $16.5 million, or $0.25 per share (basic and diluted), for the year ended December 31, 2008.

Capital Expenditures

For the year ended December 31, 2010, we incurred $208.8 million in capital expenditures compared to capital expenditures of $126.2 million for the year ended December 31, 2009. The increase in capital expenditures was primarily due to the acquisition of Amity and Petrogas in the third quarter of 2010.

In 2011, we expect our capital expenditures will range between $125.0 million and $150.0 million. Approximately 50% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Approximately 35% of these anticipated expenditures will occur in southeastern Turkey, devoted to developing crude oil production at Selmo and Arpatepe and drilling exploratory wells on various licenses. The balance of the estimated budget is divided between exploration activities in Morocco and Romania. We are seeking a joint venture partner to fund our anticipated capital expenditures in Bulgaria in 2011. If cash on hand, borrowings from our senior secured credit facility and cash flow from operations are not sufficient to fund our capital expenditures, then we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2011 capital budget is subject to change and could be reduced if we do not raise additional funds.

Settlement Provision

In conjunction with the sale of our Bahamian subsidiary effective June 20, 2005, we deposited funds into an escrow account to address any liabilities and claims relating to our prior operations in Nigeria. The remaining potential liability to us includes taxes owed for the period January through June 2005, and we expect the remaining escrow amount of $240,000 to be sufficient to cover any potential liabilities.

Liquidity and Capital Resources

Our primary sources of liquidity for 2010 were proceeds from the sale of our common shares, our cash and cash equivalents and borrowings under our various debt agreements. Our primary sources of liquidity for 2009 were proceeds from the sale of our common shares and our cash and cash equivalents. We expect that the acquisition of TBNG, if completed, will result in additional cash flow from operations.

At December 31, 2010, we had cash and cash equivalents of $34.7 million, $108.6 million in short-term debt, $30.1 million in long-term debt and a working capital deficit of $60.2 million compared to cash and cash equivalents of $90.5 million, $7.5 million in short-term debt, no long-term debt and working capital of $80.9 million at December 31, 2009. Cash used in operating activities during 2010 decreased to $43.5 million compared to cash used in operating activities of $50.8 million in 2009, primarily as a result of an increase in depreciation, depletion and amortization expense, exploration, abandonment and impairment expense, accounts payable and amortization of warrants, partially offset by an increase in accounts receivable.

Of our outstanding debt, $30.0 million is due May 25, 2011 and $73.0 million is due June 28, 2011. Should we be unable to raise additional financing, we will not have sufficient funds to continue operations beyond May 25, 2011, the maturity date of our credit agreement with Standard Bank. As a result, there is significant doubt regarding our ability to continue as a going concern. The continuing application of the going concern assumption is dependent upon our continuing ability to obtain the necessary financing to discharge our existing obligations, carry out our exploration and development programs, to fund ongoing operations and ultimately achieve profitable operations.

From September 30, 2010 through October 8, 2010, we closed a public offering of an aggregate of 30,357,143 common shares at a purchase price of $2.80 per share, raising gross proceeds of $85.0 million. Net proceeds from the offering, after deducting the placement agency fee and estimated offering expenses, were approximately $80.6 million. We used $19.0 million of the net proceeds for the repayment of the principal amount and accrued interest under the loan and security agreement between Viking International and Dalea and used the remaining net proceeds for general corporate purposes.

On November 24, 2009, we closed a Regulation S offering of common shares outside the United States and a concurrent Regulation D private placement of common shares inside the United States to accredited investors. In the aggregate, we sold 48,298,790 common shares at a price of Cdn $2.35 per common share, raising gross proceeds of approximately $106.9 million. Of the 48,298,790 common shares sold, we offered and sold 4,255,400 common shares to

 

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Dalea. Concurrently with the offerings, we completed a Regulation D private placement to two accredited investors in the United States of 750,000 common shares at Cdn $2.35 per common share for gross proceeds to us of approximately $1.66 million. We used the net proceeds from this offering for our 2010 capital expenditure program and for general corporate purposes.

On June 22, 2009, we closed a Regulation S offering of common shares outside the United States and a concurrent Regulation D private placement of common shares inside the United States to accredited investors. In the aggregate, we sold 98,377,300 common shares at a price of Cdn $1.65 per common share, raising gross proceeds of approximately $143.1 million. Of the 98,377,300 common shares sold, 41,818,000 common shares were offered and sold by us to Dalea. We used $61.8 million of the net proceeds towards paying off a credit agreement with Dalea. The remaining portion of the net proceeds were used to fund our exploration and development activities and for general corporate purposes.

As of December 31, 2010, the outstanding principal amount of our debt was $138.6 million. Of this amount, $30.0 million is due by May 25, 2011 and $73.0 million is due by June 28, 2011. As a result, we forecast that we will need to either extend the maturity date of our existing debt or raise additional debt or equity financing to refinance our existing debt and to fund our operations, including our planned exploration and development activities, beyond May 25, 2011. To obtain these funds, we are considering a number of alternatives, including:

 

   

seeking an increase in the borrowing base under our senior secured credit facility; and

 

   

considering the issuance of common shares, public debt or private debt.

However, there is no assurance that our forecasts will prove to be accurate or that our efforts to raise additional debt or equity financing will be successful. If we are unable to secure additional funds, we may not have sufficient funds to continue operations beyond May 25, 2011, the maturity date of our short-term secured credit agreement with Standard Bank. The inability to secure additional funding when and as needed could have a material adverse effect on our operations and financial condition.

In addition to cash, cash equivalents and cash flow from operations, at December 31, 2010, we had stand-by credit agreements with a Turkish bank, a short-term secured credit agreement, a loan with a Turkish bank, a credit agreement with Dalea, a senior secured credit facility and a term note with Viking Drilling, each of which is discussed below.

TEMI Credit Agreement. TEMI is a party to unsecured non-interest bearing stand-by credit agreements with a Turkish bank. At December 31, 2010, there were outstanding borrowings of 195,000 Turkish Lira (approximately $126,000), bank guarantees totaling 802,000 Turkish Lira (approximately $516,000) and $940,000 (approximately 1.5 million Turkish Lira) of bank guarantees primarily related to TEMI’s Istanbul office lease under these lines.

Short-Term Secured Credit Agreement. On August 25, 2010, TransAtlantic Worldwide entered into a short-term secured credit agreement with Standard Bank, pursuant to which TransAtlantic Worldwide could borrow up to $30.0 million from Standard Bank. The short-term secured credit agreement is guaranteed by us and by each of TransAtlantic Petroleum (USA) Corp., Amity and Petrogas. TransAtlantic Worldwide borrowed $30.0 million under the short-term secured credit agreement and used the proceeds to finance a portion of the purchase price for the shares of Amity and Petrogas.

The short-term secured credit agreement matures on May 25, 2011, although TransAtlantic Worldwide may prepay the amounts due under the short-term secured credit agreement at any time before maturity without penalty. Borrowings under the short-term secured credit agreement accrue interest at a rate of LIBOR plus the applicable margin. The applicable margin equals 3.75% for interest that accrued before November 23, 2010, 4.00% for interest that accrued on or after November 23, 2010 and before February 20, 2011, and 4.25% for interest that accrues on or after February 20, 2011 and before May 25, 2011. In addition, TransAtlantic Worldwide paid an arrangement fee of $750,000, and is required to pay (i) a commitment fee of no less than 2.5% of the aggregate principal amount of any future debt financing that is arranged or underwritten by Standard Bank if such debt financing is applied to refinance any portion of the indebtedness under the short-term secured credit agreement and (ii) a commitment fee equal to 2.5% of the amount of any increased commitments arranged by Standard Bank if partial or complete repayment of the short-term secured credit agreement is financed through an increase in the commitments under the senior secured credit facility.

The short-term secured credit agreement is secured by a pledge of (i) the receivables payable under each of Amity’s and Petrogas’ hydrocarbon sales contracts and property insurance policies, (ii) Amity’s and Petrogas’ bank accounts that receive the payments due under their respective hydrocarbon sales contracts, (iii) the shares of Amity and Petrogas and (iv) substantially all of Amity’s present and future assets and undertakings.

 

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Pursuant to the terms of the short-term secured credit agreement, until amounts under the short-term secured credit agreement are repaid, we cannot permit Amity or Petrogas to, in each case subject to certain exceptions, incur any indebtedness or create any liens, enter into any merger, consolidation or amalgamation, sell, lease, assign or transfer any of their properties, pay any dividends or distributions, make certain types of investments, enter into any transactions with an affiliate, enter into a sale and leaseback arrangement, engage in business other than as an oil and gas exploration and production company, an oil field related services company or engage in business outside of Turkey or their jurisdiction of formation, change their organizational documents, fiscal periods or accounting principles, modify certain hydrocarbon agreements and licenses or material contracts, enter into any hedge agreement for speculative purposes or open or maintain new deposit, securities or commodity accounts.

Events of default under the short-term secured credit agreement include, but are not limited to, failure to pay principal or interest when due, inaccuracy of representations or warranties, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, the award of certain monetary judgments, and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) TransAtlantic Worldwide’s failure to own, of record and beneficially, all of the equity of Amity or Petrogas; (ii) the failure by Amity or Petrogas to own or hold, directly or indirectly, all of the interests granted to them pursuant to certain hydrocarbon licenses designated in the short-term secured credit agreement; or (iii) (a) Mr. Mitchell ceases for any reason to be the chairman of our board of directors at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis; provided that, if Mr. Mitchell ceases to be chairman of the our board of directors by reason of his death or disability, such event shall not constitute a matured event of default unless we have not appointed a successor reasonably acceptable to Standard Bank within 60 days of the occurrence of such event. If an event of default shall occur and be continuing, all borrowings under the short-term secured credit agreement will bear an additional interest rate of 2.0% per annum. In the case of an event of default upon bankruptcy or insolvency, all amounts payable under the short-term secured credit agreement become immediately due and payable. In the case of any other event of default, all amounts due under the short-term secured credit agreement may be accelerated by Standard Bank or the administrative agent.

At December 31, 2010, we had borrowed $30.0 million and had no availability under the short-term secured credit agreement.

Viking International Equipment Loan. On July 21, 2010 and December 30, 2010, Viking International entered into a secured credit agreement with a Turkish bank to fund the purchase of vehicles. The credit agreement has a term of 48 months and matures on July 20, 2014, bears interest at an annual rate of 3.84% and is secured by the vehicles purchased with the proceeds of the loan. There is no further availability under the credit agreement. At December 31, 2010, the outstanding balance under the secured credit agreement was $2.9 million.

Dalea Credit Agreement. On June 28, 2010, we entered into a credit agreement with Dalea. The purpose of the credit agreement was (i) to fund the acquisition of all of the shares of Amity and Petrogas, and (ii) for general corporate purposes.

The aggregate unpaid principal balance, together with all accrued but unpaid interest and other costs, expenses or charges payable under the credit agreement are due and payable upon the earlier of (i) June 28, 2011 or (ii) the occurrence of an event of default and a demand for payment by Dalea. Amounts due under the credit agreement accrue interest at a rate of three-month LIBOR plus 2.50% per annum, to be adjusted monthly on the first day of each month. In addition, we are required to pay all accrued interest in arrears on the last day of each month until the date of repayment and at any time that the principal balance is due and payable. We may prepay the amounts due under the credit agreement at any time before maturity without penalty.

The credit agreement contains certain covenants that limit our ability to, among other things, (i) make, give, create or permit or attempt to make, give or create any mortgage, charge, lien or encumbrance over any of our assets or any subsidiary’s assets (subject to certain specified exceptions), (ii) change our name or jurisdiction of organization, (iii) declare or provide for any dividends or other similar payments, (iv) redeem or repurchase any of our shares, (v) make or permit the sale of, or disposition of, any substantial or material part of our business, assets or undertaking or that of any subsidiary, (vi) borrow or cause any subsidiary to borrow money from any person (subject to certain specified exceptions) without obtaining and delivering a duly signed assignment and postponement of claim by such person in form and terms satisfactory to Dalea, (vii) pay out or permit the payment of any shareholder loans or other indebtedness to non-arm’s length parties by us or any subsidiary, or (viii) guarantee or permit the guarantee of the obligations of any other person by us or any subsidiary

 

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except in the ordinary course of business. In addition, any proceeds received by us or any subsidiary from any debt financings (subject to certain specified exceptions) must be used to repay amounts outstanding under the credit agreement, net of reasonable transaction and financing costs. We (or any subsidiary) are also required to repay amounts outstanding under the credit agreement from (i) any proceeds of any equity issuance received from Mr. Mitchell, his immediate family or any entities owned or controlled by Mr. Mitchell or his immediate family (collectively, the “Mitchell Family”), and (ii) all proceeds of any equity issuance in excess of $75.0 million (excluding any proceeds received from the Mitchell Family), net of reasonable transaction costs. Amounts repaid under the credit agreement cannot be reborrowed. We paid for Dalea’s reasonable legal fees and other expenses incidental to the completion of the credit agreement.

In connection with our public offering of common shares from September 30, 2010 through October 8, 2010, Dalea waived its right to be repaid from the proceeds of the offering, which would have been otherwise due to Dalea under the terms of the credit agreement.

Under the terms of the credit agreement, we were required to issue Dalea 100,000 common share purchase warrants for each $1.0 million in principal amount advanced under the credit agreement. We borrowed an aggregate of $73.0 million under the credit agreement, and on September 1, 2010, we issued 7.3 million common share purchase warrants to Dalea. The common share purchase warrants are exercisable until September 1, 2013 and have an exercise price of $6.00 per share.

At December 31, 2010, we had borrowed $73.0 million under the Dalea credit agreement. No further borrowings are permitted under the Dalea credit agreement.

Dalea Loan and Security Agreement. On June 28, 2010, Viking International entered into a loan and security agreement with Dalea. The purpose of the loan and security agreement was to fund the purchase of equipment and for general corporate purposes. The initial advance under the loan and security agreement was $18.5 million and was secured by (i) the equipment named therein, and (ii) proceeds of the equipment and all accessions to, substitutions and replacements for, and rents, profits and products of, each of the foregoing.

Amounts due under the loan and security agreement accrued interest at a rate of 10% per annum. Viking International borrowed an aggregate of $18.5 million under the loan and security agreement and paid approximately $485,000 in interest. We repaid the loan in full on September 30, 2010, and on December 31, 2010, the loan and security agreement was terminated.

Senior Secured Credit Facility. On December 21, 2009, our wholly-owned subsidiaries, DMLP, TEMI, Talon and TAT (collectively, the “Borrowers”), entered into a three year senior secured credit facility with Standard Bank and BNP Paribas (Suisse) SA. The senior secured credit facility is guaranteed by us and each of Incremental Petroleum (Selmo) Pty Ltd, TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide.

The amount drawn under the senior secured credit facility may not exceed the lesser of (i) a borrowing base, and (ii) the maximum aggregate commitments provided by the lenders. The borrowing base is the present value of our hydrocarbon reserves in Turkey up to a maximum of $250 million. The borrowing base is currently $37.0 million and is re-determined at least semi-annually based on our hydrocarbon reserves in Turkey at December 31st and June 30th of each year. At December 31, 2010, the lenders had aggregate commitments of $45.0 million. On June 21, 2011 and each three month anniversary thereof, the lenders’ commitments under the senior secured credit facility are subject to reduction by 14.3% of their commitments existing on March 21, 2011.

The senior secured credit facility matures on the earlier of (i) December 21, 2012 or (ii) the date that our hydrocarbon reserves in Turkey are determined to be less than 25% of the amount shown in the May 7, 2009 reserve report prepared by RPS Energy Pty. Ltd. The senior secured credit facility includes a letter of credit sub-limit of up to $10 million. Loans under the senior secured credit facility accrue interest at a rate of three month LIBOR plus 6.25% per annum. If an event of default shall occur and be continuing, all loans under the senior secured credit facility will bear an additional interest rate of 2.0% per annum. At December 31, 2010, we had borrowed $25.0 million and had availability of $20.0 million under the senior secured credit facility.

In addition, we are required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to 3.125% per annum of the average daily unused and uncancelled portion of each lender’s commitment under the senior secured credit facility, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount available to be drawn under such letter of credit and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to Standard Bank or (b) 6.25% for all other letters of credit.

 

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The senior secured credit facility is secured by (i) receivables payable under each Borrower’s hydrocarbon sales contracts; (ii) the Borrowers’ bank accounts which receive the payments due under Borrowers’ hydrocarbon sales contracts; (iii) the shares of each of the Borrowers; and (iv) substantially all of the present and future assets of the Borrowers.

During a measurement period of the four most recently completed fiscal quarters occurring on or after March 31, 2010, the financial covenants under the senior secured credit facility require each of the Borrowers to maintain a:

 

   

ratio of total debt to EBITDAX of less than 2.50 to 1.00;

 

   

ratio of EBITDAX (less non-discretionary capital expenditures) to interest expense of greater than 4.00 to 1.00; and

 

   

ratio of current assets to current liabilities of not less than 1.10 to 1.00.

At December 31, 2010, we were in compliance with the above ratios. The senior secured credit facility defines EBITDAX as net income (excluding extraordinary items) plus, to the extent deducted in calculating such net income, (i) interest expense (excluding interest paid in kind, non-cash interest expense and interest on subordinated intercompany debt), (ii) income tax expense, (iii) depreciation and amortization expense, (iv) amortization of intangibles (including goodwill) and organization costs, (v) any extraordinary, unusual or non-recurring non-cash expenses or losses, (vi) expenses incurred in connection with oil and gas exploration activities entered into in the ordinary course of business, (vii) transaction costs, expenses and fees incurred in connection with the negotiation, execution and delivery of the senior secured credit facility and the related loan documents, and (viii) any other non-cash charges, minus, to the extent included in calculating net income, (a) any extraordinary, unusual or non-recurring income or gains (including gains on the sales of assets outside of the ordinary course of business), and (b) any other non-cash income or gains.

Pursuant to the terms of the senior secured credit facility, until amounts under the senior secured credit facility are repaid, each of the Borrowers shall not, and shall cause each of its subsidiaries not to, in each case subject to certain exceptions, incur indebtedness or create any liens, enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to create any liens, enter into any merger, consolidation or amalgamation, liquidate or dissolve, dispose of any property or business, pay any dividends or similar payments to shareholders, make certain types of investments, enter into any transactions with an affiliate, enter into a sale and leaseback arrangement, engage in business other than as an oil and gas exploration and production company or outside of Turkey or its jurisdiction of formation, change its organizational documents, fiscal periods or accounting principles, modify certain hydrocarbon agreements and licenses or material contracts, enter into any hedge agreement for speculative purposes or open or maintain new deposit, securities or commodity accounts.

An event of default under the senior secured credit facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, including failure to timely deliver to the lenders copies of our 2011 audited annual financial statements without a going concern note or similar qualification, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial tests and ratios and the occurrence of a material adverse effect. We obtained a waiver from the lenders concerning our obligation to timely deliver our 2010 audited financial statements without a going concern note. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and beneficially, all of the equity of the Borrowers or to exercise, directly or indirectly, day-to-day management and operational control of the Borrowers; (ii) the failure by the Borrowers to own or hold, directly or indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated in the senior secured credit facility agreement; or (iii) (a) Mr. Mitchell ceases for any reason to be the executive chairman of our board of directors at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person, group or company, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis. Provided that, if Mr. Mitchell ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute a matured event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event. If an event of default shall occur and be continuing, all loans under the senior secured credit facility will bear an additional interest rate of 2.0% per annum. In the case of an event of default upon bankruptcy or insolvency, all amounts payable under the senior secured credit facility become immediately due and payable. In the case of any other event of default, all amounts due under the senior secured credit facility may be accelerated by the lenders or the administrative agent. Borrowers have certain rights to cure an event of default arising from a violation of the interest coverage ratio or leverage ratio by obtaining cash equity or loans from us.

Pursuant to the senior secured credit facility, TEMI entered into costless derivative contracts and three-way collar contracts with Standard Bank and BNP Paribas (Suisse) SA, which hedge the price of oil during 2011 and 2012. See “Item

 

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7A. Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Risk.” If our borrowing base is increased in the future, we would be required under the senior secured credit facility to hedge additional volumes of oil.

Viking Drilling Note. On July 27, 2009, Viking International purchased the I-13 drilling rig and associated equipment from Viking Drilling. Viking International paid $1.5 million in cash for the drilling rig and entered into a note payable with Viking Drilling in the amount of $5.9 million. The note was due and payable on August 1, 2010, bore interest at a fixed rate of 10% per annum and was secured by the drilling rig and associated equipment. We paid interest under the note on November 1, 2009 and February 1, 2010. On February 19, 2010, Viking International purchased the I-14 drilling rig and associated equipment from Viking Drilling and entered into an amended and restated note payable to Viking Drilling in the amount of $11.8 million, which is comprised of $5.9 million payable related to the I-14 drilling rig and $5.9 million payable related to the purchase of the I-13 drilling rig. Under the terms of the amended and restated note, interest is payable monthly at a floating rate of LIBOR plus 6.25%, and the amended and restated note is due and payable August 1, 2012. The amended and restated note is secured by the I-13 and I-14 drilling rigs and associated equipment. At December 31, 2010, the outstanding balance under this note was $7.7 million.

Promissory Note. On July 23, 2009, in connection with our acquisition of Talon, our wholly-owned subsidiary, TransAtlantic Worldwide, entered into an unsecured promissory note with the sellers in the amount of $1.5 million that was due on July 23, 2010. The note bore interest at a fixed rate of 3% per annum. On June 30, 2010, the sellers agreed to waive all interest under the note and reduce the principal to $1.47 million in exchange for early payment of the note. We paid the reduced note in full on June 30, 2010.

Credit Agreement. On November 28, 2008, we entered into a credit agreement with Dalea for the purpose of funding the all cash takeover offer by TransAtlantic Australia Pty. Ltd., our wholly-owned subsidiary, for all of the outstanding shares of Incremental. Pursuant to the credit agreement, as amended, until June 30, 2009, we could request advances from Dalea of (i) up to $62.0 million for the sole purpose of purchasing Incremental common shares in connection with the offer, plus related transaction costs and expenses; and (ii) up to $14.0 million for general corporate purposes. The total outstanding balance of the advances made under the credit agreement accrued interest at a rate of ten percent (10%) per annum, calculated daily and compounded quarterly. The loan was repaid in full on June 23, 2009, at which time the credit agreement was terminated. We borrowed an aggregate of $64.6 million under the loan and paid a total of $2.0 million in interest in 2009.

Contractual Obligations

The following table presents a summary of our contractual obligations at December 31, 2010:

 

     Payments Due By Year  
     (In Thousands)  
     Total      2011      2012      2013      2014      2015      Thereafter  

Leases and other

   $ 11,101       $ 4,556       $ 2,691       $ 1,194       $ 489       $ 437       $ 1,734   

Contracts

     36,550         31,050         5,500         —           —           —           —     

Permits

     21,880         19,880         2,000         —           —           —           —     
                                                              

Total

   $ 69,531       $ 55,486       $ 10,191       $ 1,194       $ 489       $ 437       $ 1,734   
                                                              

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at December 31, 2010.

 

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Item  7A. Quantitative and Qualitative Disclosures about Market Risk.

We are exposed to market risk from changes in interest rates, foreign currency exchange and hedging contracts. A discussion of the market risk exposure in financial instruments follows. Our market risk sensitive instruments were entered into for hedging and investment purposes, not for trading purposes.

Interest Rate Risk

At December 31, 2010, our exposure to interest rate changes related primarily to borrowings under our senior secured credit facility, short-term secured credit agreement, credit agreement with Dalea and our amended and restated note with Viking Drilling. We are subject to interest rate risks associated with interest rate fluctuations on these outstanding borrowings, as described under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Pursuant to our senior secured credit facility with Standard Bank and BNP Paribas (Suisse) SA, we are subject to interest rate risks associated with interest rate fluctuations on outstanding floating rate borrowings. At December 31, 2010, we had $25.0 million in outstanding borrowings under the senior secured credit facility. The interest we pay on borrowings under the senior secured credit facility is equal to three-month LIBOR plus 6.25% per annum.

Pursuant to our short-term secured credit agreement with Standard Bank, we are subject to interest rate risks associated with interest rate fluctuations on outstanding floating rate borrowings. At December 31, 2010, we had $30.0 million in outstanding borrowings under the short-term secured credit agreement. The interest we pay on borrowings under the short-term secured credit agreement is equal to LIBOR plus 4.25% per annum for interest that accrues on or after February 20, 2011 and before May 25, 2011.

Pursuant to our credit agreement with Dalea, we are subject to interest rate risks associated with interest rate fluctuations on outstanding floating rate borrowings. At December 31, 2010, we had $73.0 million in outstanding borrowings under the credit agreement. The interest we pay on borrowings under this credit agreement is equal to three-month LIBOR plus 2.50% per annum.

Pursuant to our amended and restated note with Viking Drilling, we are subject to interest rate risks associated with interest rate fluctuations on outstanding floating rate borrowings. At December 31, 2010, we had $7.7 million in outstanding borrowings under this promissory note. The interest we pay on borrowings under this note is equal to LIBOR plus 6.25% per annum.

At December 31, 2010, we had approximately $135.8 million in outstanding floating rate borrowings. A hypothetical 1% change in interest rates as of December 31, 2010 would result in an increase or decrease in our interest costs of approximately $1.4 million per year.

Foreign Currency Risk

We are subject to changes in foreign currency exchange rates as a result of our operations in foreign countries. The assets, liabilities and results of operations of our foreign operations are measured using the functional currency of such foreign operation. The functional currency for each of our corporate entities in Turkey, Morocco, Bulgaria and Romania is the local currency. The functional currency for TransAtlantic Petroleum Ltd. is the U.S. Dollar. The functional currency of TransAtlantic Petroleum Ltd. changed from the Canadian Dollar to the U.S. Dollar effective October 1, 2009, the date upon which TransAtlantic Petroleum Ltd. continued its existence out of Canada to Bermuda. As a result, translation adjustments will result from the process of translating the functional currency of our subsidiary financial statements into the U.S. Dollar reporting currency. Our currency exposures primarily relate to the Turkish Lira, as our largest subsidiaries measure their assets, liabilities and results of operations using the Turkish Lira. Such translation adjustments are recorded on our Consolidated Balance Sheets as a component of accumulated other comprehensive income. As of December 31, 2010 and December 31, 2009, we recorded $1.8 million and $9.6 million, respectively, in accumulated other comprehensive income as a result of translation adjustments. In addition, for the years ended December 31, 2010 and 2009, we incurred a loss of $7.8 million and a gain of $9.6 million, respectively, on our Consolidated Statements of Operations and Comprehensive Loss for foreign currency translation and adjustment.

We are also subject to foreign currency exposures as a result of our operations in the other foreign countries in which we operate and foreign currency fluctuations as crude oil prices received are referenced in U.S. Dollar-denominated prices. We record foreign exchange (gain) loss on our Consolidated Statements of Operations and Comprehensive Loss as a component of other expense (income) for gains and losses which result from re-measuring transactions and monetary accounts into the functional currency in earnings. For the years ended December 31, 2010 and 2009, we recorded a foreign exchange gain of $0.8 million and a foreign exchange loss of $3.4 million, respectively.

 

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As of December 31, 2010, we had 3.8 million Turkish Lira (approximately $2.4 million) in cash and cash equivalents that are remeasured into the functional currency using the period-end exchange rate, with such re-measurement gains or losses recorded in foreign exchange (gain) loss. We estimate that a 10% change in the exchange rates would impact such cash balances and our net loss by approximately $240,000. We have not used foreign currency forward contracts to manage exchange rate fluctuations.

Commodity Price Risk

Our revenues are derived from the sale of crude oil and natural gas production. The prices for oil and natural gas are extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supplies, weather conditions, economic conditions and government actions.

Pursuant to our senior secured credit facility with Standard Bank and BNP Paribas (Suisse) SA, at least one of the Borrowers is required to maintain commodity derivative contracts with Standard Bank and BNP Paribas (Suisse) SA. In December 2009, TEMI entered into costless derivative contracts with Standard Bank and BNP Paribas (Suisse) SA, which hedge the price of oil during 2011 and 2012. In April 2010, TEMI entered into three-way collar contracts and additional costless derivative contracts with Standard Bank and BNP Paribas (Suisse) SA, which hedge the price of oil during 2011 and 2012. Pursuant to our senior secured credit facility, we cannot enter into hedge agreements that, when aggregated with any other hydrocarbon hedge agreement then in effect, covers notional volumes in excess of 75% of the reasonably projected production volumes attributable to our proved developed reserves.

The derivative contracts economically hedge against the variability in cash flows associated with the forecasted sale of our future oil production. While the use of the hedging arrangements will limit the downside risk of adverse price movements, it may also limit future gains from favorable movements.

The costless collars provide us with a lower limit “floor” price and an upper limit “ceiling” price on the hedged volumes. The floor price represents the lowest price we will receive for the hedged volumes while the ceiling price represents the highest price we will receive for the hedged volumes. The costless collars are settled monthly. These contracts may or may not involve payment or receipt of cash at inception, depending on the ceiling and floor pricing.

The three-way collar contracts consist of a purchased put, a sold call and a purchased call. The purchased put establishes a lower limit “floor” price, the sold call establishes an upper limit “ceiling” price and the purchased call establishes a “second floor” price on the hedged volumes. The three-way collar contracts require our counterparty to pay us if the settlement price for any settlement period is below the floor price. We are required to pay our counterparty if the settlement price for any settlement period is above the ceiling price but below the second floor price, and our counterparty is required to pay us if the settlement price for any settlement period is above the second floor price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price. The three-way collar contracts are settled monthly.

We have elected not to designate our derivative financial instruments as hedges for accounting purposes, and accordingly, we record such contracts at fair value and recognize changes in such fair value in current earnings as they occur. Our commodity derivative contracts are carried at their fair value in earnings as they occur. We recognize unrealized and realized gains and losses related to these contracts on a mark-to-market basis in our consolidated statement of operations under the caption “(Gain) loss on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our Consolidated Statements of Cash Flows. If commodity prices decrease, this commodity price change could have a positive impact to our earnings. Conversely, if commodity prices increase, this commodity price change could have a negative effect on our earnings. Each derivative contract is evaluated separately to determine its own fair value. During the year ended December 31, 2010, we recorded a net unrealized loss on commodity derivative contracts of $1.6 million. We recorded a net unrealized loss on commodity derivative contracts of $1.9 million in 2009.

The following tables summarize our outstanding derivatives contracts with respect to future crude oil production as of December 31, 2010:

 

Type

   Period      Quantity
(Bbl/day)
     Weighted
Average
Minimum

Price (per Bbl)
     Weighted
Average
Maximum Price
(per Bbl)
     Estimated Fair
Value of
Liability
 
                                 (in thousands)  

Collar

     January 1, 2011 — December 31, 2011         1,060       $ 64.39       $ 101.32       $ (1,342

Collar

     January 1, 2012 — December 31, 2012         960       $ 64.69       $ 106.98         (1,571
                    
               $ (2,913
                    

 

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          Collars      Additional Call         

Type

  

Period

   Quantity
(Bbl/day)
     Weighted
Average
Minimum
Price (per Bbl)
     Weighted
Average
Maximum Price
(per Bbl)
     Weighted
Average
Maximum
Price (per Bbl)
     Estimated Fair
Value of
Liability
 
                                      (in thousands)  

Three-way collar contract

   January 1, 2011 — December 31, 2011      240       $ 70.00       $ 100.00       $ 129.50       $ (270

Three-way collar contract

   January 1, 2012 — December 31, 2012      240       $ 70.00       $ 100.00       $ 129.50         (334
                       
                  $ (604
                       

 

Item  8. Financial Statements and Supplementary Data.

See Index to Financial Statements on page F-1.

 

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

Not applicable.

 

Item  9A. Controls and Procedures.

Acquisition of Amity and Petrogas

On August 25, 2010, we acquired Amity and Petrogas. For purposes of determining the effectiveness of our disclosure controls and procedures and internal control over financial reporting as of December 31, 2010, and any change in our internal control over financial reporting for the fourth quarter of 2010, management has excluded the internal control over financial reporting of Amity and Petrogas from its evaluation of these matters. The acquired businesses represent approximately 22.8% of our consolidated total assets at December 31, 2010 and approximately 8.1% of our consolidated net income for the year ended December 31, 2010. Any material change to our internal control over financial reporting due to the acquisition of Amity and Petrogas will be disclosed in our annual report for the year ending December 31, 2011 in which our assessment that encompasses Amity and Petrogas will be included.

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

As of December 31, 2010, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures. Based upon the evaluation, which excluded the internal control over financial reporting of Amity and Petrogas, and as a result of the material weaknesses in internal control over financial reporting described below, our chief executive officer and chief financial officer concluded that, as of December 31, 2010, our disclosure controls and procedures were not effective at the reasonable assurance level. See “—Acquisition of Amity and Petrogas.”

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurances of achieving their control objectives.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act, is a process designed by, or under the supervision of, the chief executive officer and chief financial officer, or persons performing similar functions, and effected by the board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP and includes those policies and procedures that: (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) 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 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.

Our management, under the supervision and with the participation of our chief executive officer and chief financial officer, conducted an evaluation of the effectiveness of our internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control—Integrated Framework. Based on its evaluation, which excluded the internal control over financial reporting of Amity and Petrogas, our management concluded that our internal control over financial reporting was not effective as of December 31, 2010 because of the identification of the material weaknesses identified below. See “—Acquisition of Amity and Petrogas.”

A material weakness (as defined in Rule 12b-2 under the Exchange Act) is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement in our annual or interim financial statements will not be prevented or detected on a timely basis. We have identified the material weaknesses described below:

 

 

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We did not maintain an effective control environment. The control environment, which is the responsibility of senior management, sets the tone of the organization, influences the control consciousness of its people, and is the foundation for all other components of internal control over financial reporting. This control deficiency, which is pervasive in nature, could contribute to a material misstatement in the financial statements not being prevented or detected on a timely basis. Specifically, we did not maintain a tone and control consciousness that consistently emphasized adherence to timely and accurate financial reporting and enforcement of the Company’s policies and procedures. This control deficiency fostered a lack of sufficient appreciation for internal control over financial reporting and resulted in an ineffective process for monitoring the adherence of the Company’s policies and procedures and was a contributing factor in the other material weaknesses described below.

 

   

We did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience, and training in the application of U.S. GAAP and in internal control over financial reporting commensurate with our financial reporting requirements and business environment. Because of this deficiency, which is pervasive in nature, we recorded material post-closing adjustments to our 2010 consolidated financial statements and there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis.

 

   

We did not maintain an effective anti-fraud program designed to detect and prevent fraud relating to an ongoing program to manage identified fraud risks. This deficiency, which is pervasive in nature, did not result in a misstatement to the financial statements. However, in combination with the other material weaknesses, this deficiency results in a reasonable possibility that a material misstatement to the annual financial statements would not be prevented or detected on a timely basis.

 

   

We did not design and maintain effective controls for the review, supervision and monitoring of our accounting operations throughout the organization and for monitoring and evaluating the adequacy of our internal control over financial reporting. Specifically, our policies and procedures with respect to the review, supervision and monitoring of our accounting operations throughout the organization were either not designed and in place or not operating effectively and there were insufficient policies and procedures to effectively determine the adequacy of our internal control over financial reporting. Because of this deficiency, which is pervasive in nature, we recorded material post-closing adjustments to our 2010 consolidated financial statements and there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis.

 

   

We did not maintain effective controls over the preparation, review and approval of all financial statement account reconciliations. Because of this deficiency, which is pervasive in nature, we recorded material post-closing adjustments to our 2010 consolidated financial statements and there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis.

 

   

We did not maintain effective controls over the recording and monitoring of intercompany accounts. Specifically, effective controls were not designed and in place to ensure that intercompany balances were completely and accurately classified and reported in our underlying accounting records and to ensure proper elimination as part of the consolidation process. Because of this deficiency, which is pervasive in nature, we recorded material post-closing adjustments to our 2010 consolidated financial statements and there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis.

 

   

We did not maintain effective controls over the re-measurement and translation of our foreign entity account balances. Specifically, effective controls were not designed and in place to ensure that foreign exchange gains, losses and cumulative translation adjustments were appropriately calculated and recorded in the respective accounts of our foreign entities. Because of this deficiency, which is pervasive in nature, we recorded material post-closing adjustments to our 2010 consolidated financial statements and there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis.

 

   

We did not maintain effective controls over the review, approval, documentation and recording of our journal entries. Specifically, effective controls were not designed and in place to ensure the existence, accuracy and completeness of the journal entries recorded, both recurring and non-recurring. Because of this deficiency, which is pervasive in nature, we recorded material post-closing adjustments to our 2010 consolidated financial statements and there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis.

 

   

We did not maintain adequate controls to integrate the accounting functions of our foreign entities. Specifically, effective controls were not designed and in place to ensure that accounting data for our foreign operations was monitored for accuracy and timely communicated. Because of this deficiency, which is pervasive in nature, we recorded material post-closing adjustments to our

 

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2010 consolidated financial statements and there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis.

 

   

We did not maintain effective controls over our information technology general controls. Specifically, appropriate policies and procedures were not in place with respect to access, program changes and system security. This control deficiency contributed in part to other control deficiencies noted such as those related to intercompany accounts and over the re-measurement and translation of our foreign entity account balances. This control deficiency, which is pervasive in nature, could contribute to a material misstatement in the financial statements not being prevented or detected on a timely basis.

 

   

We did not maintain an effective period-end financial statement closing process. Specifically, effective controls were not designed and in place to ensure detailed reviews and verification of inputs related to the analysis of accounts or transactions and schedules supporting financial statement amounts and disclosures. Because of this deficiency, which is pervasive in nature, we recorded material post-closing adjustments to our 2010 consolidated financial statements and there is a reasonable possibility that a material misstatement of our financial statements will not be prevented or detected on a timely basis.

Our independent registered public accounting firm has audited the effectiveness of our internal control over financial reporting as of December 31, 2010 as stated in their report, dated April 21, 2011, which appears herein.

Management’s Plan for Remediation of Material Weaknesses

Because our internal control over financial reporting was not effective for two consecutive years, our management has developed a plan intended to remediate our material weaknesses and to strengthen our internal control over financial reporting by December 31, 2011 through the implementation of the following remedial measures:

 

   

Staffing. In February 2011, we hired a vice president of accounting. The new vice president of accounting will reside in Istanbul. He has the necessary training and experience required to oversee the consistent application of U.S. GAAP. He has experience working for a U.S. company in an international environment. Further, he has considerable experience in training local accountants to apply U.S. GAAP. We will hire a chief financial officer who has previous experience with a U.S. public company with foreign operations. We will hire additional accountants with U.S. GAAP experience, who will either reside in Istanbul or spend considerable time in Istanbul. We will hire a full time accountant, whose responsibilities will be the monitoring the effectiveness of our internal control over financial reporting and remediating deficiencies in our internal control over financial reporting. That accountant will also be responsible to ensure we maintain an effective anti-fraud program. We will also have additional staff in Istanbul, including staff that would otherwise work in the Dallas office, until such time as management is satisfied that we are effectively implementing the plan to establish effective internal control over financial reporting. We may conclude that certain accounting functions that are expected to be performed in Istanbul may need to be performed in Dallas, if attracting and retaining sufficient accountants with U.S. GAAP experience in Istanbul becomes impractical.

 

   

Integration of accounting functions. In July 2010, we implemented a new accounting system that replaced the legacy accounting system we acquired in the acquisition of Incremental. After the implementation of the new software, however, there were still separate and distinct accounting systems located in Istanbul (used for our Turkish subsidiaries) and Dallas (used for consolidating and reporting, and for accounting for our holding companies and Moroccan, Bulgarian and Romanian subsidiaries). Immediately following the filing of our Annual Report on Form 10-K, we will combine the two databases into one database in Istanbul, effective for all activity from January 1, 2011. The combined database will have full multicurrency functionality and be largely able to generate U.S. GAAP reports for individual subsidiaries. We believe this will improve the accuracy of data entered in the system, including reducing the incidence of conflicting or redundant entries. Because the data will all be on one system the timeliness of our financial statement closing process will improve. Further, because the underlying data will largely reflect activity recorded in accordance with U.S. GAAP, the number of adjusting entries will be reduced, and the timeliness of consolidating will improve. As a result, we expect to substantially improve the timeliness of our financial reporting.

 

   

Monitoring function. We intend to develop procedures by June 30, 2011 that will assist management, including those with the responsibility for drafting and reviewing financial statements, with monitoring the performance of control activities performed at both our Istanbul and Dallas offices. Our internal control accountant will play a key role in this process. In addition, our chairman, chief executive officer, chief financial officer and vice president of accounting will regularly meet to monitor progress, identify continuing deficiencies, and make any necessary adjustments to personnel or our plan to ensure the effective implementation of remedial measures.

Changes in Internal Control over Financial Reporting

There were no material changes in our internal control over financial reporting that occurred during the fourth quarter of 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

Item  9B. Other Information.

None.

 

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PART III

 

Item  10. Directors, Executive Officers and Corporate Governance.

The information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report.

 

Item  11. Executive Compensation.

The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.

 

Item  12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.

 

Item  13. Certain Relationships and Related Transactions, and Director Independence.

The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.

 

Item  14. Principal Accounting Fees and Services.

The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report.

 

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PART IV

 

Item  15. Exhibits and Financial Statement Schedules.

 

(a) Documents filed as part of Report.

 

  1. Reports of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2010 and 2009

Consolidated Statements of Operations and Comprehensive Loss for the years ended December 31, 2010, 2009 and 2008

Consolidated Statements of Equity for the years ended December 31, 2010, 2009 and 2008

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008

Notes to Consolidated Financial Statements

 

  2. Exhibits required to be filed by Item 601 of Regulation S-K

 

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EXHIBIT INDEX

 

2.1    Share Purchase Agreement, dated July 3, 2010, by and between TransAtlantic Worldwide, Ltd., Zorlu Enerji Elektrik Üretim A.Ş. and Zorlu Holding A.Ş. (incorporated by reference to the Company’s Current Report on Form 8-K dated July 3, 2010, filed with the SEC on July 9, 2010).
2.2    Purchase Agreement, dated January 28, 2011, by and between Direct Petroleum Exploration, Inc., TransAtlantic Worldwide, Ltd. and TransAtlantic Petroleum Ltd. (incorporated by reference to the Company’s Current Report on Form 8-K dated January 28, 2011, filed with the SEC on February 3, 2011).
3.1    Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.2    Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated August 20, 2009 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.3    Bye-Laws of TransAtlantic Petroleum Ltd., dated July 14, 2009 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
4.1    Amended and Restated Registration Rights Agreement, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Riata Management, LLC (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009).
4.2    Registration Rights Agreement, dated February 18, 2011, by and between TransAtlantic Petroleum Ltd. and Direct Petroleum Exploration, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated February 18, 2011, filed with the SEC on February 24, 2011).
4.3    Common Share Purchase Warrant, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009).
4.4*    Common Share Purchase Warrant, dated September 1, 2010, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP.
4.5    Form of Common Share Certificate (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form S-3, filed with the SEC on June 9, 2010).
10.1    Service Agreement, effective as of May 1, 2008, by and among TransAtlantic Petroleum Corp., Longfellow Energy, LP, Viking Drilling, LLC, Longe Energy Limited and Riata Management, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated August 6, 2008, filed with the SEC on February 12, 2009).
10.2    Amendment to Service Agreement, effective as of October 1, 2008, by and among TransAtlantic Petroleum Corp., Longfellow Energy, LP, Viking Drilling, LLC, Longe Energy Limited, MedOil Supply LLC and Riata Management, LLC (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated August 6, 2008, filed with the SEC on February 12, 2009).
10.3*    Agreement for Management Services, dated December 15, 2009, by and between Viking

 

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   International Limited and Viking Drilling, LLC.
10.4    Amendment to Management Service Agreement, dated August 5, 2010, by and between Viking International Limited and Viking Drilling, LLC (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on November 15, 2010).
10.5    Management Services Agreement, dated August 5, 2010, by and between Viking International Limited and Maritas A.S. (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on November 15, 2010).
10.6    Agreement for Management Services, dated September 28, 2010, by and between Viking International Limited and Viking Petrol Sahasi Hizmetleri A.S. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated September 28, 2010, filed with the SEC on September 28, 2010).
10.7    Credit Agreement, dated as of December 21, 2009, by and among DMLP, Ltd., Talon Exploration, Ltd., TransAtlantic Turkey, Ltd. and TransAtlantic Exploration Mediterranean International Pty. Ltd., as borrowers, Incremental Petroleum (Selmo) Pty. Ltd., TransAtlantic Worldwide, Ltd., TransAtlantic Petroleum (USA) Corp. and TransAtlantic Petroleum Ltd., as guarantors, the lenders party thereto from time to time, and Standard Bank Plc, as letter of credit issuer, administrative agent, collateral agent and technical agent (incorporated by reference to Exhibit 10.1 to the Company’s Amendment No. 1 to the Current Report on Form 8-K/A dated December 21, 2009, filed with the SEC on January 7, 2010).
10.8    Credit Agreement, dated as of June 28, 2010, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated June 28, 2010, filed with the SEC on July 1, 2010).
10.9      Credit Agreement, dated as of August 25, 2010, by and between TransAtlantic Worldwide, Ltd., as borrower, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., Amity Oil International Pty Limited and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., as guarantors, the lenders party thereto from time to time, and Standard Bank Plc, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1 the Company’s Current Report on Form 8-K dated August 24, 2010, filed with the SEC on August 30, 2010).
10.10    Amendment to Credit Agreement, dated as of December 20, 2010, by and among TransAtlantic Worldwide, Ltd., as borrower, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., Amity Oil International Pty Limited and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., as guarantors, the lenders party thereto from time to time, and Standard Bank Plc, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated December 23, 2010, filed with the SEC on December 29, 2010).
10.11    Amendment to Credit Agreement, dated as of February 28, 2011, by and among TransAtlantic Worldwide, Ltd., as borrower, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., Amity Oil International Pty Limited and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., as guarantors, the lenders party thereto from time to time, and Standard Bank Plc, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated March 3, 2011, filed with the SEC on March 8, 2011).
10.12*    Amended and Restated Note, dated February 19, 2010, by and between Viking International Limited and Viking Drilling, LLC.
10.13*    Domestic Crude Oil Purchase/Sale Agreement, dated as of January 26, 2009, by and between Türkiye Petrol Rafinerileri A.Ş. and TransAtlantic Exploration Mediterranean International Pty. Ltd.

 

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10.14*    Domestic Crude Oil Swap Agreement, effective as of January 1, 2010, by and between Türkiye Petrolleri A.O. and TransAtlantic Exploration Mediterranean International Pty. Ltd.
10.15*    Option Agreement, dated November 8, 2008, by and between TransAtlantic Worldwide, Ltd. and Mustafa Mehmet Corporation.
10.16†    Executive Employment Agreement, effective July 1, 2005, by and between TransAtlantic Petroleum Corp. and Scott C. Larsen (incorporated by reference to Exhibit 4.1 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).
10.17†    Management Agreement, effective April 1, 2006, by and between TransAtlantic Worldwide, Ltd. and Charles Management Inc. (incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).
10.18†    Participating Interest Agreement, effective July 11, 2005, by and among TransAtlantic Worldwide, Ltd., TransAtlantic Petroleum Corp. and Scott C. Larsen (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).
10.19†    Amended and Restated Stock Option Plan (2006) (incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).
10.20    Warrant Indenture, dated December 1, 2006, by and between TransAtlantic Petroleum Corp. and Computershare Trust Company of Canada (incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form 20-F, filed with the SEC on October 9, 2007).
10.21†    Executive Employment Agreement, effective January 1, 2008, by and between TransAtlantic Petroleum Corp. and Jeffrey S. Mecom (incorporated by reference to Exhibit 4.8 to the Company’s Annual Report on Form 20-F, filed with the SEC on May 14, 2008).
10.22†    Executive Employment Agreement, effective May 1, 2008, by and between TransAtlantic Petroleum Corp. and Hilda Kouvelis (incorporated by reference to Exhibit 4.9 to the Company’s Annual Report on Form 20-F, filed with the SEC on May 14, 2008).
10.23†    Letter Agreement, dated January 31, 2011, by and between TransAtlantic Petroleum Ltd. and Hilda Kouvelis (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, dated January 28, 2011, filed with the SEC on February 3, 2011).
10.24    Form of Common Share Purchase Warrant, dated April 2, 2009, by and between TransAtlantic Petroleum Corp. and holders of options to purchase shares of Incremental Petroleum Limited (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 27, 2009).
10.25†    TransAtlantic Petroleum Corp. 2009 Long-Term Incentive Plan (incorporated by reference to Appendix B to the Definitive Proxy Statement filed by TransAtlantic Petroleum Corp. with the SEC on April 30, 2009).
10.26†    Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated June 16, 2009, filed with the SEC on June 22, 2009).
10.27†    Form of Share Option Agreement (incorporated by reference to Exhibit 99.3 to the Company’s Registration Statement on Form S-8, filed with the SEC on November 2, 2009).
10.28    Amendment to Credit Agreement, dated as of April 1, 2011, by and among TransAtlantic Worldwide, Ltd., as borrower, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., Amity Oil International Pty Limited and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., as guarantors, the lenders as defined in the Credit Agreement, and Standard Bank Plc, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K dated April 1, 2011, filed with the SEC on April 6, 2011).
21.1*    Subsidiaries of the Company.
23.1*    Consent of KPMG LLP.
23.2*    Consent of DeGolyer and MacNaughton.

 

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31.1*    Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*    Certification of the Chief Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*    Certification of the Chief Executive Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*    Certification of the Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*    Report of DeGolyer and MacNaughton, dated March 7, 2011.

 

Management contract or compensatory plan arrangement
* Filed herewith.

 

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SIGNATURES

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

April 21, 2011

 

TRANSATLANTIC PETROLEUM LTD.
/S/    MATTHEW W. MCCANN        

Matthew W. McCann,

Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

 

Signature

  

Capacity

 

Date

/S/    MATTHEW W. MCCANN        

Matthew W. McCann

  

Chief Executive Officer
(Principal Executive Officer)

  April 21, 2011

/S/    HILDA D. KOUVELIS        

Hilda D. Kouvelis

  

Chief Financial Officer
(Principal Financial Officer and
Principal Accounting Officer/Controller)

  April 21, 2011

/S/    N. MALONE MITCHELL, 3RD        

N. Malone Mitchell, 3rd

  

Chairman

  April 21, 2011

/S/    BOB G. ALEXANDER        

Bob G. Alexander

  

Director

  April 21, 2011

/S/    BRIAN E. BAYLEY        

Brian E. Bayley

  

Director

  April 21, 2011

/S/    SCOTT C. LARSEN        

Scott C. Larsen

  

Director

  April 21, 2011

/S/    ALAN C. MOON        

Alan C. Moon

  

Director

  April 21, 2011

/S/    MEL G. RIGGS        

Mel G. Riggs

  

Director

  April 21, 2011

/S/    MICHAEL D. WINN        

Michael D. Winn

  

Director

  April 21, 2011

 

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

AND FINANCIAL STATEMENT SCHEDULES

 

     Page  

Reports of Independent Registered Public Accounting Firm

     F-2   

Consolidated Balance Sheets as of December 31, 2010 and 2009

     F-6   

Consolidated Statements of Operations and Comprehensive Loss for the years ended December 31, 2010, 2009 and 2008

     F-7   

Consolidated Statements of Equity for the years ended December 31, 2010, 2009 and 2008

     F-8   

Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008

     F-9   

Notes to Consolidated Financial Statements

     F-10   

 

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

TransAtlantic Petroleum Ltd.

We have audited TransAtlantic Petroleum Ltd.’s (the “Company”) internal control over financial reporting as of December 31, 2010, based on Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). TransAtlantic Petroleum Ltd.’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, included in the accompanying Management’s Report on Internal Control Over Financial Reporting in Item 9A. 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, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included 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.

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of a company’s annual or interim financial statements will not be prevented or

 

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detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment:

 

   

The Company did not maintain an effective control environment.

 

   

The Company did not maintain a sufficient complement of personnel with an appropriate level of accounting knowledge, experience, and training in the application of U.S. generally accepted accounting principles and in internal control over financial reporting commensurate with its financial reporting requirements and business environment.

 

   

The Company did not maintain an effective anti-fraud program designed to detect and prevent fraud relating to an ongoing program to manage identified fraud risks.

 

   

The Company did not design and maintain effective controls for the review, supervision and monitoring of its accounting operations throughout the organization and for monitoring and evaluating the adequacy of its internal control over financial reporting.

 

   

The Company did not maintain effective controls over the preparation, review and approval of all financial statement account reconciliations.

 

   

The Company did not maintain effective controls over the recording and monitoring of intercompany accounts.

 

   

The Company did not maintain effective controls over the re-measurement and translation of its foreign entity account balances.

 

   

The Company did not maintain effective controls over the review, approval, documentation and recording of its journal entries.

 

   

The Company did not maintain adequate controls to integrate the accounting functions of its foreign entities.

 

   

The Company did not maintain effective controls over its information technology general controls.

 

   

The Company did not maintain an effective period-end financial statement closing process.

TransAtlantic Petroleum Ltd. acquired Amity Oil International Pty. Ltd. (“Amity”) and Petrogas Petrol Gaz vs Petrokimya Urunleri Insaat Sanayi ve Ticaret A.S. (“Petrogas”) during 2010, and management excluded from its assessment of effectiveness of TransAtlantic Petroleum Ltd.’s internal control over financial reporting as of December 31, 2010, Amity’s and Petrogas’s internal control over financial reporting. The acquired businesses represent approximately 22.8% of the Company’s consolidated total assets at December 31, 2010 and approximately 8.1% of the Company’s consolidated net income for the year ended December 31, 2010. Our audit of internal control over financial reporting of TransAtlantic Petroleum Ltd. also excluded an evaluation of the internal control over financial reporting of Amity and Petrogas.

 

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We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of TransAtlantic Petroleum Ltd. and subsidiaries. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2010 consolidated financial statements, and this report does not affect our report dated April 21, 2011, which expressed an unqualified opinion on those consolidated financial statements.

In our opinion, because of the effect of the aforementioned material weaknesses on the achievement of the objectives of the control criteria, TransAtlantic Petroleum Ltd. has not maintained effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

(signed) KPMG LLP

Calgary, Canada

April 21, 2011

 

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

TransAtlantic Petroleum Ltd.:

We have audited the accompanying consolidated balance sheets of TransAtlantic Petroleum Ltd. and subsidiaries (the “Company”) as of December 31, 2010 and 2009, and the related consolidated statements of operations and comprehensive loss, equity and cash flows for each of the years in the three-year period ended December 31, 2010. 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 financial position of TransAtlantic Petroleum Ltd. and subsidiaries as of December 31, 2010 and 2009, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in note 2 to the consolidated financial statements, the Company has suffered recurring losses from operations, has a working capital deficiency and significant commitments, which raise substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in note 2. 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), TransAtlantic Petroleum Ltd.’s internal control over financial reporting as of December 31, 2010, 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 April 21, 2011 expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.

(signed) KPMG LLP

Calgary, Canada

April 21, 2011

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

As of December 31, 2010 and 2009

(in thousands of U.S. dollars, except share data)

 

     2010     2009  

ASSETS

    

Current assets:

    

Cash and cash equivalents

   $ 34,676      $ 90,484   

Accounts receivable

    

Oil and gas sales, net

     23,077        6,926   

Related party (note 18)

     3,783        —     

Other

     6,326        2,827   

Prepaid and other current assets

     6,376        8,251   

Deferred income taxes (note 13)

     991        1,580   
                

Total current assets

     75,229        110,068   
                

Property and equipment (note 7):

    

Oil and gas properties (successful efforts method)

    

Proved

     157,508        66,313   

Unproved

     73,203        12,363   

Drilling services and other equipment

     174,654        106,641   
                
     405,365        185,317   

Less accumulated depreciation, depletion and amortization

     (38,140     (8,053
                

Property and equipment, net

     367,225        177,264   

Other long-term assets:

    

Restricted cash (note 6)

     7,956        7,780   

Deposit on acquisition (note 20)

     10,000        —     

Deferred charges

     1,596        1,904   

Goodwill (note 5)

     10,341        10,067   
                

Total other assets

     29,893        19,751   
                

Total assets

   $ 472,347      $ 307,083   
                

LIABILITIES AND SHAREHOLDERS’ EQUITY

    

Current liabilities:

    

Accounts payable

   $ 15,842      $ 7,385   

Accounts payable – related party (note 18)

     969        1,075   

Accrued liabilities

     10,089        12,172   

Settlement provision

     240        240   

Loans payable (note 10)

     30,869        1,595   

Loan payable – related party (notes 11 and 18)

     75,804        5,906   

Derivative liabilities (note 8)

     1,612        762   
                

Total current liabilities

     135,425        29,135   

Long-term liabilities:

    

Asset retirement obligations (note 9)

     6,943        3,125   

Accrued liabilities

     724        —     

Deferred income taxes (note 13)

     22,641        9,056   

Loan payable (note 10)

     27,147        —     

Loans payable – related party (note 11 and 18)

     2,932        —     

Derivative liabilities (note 8)

     1,905        1,160   
                

Total long-term liabilities

     62,292        13,341   
                

Total liabilities

     197,717        42,476   

Going concern (note 2)

    

Commitments and Contingencies (notes 10, 11, 16 and 17)

    

Shareholders’ equity (note 12):

    

Common shares, $0.01 par value, 1,000,000,000 shares authorized, issued and outstanding 336,442,984 as of December 31, 2010 and 303,265,456 as of December 31, 2009

     3,364        3,033   

Additional paid in capital

     456,390        371,905   

Additional paid in capital—warrants

     9,583        5,435   

Accumulated other comprehensive income

     1,812        9,601   

Accumulated deficit

     (196,519     (125,367
                

Total shareholders’ equity

     274,630        264,607   
                

Total liabilities and shareholders’ equity

   $ 472,347      $ 307,083   
                

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

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Operations and Comprehensive Loss

For the years ended December 31, 2010, 2009 and 2008

(U.S. dollars and shares in thousands, except per share amounts)

 

     2010     2009     2008  

Revenues:

      

Oil and gas sales

   $ 69,839      $ 27,681      $ 111   

Oilfield services

     15,724        1,588        —     
                        

Total revenues

     85,563        29,269        111   

Costs and expenses:

      

Production

     20,286        10,168        73   

Exploration, abandonment and impairment

     32,615        24,791        —     

Seismic and other exploration

     12,319        10,538        7,901   

International oil and gas activities

     23,658        12,349        5,183   

General and administrative

     29,730        16,129        3,592   

Depreciation, depletion and amortization

     28,219        7,942        53   

Accretion of asset retirement obligations (note 9)

     470        164        6   
                        

Total costs and expenses

     147,297        82,081        16,808   
                        

Operating loss

     61,734        52,812        16,697   

Other expense (income):

      

Interest and other expense

     8,841        2,748        116   

Interest and other income

     (353     (213     (338

Loss on commodity derivative contracts (note 8)

     1,624        1,922        —     

Foreign exchange (gain) loss

     (811     3,449        —     
                        

Total other expense (income)

     9,301        7,906        (222

Loss before income taxes:

     71,035        60,718        16,475   
                        

Current income tax expense

     1,813        2,142        —     

Deferred income tax benefit

     (1,696     (843     —     
                        

Net loss

   $ 71,152      $ 62,017      $ 16,475   

Non controlling interest, net of tax

     —          129        —     
                        

Net loss attributable to common shareholders

   $ 71,152      $ 62,146      $ 16,475   

Other comprehensive loss (gain)

      

Foreign currency translation adjustment

     7,789        (9,601     —     
                        

Comprehensive loss

   $ 78,941      $ 52,545      $ 16,475   
                        

Net loss per common share attributable to common shareholders:

      

Basic and diluted net loss attributable to common shareholders, per common share

   $ 0.23      $ 0.29      $ 0.25   

Basic and diluted weighted average number of shares outstanding

     312,488        212,320        66,524   

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

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Equity

For the years ended December 31, 2010, 2009 and 2008

(U.S. dollars and shares in thousands)

 

     Common
Shares
     Warrants
(Number)
    Common
Shares ($)
     Additional
Paid-in
Capital
    Additional
Paid-in
Capital
Warrants
    Accumulated
Other
Comprehensive
Income (loss)
    Accumulated
Deficit
    Non-
Controlling
Interest
    Total
Shareholders’
Equity
 

Balance at December 31, 2007

     43,271         4,719      $ —         $ 47,837      $ 1,108      $ —        $ (46,875   $ —        $ 2,070   

Issuance of common shares

     110,000         —          —           83,072        —          —          —          —          83,072   

Issuance of warrants

     —           10,000        —           —          5,228        —          —          —          5,228   

Issuance costs

     —           —          —           (1,199     —          —          —          —          (1,199

Exercise of stock options

     247         —          —           149        —          —          —          —          149   

Exercise of warrants

     1,440         (1,440     —           1,907        (395     —          —          —          1,512   

Expiration of warrants

     —           (3,279     —           713        (713     —          —          —          —     

Share-based compensation

     —           —          —           583        —          —          —          —          583   

Net loss attributable to common shareholders

     —           —          —           —          —          —          (16,475     —          (16,475
                                                                          

Balance at December 31, 2008

     154,958         10,000        —           133,062        5,228        —          (63,350     —          74,940   

Issuance of common shares

     147,426         —          3,033         248,615        —          —          —          —          251,648   

Issuance of shares and warrants in connection with the Incremental acquisition

     102         830        —           71        207        —          —          —          278   

Issuance costs

     —           —          —           (12,058     —          —          —          —          (12,058

Exercise of stock options

     780         —          —           575        —          —          —          —          575   

Exercise of warrants

     —           —          —           —          —          —          —          —          —     

Expiration of warrants

     —           —          —           —          —          —          —          —          —     

Share-based compensation

     —           —          —           1,640        —          —          —          —          1,640   

Non-controlling interest

     —           —          —           —          —          —          —          129        129   

Foreign currency translation adjustments

     —           —          —           —          —          9,601        —          —          9,601   

Net loss attributable to common shareholders

     —           —          —           —          —          —          (62,017     (129     (62,146
                                                                          

Balance at December 31, 2009

     303,266         10,830        3,033         371,905        5,435        9,601        (125,367     —          264,607   

Issuance of common shares

     30,357         —          304         84,696        —          —          —          —          85,000   

Issuance costs

     —           —          —           (4,350     —          —          —          —          (4,350

Issuance of warrants

     —           7,300        —           —          4,330        —          —          —          4,330   

Exercise of warrants

     731         (731     7         1,053        (182     —          —          —          878   

Exercise of stock options

     1,212         —          12         1,078        —          —          —          —          1,090   

Issuance of restricted stock units

     877         —          8         (8     —          —          —          —          —     

Share based compensation

     —           —          —           2,016        —          —          —          —          2,016   

Foreign currency translation adjustments

     —           —          —           —          —          (7,789     —          —          (7,789

Net loss attributable to common shareholders

     —           —          —           —          —          —          (71,152     —          (71,152
                                                                          

Balance at December 31, 2010

     336,443         17,399      $ 3,364       $ 456,390      $ 9,583      $ 1,812      $ (196,519   $ —        $ 274,630   
                                                                          

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

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

For the years ended December 31, 2010, 2009 and 2008

(in thousands of U.S. dollars)

 

     2010     2009     2008  

Operating activities:

      

Net loss

   $ (71,152   $ (62,017   $ (16,475

Adjustments to reconcile net loss to net cash used in operating activities:

      

Share-based compensation

     2,016        1,640        583   

Foreign currency loss (gain)

     712        (492     —     

Unrealized loss on commodity derivative contracts

     1,595        1,922        —     

Amortization of debt issuance costs

     1,336        —          —     

Deferred income tax benefit

     (1,696     (843     —     

Amortization of warrants – related party

     2,358        —          —     

Exploration, abandonment and impairment

     5,343        290        —     

Depreciation, depletion and amortization

     28,219        7,942        53   

Accretion of asset retirement obligations

     470        164        6   

Changes in operating assets and liabilities, net of effect of acquisitions (note 5):

      

Accounts receivable

     (24,174     (2,905     (761

Prepaid expenses and other assets

     3,529        (2,384     (1,180

Accounts payable and accrued liabilities

     7,948        5,841        4,101   
                        

Net cash used in operating activities

     43,496        (50,842     (13,673

Investing activities:

      

Deposit on acquisition

     (10,000     —          —     

Acquisition of Amity and Petrogas, net of cash (note 5)

     (96,248     —          —     

Acquisition of Incremental Petroleum Ltd., net of cash (note 5)

     —          (37,934     —     

Acquisition of Incremental Petroleum Ltd. shares – related party (notes 5 and 18)

     —          (11,182     —     

Acquisition of non-controlling interest in Incremental Petroleum Ltd. (note 5)

     —          (2,761     —     

Acquisition of Talon Exploration, Ltd., net of cash (note 5)

     —          (6,192     —     

Additions to oil and gas properties

     (53,766     (14,238     3,760   

Additions to drilling services and other equipment

     (58,817     (46,471     (14,028

Deferred charges

     —          —          (181

Restricted cash

     (176     (4,512     (996
                        

Net cash used in investing activities

     (219,007     (123,290     (11,445

Financing activities:

      

Exercise of stock options and warrants

     1,968        575        1,661   

Issuance of common shares

     80,000        181,481        53,769   

Issuance of common shares – related party (notes 12 and 18)

     5,000        70,167        —     

Issuance costs

     (4,350     (12,058     (484

Loan proceeds

     59,103        95        —     

Loan proceeds – related party (note 11)

     91,500        64,621        —     

Loan repayment

     (2,682     (4,722     (2,000

Loan repayment – related party (note 11)

     (22,614     (64,621     —     

Loan financing costs

     (1,028     (1,834     —     
                        

Net cash provided by financing activities

     206,897        233,704        52,946   

Effect of exchange rate changes on cash

     (202     860        —     

Net (decrease) increase in cash and cash equivalents

     (55,808     60,432        27,828   

Cash and cash equivalents, beginning of year

     90,484        30,052        2,224   
                        

Cash and cash equivalents, end of year

   $ 34,676      $ 90,484