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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, 2009
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 000-31643
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.) |
| 5910 N. Central Expressway, Suite 1755 Dallas, Texas |
75206 | |
| (Address of principal executive offices) | (Zip Code) |
Registrant’s telephone number, including area code: (214) 220-4323
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 LLC |
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 x
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 x
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 x 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 | x | |||
| 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 x
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, 2009 (the last business day of the registrant’s most recently completed second fiscal quarter), was approximately $172.8 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 March 26, 2010, there were 303,795,963 common shares outstanding.
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FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009
INDEX
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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; the global economic crisis and 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; 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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PART I
| Item 1. | Business. |
In this Annual Report on Form 10-K, references to “we,” “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, development, exploration, and production of crude oil and natural gas. We hold interests in developed and undeveloped oil and gas properties in Turkey, Morocco, Romania, and California. We own our own drilling rigs and oilfield service equipment, which we use to develop our properties in Turkey and Morocco. In addition, we provide oilfield services and contract drilling services to third parties in Turkey and plan to provide similar services in Morocco.
Strategic Transformation. We underwent a strategic transformation during 2008 as a result of a series of transactions with N. Malone Mitchell, 3rd, chairman of our board of directors. Mr. Mitchell founded Riata Energy, Inc. in 1985 and built it into one of the largest privately held oil and gas producers in the United States. In 2006, Mr. Mitchell sold his controlling interest in Riata Energy, Inc. (now Sandridge Energy, Inc.) and founded a group of companies that are primarily focused on investing in international energy opportunities.
In March 2008, we announced that we had entered into a strategic relationship with Riata Management, LLC (“Riata”), an entity owned by Mr. Mitchell and his wife. Our initial arrangements with Riata included an equity investment into us, the replacement of our farm-in partner in both of our Moroccan properties, the extension of a short term credit facility to us to repay our outstanding short-term debt, and the provision of technical and management expertise to assist us in successfully developing and expanding our international portfolio of projects.
During the second quarter of 2008, we completed a two-stage private placement issuing 35,000,000 common shares to Riata TransAtlantic, LLC (“Riata TransAtlantic”), Dalea Partners, LP (“Dalea”) and certain friends and family of Mr. Mitchell, for aggregate gross proceeds of approximately $11.2 million. Mr. Mitchell is a manager of Riata TransAtlantic, and Mr. Mitchell also owns and controls Dalea. We used the net proceeds to pay off all of our short-term debt, to fund international exploration activities and for general corporate purposes. Longe Energy Limited (“Longe”), an entity that was indirectly owned by Mr. Mitchell, his wife and children, replaced our prior farm-in partner in our Moroccan properties. In addition, Mr. Mitchell and Matthew McCann, general counsel for Riata, were designated by Riata and elected to our board of directors in connection with the private placement. Mr. Mitchell serves as chairman of our board of directors, and Mr. McCann also serves as our chief executive officer.
In the third quarter of 2008, we changed our operating strategy from a prospect generator to a vertically integrated project developer. To execute this new strategy, in December 2008, we acquired 100% of the issued and outstanding shares of Longe from Longfellow Energy, LP (“Longfellow”), an entity indirectly owned by Mr. Mitchell, his wife and children, in consideration for the issuance of 39,583,333 common shares and 10,000,000 common share purchase warrants. Concurrently, we issued 35,416,667 common shares in a private placement with Dalea, Riata TransAtlantic, Mr. McCann and other purchasers that have business or familial relationships with Mr. Mitchell, for gross proceeds of $42.5 million. Longe owned interests in our Moroccan properties and four drilling rigs, as well as associated service equipment, tubulars and supplies. 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”), an entity owned 85% by Dalea, at Viking’s cost.
We anticipate 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 timing for development of our properties, thereby providing a competitive advantage. Because the availability of drilling rigs and service equipment is limited in Turkey, Morocco and Romania, we also anticipate that ownership of our own drilling rigs and service equipment will create opportunities to increase acreage in each country in which we operate by drilling to earn interests in existing third party licenses. When the rigs and equipment are not operating on our properties, we expect to use them to provide drilling and oilfield services to third parties, creating additional opportunities.
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Incremental Acquisition. In the first quarter of 2009, we acquired Incremental Petroleum Limited (“Incremental”) through our wholly-owned subsidiary, TransAtlantic Australia Pty. Ltd. (“TransAtlantic Australia”). We announced our intention to make an all cash takeover offer to acquire all of the outstanding shares of Incremental in the fourth quarter of 2008. The offer expired on March 6, 2009 and Incremental delisted from the Australian Stock Exchange on March 26, 2009. At March 31, 2009, we owned approximately 96% of Incremental’s outstanding common shares. We completed the acquisition of the remaining 4% of Incremental’s outstanding common shares through an Australian statutory procedure on April 20, 2009. The acquisition of Incremental expanded our rig fleet and increased our workforce of highly qualified field staff, engineers and geologists in Turkey, one of our target countries. Through the Incremental acquisition, we acquired:
| • | 100% working interest in a production lease in the Selmo oil field in southeastern Turkey. Situated on the northern edge of the Zagros fold belt of Iran and Iraq in southeast Turkey, Selmo has produced approximately 85 million barrels of oil to date. For 2009, our net production of crude oil in the Selmo field, after royalties, was 411,964 barrels of crude oil at an average rate of 1,369 barrels per day. We plan on drilling 18 or more development wells at Selmo during 2010. |
| • | 55% working interest in an exploration license in the Edirne gas field located in the Thrace Basin in northwestern Turkey. We completed construction of a gathering system and facilities in the Thrace Basin necessary to begin selling natural gas from our discoveries in the Edirne gas field, and we expect our initial eight wells in the Edirne field to come online in April 2010. We expect our net production to exceed 5.5 million cubic feet of natural gas per day starting in the second quarter of 2010. We plan to drill 16 or more wells on the Edirne license during the remainder of 2010. |
| • | 100% working interest in License 4262, covering 2,805 acres in southeastern Turkey, a 100% working interest in four exploration licenses in Midyat in southeastern Turkey covering approximately 460,400 acres and a 50% working interest in eight exploration licenses in the Tuz Golu Basin in central Turkey covering approximately 870,000 acres. |
| • | farm-outs on the McFlurrey project and the South East Kettleman North Dome oil field and a small non-operated working interest in the Kettlemen Middle Dome Unit. In February 2010, we resigned as operator of the McFlurrey and South East Kettleman North Dome farm-outs. See “Item 2. Properties—United States.” |
Sale of Common Shares. 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 was used to fund our exploration and development activities and for general corporate purposes. In connection with these offerings, we entered into a registration rights agreement providing for the registration of up to 98,377,300 common shares issued in these offerings, of which 55,544,300 shares have been registered for resale under the Securities Act of 1933, as amended (the “Securities Act”).
EOT Acquisition. On July 23, 2009, our wholly-owned subsidiary, TransAtlantic Worldwide Ltd., acquired all of the ownership interests in Energy Operations Turkey, LLC (“EOT”) for total consideration of $7.8 million. EOT’s assets include a 50% interest in License 3118, interests in ten other exploration licenses in southern and southeastern Turkey, inventory and seismic data. License 3118, which covers approximately 96,000 acres (389 square kilometers), is located near the city of Diyarbakir in southeastern Turkey. In April and September 2008, EOT participated in the drilling of the Arpatepe-1 and Arpatepe-2 wells on License 3118, which represent Turkey’s first and second economic discoveries of crude oil from deeper, onshore Paleozoic sandstone formations. The wells, which flowed naturally and were not stimulated, had initial production rates of approximately 440 and 190 gross barrels of oil per day, respectively, from limited perforations. In 2009, our net production of crude oil in the Arpatepe field, after royalties, was 5,107 barrels of crude oil at an average rate of 33 barrels per day. In early March 2010, we acidized the Arpatepe-1 well to clean up perforations and eliminate damage incurred during the initial completion in the Bedinan sandstone. The well is currently flowing at an average rate of approximately 500 gross barrels of oil per day.
Continuance to Bermuda. Effective October 1, 2009, we continued to the jurisdiction of Bermuda under the Companies Act 1981 of Bermuda from the Province of Alberta and changed our name from TransAtlantic Petroleum Company to TransAtlantic Petroleum Ltd. Our shareholders approved the continuance by a special resolution at a special meeting of shareholders held on July 14, 2009. In connection with the continuance, each of our common shares became and remained a common share of TransAtlantic Petroleum Ltd., and we became subject to the laws of Bermuda as if we had originally been incorporated under the Companies Act 1981 of Bermuda.
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Offering of Common Shares. 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 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 intend to use the net proceeds from these offerings for our 2010 capital expenditure program and for general corporate purposes. In connection with these offerings, we entered into a registration rights agreement providing for the registration of up to 48,298,790 common shares issued in these offerings, of which 42,838,451 shares have been registered for resale under the Securities Act.
Credit Facility. On December 21, 2009, our wholly-owned subsidiaries, DMLP, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd. (“TEMI”), Talon Exploration, Ltd. and TransAtlantic Turkey, Ltd. (collectively, the “Borrowers”) entered into a three year senior secured credit facility with Standard Bank Plc and BNP Paribas (Suisse) SA. The credit facility is guaranteed by us and each of Incremental Petroleum (Selmo) Pty. Ltd., TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (collectively, the “Guarantors”). The 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 DMLP, Ltd., Talon Exploration, Ltd., TEMI and TransAtlantic Turkey, Ltd.; and (iv) substantially all of the present and future assets of the Borrowers. The initial borrowing base under the credit facility is $30 million, subject to redetermination from time to time. Loans under the credit facility will accrue interest at a rate of three months LIBOR plus 6.25% per annum. We intend to use the credit facility to finance a portion of the development of our oil and gas properties in Turkey, acquisitions and for general corporate and working capital purposes. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Senior Secured Credit Facility.”
Current Activities. Our current activities are focused on integrating the acquisitions of Incremental and EOT, developing our existing oil and gas properties in Turkey, Morocco and Romania, increasing our portfolio of properties in Turkey, and expanding our drilling and other oilfield services to more rapidly drill and develop our oil and gas properties. Our success will depend in part on discovering hydrocarbons in commercial quantities and then bringing these discoveries into production. As of March 15, 2010, we were producing an aggregate of approximately 2,500 gross barrels of oil per day from the Selmo and Arpatepe oil fields and were engaged in the following drilling and exploration activities:
Turkey
| • | Drilling the S-61 development well on the Selmo oil field |
| • | Participating in the drilling of the Arpatepe-3 well on License 3118 |
| • | Participating in the drilling of the Pinarbarsi-1 well in southeastern Turkey |
| • | Drilling the Yolboyu-1 well on the Edirne gas field |
| • | Re-entering and deepening the Goksu-1 well on License 4174 |
| • | Connecting our gas gathering facility to a pipeline to transport Edirne gas field production to market |
| • | Increasing crude oil production at the Selmo and Arpatepe oil fields through workovers and stimulation of existing wells |
Morocco
| • | Drilling the HKE-1 exploratory well on the Ouezzane-Tissa permits |
| • | Preparing to drill the BTK-1 exploratory well on the Tselfat permit |
Romania
| • | Evaluating the re-development wells on the Vanatori and Marsa licenses |
| • | Testing two exploratory wells on the Sud Craiova license |
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Planned 2010 Activities. Capital expenditures for 2010 are expected to range between $135 million and $150 million. Our projected 2010 capital budget is subject to change. We currently plan to execute on the following drilling and exploration activities in 2010:
Turkey
| • | Drill 18 or more development wells on the Selmo oil field, including 1 well to test deeper horizons and 1 salt water disposal well. We are currently drilling the third of these development wells for 2010, the S-61 well (100% working interest) |
| • | Drill or participate in the drilling of 6 or more appraisal and exploration wells on the Arpatepe oil field in addition to the Arpatepe-3 well currently being drilled by the operator of this field (50% working interest) |
| • | Drill 16 or more appraisal and exploration wells in addition to the three wells drilled this year on the Edirne gas field (55% working interest) |
| • | Participate in the drilling of 2 or more exploration wells in southeastern Turkey, one of which is currently being drilled by the operator (50% working interest) |
| • | Drill 5 exploration wells on other licenses |
Morocco
| • | Complete drilling and testing of the HKE-1 well on the Ouezzane-Tissa permits (50% working interest) |
| • | Drill another exploratory well on the Ouezzane-Tissa permits (50% working interest) |
| • | Drill the BTK-1 exploratory well on the Tselfat permit (100% working interest) |
| • | Drill 2 additional exploratory wells on the Tselfat permit (100% working interest) |
| • | Drill 1 exploratory well on the Asilah permits (50% working interest) |
| • | Drill 1 exploratory well on the Guercif permits (80% working interest) |
Romania
| • | Drill 1 appraisal well on the Izvoru license (100% working interest) |
| • | Drill up to 3 exploration wells on the Sud Craiova license (50% working interest) |
Drilling Services. As of March 15, 2010, we own 5 drilling rigs that are located in Turkey and 2 drilling rigs that are located in Morocco. We also manage 2 drilling rigs in Turkey for Viking pursuant to a management services agreement. We are in the process of expanding our drilling services activities, particularly in Turkey, to include products and services used to drill and evaluate oil and natural gas wells, consulting services used in the analysis of oil and gas reservoirs and equipment and services used from the completion phase through the productive life of oil and natural gas wells. To support these services, we are in the process of establishing a wireline division and a stimulation division. We have already established a seismic division and a cementing division, and the seismic division has already commenced third party work in Turkey. We have:
| • | Expanded our seismic acquisition services by adding a second crew and will add 3D seismic capabilities to both crews |
| • | Begun constructing all of our drilling locations in Turkey and Morocco using our own equipment |
| • | Added one workover rig and recently purchased the I-14 drilling rig for use in Turkey |
| • | Contracted to manage two 2,000 horsepower drilling rigs that have been shipped to Turkey |
| • | Purchased wireline equipment for establishing a wireline division |
| • | Formed a cementing division, which is now fully operational |
| • | Begun establishing a pressure pumping and fracture stimulation division |
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Exploration and Production
Turkey. We began 2009 with interests in twelve onshore exploration licenses in Turkey. As of March 15, 2010, we held interests in 33 onshore exploration licenses and one onshore production lease covering a total of 3.36 million gross acres (2.70 million net acres) in Turkey.
Through the Incremental acquisition in March 2009, we acquired a 100% working interest in a production lease in the Selmo oil field in southeastern Turkey. For 2009, our net production of crude oil in the Selmo field, after royalties, was 411,964 barrels of crude oil at an average rate of 1,369 barrels per day. Substantially all of our crude oil production is currently concentrated in the Selmo field. Türkiye Petrolleri Anonim Ortaklığı (“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 have drilled six wells in the Selmo field, four of which are now in production. We plan a continuous drilling program on the Selmo oil field throughout 2010.
We also acquired a 55% interest in an exploration license in the Edirne gas field in the Thrace Basin on which there have been drilled eight successful shallow gas wells. In 2009, we drilled and completed two wells and successfully completed two other wells on the Edirne license. We completed 90% of a 90 square kilometer 3D seismic survey over the western portion of the Edirne license, and we expect to complete the remainder of the survey in the second quarter of 2010. In addition, we completed construction of a gathering system and facilities in the Thrace Basin necessary to begin selling natural gas from our discoveries in the Edirne gas field. In December 2009, we entered into a five-year gas sales agreement pursuant to which AKSA Dogolgaz Toptan Satis A.Ş. (“AKSA”), a natural gas distributor in Turkey, agreed to purchase all of our gas production from the Edirne field. We will sell the gas at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAS Petroleum Pipeline Corporation (“BOTAS”), the state-owned crude oil and natural gas pipelines and trading company in Turkey. We expect our initial eight wells in the Edirne field to come online in April 2010. We expect our net production to exceed 5.5 million cubic feet of natural gas per day starting in the second quarter of 2010. We are currently drilling our third well in 2010 at Edirne and plan to drill an additional 16 or more wells during the remainder of the year.
With the acquisition of Incremental, we also acquired:
| • | 100% working interest in License 4262 in southeastern Turkey. We drilled the Atesler well on License 4262 to a depth of 10,851 feet. We tested the Atesler well in early August 2009 and determined that the well was non-commercial. The Atesler well has been plugged and abandoned. |
| • | 100% working interest in four exploration licenses located in Midyat in southeastern Turkey. We recently conducted a gravity survey over the Midyat licenses to assist us in identifying prospective areas. |
| • | 50% working interest in eight exploration licenses in the Tuz Golu Basin. These licenses are in a large, relatively unexplored basin south of Ankara. In February 2010, we acquired the remaining 50% working interest in these licenses in exchange for a 2% overriding royalty interest. We recently conducted field geology studies over the area to facilitate the next phase of exploration on these licenses. |
Through the EOT acquisition in July 2009, we acquired a 50% working interest in License 3118 and interests in ten other exploration licenses in southern and southeastern Turkey. License 3118 is located near the city of Diyarbakir in southeastern Turkey. In April and September 2008, EOT participated in the drilling of the Arpatepe-1 and Arpatepe-2 wells on License 3118, which represent Turkey’s first and second economic discoveries of crude oil from deeper, onshore Paleozoic sandstone formations. The wells, which flowed naturally and were not stimulated, had initial production rates of approximately 440 and 190 gross barrels per day, respectively, from limited perforations. In 2009, our net production of crude oil in the Arpatepe field, after royalties, was 5,107 barrels of crude oil, at an average rate of 33 barrels per day. We are currently participating in the drilling of the Arpatepe-3 well, which the operator commenced drilling in December 2009. In early March 2010, we acidized the Arpatepe-1 well to clean up perforations and eliminate damage incurred during the initial completion in the Bedinan sandstone. The well is currently flowing at an average rate of approximately 500 gross barrels of oil per day.
We also expanded our portfolio of properties in southeastern Turkey through a farm-in agreement and through applying for licenses directly with the Turkish General Directorate for Petroleum Affairs (“GDPA”). In August 2008, we were awarded six licenses by the GDPA in the Malatya area. We paid a party who will be a 10% participant in these licenses cash consideration and agreed that that party would back-in after payout for 10% in the first well to be drilled on these licenses. In April 2009, we farmed-in to an exploration license, License 4325, for cash consideration and the obligation to carry a 10% interest in the first well drilled to earn 90% interest in the license. To date, we have conducted field geology over this license. In January 2010, we acquired two additional licenses in the Malatya area of south-central Turkey. In February 2010, we entered into a farm-in agreement to acquire a 50% interest in an additional license in southeastern Turkey. We reimbursed the operator past costs of $1.5 million and will pay 50% of the cost of the well currently being drilled by the operator, the Pinarbarsi-1. We will pay the operator $1.0 million when the well is successfully drilled. In March 2010, we entered into a farm-in agreement to acquire a 50% interest in an additional license in southeastern Turkey. We will drill the Bakuk-101 well to earn the 50% interest in the license. In March 2010, we entered into a farm-in agreement to acquire a 50% interest in five 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.
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In July 2007, we were awarded three additional onshore exploration licenses, Blocks 4268, 4269 and 4270, all of which are in southeastern Turkey on the border with Iraq. These licenses will also involve a work program, including technical studies, reprocessing of data and contingent plans for drilling wells. We are the operator and 100% working interest owner of these licenses. Our work program on these blocks has been delayed due to security concerns.
In June 2006, we were awarded three onshore exploration licenses in southeastern Turkey. Two of the licenses, Block 4173 and Block 4174, are located near Bismil on the Tigris River. In March 2008, we farmed-out 75% of our working interest in Blocks 4173 and 4174 to EOT. In exchange for a 75% interest in the exploration licenses, EOT drilled an exploration well at its cost to test the Bedinan Ordivician formation (approximately 3,700 meters) on one of the licenses. The well encountered mechanical difficulties shortly after encountering the target formation and was abandoned. Through the acquisition of EOT in July 2009, we are the operator and 100% working interest owner of Blocks 4173 and 4174. We have re-entered the Goksu-1 well on Block 4174 and plan to deepen the well by approximately 3,000 feet.
The third license, Block 4175, is located near Cizre about 60 kilometers from the Iraq border. We have conducted an initial work program of detailed fieldwork and geochemical analysis on this license. In the first quarter of 2009, we completed a 105 kilometers 2D seismic shoot over the license. We plan to drill the initial well on Block 4175 in the first half of 2010. We are the operator and 100% working interest owner of Block 4175.
In December 2008, we leased an equipment yard in Diyarbakir and started shipping tubulars, drilling equipment and supplies into the country in support of our planned drilling activities. With the acquisition of Incremental, we acquired a second yard at Selmo and have since purchased acreage and started an equipment yard on the Edirne license to support drilling activities in the Thrace Basin. We currently own five drilling rigs located in Turkey and manage two other drilling rigs for Viking in Turkey.
Morocco. We own interests in ten onshore exploration permits in northern Morocco. Our Tselfat exploration permit was awarded to us in May 2006, and we are the operator and 100% working interest owner in the Tselfat permit. As part of our Tselfat work program, in the second quarter of 2008, we completed a 3D seismic survey over the Brou Draa and Haricha fields. In 2009, we drilled the HR-33bis well in the Haricha field on the Tselfat exploration permit to help assess whether there is the opportunity for redevelopment of the previously produced but abandoned Haricha field. We plan to complete our testing of this well in the second quarter of 2010. We plan to begin drilling one deeper exploration well, the BTK-1, by the end of the second quarter of 2010 and plan to drill two additional shallow exploration wells on the Tselfat permit in 2010.
In July 2008, we agreed to farm-in to five Ouezzane-Tissa and two Asilah exploration permits held by Direct Petroleum Morocco, Inc. and Anschutz Morocco Corporation (collectively, “Direct”) in northern Morocco. Under the farm-in agreement, we will earn a 50% interest in the Ouezzane-Tissa and Asilah exploration permits by carrying Direct for 100% of the costs of drilling three wells on the Ouezzane-Tissa and Asilah permits. If one of the three wells is a commercial success, as defined in the farm-in agreement, then we would carry Direct in the drilling of a fourth well. We became the operator of the Ouezzane-Tissa and Asilah exploration permits after receiving government approval. We drilled our first well on the Ouezzane-Tissa exploration permits, the OZW-1 well. We encountered an extremely high pressure water zone near 9,000 feet which we could not drill through. Accordingly, we have plugged and abandoned this well. We are currently drilling at our cost a second well on the Ouezzane-Tissa exploration permits, the HKE-1 well. Upon completion of this well, we are required under the terms of the farm-in agreement to drill another well on the Ouezzanne-Tissa permits in 2010. On the Asilah permits, we conducted a 2D seismic survey in late 2008 and acquired 200 kilometers of 2D seismic, and in 2009, we acquired an additional approximately 90 kilometers of 2D seismic on the Asilah permits. We are evaluating the data for a planned well on the Asilah permits in 2010.
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. We are committed to drill another well before the end of 2010 and will carry the 20% owner in the Guercif exploration permits in that well. In addition, we replaced our obligation to acquire 300 kilometers of 2D seismic with the obligation to drill another well.
We lease an equipment yard in Meknes, and we currently have two drilling rigs located in Morocco.
Romania. We own interests in four onshore production licenses in Romania. In February 2006, we were awarded the Izvoru, Vanatori and Marsa licenses. We are the operator and 100% working interest owner in the licenses. In 2009, we drilled two wells on the Izvoru license, two wells on the Vanatori license and one well on the Marsa license. Both wells on the Izvoru license were unsuccessful and will be plugged and abandoned as dry holes. The first well on the Vanatori license failed to reach total depth and was plugged and abandoned. We skid the rig to drill a second well on the Vanatori license. We are currently evaluating the Marsa well and the second Vanatori well.
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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). At casing point in each well, we and Sterling will each elect whether to proceed to completion and will each bear our proportionate share of completion and infrastructure costs. Sterling will remain the operator of the Sud Craiova license. We began drilling the first of the three exploration wells at our cost on the Sud Craiova license in November 2009. The NG-02 well encountered gas shows and is being tested, and the NG-04 well has been plugged and abandoned because it was non-commercial. The NG-01 well has been drilled and is awaiting testing.
We lease an equipment yard in Izvoru. We do not own any drilling rigs in Romania.
United States. With the acquisition of Incremental, 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. Incremental acquired these projects in May 2008.
The McFlurrey farm-out covers 9,100 net acres of leasehold in Kings, Fresno and Kerns counties in California. We drilled two wells in March and April 2009, paying 100% of the cost. We tested the first well and determined it was non-commercial. Based on these results, we did not test the second well. The South East Kettleman North Dome farm-out covers 1,155 net acres of leasehold in Kings County, northeast of the McFlurrey farm-out. 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. In addition, we agreed to pay 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 estimate our costs for plugging, abandonment and restoration of the two wells will be approximately $65,000.
We own a non-operated working interest in the Kettleman Middle Dome Unit located in Kings County California. This unit produces approximately 125 gross barrels 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. The operator plans to recomplete two of the five wells located in the unit. Plans for further development will be addressed after the results of the two recompletions are evaluated. We are currently seeking purchasers for our interest in the Kettleman Middle Dome Unit.
Nigeria. We originally acquired an interest in the OML 109 offshore Nigerian concession in 1992. In June 2005, we sold our Bahamian subsidiary which owned the interest in OML 109. We reserved $2.5 million as an abandonment fund, of which $1.8 million was deposited into an escrow fund to address any liabilities and claims relating to our prior operations in Nigeria. Approximately $720,000 of these funds were returned to us in 2007. As of December 31, 2009, the balance of the escrow fund was $240,000. The remaining potential liability to us is for taxes owed for the period January through June 2005, and we expect the remaining escrow amount to be sufficient to cover any potential tax liabilities.
Principal Capital Expenditures and Divestitures
The following table sets forth our principal capital expenditures during 2009 (in thousands of dollars):
| Expenditure Type |
Fiscal Year Ended December 31, 2009 | ||
| Oil and gas properties |
$ | 14,238 | |
| Drilling services and other equipment |
52,377 | ||
| Subtotal |
66,615 | ||
| Acquisition of Incremental Petroleum Limited, net of cash received |
51,877 | ||
| Acquisition of Energy Operations Turkey, LLC, net of cash received |
7,692 | ||
| Total capital expenditures and divestitures |
$ | 126,184 | |
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There were no capital divestitures during 2009.
Principal Markets
In accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, Segment Reporting (“ASC 280”) (formerly Statement of Financial Accounting Standards (“SFAS”) No. 131, Disclosures about Segments of an Enterprise and Related Information), we have two reportable operating segments, exploration and production of oil and natural gas (“E&P”) and drilling services, within three reportable geographic segments: Romania, Turkey and Morocco. For financial information about our operating segments and geographic areas, refer to “Note 13—Segment information” to our consolidated financial statements.
Customers
During 2009, 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 2009, we sold $27.2 million of crude oil to TPAO and TUPRAS, representing 98.2% of our total revenues. In December 2009, we entered into a five year gas sales agreement pursuant to which AKSA, a natural gas distributor in Turkey, agreed to purchase all of our gas production from the Edirne field. We will sell the gas at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAS. We expect gas sales to commence in April 2010. The loss of any of these customers could have a material adverse effect on us.
Competition
We operate in the highly competitive areas of oil and gas exploration, development 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 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.
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 standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters. Compliance with these requirements 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, border disputes, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs; |
| • | 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 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 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 may 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 March 15, 2010, we employed approximately 566 people and, through a service agreement with Longfellow, Viking, Longe, MedOil Supply, LLC and Riata, contracted for the services of approximately 51 additional people. As of March 15, 2010, approximately 65 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 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 Companies Act 1981 of Bermuda under the name “TransAtlantic Petroleum Ltd.”
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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.
| Item 1A. | Risk Factors. |
Risks Related to Our Business
We have a history of losses and may never be profitable.
We have incurred substantial losses in prior years. During 2009, our comprehensive loss was approximately $52.5 million and we used $50.8 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.
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We will require significant capital to continue our exploration and development activities beyond December 2010.
We recently expanded our planned 2010 drilling program. We may not have sufficient funds to conduct our exploration and development activities beyond December 2010. If we are unable to finance our planned exploration and development activities on acceptable terms or at all, our 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 Romania, Morocco and Turkey; |
| • | 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. |
We might not be able to obtain necessary financing on acceptable terms, or at all. If sufficient capital resources are not available, we might be forced to 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.
Difficulties in combining the operations of Incremental and EOT 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 Incremental and EOT. The acquisitions are expected to provide substantial benefits, including among other things, expanding our rig fleet and increasing our workforce of highly qualified field staff, engineers and geologists in Turkey, one of our target countries. Achieving such expected benefits is subject to a number of uncertainties, including:
| • | whether the operations of Incremental and EOT 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 |
| • | intensified 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, 2009 related to our acquisition and integration of Incremental. 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.
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 secured credit facility contains 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, Plc and BNP Paribas (Suisse) SA may adversely affect our ability to finance future operations or capital needs or to engage in other business activities. Our credit facility contains various covenants that restrict our ability to, among other things:
| • | incur additional debt; |
| • | create liens; |
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| • | 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; or |
| • | enter into any merger, consolidation or amalgamation. |
In addition, the credit facility requires us to maintain specified financial ratios and tests and to maintain commodity price hedge agreements, as described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Senior Secured Credit Facility.” 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 credit facility and could result in a default under the credit facility.
An event of default under the credit facility includes, among other events, breach of certain covenants and obligations, our bankruptcy or insolvency, and failure to meet the required financial tests and ratios. In the event of our bankruptcy or insolvency, all amounts payable under the credit facility become immediately due and payable. In the event of any other default under our 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 credit facility. In addition, in the event of a default under the credit facility, which is secured by substantially all of the assets of the Borrowers, the lenders could proceed to foreclose against the assets securing such obligations. In the event of an acceleration of our indebtedness or a foreclosure on all or substantially all of the assets of the Borrowers, our business, financial condition and results of operations may be materially and adversely affected.
Global financial conditions have been subject to increased volatility. This may impact our ability to obtain equity, debt or bank financing in the future and may adversely impact our operations.
Current global financial conditions have been subject to increased volatility and numerous commercial and financial enterprises have either gone into bankruptcy or creditor protection or have had to be rescued by governmental authorities. Access to public financing has been negatively impacted by sub-prime mortgage defaults, the liquidity crisis affecting the asset-backed commercial paper and collateralized debt obligation markets, massive investment losses by banks with resultant recapitalization efforts and deterioration in the global economy. 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. If these increased levels of volatility and market turmoil continue, our operations could be adversely impacted and the trading price of our securities could continue to be adversely affected.
Banks have been adversely affected by the worldwide economic 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.
We depend on a limited number of key personnel who would be difficult to replace.
We depend on the performance of Mr. Mitchell, Scott C. Larsen, president, Matthew McCann, chief executive officer, and Gary Mize, chief operating officer. The loss of any of Messrs. Mitchell, Larsen, 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.
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Our contract drilling operations will depend on the level of activity in the oil and natural gas exploration and production industry.
Our contract drilling operations 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 that activity. Because oil and natural gas prices are volatile, the level of exploration and production activity can also be volatile. Lower oil and natural gas prices may depress our level of exploration and production activity.
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 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 limited current production.
We have limited current production. Substantially all of our crude oil production is 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. In addition, substantially all of our natural gas production will be concentrated in the Edirne field when our wells in the Edirne field come online, which we expect to occur in April 2010. AKSA, a natural gas distributor in Turkey, has agreed to purchase all of our gas production from the Edirne field. If any 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 March 15, 2010, approximately 65 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 Industries (KIPLAS) and the Petroleum, Chemical and Rubber Workers Union of Turkey (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.
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Our operations are primarily conducted in Morocco, Romania and Turkey 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, border disputes, renegotiation or modification of existing contracts, and import, export and transportation regulations and tariffs; |
| • | 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 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 Turkey could adversely affect our business.
We currently derive substantially all of our revenue from the Selmo oil field in southeastern Turkey. In addition, we have plans for substantial exploration activities in Turkey and expect to begin producing gas from the Thrace Basin in northwestern Turkey in April 2010. Recently, areas of Turkey have 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.
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We could be assessed for Canadian federal tax as a result of our recent continuance under the Companies Act 1981 of Bermuda.
For Canadian tax purposes, we are deemed, immediately before the completion of our continuance under the Companies Act 1981 of Bermuda, 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, will determine 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, our final determination of the fair market value of our property may be higher than currently anticipated or the Canada Revenue Agency (“CRA”) may not accept our determination of the fair market value of our property. In the event that our final determination or CRA’s determination of fair market value is significantly higher than currently anticipated 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.
Substantially all of our 2009 revenue was generated from the sale of oil produced from the Selmo oil field in Turkey. Our subsidiary, Incremental, 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.
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 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 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 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 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.
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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 and EOT 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 flows 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.
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.
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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.
We are subject to complex laws and regulations, including environmental regulations, which can have a material adverse effect on our cost, manner or feasibility of doing business.
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, including complex tax laws and environmental laws and regulations, and requires various permits and approvals from various governmental agencies. If these permits are not issued or unfavorable restrictions or conditions are imposed on our 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 permits, might result in the suspension or termination of operations and subject us to penalties. Our costs to comply with these numerous laws, regulations and permits are significant. Further, these laws and regulations could change in ways that substantially increase our costs and associated liabilities. Existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations may harm our business, results of operations and financial condition.
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.
We do not intend to insure against all risks. Our natural gas and oil exploration and production activities 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.
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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 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 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 development plans 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.
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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 licenses 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, 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.
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 March 15, 2010, Mr. Mitchell beneficially owned approximately 48.7% 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.
We have registered for resale 98,382,751 common shares pursuant to two effective registration statements under the Securities Act. 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, 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:
| • | the global economic crisis and general economic conditions in Canada, the United States, Romania, Morocco, Turkey 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; |
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| • | 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; |
| • | 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.
| Item 1B. | Unresolved Staff Comments. |
None.
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| Item 2. | Properties. |
Turkey
General. We began 2009 with interests in twelve onshore exploration licenses in Turkey. As of March 15, 2010, we held interests in 33 onshore exploration licenses and one onshore production lease covering a total of 3.36 million gross acres (2.70 million net acres) in Turkey. The following is a map showing our interests in Turkey:
Selmo (Production Lease 829). Through the Incremental acquisition, we acquired a production lease in the Selmo oil field on Block 829. The lease covers 8,886 acres (36 square kilometers) in southeastern Turkey. We have drilled the S-51, S-52, S-53, S-54, S-58 and S-62 wells in the Selmo field, four of which are now in production. We are currently drilling the S-61 well. We are the operator and 100% working interest owner in the Selmo production lease. For 2009, our net production of crude oil in the Selmo field, after royalties, was 411,964 barrels of crude oil, at an average rate of 1,369 barrels per day. The lease is set to expire in June 2015 but can be renewed for an additional ten-year period based on continued production.
Edirne (License 3839). Through the Incremental acquisition, we acquired an interest in an exploration license in the Edirne gas field on Block 3839, covering 119,125 acres (482 square kilometers) in the Thrace Basin of northwestern Turkey, on which there have been drilled eight successful shallow gas wells. We drilled and completed the Kirmizihoyuk-1 well and the Kusey Ikihoyuk-1 well on the Edirne license and successfully completed two other wells on the license in 2009. We completed 90% of a 90 square kilometer 3D seismic survey over the western portion of the Edirne license, and we expect to complete the remainder of the survey in the second quarter of 2010. In addition, we completed construction of a gathering system and facilities in the Thrace Basin necessary to begin selling natural gas from our discoveries in the Edirne gas field. In December 2009, we entered into a five-year gas sales agreement pursuant to which AKSA, a natural gas distributor in Turkey, agreed to purchase all of our gas production from the Edirne field. We will sell the gas at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAS. We expect our initial eight wells in the Edirne field to come online in April 2010. We expect our net production to exceed 5.5 million cubic feet of natural gas per day starting in the second quarter of 2010. We have drilled, logged and cased two wells in 2010 and are currently drilling our third well. Upon completion of the third well, we plan to drill 16 or more additional wells on the Edirne license during the remainder of 2010. We are the operator and 55% working interest owner in the Edirne license.
Arpatepe (License 3118). Through the EOT acquisition, we acquired a 50% non-operated working interest in Block 3118, which covers approximately 96,000 acres (389 square kilometers) near the city of Diyarbakir in southeastern Turkey. In April and September 2008, EOT participated in the drilling of the Arpatepe-1 and Arpatepe-2 wells on Block 3118, which represent Turkey’s first and second economic discoveries of crude oil from deeper, onshore Paleozoic sandstone formations. The wells, which flowed naturally and were not stimulated, had initial production rates of approximately 440 and 190 gross barrels per day, respectively, from limited perforations. For 2009, our net production of crude oil in the Arpatepe field, after royalties, was 5,107 barrels of crude oil, at an average rate of 33 barrels per day. In early March 2010, we acidized the Arpatepe-1 well to clean up perforations and eliminate damage incurred during the initial completion in the Bedinan sandstone. The well is currently flowing at an average rate of approximately 500 gross barrels of oil per day. We are currently participating in the drilling of the Arpatepe-3 well, which the operator commenced drilling in December 2009.
Licenses 4173, 4174 and 4175. In June 2006, we were awarded three onshore exploration licenses in southeastern Turkey. The three licenses together cover a total of 162,762 acres (660 square kilometers) and expire in June 2010.
Two of the licenses, Block 4173 and Block 4174, are located near Bismil on the Tigris River. Our primary target is an under explored Paleozoic play at a depth of approximately 9,800 feet. The work program involves conducting geochemical studies and reprocessing existing 2D seismic data, and based on these results additional 2D seismic may be shot or a well drilled. In March 2008, we farmed-out 75% of our working interest in Blocks 4173 and 4174 to EOT. In exchange for a 75% interest in the exploration licenses, EOT drilled an exploration well at its cost to test the Bedinan Ordivician formation (approximately 3,700 meters) on one of the licenses. The well encountered mechanical difficulties shortly after encountering the target formation and was abandoned. Through the acquisition of EOT in July 2009, we are the operator and 100% working interest owner of Blocks 4173 and 4174. We have re-entered the Goksu-1 well on Block 4174 and plan to deepen it by approximately 3,000 feet.
The third license, Block 4175, is located near Cizre about 60 kilometers from the Iraq border. The target is a deep sub-thrust play similar to the major Iraqi and Iranian Zagros fields to the south. We have conducted an initial work program of detailed fieldwork and geochemical analysis on this license. In the first quarter of 2009, we completed a 105
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kilometers 2D seismic shoot over the license. We plan to drill the initial well on Block 4175 in the first half of 2010. We are the operator and 100% working interest owner of Block 4175.
Hakkari (Licenses 4268, 4269 and 4270). In July 2007, we were awarded three additional onshore exploration licenses, Blocks 4268, 4269 and 4270, all of which are in southeastern Turkey on the border with Iraq. The three licenses cover a total of 334,600 acres (1,354 square kilometers) and expire in June 2010, but can be extended for an additional year by posting a $50,000 bond. These licenses will also involve a work program, including technical studies, reprocessing of data and contingent plans for drilling wells. We are the operator and 100% working interest owner of these licenses. Our work program on these blocks has been delayed due to security concerns.
Malatya (Licenses 4572, 4573, 4574, 4575, 4576, 4577, 4659 and 4660). In August 2008, we were awarded exploration licenses by the GDPA on Blocks 4572, 4573, 4574, 4575, 4576 and 4577 covering an aggregate of 733,901 acres (2,970 square kilometers) in the Malatya area of south-central Turkey. We paid a party who will be a 10% participant in these licenses cash consideration and agreed that that party would back-in after payout for 10% in the first well to be drilled on these licenses. We are the operator and 90% working interest owner of these licenses, which expire in August 2012. In January 2010, we acquired two additional licenses (Licenses 4659 and 4660) in the Malatya area of south-central Turkey.
Tuz Golu and Haymana (Licenses 4310, 4311, 4314, 4315, 4316, 4317, 4342 and 4344). Through the Incremental acquisition, we acquired a 50% working interest in exploration licenses on Blocks 4310, 4311, 4314, 4315, 4316, 4317, 4342 and 4344 covering an aggregate of 870,000 acres (3,521 square kilometers) in the Tuz Golu Basin south of Ankara in central Turkey. These licenses are in a large, relatively unexplored basin and expire in May 2012. In February 2010, we acquired the remaining 50% working interest in these licenses in exchange for a 2% overriding royalty interest. We recently conducted field geology studies over the area to facilitate the next phase of exploration on these licenses. We are the operator and 100% working interest owner in these licenses.
Midyat (Licenses 3969, 3970, 3971 and 3972). Through the Incremental acquisition, we acquired exploration licenses on Blocks 3969, 3970, 3971 and 3972 covering an aggregate of 460,400 acres (1,863 square kilometers) in Midyat in southeastern Turkey. These licenses expire in November 2010. We recently conducted a gravity survey over these licenses to assist us in identifying prospective areas of the licenses. We are the operator and 100% working interest owner in these licenses.
Gurun (License 4325). In April 2009, we farmed-in to an exploration license on Block 4325 for cash consideration and the obligation to carry a 10% interest in the first well drilled to earn 90% interest in the license. To date, we have conducted field geology over this license. Block 4325 covers 122,246 acres (495 square kilometers) in south-central Turkey. We are the operator of the license, which expires in February 2012.
License 4262. Through the Incremental acquisition, we acquired an exploration license on Block 4262, covering 2,805 acres (12 square kilometers) in southeastern Turkey. We drilled the Atesler well on Block 4262 to a depth of 10,851 feet. We tested the Atesler well in early August 2009 and determined that the well was non-commercial. The Atesler well has been plugged and abandoned. We are the operator and 100% working interest owner in this license, which we plan to relinquish upon completion of abandonment and reclamation activities and submission of a final report to the GDPA.
Other. In February 2010, we entered into a farm-in agreement to acquire a 50% interest in a license in southeastern Turkey. We reimbursed the operator past costs of $1.5 million and will pay 50% of the cost of the well currently being drilled by the operator, the Pinarbarsi-1. We will pay the operator $1.0 million when the well is successfully drilled. In March 2010, we entered into a farm-in agreement to acquire a 50% interest in an additional license in southeastern Turkey. We will drill the Bakuk-101 well to earn the 50% interest in the license. In March 2010, we entered into a farm-in agreement to acquire a 50% interest in five licenses in south-central Turkey. To earn the 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. In December 2008, we leased an equipment yard in Diyarbakir and started shipping tubulars, drilling equipment and supplies into the country in support of our planned drilling activities. With the acquisition of Incremental, we acquired a second yard at Selmo and have since purchased acreage and started an equipment yard on the Edirne license to support our Thrace Basin drilling activities. We currently own 5 drilling rigs located in Turkey and manage 2 other drilling rigs for Viking in Turkey.
We had total net proved reserves of 10,426 Mbbl at the Selmo and Arpatepe oil fields and 7,339 MMcf at the Edirne gas field as of December 31, 2009.
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.
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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 covert 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.
Morocco
General. We own interests in ten onshore exploration permits in northern Morocco. The following is a map showing our interests in Morocco:
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 the national oil company of Morocco, Office of National des Hydrocarbures et des Mines (“ONHYM”).
Pursuant to a participation agreement between us (30%), Stratic Energy Corporation (“Stratic”) (20%) and Sphere Petroleum QSC (“Sphere”) (50%), Sphere agreed to bear the entire cost of an initial three-year work program to earn its 50% interest in the two Guercif exploration permits. In addition, Sphere posted a $2 million bank guarantee for the initial work program with the Moroccan government and agreed to reimburse us and Stratic for our respective back costs. In April 2008, Sphere assigned all of its interests in the Guercif participation agreement to Longe in exchange for Longe’s assumption of all of Sphere’s obligations under those agreements. We acquired Longe in December 2008. As a result, we are the operator and 80% working interest owner of the Guercif exploration permits.
The Guercif exploration permits are for an eight-year term divided into three periods, each with a defined work program. Under the initial three-year work program, we have re-entered, logged and tested the MSD-1 well, a well previously drilled in the area, which we completed as a dry hole in the fourth quarter of 2008. The logs and test failed to establish the presence of hydrocarbons. We are committed to drill another well before the end of 2010 and will carry the 20% owner in the Guercif exploration permits in that well. In addition, we replaced our obligation to acquire 300 kilometers of 2D seismic with the obligation to drill another well.
Tselfat. In May 2006, we were awarded the Tselfat exploration permit covering 222,345 acres (900 square kilometers) in
northern Morocco pursuant to a petroleum agreement with ONHYM. Tselfat has three fields, Haricha, Brou Draa and Tselfat, that produced from the early 1920s to 1970s, with limited production continuing into the 1990s. All of the wells are presently abandoned. 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.
In August 2007, we reached an agreement to farm-out 50% of our interest in the Tselfat exploration permit to Sphere. In exchange for an option to acquire 50% of our interest in the Tselfat permit, Sphere agreed to fund the costs to acquire a 3D seismic survey over the Haricha field and northern portion of the Brou Draa field and fund the cost of additional geological studies. Upon the exercise of its option, Sphere agreed to fund the drilling and testing of an exploratory well and replace our bank guarantee deposited with the Moroccan government. In April 2008, Sphere assigned all of its interests in the Tselfat farm-out and option agreement to Longe in exchange for Longe’s assumption of all of Sphere’s obligations under those agreements. We acquired Longe in December 2008. As a result, we have a 100% working interest and operate the Tselfat permit.
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Since the award of the Tselfat exploration permit, we have been collecting, collating, digitizing and reviewing all of the existing well, production, seismic and other data. We have reprocessed some of the 2D seismic that exists over the block. In addition, we shot a 175 square kilometer 3D seismic survey over the Brou Draa and Haricha fields, which was completed in the second quarter of 2008. We drilled the HR-33bis well in the Haricha field on the Tselfat exploration permit to help assess whether there is the opportunity for redevelopment of the previously produced but abandoned Haricha field. We plan to complete our testing of this well in the second quarter of 2010. We plan to begin drilling one deeper exploration well, the BTK-1, by the end of the second quarter of 2010 and plan to drill two additional shallow exploration wells on the Tselfat permit in 2010. We posted a $3.0 million bank guarantee in support of the program, of which $2.0 million has been returned to us.
Ouezzane-Tissa and Asilah. In July 2008, we agreed to farm-in to five Ouezzane-Tissa and two Asilah exploration permits held by Direct in northern Morocco. The Ouezzane-Tissa exploration permits cover a combined area of 2,355,606 acres (9,353 square kilometers). The Asilah exploration permits cover a combined area of 680,578 acres (2,754 square kilometers). Under the farm-in agreement, we will earn a 50% interest in the Ouezzane-Tissa and Asilah exploration permits by carrying Direct for 100% of the costs of drilling three wells on the Ouezzane-Tissa and Asilah permits. If one of the three wells is a commercial success, as defined in the farm-in agreement, then we would carry Direct in the drilling of a fourth well. Longfellow has posted a $25.0 million guaranty of our obligations under the farm-in agreement with Direct. We became the operator of the Ouezzane-Tissa and Asilah exploration permits after receiving government approval. The initial period of the Ouezzane-Tissa permits expire in August 2010. We drilled our first well on the Ouezzane-Tissa exploration permits, the OZW-1 well. We encountered an extremely high pressure water zone near 9,000 feet which we could not drill through and plugged and abandoned the well. We are currently drilling at our cost our second well on the Ouezzane-Tissa exploration permits, the HKE-1 well. Upon completion of this well, we are required under the terms of the farm-in agreement to drill another well on the Ouezzanne-Tissa permits in 2010. In 2009, we extended the Asilah permits into the second period of the exploration permit and reduced the Asilah acreage by approximately 20%. The Asilah permits expire in May 2012. On the Asilah permits, we conducted a 2D seismic survey in late 2008 and recently acquired 200 kilometers of 2D seismic, and in 2009, we acquired an additional approximately 90 kilometers of 2D seismic on the Asilah permits. We are evaluating the data for a planned well on the Asilah permits in 2010.
Other. 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, 2009.
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, Ouezzane-Tissa 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. At Guercif, the discovery bonus at conversion is $500,000 and the one-time production bonuses are as follows: 10,000 Bbls/day—$500,000; 20,000 Bbls/day—$750,000; 30,000 Bbls/day—$1 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 Bcf 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
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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.
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.
Romania
General. We own interests in four onshore production licenses in Romania. The following is a map showing our interests in Romania:
Izvoru, Vanatori and Marsa. In February 2006, we were awarded the Izvoru, Vanatori and Marsa licenses, covering approximately 1,200 acres (5 square kilometers), 780 acres (4 square kilometers) and 188 acres (1 square kilometer), respectively. The fields on the licenses were discovered by the former Romanian national oil company and are all located within 100 kilometers of Romania’s capital, Bucharest. The licenses were awarded to us based upon our commitment to perform certain work programs on each of the respective fields, including shooting seismic and drilling or re-entering wells. There is no current production from any of the licenses. We are the operator and 100% working interest owner of the fields. We entered into petroleum agreements with the Romanian government covering each license, which were finalized in September 2007 and expire in August 2010.
The initial work program includes the drilling of two new wells in the Izvoru field. We shot a 25 square kilometer 3D seismic survey over the Izvoru field in late 2006. We shot a 2D seismic survey over both Vanatori and Marsa fields in late 2006. In 2009, we drilled two wells on the Izvoru license, two wells on the Vanatori license and one well on the Marsa license. Both wells on the Izvoru license were unsuccessful and will be plugged and abandoned as dry holes. The first well on the Vanatori license failed to reach total depth and was plugged and abandoned. We skid the rig to drill a second well on the Vanatori license. We are currently evaluating the Marsa well and the second Vanatori well.
Sud Craiova. In June 2009, we entered into an agreement to farm-in to Sterling’s Sud Craiova Block E III-7, covering approximately 1.5 million acres (6,070 square kilometers) 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). At casing point in each well, we and Sterling will each elect whether to proceed to completion and will each bear our proportionate share of completion and infrastructure costs. Sterling will remain the operator of the Sud Craiova license. We began drilling the first of the three exploration wells at our cost on the Sud Craiova license in November 2009. The NG-02 well encountered gas shows and is being tested, and the NG-04 well has been plugged and abandoned because it was non-commercial. The NG-01 well has been drilled and is awaiting testing.
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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, 2009.
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
With the acquisition of Incremental, 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. Incremental acquired these projects in May 2008.
The McFlurrey farm-out covers 9,100 net acres of leasehold in Kings, Fresno and Kerns counties in California. We drilled two wells in March and April 2009, paying 100% of the cost. We tested the first well and determined it was non-commercial. Based on these results, we did not test the second well. The South East Kettleman North Dome farm-out covers 1,155 net acres of leasehold in Kings County northeast of the McFlurrey farm-out. 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. In addition, we agreed to pay 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 estimate our costs for plugging, abandonment and restoration of the two wells will be approximately $65,000.
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We own a non-operated working interest in the Kettleman Middle Dome Unit located in Kings County California. This unit produces approximately 125 gross barrels 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. The operator plans to recomplete two of the five wells located in the unit. Plans for further development will be addressed after the results of the two recompletions are evaluated. We are currently seeking purchasers for our interest in the Kettleman Middle Dome Unit.
In Oklahoma, we lease two properties, one in Dewey County (128 net acres) and one in McClain County (29 net acres). We participated for a 20% non-operated working interest in a well drilled on the Dewey County property at the end of 2006 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, 2009.
Summary of Oil and Gas Reserves
The following table summarizes our proved reserves in Turkey at December 31, 2009 in accordance with the rules and regulations of the SEC.
| Reserves | ||||||
| Reserves Category |
Oil (Mbbl) |
Natural Gas (Mmcf) |
Total (Mmboe)(1) | |||
| Proved Reserves |
||||||
| Proved Developed |
5,649 | 4,787 | 6,447 | |||
| Proved Undeveloped |
4,777 | 2,552 | 5,202 | |||
| Total Proved |
10,426 | 7,339 | 11,649 | |||
| (1) | The conversion factor we have applied in this Annual Report on Form 10-K is the current convention used by many oil and gas companies, where six thousand cubic feet (“Mcf”) of natural gas is equal to one barrel (“Bbl”) of oil. The barrels of oil equivalent (“Boe”) conversion ratio we use is based on an energy equivalency conversion method primarily applicable at the burner tip. It may not represent a value equivalency at the wellhead and may be misleading, particularly if used in isolation. |
Value of Proved Reserves
The following table shows our estimated future net revenue, present value at 10% (“PV-10”) and total standardized measure of discounted future net cash flows as of December 31, 2009:
| (in thousands) |
|||
| Future net revenue |
$ | 492,596 | |
| Total PV-10(1) |
$ | 312,493 | |
| Total standardized measure of after tax discounted future net cash flows |
$ | 250,009 | |
| (1) | Management believes that the presentation of PV-10, while not a financial measure in accordance with U.S. generally accepted accounting principles (“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 |
$ | 312,493 | |
| Future income taxes |
(94,468) | ||
| Discount of future income taxes at 10% per annum |
31,984 | ||
| Standardized measure |
$ | 250,009 | |
Internal Controls
Management has established, and is responsible for, a number of internal controls designed to provide reasonable assurance that the estimates of proved 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 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 2009. 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 four 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 using the standards contained in Rule 4-10(a) of the SEC’s Regulation S-X. The estimates of proved reserves presented as of December 31, 2009 have been prepared by DeGolyer and MacNaughton, our external engineers. The technical persons responsible for preparing the reserve estimates are independent petroleum engineers and geoscientists that meet 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 our independent petroleum consultants to ensure the integrity, accuracy and timeliness of data furnished to independent petroleum consultants for preparation of their reserves estimates. Our senior reservoir engineer oversees the reserve estimation process. He has a Bachelor of Science degree in Petroleum Engineering from the University of Oklahoma. He has over 10 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.
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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 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 proved reserves estimates prepared by DeGolyer and MacNaughton for the year ended December 31, 2009 included a detailed review of our Arpatepe, Edirne and Selmo properties in Turkey. DeGolyer and MacNaughton determined that our estimates of reserves conform to the guidelines of the SEC, including the 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. Under NI 51-101, proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. Under NI 51-101, reported proved reserves should target, under a specific set of economic conditions, at least a 90% probability that the quantities of oil and natural gas actually recovered will equal or exceed the estimated proved reserves.
Proved Undeveloped Reserves
At December 31, 2009, our estimated proved undeveloped (“PUD”) reserves were approximately 5.20 Mmboe. We had no PUDs at December 31, 2008.
Oil and Gas Production, Production Prices and Production Costs
The following table sets forth our net production of oil (in Bbls) and natural gas (Mcf), after royalties for 2009, 2008 and 2007:
| Net Production | ||||
| Year |
Oil(1) | Natural Gas | ||
| Turkey(2) |
||||
| 2009 |
417,071 | 0 | ||
| 2008 |
0 | 0 | ||
| 2007 |
0 | 0 | ||
| United States |
||||
| 2009 |
798 | 1,429 | ||
| 2008 |
863 | 2,029 | ||
| 2007 |
6,079 | 41,409 | ||
Notes:
| (1) | “Oil” volumes include condensate (light oil) and medium crude oil. |
| (2) | During 2009, our net production of crude oil in the Selmo field, after royalties, was 411,964 Bbls. |
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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 2009, 2008 and 2007:
| 2009 | 2008 | 2007 | ||||
| Turkey |
||||||
| Average Sales Price |
||||||
| Oil ($/Bbl) |
66.05 | — | — | |||
| Natural Gas ($/Mcf) |
— | — | — | |||
| Unit Costs |
||||||
| Production ($/Boe) |
23.53 | — | — | |||
| United States |
||||||
| Average Sales Price |
||||||
| Oil ($/Bbl) |
54.47 | 100.98 | 66.63 | |||
| Natural Gas ($/Mcf) |
5.07 | 11.70 | 5.98 | |||
| Unit Costs |
||||||
| Production ($/Boe) |
43.01 | 60.77 | 89.90 | |||
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 2009, 2008 and 2007:
| Development Wells | Exploratory Wells | ||||||||
| Productive | Dry | Productive | Dry | ||||||
| Morocco |
|||||||||
| 2009 |
0 | 0 | 0 | 1.5 | |||||
| 2008 |
0 | 0 | 0 | 0 | |||||
| 2007 |
0 | 0 | 0 | 0 | |||||
| Turkey |
|||||||||
| 2009 |
5.1 | 0 | 0 | 1 | |||||
| 2008 |
0 | 0 | 0 | 0 | |||||
| 2007 |
0 | 0 | 0 | 0 | |||||
| Romania |
|||||||||
| 2009 |
0 | 3 | 0 | 0.5 | |||||
| 2008 |
0 | 0 | 0 | 0 | |||||
| 2007 |
0 | 0 | 0 | 0 | |||||
| United States |
|||||||||
| 2009 |
0 | 0 | 0 | 1 | |||||
| 2008 |
0 | 0 | 0 | 0 | |||||
| 2007 |
0 | 1 | 0 | 0 | |||||
Current Activities. Our current activities are focused on integrating the acquisitions of Incremental and EOT, developing our existing oil and gas properties in Turkey, Morocco and Romania, increasing our portfolio of properties in Turkey, and expanding our drilling and other oilfield services to more rapidly drill and develop our oil and gas properties. Our success will depend in part on discovering hydrocarbons in commercial quantities and then bringing these discoveries into production. As of March 15, 2010, we were producing an aggregate of approximately 2,500 gross barrels of oil per day from the Selmo and Arpatepe oil fields and were engaged in the following drilling and exploration activities:
Turkey
| • | Drilling the S-61 development well on the Selmo oil field |
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| • | Participating in the drilling of the Arpatepe-3 well on License 3118 |
| • | Participating in the drilling of the Pinarbarsi-1 well in southeastern Turkey |
| • | Drilling the Yolboyu-1 well on the Edirne gas field |
| • | Re-entering and deepening the Goksu-1 well on License 4174 |
| • | Connecting our gas gathering facility to a pipeline to transport Edirne gas field production to market |
| • | Increasing crude oil production at the Selmo and Arpatepe oil fields through workovers and stimulation of existing wells |
Morocco
| • | Drilling the HKE-1 exploratory well on the Ouezzane-Tissa permits |
| • | Preparing to drill the BTK-1 exploratory well on the Tselfat permit |
Romania
| • | Evaluating the re-development wells on the Vanatori and Marsa licenses |
| • | Testing the two exploratory wells on the Sud Craiova license |
As of December 31, 2009, we were in the process of drilling 1 gross well (0.5 net wells) in Morocco and 1 gross well (1 net well) in Turkey.
Planned 2010 Activities. Capital expenditures for 2010 are expected to range between $135 million and $150 million. Our projected 2010 capital budget is subject to change. We currently plan to execute on the following drilling and exploration activities in 2010:
Turkey
| • | Drill 18 or more development wells on the Selmo oil field, including 1 well to test deeper horizons and 1 salt water disposal well. We are currently drilling the third of these development wells for 2010, the S-61 well (100% working interest) |
| • | Drill or participate in the drilling of 6 or more appraisal and exploration wells on the Arpatepe oil field in addition to the Arpatepe-3 well currently being drilled by the operator of this field (50% working interest) |
| • | Drill 16 or more appraisal and exploration wells in addition to the three wells drilled this year on the Edirne gas field (55% working interest) |
| • | Participate in the drilling of 2 or more exploration wells in southeastern Turkey, one of which is currently being drilled by the operator (50% working interest) |
| • | Drill 5 exploration wells on other licenses |
Morocco
| • | Complete drilling and testing of the HKE-1 well on the Ouezzane-Tissa permits (50% working interest) |
| • | Drill another exploratory well on the Ouezzane-Tissa permits (50% working interest) |
| • | Drill the BTK-1 exploratory well on the Tselfat permit (100% working interest) |
| • | Drill 2 additional exploratory wells on the Tselfat permit (100% working interest) |
| • | Drill 1 exploratory well on the Asilah permits (50% working interest) |
| • | Drill 1 exploratory well on the Guercif permits (80% working interest) |
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Romania
| • | Drill 1 appraisal well on the Izvoru license (100% working interest) |
| • | Drill up to 3 exploration wells on the Sud Craiova license (50% working interest) |
Drilling Services. As of March 15, 2010, we own 5 drilling rigs that are located in Turkey and 2 drilling rigs that are located in Morocco. We also manage 2 drilling rigs in Turkey for Viking pursuant to a management services agreement. We are in the process of expanding our drilling services activities, particularly in Turkey, to include products and services used to drill and evaluate oil and natural gas wells, consulting services used in the analysis of oil and gas reservoirs and equipment and services used from the completion phase through the productive life of oil and natural gas wells. To support these services, we are in the process of establishing a wireline division and a stimulation division. We have already established a seismic division and a cementing division and the seismic division has already commenced third party work in Turkey. We have:
| • | Expanded our seismic acquisition services by adding a second crew and will add 3D seismic capabilities to both crews |
| • | Begun constructing all of our drilling locations in Turkey and Morocco using our own equipment |
| • | Added one workover rig and recently purchased the I-14 drilling rig for use in Turkey |
| • | Contracted to manage two 2,000 horsepower drilling rigs that have been shipped to Turkey |
| • | Purchased wireline equipment for establishing a wireline division |
| • | Formed a cementing division, which is now fully operational |
| • | Begun establishing a pressure pumping and fracture stimulation division |
Oil and Gas Properties, Wells, Operations, and Acreage
Productive Wells. The following table sets forth the number of productive wells (wells that are currently producing oil or natural gas or capable of production) in which we held a working interest as of December 31, 2009:
| Oil | Natural Gas | |||||||
| Gross(1) | Net(2) | Gross(1) | Net(2) | |||||
| Turkey |
25 | 24 | 0 | 0 | ||||
| United States |
3 | 0.15 | 1 | 0.2 | ||||
Notes:
| (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, 2009:
| Developed (Acres) | ||||
| Gross(1) | Net(2) | |||
| Turkey |
224,002 | 122,400 | ||
| United States |
2,228 | 131 | ||
| Total |
226,230 | 122,531 | ||
Notes:
| (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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Undeveloped Acreage. The following table sets forth our undeveloped land position as of December 31, 2009:
| Undeveloped (Acres) | ||||
| Gross(1) | Net(2) | |||
| Morocco |
4,083,595 | 2,441,570 | ||
| Romania |
1,444,022 | 723,095 | ||
| Turkey |
2,692,158 | 2,244,924 | ||
| United States |
10,629 | 5,329 | ||
| Total |
8,230,404 | 5,414,918 | ||
Notes:
| (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. |
| Item 3. | Legal Proceedings. |
Incremental has been involved in litigation with persons who claim ownership of a portion of the surface at the Selmo field in Turkey. These cases are being vigorously defended by Incremental 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 Court of First Instance in Turkey with seven title survey certificates dating back to Ottoman times. These villagers were granted a title registration certificate for seven tracts of land. The exact locations of the land were not defined on the certificates. In 2005, these villagers applied to the Kozluk Court of First Instance to enlarge the areas covered by the certificates to 20,284,540 square meters. Neither we nor, to our knowledge, any ministry in the Turkish government received notice of this court proceeding. The Kozluk Court of First Instance granted a ruling that enlarged the area of five of the seven title certificates to 11,533,361 square meters. Almost all of our production wells at the Selmo field lie within this enlarged area.
After receiving the judgment, the villagers sued TEMI in the Kozluk Court of First Instance for compensation from their alleged losses and to compel TEMI to remove all facilities and leave the Selmo field. The Turkish General Directorate of Forestry requested the Kozluk Court of First Instance to reverse its ruling on the enlarged title area. The General Directorate of Cadastre also filed a request for a rehearing on title enlargement. Both the General Directorate of Forestry and the General Directorate of Cadastre joined TEMI as co-defendants in the case. In addition, the General Directorate of Judicial Examination applied to the High Court of Turkey requesting that the court overrule the title enlargement decision.
In 2008, the Kozluk Court of First Instance rejected the General Directorate of Cadastre’s request for a rehearing on title enlargement. This decision was appealed to the High Court. The High Court overruled the title enlargement decision of the Kozluk Court of First Instance and, in March of 2009, reversed the same court’s decision on its rejection of the General Directorate of Cadastre’s rehearing request. In September of 2009, all cases were consolidated at the newly established Kozluk Cadastre Court. Based on the decision of the High Court, there will be a rehearing on the title enlargement. Hearings on the consolidated case are expected to continue through May of 2010.
| Item 4. | Reserved. |
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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 | |||||
| Fiscal year ended December 31, 2008: |
||||||
| First Quarter |
$ | 0.37 | $ | 0.26 | ||
| Second Quarter |
$ | 1.50 | $ | 0.29 | ||
| Third Quarter |
$ | 1.73 | $ | 1.12 | ||
| Fourth Quarter |
$ | 1.45 | $ | 0.70 | ||
| Fiscal year ended December 31, 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 | |||||
| 2009: |
||||||
| Fourth Quarter (from December 8, 2009) |
$ | 3.90 | $ | 2.64 | ||
Common Shares and Dividends
As of March 15, 2010, 303,565,456 common shares were issued and outstanding and held by 314 record holders, including nominee holders such as banks and brokerage firms who hold shares for beneficial owners.
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.
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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 Minster 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, 2009. 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, | |||||||||||||||
| 2009 | 2008 | 2007 | 2006 | 2005 | |||||||||||
| (Amounts in Thousands, Except per Share Amounts) | |||||||||||||||
| Revenue from continuing operations |
$ | 29,269 | $ | 111 | $ | 653 | $ | 1,613 | $ | 1,409 | |||||
| Net loss from continuing operations attributable to TransAtlantic Petroleum Ltd. |
62,146 | 16,475 | 6,318 | 12,285 | 4,647 | ||||||||||
| Comprehensive loss from continuing operations |
52,545 | 16,475 | 6,318 | 12,413 | 4,500 | ||||||||||
| Basic and diluted net loss from continuing operations per common share attributable to TransAtlantic Petroleum Ltd. |
0.29 | 0.25 | 0.15 | 0.32 | 0.14 | ||||||||||
| Basic and diluted net loss from continuing operations per common share |
0.29 | 0.25 | 0.15 | 0.32 | 0.14 | ||||||||||
| Cash dividends per common share |
$ | — | $ | — | $ | — | $ | — | $ | — | |||||
| Basic and diluted weighted average number of shares outstanding |
212,320 | 66,524 | 43,047 | 38,182 | 33,023 | ||||||||||
| Total assets |
307,083 | 81,254 | 5,107 | 15,136 | 17,943 | ||||||||||
| Long term liabilities |
13,341 | 14 | 8 | 1,939 | 556 | ||||||||||
| Stockholders’ equity |
264,607 | 74,940 | 2,070 | 6,518 | 14,952 | ||||||||||
| Capital expenditures |
126,184 | 10,268 | 4,126 | 3,160 | 3,914 | ||||||||||
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| 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, development, exploration, and production of crude oil and natural gas. We hold interests in developed and undeveloped oil and gas properties in Turkey, Morocco, Romania, and California. We own our own drilling rigs and oilfield service equipment, which we use to develop our properties in Turkey and Morocco. In addition, we provide oilfield services and contract drilling services to third parties in Turkey and plan to provide similar services in Morocco.
Executive Overview and Recent Developments
Strategic Transformation. We underwent a strategic transformation during 2008 as a result of a series of transactions with N. Malone Mitchell, 3rd, chairman of our board of directors. Mr. Mitchell founded Riata Energy, Inc. in 1985 and built it into one of the largest privately held oil and gas producers in the United States. In 2006, Mr. Mitchell sold his controlling interest in Riata Energy, Inc. (now Sandridge Energy, Inc.) and founded a group of companies that are primarily focused on investing in international energy opportunities.
In March 2008, we announced that we had entered into a strategic relationship with Riata, an entity owned by Mr. Mitchell and his wife. Our initial arrangements with Riata included an equity investment into us, the replacement of our farm-in partner in both of our Moroccan properties, the extension of a short term credit facility to us to repay our outstanding short-term debt, and the provision of technical and management expertise to assist us in successfully developing and expanding our international portfolio of projects.
During the second quarter of 2008, we completed a two-stage private placement issuing 35,000,000 common shares to Riata TransAtlantic, Dalea and certain friends and family of Mr. Mitchell, for aggregate gross proceeds of approximately $11.2 million. Mr. Mitchell is a manager of Riata TransAtlantic, and Mr. Mitchell also owns and controls Dalea. We used the net proceeds to pay off all of our short-term debt, to fund international exploration activities and for general corporate purposes. Longe, an entity that was indirectly owned by Mr. Mitchell, his wife and children, replaced our prior farm-in partner in our Moroccan properties. In addition, Mr. Mitchell and Matthew McCann, general counsel for Riata, were designated by Riata and elected to our board of directors in connection with the private placement. Mr. Mitchell serves as chairman of our board of directors, and Mr. McCann also serves as our chief executive officer.
In the third quarter of 2008, we changed our operating strategy from a prospect generator to a vertically integrated project developer. To execute this new strategy, in December 2008, we acquired 100% of the issued and outstanding shares of Longe from Longfellow, an entity indirectly owned by Mr. Mitchell, his wife and children, in consideration for the issuance of 39,583,333 common shares and 10,000,000 common share purchase warrants. Concurrently, we issued 35,416,667 common shares in a private placement with Dalea, Riata TransAtlantic, Mr. McCann and other purchasers that have business or familial relationships with Mr. Mitchell, for gross proceeds of $42.5 million. Longe owned interests in our Moroccan properties and four drilling rigs, as well as associated service equipment, tubulars and supplies. Immediately after the Longe acquisition, we purchased an additional $8.3 million in drilling and service equipment, tubulars and supplies from Viking, an entity owned 85% by Dalea, at Viking’s cost.
We anticipate 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 timing for development of our properties, thereby providing a competitive advantage. Because the availability of drilling rigs and service equipment is limited in Turkey, Morocco and Romania, we also anticipate that ownership of our own drilling rigs and service equipment will create opportunities to increase acreage in each country in which we operate by drilling to earn interests in existing third party licenses. When the rigs and equipment are not operating on our properties, we expect to use them to provide drilling and oilfield services to third parties, creating additional opportunities.
Incremental Acquisition. In the first quarter of 2009, we acquired Incremental through our wholly-owned subsidiary, TransAtlantic Australia. We announced our intention to make an all cash takeover offer to acquire all of the outstanding shares of Incremental in the fourth quarter of 2008. The offer expired on March 6, 2009 and Incremental delisted from the Australian Stock Exchange on March 26, 2009. At March 31, 2009, we owned approximately 96% of Incremental’s outstanding common shares. We completed the acquisition of the remaining 4% of Incremental’s outstanding common shares through an Australian statutory procedure on April 20, 2009. The acquisition of Incremental expanded our rig fleet and increased our workforce of highly qualified field staff, engineers and geologists in Turkey, one of our target countries. Through the Incremental acquisition, we acquired:
| • | 100% working interest in a production lease in the Selmo oil field in southeastern Turkey. Situated on the northern edge of the Zagros fold belt of Iran and Iraq in southeast Turkey, Selmo has produced approximately 85 million barrels of oil to date. For 2009, our net production of crude oil in the Selmo field, after royalties, was 411,964 barrels of crude oil at an average rate of 1,369 barrels per day. We plan on drilling 18 or more development wells at Selmo during 2010. |
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| • | 55% working interest in an exploration license in the Edirne gas field located in the Thrace Basin in northwestern Turkey. In 2009, we drilled and completed two wells and successfully completed two other wells on the Edirne license. We completed 90% of a 90 square kilometer 3D seismic survey over the western portion of the Edirne license, and we expect to complete the remainder of the survey in the second quarter of 2010. In addition, we completed construction of a gathering system and facilities in the Thrace Basin necessary to begin selling natural gas from our discoveries in the Edirne gas field. In December 2009, we entered into a five year gas sales agreement pursuant to which AKSA, a natural gas distributor in Turkey, agreed to purchase all of our gas production from the Edirne field. We will sell the gas at a price equal to a 15% discount to the Industrial Interruptible Tariff benchmark set by BOTAS. We expect our initial eight wells in the Edirne field to come online in April 2010. We expect our net production to exceed 5.5 million cubic feet of natural gas per day starting in the second quarter of 2010. We are currently drilling our third well in 2010 at Edirne and plan to drill an additional 16 or more wells during the remainder of 2010. |
| • | 100% working interest in License 4262, covering 2,805 acres in southeastern Turkey, a 100% working interest in four exploration licenses in Midyat in southeastern Turkey covering approximately 460,400 acres and a 50% working interest in eight exploration licenses in the Tuz Golu Basin in central Turkey covering approximately 870,000 acres. |
| • | farm-outs on the McFlurrey project and the South East Kettleman North Dome oil field and a small non-operated working interest in the Kettlemen Middle Dome Unit. In February 2010, we resigned as operator of the McFlurrey and South East Kettleman North Dome farm-outs. See “Item 2. Properties—United States.” |
Sale of Common Shares. 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 was used to fund our exploration and development activities and for general corporate purposes. In connection with these offerings, we entered into a registration rights agreement providing for the registration of up to 98,377,300 common shares issued in these offerings, of which 55,544,300 shares have been registered for resale under the Securities Act.
EOT Acquisition. On July 23, 2009, our wholly-owned subsidiary, TransAtlantic Worldwide Ltd., acquired all of the ownership interests in EOT for total consideration of $7.8 million. EOT’s assets include a 50% interest in License 3118, interests in ten other exploration licenses in southern and southeastern Turkey, inventory and seismic data. License 3118, which covers approximately 96,000 acres (389 square kilometers), is located near the city of Diyarbakir in southeastern Turkey. In April and September 2008, EOT participated in the drilling of the Arpatepe-1 and Arpatepe-2 wells on License 3118, which represent Turkey’s first and second economic discoveries of crude oil from deeper, onshore Paleozoic sandstone formations. The wells, which flowed naturally and were not stimulated, had initial production rates of approximately 440 and 190 gross barrels of oil per day, respectively, from limited perforations. In 2009, our net production of crude oil in the Arpatepe field, after royalties, was 5,107 barrels of crude oil at an average rate of 33 barrels per day. In early March 2010, we acidized the Arpatepe-1 well to clean up perforations and eliminate damage incurred during the initial completion in the Bedinan sandstone. The well is currently flowing at an average rate of approximately 500 gross barrels of oil per day.
Continuance to Bermuda. Effective October 1, 2009, we continued to the jurisdiction of Bermuda under the Companies Act 1981 of Bermuda from the Province of Alberta and changed our name from TransAtlantic Petroleum Corp. to TransAtlantic Petroleum Ltd. Our shareholders approved the continuance by a special resolution at a special meeting of shareholders held on July 14, 2009. In connection with the continuance, each of our common shares became and remained a common share of TransAtlantic Petroleum Ltd., and we became subject to the laws of Bermuda as if we had originally been incorporated under the Companies Act 1981 of Bermuda.
Offering of Common Shares. 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
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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 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 intend to use the net proceeds from these offerings for our 2010 capital expenditure program and for general corporate purposes. In connection with these offerings, we entered into a registration rights agreement providing for the registration of up to 48,298,790 common shares issued in these offerings, of which 42,838,451 shares have been registered for resale under the Securities Act.
Credit Facility. On December 21, 2009, the Borrowers entered into a three year senior secured credit facility with Standard Bank Plc and BNP Paribas (Suisse) SA. The credit facility is guaranteed by the Guarantors. The initial borrowing base under the credit facility is $30 million, subject to redetermination from time to time. Loans under the credit facility will accrue interest at a rate of three month LIBOR plus 6.25% per annum. We intend to use the credit facility to finance a portion of the development of our oil and gas properties in Turkey, acquisitions and for general corporate and working capital purposes. See “Senior Secured Credit Facility.”
Current Activities. Our current activities are focused on integrating the acquisitions of Incremental and EOT, developing our existing oil and gas properties in Turkey, Morocco and Romania, increasing our portfolio of properties in Turkey, and expanding our drilling and other oilfield services to more rapidly drill and develop our oil and gas properties. Our success will depend in part on discovering hydrocarbons in commercial quantities and then bringing these discoveries into production. As of March 15, 2010, we were producing an aggregate of approximately 2,500 gross barrels of oil per day from the Selmo and Arpatepe oil fields and were currently engaged in the following drilling and exploration activities:
Turkey
| • | Drilling the S-61 development well on the Selmo oil field |
| • | Participating in the drilling of the Arpatepe-3 well on License 3118 |
| • | Participating in the drilling of the Pinarbarsi-1 well in southeastern Turkey |
| • | Drilling the Yolboyu-1 well on the Edirne gas field |
| • | Re-entering and deepening the Goksu-1 well on License 4174 |
| • | Connecting our gas gathering facility to a pipeline to transport Edirne gas field production to market |
| • | Increasing crude oil production at the Selmo and Arpatepe oil fields through workovers and stimulation of existing wells |
Morocco
| • | Drilling the HKE-1 exploratory well on the Ouezzane-Tissa permits |
| • | Preparing to drill the BTK-1 exploratory well on the Tselfat permit |
Romania
| • | Evaluating the re-development wells on the Vanatori and Marsa licenses |
| • | Testing two exploratory wells on the Sud Craiova license |
Planned 2010 Activities. Capital expenditures for 2010 are expected to range between $135 million and $150 million. Our projected 2010 capital budget is subject to change. We currently plan to execute on the following drilling and exploration activities in 2010:
Turkey
| • | Drill 18 or more development wells on the Selmo oil field, including 1 well to test deeper horizons and 1 salt water disposal well. We are currently drilling the third of these development wells for 2010, the S-61 well (100% working interest) |
| • | Drill or participate in the drilling of 6 or more appraisal and exploration wells on the Arpatepe oil field in addition to the Arpatepe-3 well currently being drilled by the operator of this field (50% working interest) |
| • | Drill 16 or more appraisal and exploration wells in addition to the three wells drilled this year on the Edirne gas field (55% working interest) |
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| • | Participate in the drilling of 2 or more exploration wells in southeastern Turkey, one of which is currently being drilled by the operator (50% working interest) |
| • | Drill 5 exploration wells on other licenses |
Morocco
| • | Complete drilling and testing of the HKE-1 well on the Ouezzane-Tissa permits (50% working interest) |
| • | Drill another exploratory well on the Ouezzane-Tissa permits (50% working interest) |
| • | Drill the BTK-1 exploratory well on the Tselfat permit (100% working interest) |
| • | Drill 2 additional exploratory wells on the Tselfat permit (100% working interest) |
| • | Drill 1 exploratory well on the Asilah permits (50% working interest) |
| • | Drill 1 exploratory well on the Guercif permits (80% working interest) |
Romania
| • | Drill 1 appraisal well on the Izvoru license (100% working interest) |
| • | Drill up to 3 exploration wells on the Sud Craiova license (50% working interest) |
Drilling Services. As of March 15, 2010, we own 5 drilling rigs that are located in Turkey and 2 drilling rigs that are located in Morocco. We also manage 2 drilling rigs in Turkey for Viking pursuant to a management services agreement. We are in the process of expanding our drilling services activities, particularly in Turkey, to include products and services used to drill and evaluate oil and natural gas wells, consulting services used in the analysis of oil and gas reservoirs and equipment and services used from the completion phase through the productive life of oil and natural gas wells. To support these services, we are in the process of establishing a wireline division and a stimulation division. We have already established a seismic division and a cementing division and the seismic division has already commenced third party work in Turkey. We have:
| • | Expanded our seismic acquisition services by adding a second crew and will add 3D seismic capabilities to both crews |
| • | Begun constructing all of our drilling locations in Turkey and Morocco using our own equipment |
| • | Added one workover rig and recently purchased the I-14 drilling rig for use in Turkey |
| • | Contracted to manage two 2,000 horsepower drilling rigs that have been shipped to Turkey |
| • | Purchased wireline equipment for establishing a wireline division |
| • | Formed a cementing division, which is now fully operational |
| • | Begun establishing a pressure pumping and fracture stimulation division |
Change in Method of Accounting for Oil and Gas Exploration and Development Activities
Effective January 1, 2009, we changed our method of accounting for our oil and gas exploration and development activities from the full cost method to the successful efforts method. In accordance with FASB ASC 250, Accounting Changes and Error Corrections (formerly SFAS No. 154, “Accounting Changes and Error Corrections”) financial information for prior periods has been revised to reflect retrospective application of the successful efforts method, as prescribed by ASC 932, Extractive Activities – Oil and Gas (formerly SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”). Although the full cost method of accounting for oil and gas exploration and development activities continues to be an accepted alternative, the successful efforts method of accounting is the preferred method. We believe the successful efforts method provides a more transparent representation of our results of operations and the ability to assess our investments in oil and gas properties for impairment based on their estimated fair values rather than being required to base valuation on prices and costs as of the balance sheet date.
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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 2—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. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales 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”) (formerly SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets”). 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.
Business Combinations. We follow ASC 805, Business Combinations (“ASC 805”) (formerly SFAS No. 141R, “Business Combinations”), and ASC 810-10-65, Consolidation (“ASC 810-10-65”) (formerly SFAS No. 160, “Non-Controlling Interests in Consolidated Financial Statements”). 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 805 is effective for periods beginning on or after December 15, 2008 and has been applied to the Incremental and EOT acquisitions. 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. ASC 810-10-65 is effective for periods beginning on or after December 15, 2008 and has been applied to the non-controlling interests from the Incremental acquisition.
Per Share Information. Basic per share amounts are calculated using the weighted average common shares outstanding during the year. We use the treasury stock method to determine the dilutive effect of stock options and other dilutive
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instruments. Under the treasury stock method, only “in the money” dilutive instruments impact the diluted calculations in computing diluted earnings per share. Diluted calculations reflect the weighted average incremental common shares that would be issued upon exercise of dilutive options assuming the proceeds would be used to repurchase shares at average market prices for the period.
Foreign Currency Translation. We follow ASC 830, Foreign Currency Matters (“ASC 830”) (formerly SFAS No. 52, “Foreign Currency Translation”). 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. Because the functional currency is now the local currency, translation adjustments will result from the process of translating subsidiary financial statements into the U.S. Dollar reporting currency. Translation adjustments will not be included in determining net income but will be 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. The change in functional currency will have no impact on our actual foreign-based revenues and expenditures in these countries.
Other Recent Accounting Pronouncements
In June 2009, the FASB issued SFAS No. 168, “The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles” (“SFAS 168”). SFAS 168 replaces SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS 162”), and establishes the FASB Accounting Standards Codification (the “Codification”) as the sole source of authoritative U.S. GAAP recognized by the FASB, excluding SEC guidance, to be applied by nongovernmental entities. SFAS 168 is effective for interim and annual periods ending after September 15, 2009. We have revised our references to pre-Codification GAAP and noted no impact on our financial condition or results of operations.
The FASB issued ASC 855, Subsequent Events (“ASC 855”) (formerly SFAS No. 165, “Subsequent Events”), on May 28, 2009. ASC 855 establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Although there is new terminology, the standard is based on the same principles as those that currently exist in the auditing standards.
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.
In December 2008, the SEC adopted release no. 34-59192, “Modernization of Oil and Gas Reporting,” which revised the Regulation S-K and Regulation S-X oil and gas reporting requirements to align them with current industry practices and technological advances. The release revises a number of definitions relating to oil and gas reserves, permits the disclosure in filings with the SEC of probable and possible reserves and permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (i) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (ii) file a report of a third party if a company represents that the third party prepared reserves estimates or conducted a reserves audit, (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices, and (iv) disclose, in narrative form, the status of proved undeveloped reserves and changes in status of these from period to period. The provisions of this release became effective for disclosures in this Annual Report on Form 10-K.
U.S. Operations
In 2007, we decided to exit our U.S. operations and focus on the development of our international properties. As a result of the decision to sell our U.S. operations, we reclassified our U.S. properties as “discontinued operations.” Accordingly, revenues and expenses associated with our U.S. cost center in 2008 and comparative periods were reflected as components of “loss from discontinued operations.” Substantially all of these properties were sold late in 2007 and we recorded a write-down in 2007 of $447,000.
As a result, at December 31, 2008, the net book value of property and equipment in the U.S. was $0. In addition, $14,000 of asset retirement obligations remained at December 31, 2008 relating to property in Oklahoma that was retained.
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In connection with the acquisition of Incremental, we acquired interests in non-operated properties in California. As a result of acquiring these properties in California, previously reported U.S. discontinued operations are now continuing and the results of operations in 2008 and 2007 previously reported as discontinued have been reclassified to operating revenues, costs and expenses.
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 is 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 barrels of crude oil from March 5, 2009, the date of our acquisition of Incremental, through December 31, 2009 at an average rate of 1,402 barrels 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 is the result of the acquisition of Incremental and its producing properties in the first quarter of 2009 and the acquisition of EOT 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 is primarily due to the abandonment of the Atesler-1 well in Turkey, the OZW-1 and HR-33bis 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 is 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 | |||||
| Morocco |
$ | 4,485 | $ | 2,217 | |||
| Romania |
586 | 762 | |||||
| Turkey |
4,594 | 917 | |||||
| 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 write-down and sale of substantially all of our U.S. properties during 2007. The increase is due to the acquisition of Incremental in the first quarter of 2009 and drilling services equipment put in service during 2009.
Comprehensive Loss. The comprehensive loss for the year ended December 31, 2009 was $52.5 million, or $0.29 per share (basic and diluted), compared to a comprehensive loss of $16.5 million, or $0.25 per share (basic and diluted), for the year ended December 31, 2008. The comprehensive loss for 2009 is 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.
Results of Operations – Fiscal Year Ended December 31, 2008 Compared to Fiscal Year Ended December 31, 2007
Revenue. We recognized net crude oil and natural gas sales of $111,000 for the year ended December 31, 2008 from non-operated production in the U.S. This U.S. revenue represented a substantial decrease from sales for the year ended December 31, 2007 of $653,000. The decrease is the result of the sale of our South Gillock and Jarvis Dome properties in the fourth quarter of 2007.
Production Expenses. Lease operating expenses for the year ended December 31, 2008 decreased to $73,000 from $1.2 million as reported for the year ended December 31, 2007. The decrease in lease operating expense is the result of the sale of our South Gillock and Jarvis Dome properties in the fourth quarter of 2007.
Seismic and Other Exploration. Seismic and other exploration costs increased to $7.9 million in 2008 from $0 in 2007 primarily related to two seismic surveys in Morocco and one in Turkey.
International Oil and Gas Activities. During the year ended December 31, 2008, we continued exploration activities in foreign countries including salaries, consulting, legal, accounting, travel and other costs necessary to further our identification and development of business opportunities. Expense reimbursements totaling $832,000 from Longe relating to our Moroccan properties are included in international oil and gas activities during the year ended December 31, 2008. The following table presents expenditures by country:
| For the Year Ended December 31, | ||||||
| (In Thousands) |
2008 | 2007 | ||||
| Morocco |
$ | 2,217 | $ | 745 | ||
| Romania |
762 | 811 | ||||
| Turkey |
917 | 239 | ||||
| Other and unallocated |
1,287 | 517 | ||||
| Total |
$ | 5,183 | $ | 2,312 | ||
General and Administrative Expense. General and administrative costs of $3.6 million in 2008 increased from $2.7 million in 2007, primarily because of increased salaries, contract labor, insurance, legal and professional fees.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization decreased to $53,000 for 2008 as compared with $80,000 in 2007 due to the sale of substantially all of our U.S. properties during 2007. We recorded an impairment charge of $447,000 in 2007. The depreciation expense in 2008 relates to drilling equipment and other property acquired in the acquisition of Longe in December 2008.
Interest and Other Income. Interest and other income increased $98,000 to $338,000 in 2008 as compared to $240,000 in 2007, resulting from increased interest income on higher invested cash balances from the private placement in the second quarter of 2008 and from a $56,000 distribution in the third quarter of 2008 for overpayment of expenses from the former contract operator of our Nigerian operations which were sold in 2005.
Comprehensive Loss. The comprehensive loss for the year ended December 31, 2008 was $16.5 million or $0.25 per share (basic and diluted), compared to a comprehensive loss of $6.3 million or $0.15 per share (basic and diluted) for the year ended
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December 31, 2007. The 2008 loss is primarily composed of general and administrative expense of $3.6 million, seismic and other exploration expenses of $7.9 million and $5.2 million relating to international oil and gas activities.
Capital Expenditures
For the year ended December 31, 2009, we incurred $126.2 million in capital expenditures compared to net capital expenditures of $10.3 million for the year ended December 31, 2008. The increase in capital expenditures is primarily due to acquisitions, increased drilling and exploration activity.
In 2008, we incurred capital expenditures of $10.3 million, including $7.9 million in seismic-related costs which was expensed, $402,000 for wellsite preparation in Romania, $127,000 for wellsite preparation in Morocco, and $1.2 million for wellsite preparation and drilling in Turkey. We also recorded $202,000 for computer and telecommunication equipment in 2008.
In 2010, we expect our capital expenditures will range between $135 million and $150 million. The anticipated expenditures are balanced between development of our Selmo, Thrace Basin, and Arpatepe assets, exploration on potential high impact blocks in Turkey and Morocco, lower risk exploration on the Tselfat permit in Morocco, exploration and seismic acquisition in Turkey and Romania and acquisitions of equipment.
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 2007 were cash and cash equivalents and sale of assets. Our primary sources of liquidity for 2008 and the first three months of 2009 were our cash and cash equivalents and proceeds from the issuance of our common shares. Since the acquisition of Incremental, our primary sources of liquidity have been cash flow from operations from our acquisition of Incremental, which included a 100% working interest in the producing Selmo oil field among other assets, and proceeds from the sale of our common shares. We expect to generate additional cash flow from operations in 2010 when our initial eight wells in the Edirne field come online, which we expect to occur in April 2010. On December 21, 2009, we entered into a senior secured credit facility. See “—Senior Secured Credit Facility.” At December 31, 2009, we had 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 compared to cash and cash equivalents of $30.1 million, no debt, and working capital of $28.9 million at December 31, 2008. Cash used in operating activities during 2009 increased to $50.8 million compared to cash used in operating activities of $13.7 million in 2008, primarily as a result of increased drilling and exploration activity.
Upon the acquisition of Incremental, we became party to a loan which TEMI had entered into (the “TEMI Credit Agreement”) with Turkiye Garanti Bankasi. TEMI borrowed $5.5 million under the TEMI Credit Agreement in order to fund drilling and development activity in the Selmo oil field. The amortizing loan had a fixed interest rate of 7.6% per annum and all outstanding principal and interest under the TEMI Credit Agreement was due August 6, 2010. The TEMI Credit Agreement was repaid in full during December 2009, at which time the TEMI Credit Agreement was terminated. In addition, TEMI entered into unsecured non-interest bearing stand-by credit agreements totaling 1.2 million Turkish Lira (approximately $800,000) with a local bank. At December 31, 2009, there were outstanding borrowings of $95,000, bank guarantees totaling 540,000 Turkish Lira (approximately $350,000) and a $324,000 bank guarantee issued in September 2009 related to TEMI’s Istanbul office lease under these lines.
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.
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In December 2008, we issued 35,416,667 common shares at a price of $1.20 per share in a private placement with Dalea, Riata TransAtlantic, Mr. McCann, and other purchasers with business or familial relationships with Mr. Mitchell, that resulted in gross proceeds of $42.5 million. We used substantially all of the net proceeds to purchase additional equipment for our planned drilling and service operations in Turkey, Morocco and Romania, to fund drilling activities in those countries 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.
On July 23, 2009, in connection with our acquisition of EOT, our wholly-owned subsidiary, TransAtlantic Worldwide, Ltd., entered into an unsecured promissory note with the sellers in the amount of $1.5 million due July 23, 2010. The note bears interest at a fixed rate of 3% per annum.
On July 27, 2009, our wholly-owned subsidiary, Viking International Limited (“Viking International”), purchased the I-13 drilling rig and associated equipment from Viking. Viking International paid $1.5 million in cash for the drilling rig and entered into a note payable to Viking 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, we amended and restated the terms of the note with Viking in connection with the purchase of the I-14 drilling rig and associated equipment from Viking. On February 19, 2010, Viking International purchased the I-14 drilling rig and associated equipment from Viking. Viking International paid $1.5 million in cash for the drilling rig and entered into an amended and restated note payable to Viking 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 in July 2009. 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.
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 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 intend to use the net proceeds from these offerings for our 2010 capital expenditure program and for general corporate purposes.
Senior Secured Credit Facility
On December 21, 2009, the Borrowers entered into a three year senior secured credit facility with Standard Bank Plc and BNP Paribas (Suisse) SA. We intend to use the credit facility to finance a portion of the development of our oil and gas properties in Turkey and for general corporate and working capital purposes.
The amount drawn under the 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 initial borrowing base is $30 million and the borrowing base will be re-determined at least semi-annually based on our hydrocarbon reserves in Turkey at December 31st and June 30th of each year. The lenders have aggregate commitments of $30 million. On June 21, 2011 and each three month anniversary thereof, the lenders’ commitments under the credit facility are subject to reduction by 14.3% of their commitments existing on March 21, 2011.
The credit facility matures on the earlier of (i) December 21, 2011 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. The credit facility includes a letter of credit sub-limit of up to $10 million.
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The credit facility is guaranteed by us and the Guarantors. Loans under the credit facility will accrue interest at a rate of three month LIBOR plus 6.25% per annum. At December 31, 2009, we had no outstanding borrowings under this credit agreement. 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 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 Plc or (b) 6.25% for all other letters of credit. We have deferred $1.9 million in placement fees and issuance costs associated with the credit facility that will be amortized over the three-year contractual period using the effective yield method.
The 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 DMLP, Ltd., Talon Exploration, Ltd., TEMI and TransAtlantic Turkey, Ltd.; 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 credit facility require each of the Borrowers to maintain a:
| • | ratio of total debt to EBITDAX of greater than 2.50 to 1.00; |
| • | ratio of EBITDAX (less non-discretionary capital expenditures) to interest expense of less than 4.00 to 1.00; and |
| • | ratio of current assets to current liabilities of not less than 1.10 to 1.00. |
The 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 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 credit facility, until amounts under the 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 credit facility includes, among other events, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency 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) 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 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
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default shall occur and be continuing, all loans under the 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 credit facility become immediately due and payable. In the case of any other event of default, all amounts due under the 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 credit facility, TEMI entered into zero cost collars with Standard Bank Plc and BNP Paribas, which hedge the price of oil during 2010, 2011 and 2012 under the terms set forth below. See “Item 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 credit facility to hedge additional volumes of oil.
| Year |
Quantity (Bbl/day) |
Weighted Average Minimum Price (per Bbl) |
Weighted Average Maximum Price (per Bbl) | |||||
| 2010 |
800 | $ | 61.50 | $ | 89.13 | |||
| 2011 |
700 | $ | 61.50 | $ | 102.00 | |||
| 2012 |
600 | $ | 61.50 | $ | 109.83 | |||
We expect to have sufficient cash, cash equivalents, availability under the senior secured credit facility and cash flow from operations to fund our operations for at least the next twelve months. However, we may not have sufficient funds to conduct our planned exploration and development activities beyond December 2010.
Contractual Obligations
The following table presents a summary of our contractual obligations at December 31, 2009:
| Payments Due By Year | |||||||||||||||||||||||||
| (In Thousands) | |||||||||||||||||||||||||
| Total | 2010 | 2011 | 2012 | 2013 | 2014 | Thereafter | |||||||||||||||||||
| Leases and other |
$ | 5,135 | $ | 1,610 | $ | 1,385 | $ | 1,170 | $ | 619 | $ — | $ | 351 | ||||||||||||
| Contracts |
17,000 | 13,200 | 3,800 | — | — | — | — | ||||||||||||||||||
| Permits |
5,655 | 705 | 4,950 | |
— |
|
— | — | — | ||||||||||||||||
| Total |
$ | 27,790 | $ | 15,515 | $ | 10,135 | $ | 1,170 | $ | 619 | $ — | $ | 351 | ||||||||||||
Off-Balance Sheet Arrangements
We did not have any off-balance sheet arrangements at December 31, 2009.
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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
Pursuant to our credit agreement with Standard Bank Plc and BNP Paribas, we are subject to interest rate risks associated with interest rate fluctuations on outstanding borrowings, as described under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Senior Secured Credit Facility.” At December 31, 2009, we had no outstanding borrowings under this credit agreement. The interest we pay on borrowings under this credit agreement is set every three months equal to LIBOR plus 6.25% per annum.
Foreign Currency Risk
We are subject to changes in foreign currency exchange rates as a result of our operations in foreign countries. Our currency exposures relate to transactions denominated in the Australian Dollar, Canadian Dollar, British Pound, European Union Euro, Romanian New Leu, Moroccan Dirham and Turkish Lira, and we are also exposed to foreign currency fluctuations as crude oil prices received are referenced in United States Dollar-denominated prices. In addition, the assets, liabilities and results of operations of our foreign operations are measured using the functional currency of such foreign operation. Effective January 1, 2009, the functional currency for each of our corporate entities in Morocco, Turkey, Canada and Romania is the local currency. 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 subsidiary financial statements into the U.S. Dollar reporting currency. Such translation adjustments are recorded as a component of other comprehensive income. The balance of $9.6 million recorded in other comprehensive income in 2009 consisted solely of foreign currency translation adjustments.
We recorded foreign currency gains and losses which result from re-measuring transactions and monetary accounts into the functional currency in earnings. As of December 31, 2009, we had 9.8 million Euros (approximately $14.0 million), 55.7 million Canadian Dollars (approximately $53.0 million) and 460,000 Turkish Lira (approximately $305,000) in cash and cash equivalents that are re-measured into the functional currency using the period-end exchange rate, with such re-measurement gains or losses recorded in earnings. We estimate that a 10% change in the exchange rates would impact such cash balances and our consolidated net loss by approximately $6.2 million. Foreign currency forward contracts have not been used to manage exchange rate fluctuations.
We agreed to a fixed currency exchange rate of AUD $1.00 to US $0.7024 in the Credit Agreement with Dalea (see “Note 10—Loans payable” to our consolidated financial statements). On June 23, 2009, the loan was repaid in its entirety and the Credit Agreement was terminated. The resulting realized exchange loss was $4.2 million for the year ended December 31, 2009, which was partially offset by approximately $800,000 of transaction gains and losses and re-measurement of monetary accounts consisting principally of our cash balances described above.
Commodity Price Risk
Our revenues are derived from the sale of our 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 the Lenders, at least one of the Borrowers is required to maintain commodity derivative contracts with Standard Bank Plc and BNP Paribas. In December 2009, TEMI entered into costless derivative contracts with Standard Bank Plc and BNP Paribas, which hedge the price of oil during 2010, 2011 and 2012. Pursuant to our 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 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 derivative contracts with Standard Bank Plc and BNP Paribas are in the form of costless collars. 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.
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We have elected not to designate our derivative financial instruments as hedges, 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. Our commodity derivative contracts are carried at their fair value on our consolidated balance sheet under either the caption “Derivative liabilities” or “Derivative assets.” 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 cash flows on our consolidated statement 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. As of December 31, 2009, we recorded a net unrealized loss on commodity derivative contracts of $1.9 million. We were not a party to any derivative contracts for the comparable period of 2008.
The following table summarizes our oil and natural gas derivatives contracts as of December 31, 2009:
| Year |
Quantity (Bbl/day) |
Weighted Average Minimum Price (per Bbl) |
Weighted Average Maximum Price (per Bbl) |
Estimated Fair Value of Liability (in thousands) |
||||||||
| 2010 |
800 | $ | 61.50 | $ | 89.13 | $ | (762 | ) | ||||
| 2011 |
700 | $ | 61.50 | $ | 102.00 | $ | (682 | ) | ||||
| 2012 |
600 | $ | 61.50 | $ | 109.83 | $ | (478 | ) | ||||
| (1,922 | ) | |||||||||||
| 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. |
Evaluation of Disclosure Controls and Procedures
Disclosure controls and procedures are controls and procedures that are designed to ensure that information required to be disclosed in the 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 the reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.
As of December 31, 2009, 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 the design and operation of our disclosure controls and procedures. 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. Based upon the evaluation, and as a result of the material weaknesses described below, our chief executive officer and chief financial officer have concluded that our disclosure controls and procedures were not effective at the reasonable assurance level.
Management’s Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Because of inherent limitations, a system of internal control over financial reporting may not prevent or detect material misstatements on a timely basis. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate due to 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, our management concluded that our internal control over financial reporting was not effective as of December 31, 2009 because of the identification of the material weaknesses identified below.
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 the annual or interim financial statements will not be prevented or detected on a timely basis. We have identified material weaknesses as described below:
| • | We did not maintain adequate controls to facilitate the flow of information used in financial reporting throughout the organization. Specifically, as of December 31, 2009, we have not successfully integrated our existing accounting function with the accounting function of Incremental acquired on March 5, 2009, including creating an organizational structure that aligned appropriate authority with responsibility in the financial reporting function. Our financial reporting staff located in Dallas, Texas, who had the responsibility to gather the necessary data to consolidate the results of our operations, analyze those results for existence, completeness, accuracy, and compliance with U.S. GAAP, and report those results in our periodic filings, were not able to receive financial data from Incremental in time to perform a thorough and complete review of the data in connection with the preparation of our 2009 year-end financial statements. Because of this deficiency, which is pervasive in nature, material adjustments were discovered in our year end financial statements that had to be corrected before they were issued. |
| • | We did not maintain an effective period-end financial statement closing process. Specifically, we did not design effective procedures for reconciling and compiling our financial records in a timely manner. Because of this deficiency, which is pervasive in nature, material adjustments were discovered in our year end financial statements that had to be corrected before they were issued. |
| • | We did not design procedures to ensure detailed reviews and verification of |
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| 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, material adjustments were discovered in our year end financial statements that had to be corrected before they were issued. |
| • | We did not maintain effective monitoring controls over foreign operations in our Istanbul location. Specifically, we did not design control activities, including oversight and review procedures necessary to monitor the effectiveness of control activities at our Istanbul location. Because of this deficiency, which is pervasive in nature, material adjustments were discovered in our year end financial statements that had to be corrected before they were issued. |
Our independent registered public accounting firm has audited the effectiveness of our internal control over financial reporting as of December 31, 2009 as stated in their report, dated March 30, 2010, which appears herein.
Management’s Plan for Remediation of Material Weaknesses
In light of the conclusion that our internal control over financial reporting was not effective, our management has developed a plan intended to remediate such ineffectiveness and to strengthen our internal control over financial reporting through the implementation of certain remedial measures, which include:
| • | We plan to hire a controller in Incremental’s Istanbul office with sufficient experience in U.S. GAAP and financial reporting. Management will provide this person with all the proper authority to carry out his or her responsibilities so that financial information in compliance with U.S. GAAP is received, analyzed, compiled and reported in our periodic reports in a timely manner. Further, we are currently in the process of replacing Incremental’s accounting system with the system being utilized by the accounting and financial reporting function in the Dallas office. We believe this will allow us greater visibility into the financial data from Incremental and assist in the review process. |
| • | We plan to review our financial statement close process and reinforce the importance of a timely close with an increased focus on the review of inputs and analysis of accounts as well as reinforcing the need to have adequate supporting documentation for data contained in the filings. |
| • | We will develop a plan to assist management, including those with responsibility for drafting and reviewing the financial statements, with monitoring the performance of controls activities performed at our Istanbul office. |
Changes in Internal Control over Financial Reporting
On December 30, 2008, we acquired Longe Energy Limited. During 2009, we fully integrated Longe, a development stage enterprise, into our existing control structure including controls and procedures around general ledger accounting and inventory and equipment management. We consider the integration of Longe a material change in our internal control over financial reporting.
On March 5, 2009, we acquired Incremental. As indicated above, we are currently in the process of incorporating Incremental into our control environment but have experienced substantial difficulty in doing so. We consider the ongoing integration of Incremental a material change in 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. |
Directors and Executive Officers
The following sets forth the biographical background information for each of our directors and executive officers. In addition, the biographies of our directors include a brief description of the specific experience, qualifications, attributes or skills that led to the conclusion that each person should serve as a director. In addition to the specific experience, qualifications, attributes and skills described below, all of the directors have the professional experience and personal character that make them highly qualified directors for our company and collectively comprise an experienced board that works well together as a whole.
N. Malone Mitchell, 3rd, age 48, has served as a director since April 2008 and as our chairman since May 2008. Since 2005, Mr. Mitchell has served as the president of Riata Management LLC, an Oklahoma City-based private oil and gas exploration and production company. From June to December 2006, Mr. Mitchell served as president and chief operating officer of Sandridge Energy, Inc. (formerly Riata Energy, Inc.), an independent natural gas and oil company concentrating in exploration, development and production activities. Until he sold his controlling interest in the company in June 2006, Mr. Mitchell also served as president, chief executive officer and chairman of Riata Energy, Inc., which Mr. Mitchell founded in 1985 and built into one of the largest privately held energy companies in the United States.
Mr. Mitchell brings to the board extensive executive leadership experience, organizational experience, experience with us and over 25 years of experience with the oil and gas industry. He is familiar with our day-to-day operations and is critical to the formulation and execution of our strategy. His insight into our operations, performance and into the oil and gas industry in general are critical to board discussions.
Brian E. Bayley, age 57, has served as a director since 2001. Since May 2009, Mr. Bayley has served as president, chief executive officer and director of Quest Capital Corp., a publicly traded mortgage investment corporation listed on the TSX and NYSE Amex. From January 2008 until May 2009, Mr. Bayley served as co-chairman of Quest, and from June 2003 until January 2008 and during March 2008, Mr. Bayley served as president and chief executive officer, respectively. He has also served as the president and a director of Ionic Management Corp., a private management company that provides various consulting, administrative, management and related services to publicly traded companies, since December 1996.
Mr. Bayley brings to the board extensive financial, executive leadership and organizational experience. This experience makes him an effective member of our audit committee. Mr. Bayley also has significant experience serving as a director of other public companies, which brings important insights into board oversight, compensation and corporate governance matters.
Alan C. Moon, age 64, has served as a director since 2004. Mr. Moon has been the president of Crescent Enterprises Inc., a private Calgary-based investment firm, since he formed it in 1997. Prior to that, Mr. Moon was president and chief operating officer of TransAlta Energy Corporation, an international independent electric power generation and distribution company that had approximately $1 billion in assets and operated in Ontario, New Zealand, Australia, South America, and the United States during the period Mr. Moon served as an executive officer of the company.
Mr. Moon brings to the board extensive financial, executive leadership and organizational experience. This background makes him an effective chairman of our compensation committee and our corporate governance committee. In addition, Mr. Moon has significant experience serving as a director of other public companies. This background brings important insights into board oversight, compensation and corporate governance matters.
Mel G. Riggs, age 55, has served as a director since July 2009. Mr. Riggs has served as senior vice president—finance, secretary, treasurer, and chief financial officer since 1991, and as a director since 1994, of Clayton Williams Energy, Inc., an independent exploration and production company that develops and produces oil and natural gas. Since 1989, Mr. Riggs has served as manager of finance of the Williams Companies, Inc. From 1984 to 1989, Mr. Riggs was initially employed as senior vice president of finance and treasurer of ClayDesta Communications, Inc., and thereafter as vice president of finance of Advanced Telecommunications Corporation, which acquired ClayDesta Communications, Inc. in March 1989.
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Mr. Riggs brings to the board extensive financial, executive leadership and organizational experience, including over 30 years experience as a certified public accountant and 19 years experience as a chief financial officer. This experience makes him an audit committee financial expert under SEC rules and regulations and an effective chairman of our audit committee. Mr. Riggs also has significant experience serving as a director of other public companies, which brings important insights into board oversight and corporate governance matters.
Michael D. Winn, age 48, has served as a director since 2004. He has been the president of Terrasearch Inc., a private consulting company that provides analysis on mining and energy companies, since he formed that company in 1997. Prior to that, Mr. Winn spent four years as an analyst for a Southern California-based brokerage firm where he was responsible for the evaluation of emerging oil and gas and mining companies. Mr. Winn has worked in the oil and gas industry since 1983 and the mining industry since 1992.
Mr. Winn brings to the board extensive financial, executive leadership and organizational experience. Mr. Winn also has significant experience serving as a director of other public companies, which brings important insights into board oversight, compensation and corporate governance matters.
Matthew W. McCann, age 41, 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 & 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.
Mr. McCann brings to the board extensive executive leadership experience, organizational experience, experience with us and experience with the oil and gas industry. He is responsible for, and familiar with, our day-to-day operations and the implementation of our strategy. His insight into our performance and into the oil and gas industry in general are critical to board discussions.
Scott C. Larsen, age 57, has served as our president since March 2004 and served as our chief executive officer from May 2005 to January 2009. He has served as a director since May 2005. He previously served as our vice president—operations from July 2002 until March 2004, has been involved in our international activities since their inception in 1994. An attorney by training with over 25 years experience in the oil and gas industry, Mr. Larsen served previously as general counsel for Humble Exploration, and independent exploration company. Additionally, he spent several years as a partner in Vineyard, Drake & Miller, a business litigation law firm and served as general counsel for Summit Partners Management Co., a venture capital and management company.
Mr. Larsen brings to the board executive leadership experience, organizational experience, extensive experience with us and extensive experience with the oil and gas industry, including international oil and gas exploration. He is familiar with our day-to-day operations and the implementation of our strategy. His insight into our performance and into the oil and gas industry in general are critical to board discussions.
Gary T. Mize, age 57, was appointed as our vice president and chief operating officer in January 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.
Hilda D. Kouvelis, age 47, has served as our chief financial officer since January 2007 and as a vice president since May 2007. She served as our controller since joining us in July 2005 until January 2007. From November 2007 until May 2008, Ms. Kouvelis served as chief financial officer of Sky Petroleum Inc. and Southern Star Energy Inc. Prior to that, Ms. Kouvelis served as controller for Ascent Energy, Inc., an oil and natural gas exploration and development company, from 2001 to 2004. 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 1998-2000, Ms. Kouvelis served as Controller for international operations at PetroFina S.A.’s headquarters in Brussels, Belgium.
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Jeffrey S. Mecom, age 44, 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 NYSE-listed international metals recycling and processing company, from 1995 until April 2005.
Messrs. Mitchell, Winn, Bayley, and Riggs either currently serve or within the past five years have served on the board of directors of the public companies listed below:
| Name of Director |
Name of Company | Period Served | ||
| N. Malone Mitchell | Quest Resource Corporation | April 2007 – May 2008 | ||
| Michael D. Winn | Alexco Resource Corporation | January 2005 – Present | ||
| Quest Capital Corp. | July 2002 – December 2007 | |||
| Brian E. Bayley | American Natural Energy Corporation | June 2001 – Present | ||
| Esperanza Silver Corporation | December 1999 – Present | |||
| Kirkland Lake Gold Inc. | October 1998 – Present | |||
| Quest Capital Corp. | June 2003 – Present | |||
| Midway Gold Corp. | May 1996 – November 2008 | |||
| Mel G. Riggs | Clayton Williams Energy, Inc. | May 1994 – Present | ||
To the best of our knowledge there are no arrangements or understandings between any director or officer and any other person pursuant to which any person was selected as a director or officer.
There are no family relationships between any of our directors, nominees for director or executive officers. To our knowledge, there have been no material legal proceedings as described in Item 401(f) of Regulation S-K during the last ten years that are material to an evaluation of the ability or integrity of any of our directors or executive officers.
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires our directors, executive officers, and any persons who own more than 10% of a registered class of our equity securities, to file reports of ownership and changes in ownership with the SEC. SEC regulations require executive officers, directors and greater than 10% shareholders to furnish us with copies of all Section 16(a) forms they file. Based solely on our review of the copies of such forms furnished or available to us, we believe that our directors, executive officers and 10% shareholders complied with all Section 16(a) filing requirements for the fiscal year ended December 31, 2009 except as follows: one late Form 4 was filed by Mr. Mitchell on January 5, 2009 to report the acquisition of common shares and common share purchase warrants on December 30, 2008 and one late Form 4 was filed by each of Messrs. McCann, Mecom and Larsen and Ms. Kouvelis on August 19, 2009 to report the acquisition of restricted stock units on August 10, 2009.
Code of Business Conduct
We have adopted a code of ethics that applies to all our officers, directors and employees, including our principal executive officer, principal financial officer, principal accounting officer and controller. The full text of our Code of Conduct is published on our web site at www.transatlanticpetroleum.com, under the Investors tab. We intend to disclose future amendments to certain provisions of the Code of Conduct, or waivers of such provisions granted to executive officers and directors, on our website within four business days following the date of such amendment or waiver.
Audit Committee
The board of directors has established a separately-designated standing audit committee in accordance with section 3(a)(58)(A) of the Exchange Act. Messrs. Winn, Bayley, Moon and Riggs serve on the audit committee. The board of directors has determined that Mr. Riggs meets the qualifications of an “audit committee financial expert” in accordance with SEC rules and regulations and that Mr. Riggs meets the appropriate standards for independence in accordance with the NYSE Amex listing standards.
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| Item 11. | Executive Compensation. |
Compensation Discussion and Analysis
Executive Compensation Philosophy
Our executive compensation program is designed to attract, motivate and retain talented executives enabling us to produce superior results and maximize return to shareholders. Our pay for performance philosophy focuses executives’ efforts on achieving strategic corporate goals, thereby enabling us to deliver short-term and long-term financial successes for our shareholders without encouraging excessive risk taking. At this stage of our company’s development, executive compensation is not tied to specific performance metrics, but is intended to focus our executives on successfully executing our strategy to become a vertically-integrated international oil and gas exploration, production and service company. Our compensation committee, which consists entirely of independent board members, controls the executive compensation program for our named executive officers, as well as for our other officers and employees. Our executive compensation objectives are to:
| • | pay for performance without excessive risk; |
| • | attract, retain and motivate superior executives; |
| • | pay competitive levels of salary and total compensation; and |
| • | align the interests of management with the interests of our shareholders. |
Process of Determining Compensation
Our compensation committee determines executive compensation. Our chairman and other members of our board may also participate in compensation committee meetings to provide their evaluation of the performance of our executive officers, and our chief executive officer provides compensation recommendations as to executive officers other than himself. Management plays a significant role in this process, through evaluating employee performance, recommending salary levels, discretionary cash bonuses and restricted stock unit awards and preparing meeting information for use in compensation committee meetings. Although the compensation committee has not retained a compensation consultant, it may do so in the future.
Elements of Executive Compensation
The 2009 compensation program consisted of base salary, a cash incentive bonus award, and restricted stock units. Executives also received standard employee benefits. There is no formal policy regarding the allocation between short-term or long-term incentive compensation or between cash and non-cash incentive compensation for our executive officers. The compensation committee relies on each committee member’s knowledge and experience as well as information provided by management when determining the appropriate level and mix of compensation. In general, the compensation committee believes that long-term, non-cash incentive compensation should be emphasized over short-term, cash incentive compensation for our executive officers. We have not adopted formal stock ownership guidelines for our named executive officers, but we believe that named executive officers owning stock helps align their interest with those of long-term shareholders.
Base Salaries. Our compensation committee reviews and sets base salaries annually. When determining base salary levels for the chief executive officer and other named executive officers, the compensation committee reviews their performance and contribution to the achievement of corporate objectives.
We entered into an oral arrangement with respect to Mr. McCann’s compensation, which set an initial base salary that is subject to the annual review and discretion of our compensation committee and the board of directors. Ms. Kouvelis and Messrs. Larsen and Mecom have entered into employment agreements with us. These agreements provide for an initial base salary, which may be reviewed and increased at the discretion of the board. See “—Discussion Regarding Fiscal Year 2009, 2008 and 2007 Summary Compensation Table and Fiscal Year 2009 Grants of Plan-Based Awards Table—Employment Agreements” for more information on these agreements.
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Short-Term Incentive Compensation. In addition to base salaries, we award cash bonuses on a discretionary basis to our employees, including the named executive officers. For the named executive officers other than our chief executive officer, the compensation committee, in consultation with our chief executive officer, recommends cash bonuses for the board’s approval. The compensation committee reviews the performance of our chief executive officer and recommends the bonus for our chief executive officer to the board of directors. Cash bonuses are based on the officer’s performance, the officer’s contribution to achieving corporate goals and our achievement of goals set by the board of directors. The compensation committee does not assign any specific weights to these measures or use a formula to determine bonus amounts.
We do not have a formal cash incentive bonus plan, although we have historically paid year-end cash bonuses in the range of 10% to 20% of annual base salary. For 2009, Mr. McCann, Ms. Kouvelis, Mr. Larsen and Mr. Mecom were awarded cash bonuses of $32,692, $21,115, $45,192 and $20,000 respectively. Of Mr. McCann’s discretionary bonus, $7,692 was paid in 2009 and $25,000 was paid in 2010. Of Ms. Kouvelis’ discretionary bonus, $8,615 was paid in 2009 and $12,500 was paid in 2010. Of Mr. Larsen’s discretionary bonus, $20,192 was paid in 2009 and $25,000 was paid in 2010. Of Mr. Mecom’s discretionary bonus, $7,500 was paid in 2009 and $12,500 was paid in 2010. For 2009, the compensation committee determined that 25% of executive bonuses would be paid in cash and 75% would be paid as long-term incentives in the form of restricted stock units.
Long-Term Incentive Compensation. Our board of directors designed our long-term incentive plan to ensure that incentive compensation rewards our employees’ contributions to the long-term positive performance of our company, and is intended to align our executives’ interests with our shareholders’ interests. Long-term incentive awards are granted by the board of directors on the recommendation of the chief executive officer, in the case of employees, and by the compensation committee, in the case of named executive officers including the chief executive officer, president and chief financial officer. Long-term incentive awards are generally awarded by the board of directors upon the commencement of employment with us based on the level of responsibility of the employee. The number of long-term incentive awards outstanding to a particular individual and their length of service are taken into consideration when awarding new awards. Additional grants have been made periodically to ensure that the number of awards granted to any particular individual is commensurate with the individual’s level of ongoing responsibility within our company.
In 2009, our compensation committee decided to alter the use of long-term incentives to award restricted stock units instead of stock options. On February 9, 2009, our board of directors approved the TransAtlantic Petroleum Corp. 2009 Long-Term Incentive Plan (the “Incentive Plan”), which was approved by our shareholders at our annual and special meeting of shareholders held on June 16, 2009. Our Amended and Restated Stock Option Plan (2006) (the “Option Plan,” and together with the Incentive Plan, the “Plans”) expired at the close of the shareholder meeting with respect to all unallocated shares thereunder, and all options previously granted under the Option Plan remained in full force and effect. We discontinued granting stock options following the termination of the Option Plan and began granting restricted stock units pursuant to the Incentive Plan.
In connection with the approval of the Incentive Plan, our compensation committee adopted a long-term incentive policy designed to attract and retain qualified professionals throughout our company and to attract and retain skilled, dedicated employees who are willing to commit to a long term of foreign service, while being able to pay modest salaries and create a meaningful ownership stake in our company. The long-term incentive policy provides for a semi-annual grant of restricted stock units equal to a percentage of base salary to participants, including our chief executive officer and our named executive officers. For 2009 and 2010, the percentage was 25% of base salary. The compensation committee reviews this policy annually, and may also grant additional discretionary awards for exceptional service. The compensation committee believes that this structure will incentivize and motivate our professionals to provide the additional effort needed to maximize our success. In addition, restricted stock units provide executives with an opportunity to earn our common shares. The compensation committee believes this structure provides greater balance and stability to our long-term incentives for executives. It also provides a form of long-term compensation that aids retention, encourages long-term value creation and aligns financial interests with shareholders (but does not encourage excessive risk taking). The restricted stock units awarded to our named executive officers generally vest in three annual installments and are subject to the continued employment of the named executive officer through each such restricted period.
Pursuant to our long-term incentive policy, Mr. McCann, Ms. Kouvelis, Mr. Larsen and Mr. Mecom were granted restricted stock units on February 9, 2009 of 125,000, 50,000, 150,000 and 50,000, respectively. These awards were subject to the approval of the Incentive Plan and the ratification of the awards by our shareholders at our annual and special meeting held on June 16, 2009. These initial grants include awards of restricted stock units equal to 25% of base salary, plus an additional amount of restricted stock units in recognition of the executives’ contributions to the achievement of our goals in
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2008. These restricted stock units vested one-third on January 15, 2010, and vest one-third on January 15, 2011 and one-third on January 15, 2012. They were also granted restricted stock units on August 10, 2009 of 14,451, 26,561, 18,064 and 25,838 respectively. These restricted stock units vest one-third on July 15, 2010, one-third on July 15, 2011 and one-third on July 15, 2012.
Employee Benefits
We offer core employee benefits coverage in order to provide our global workforce with a reasonable level of financial support in the event of illness or injury and to enhance productivity and job satisfaction through programs that focus on work/life balance. The benefits available are the same for all U.S. employees and include medical and dental coverage. In addition, we offer a 401(k) plan, which provides a reasonable level of retirement income reflecting employees’ careers with the company. U.S. employees are eligible to participate in these plans.
Severance and Change in Control Agreements
Our employment agreements with Ms. Kouvelis and Messrs. Larsen and Mecom generally provide for severance benefits in the event of termination of employment for cause or “constructive dismissal.” No payments are made if employment is terminated due to death, disability or cause. These employment agreements also provide for certain payments if a termination of employment or “constructive dismissal” follows a change in control of our company. At the time of entering into these agreements, we believed these agreements ensured the continuity of these executives and allowed them to focus on serving us in a change of control situation without the distraction of concern for their employment. See “—Discussion Regarding Fiscal Year 2009, 2008 and 2007 Summary Compensation Table and Fiscal Year 2009 Grants of Plan-Based Awards Table—Employment Agreements.”
Compensation Committee Report on Executive Compensation
Our compensation committee has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the compensation committee recommended to our board of directors that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K.
The foregoing report is provided by the following directors, who constitute the compensation committee.
| COMPENSATION COMMITTEE |
| Michael D. Winn |
| Brian E. Bayley |
| Alan C. Moon |
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Compensation Committee Interlocks and Insider Participation
During the fiscal year ended December 31, 2009, the compensation committee was comprised of Messrs. Winn, Bayley and Moon. During the fiscal year ended December 31, 2009, no member of our compensation committee is or has been an officer or employee of us or any of our subsidiaries or had any relationship requiring disclosure pursuant to Item 404 of Regulation S-K. None of our executive officers served as a director or member of the compensation committee (or other board committee performing similar functions or, in the absence of any such committee, the entire board of directors) of another entity, one of whose executive officers served on our compensation committee or as one of our directors.
Compensation of Executive Officers
Fiscal Year 2009, 2008 and 2007 Summary Compensation Table
The following Fiscal Year 2009, 2008 and 2007 Summary Compensation Table contains information regarding compensation for 2009, 2008 and 2007 that we paid to: (a) our chief executive officer, Matthew W. McCann, (b) our chief financial officer, Hilda Kouvelis, and (c) our only other two executive officers as of December 31, 2009, Jeffrey S. Mecom and Scott C. Larsen.
| Name and Principal Position |
Year | Salary ($)(3) | Bonus ($)(3) | Stock Awards ($)(4) |
Option Awards ($)(4) |
All Other Compensation ($)(3)(5) |
Total ($) | |||||||
| Matthew W. McCann(1) |
2009 | 200,000 | 32,692 | 131,431 | 0 | 4,800 | 368,923 | |||||||
| Hilda Kouvelis |
2009 | 160,000 | 21,115 | 107,606 | 0 | 4,000 | 292,721 | |||||||
| 2008 | 142,418 | 40,000 | 0 | 76,583 | 10,085 | 269,086 | ||||||||
| 2007 | 147,000 | 10,000 | 0 | 31,992 | 0 | 188,992 | ||||||||
| Scott C. Larsen(2) |
2009 | 250,000 | 45,192 | 159,622 | 0 | 19,500 | 474,314 | |||||||
| 2008 | 250,000 | 60,000 | 0 | 0 | 10,350 | 320,350 | ||||||||
| 2007 | 240,000 | 120,000 | 0 | 237,951 | 0 | 597,951 | ||||||||
| Jeffrey S. Mecom |
2009 | 150,000 | 20,000 | 105,462 | 0 | 7,500 | 282,962 | |||||||
| 2008 | 150,000 | 15,000 | 0 | 76,583 | 10,572 | 252,155 | ||||||||
| 2007 | 120,000 | 15,000 | 0 | 80,251 | 0 | 215,251 | ||||||||
| (1) | Mr. McCann was appointed our chief executive officer effective January 1, 2009. |
| (2) | Mr. Larsen served as our chief executive officer from May 17, 2005 to December 31, 2008. Mr. Larsen has served as our president since March 9, 2004. |
| (3) | As of November 1, 2008, Riata pays the salary, bonus and benefits earned by each named executive officer pursuant to that certain service agreement, as amended (the “Service Agreement”), effective May 1, 2009, with Longfellow, Viking, MedOil Supply, LLC and Riata. We reimburse Riata for the actual cost of such salaries, bonuses and benefits, all as more fully described under “Item 13. Certain Relationships and Related Transactions, and Director Independence—Certain Relationships and Related Transactions—Service Agreement.” |
| (4) | Amounts shown do not reflect compensation actually received by the named executive officers. Rather, the amounts represent the aggregate grant date fair value computed in accordance with ASC 718, Compensation—Stock Compensation (“ASC 718”). The assumptions used in the calculation of the aggregate grant date fair value of restricted stock units and stock options are set forth under “Note 11—Stockholder’s equity” to our consolidated financial statements. |
| (5) | These amounts consist of company-paid portions of insurance premiums, company contributions to a 401(k) savings plan and company-paid international travel incentives. |
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Fiscal Year 2009 Grants of Plan-Based Awards Table
The table below lists each grant of a plan-based award to our named executive officers during 2009.
| Name |
Grant Date |
Compensation Committee Approval Date |
All Other Stock Awards: Number of Shares of Stock or Units (#)(1) |
Grant Date Fair Value of Stock Awards ($) | |||||
| Matthew W. McCann |
6/16/09 | 2/09/09 | 125,000 | $ | 93,325 | ||||
| 8/10/09 | 8/10/09 | 14,451 | $ | 38,106 | |||||
| Hilda Kouvelis |
6/16/09 | 2/09/09 | 50,000 | $ | 37,330 | ||||
| 8/10/09 | 8/10/09 | 26,561 | $ | 70,276 | |||||
| Scott C. Larsen |
6/16/09 | 2/09/09 | 150,000 | $ | 111,990 | ||||
| 8/10/09 | 8/10/09 | 18,064 | $ | 47,632 | |||||
| Jeffrey S. Mecom |
6/16/09 | 2/09/09 | 50,000 | $ | 37,330 | ||||
| 8/10/09 | 8/10/09 | 25,838 | $ | 68,132 | |||||
| (1) | These are restricted stock units awarded pursuant to our 2009 Long-Term Incentive Plan. |
Discussion Regarding Fiscal Year 2009, 2008 and 2007 Summary Compensation Table and Fiscal Year 2009 Grants of Plan-Based Awards Table
Employment Agreements
McCann. We entered into an oral arrangement with Mr. McCann, effective January 1, 2009. Pursuant to our arrangement, Mr. McCann is paid an annual base salary of $200,000, subject to the annual review and discretion of the board. Effective January 1, 2010, Mr. McCann’s annual base salary was increased to $275,000. Mr. McCann is eligible for an annual discretionary bonus, which is determined annually by our compensation committee. This arrangement also provides that Mr. McCann is eligible to participate in all other benefits made available to our executives resident in the United States.
Kouvelis. We entered into an employment agreement with Ms. Kouvelis, our vice president and chief financial officer, effective May 1, 2008. The agreement expires upon her death, disability, resignation or other termination of employment. This agreement provides for an annual base salary to Ms. Kouvelis, at the rate of $160,000 per year, which may be reviewed and increased at the discretion of the board. Effective January 1, 2010, Ms. Kouvelis’ annual base salary was increased to $185,000. The agreement also provides that Ms. Kouvelis is eligible to receive a bonus as determined by and at the discretion of the board, and she is eligible to participate in all other benefits made available to our executives resident in the United States.
Pursuant to Ms. Kouvelis’ employment agreement, if Ms. Kouvelis is terminated (i) by us at any time without “cause” or (ii) by Ms. Kouvelis within sixty days of an event that constitutes “constructive dismissal”, then we will pay Ms. Kouvelis a lump sum amount equal to one-half of her annual salary plus $7,500. In addition, if a “change in control” results in (i) the termination of employment of Ms. Kouvelis without cause within thirty days prior to or within six months after the change in control, or (ii) a constructive dismissal within six months of the change in control and Ms. Kouvelis elects to terminate her employment with us, we will pay Ms. Kouvelis a lump sum amount equal to one-half of her annual salary plus $7,500. See “—Potential Payments Upon Termination or Change of Control—Employment Agreements” for the definitions of “cause,” “constructive dismissal” and “change in control.”
Larsen. We entered into an employment agreement with Mr. Larsen, our president and former chief executive officer, effective July 1, 2005. The agreement expires upon his death, disability, resignation or other termination of employment. This agreement provides for an annual base salary to Mr. Larsen, at the rate of $240,000 per year, which may be reviewed and increased at the discretion of the board. Effective January 1, 2008, Mr. Larsen’s annual base salary was increased to $250,000. Effective January 1, 2010, Mr. Larsen’s annual base salary was increased to $275,000. The agreement also provides that Mr. Larsen is eligible to receive a bonus as determined by and at the discretion of the board, and he is eligible to participate in all other benefits made available to our executives resident in the United States. In accordance with the terms of the agreement, one of our subsidiaries pays a portion of Mr. Larsen’s annual salary to Charles Management Inc., a consulting company wholly-owned by Mr. Larsen.
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Pursuant to our employment agreements, if Mr. Larsen is terminated (i) by us at any time without “cause” or (ii) by Mr. Larsen within sixty days of an event that constitutes “constructive dismissal”, then we will pay Mr. Larsen a lump sum amount equal to Mr. Larsen’s annual salary plus $15,000. In addition, if a “change in control” results in either (i) the termination of employment of Mr. Larsen without cause within thirty days prior to or within one year after the change in control, or (ii) a constructive dismissal within one year of the change in control and Mr. Larsen elects to terminate his employment with us, we will pay Mr. Larsen a lump sum amount equal to his annual salary plus $15,000. See “—Potential Payments Upon Termination or Change of Control—Employment Agreements” for the definitions of “cause,” “constructive dismissal” and “change in control.”
Mecom. We entered into an employment agreement with Mr. Mecom, our vice president and corporate secretary, effective January 1, 2008. The agreement expires upon his death, disability, resignation or other termination of employment. This agreement provides for an annual base salary to Mr. Mecom, at the rate of $150,000 per year, which may be reviewed and increased at the discretion of the board. Effective January 1, 2010, Mr. Mecom’s annual base salary was increased to $172,000. The agreement also provides that Mr. Mecom is eligible to receive a bonus as determined by and at the discretion of the board, and he is eligible to participate in all other benefits made available to our executives resident in the United States.
Pursuant to Mr. Mecom’s employment agreement, if Mr. Mecom is terminated (i) by us at any time without “cause” or (ii) by Mr. Mecom within sixty days of an event that constitutes “constructive dismissal”, then we will pay Mr. Mecom a termination amount equal to one-half of his annual salary plus $7,500. In addition, if a “change in control” results in either (i) the termination of employment of Mr. Mecom without cause within thirty days prior to or within six months after the change in control, or (ii) a constructive dismissal within six months of the change in control and Mr. Mecom elects to terminate his employment with us, we will pay Mr. Mecom a lump sum amount equal to one-half of his annual salary plus $7,500. See “—Potential Payments Upon Termination or Change of Control—Employment Agreements” for the definitions of “cause,” “constructive dismissal” and “change in control.”
Equity Incentive Plan Awards
Incentive Plan. On February 9, 2009 and August 10, 2009, the compensation committee approved awards of restricted stock units to our named executive officers pursuant to the Incentive Plan. The restricted stock units awarded on February 9, 2009 were subject to approval of the Incentive Plan by our shareholders at our annual and special meeting held June 16, 2009 and so bear June 16, 2009 as the grant date. These restricted stock units vested one-third on January 15, 2010, and will vest one-third on January 15, 2011 and one-third on January 15, 2012, subject to the continued employment of the named executive officer through each such restricted period. The restricted stock units granted August 10, 2009 will vest one-third on July 15, 2010, one-third on July 15, 2011 and one-third on July 15, 2012, subject to the continued employment of the named executive officer through each such restricted period. Upon a termination of service within six months of a change in control or a termination in service due to death or disability, all unvested restricted stock units would vest immediately. Upon a termination of service for cause, all unvested restricted stock units would be forfeited. Upon a termination of service for any other reason, all unvested restricted stock units would be forfeited, except those restricted stock units that would have vested within one month of the termination date.
Option Plan. The compensation committee approved awards of stock options pursuant to the Option Plan in 2007 and 2008. The Option Plan terminated at the close of our annual and special meeting of shareholders held on June 16, 2009 with respect to all unallocated shares thereunder. All options previously granted under the Option Plan remained in full force and effect.
On January 10, 2007, the compensation committee approved stock option awards for Ms. Kouvelis and Messrs. Larsen and Mecom. On December 4, 2007, the compensation committee approved additional stock option awards to Messrs. Larsen and Mecom. For 2008, the compensation committee approved stock option awards to Messrs. McCann and Mecom and to Ms. Kouvelis on June 11, 2008. The awards granted to Ms. Kouvelis and Mr. Mecom on January 10, 2007 vested one-half on the date of grant and one-half upon the first anniversary on the date of grant. All other option awards granted in 2007 and 2008 vested one-third on the date of grant and vest one-third upon the anniversary of the date of grant and one-third upon the second anniversary of the date of grant. Upon the death of a named executive officer, or if the named executive officer ceases to be an employee, officer or director within six months following a change of control of us, all stock options held by such named executive officer would vest immediately.
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Fiscal Year 2009 Outstanding Equity Awards At Fiscal Year-End Table
The following table lists all of the outstanding stock options and stock awards held on December 31, 2009 by each of our named executive officers. The table also includes the value of the stock awards based on the closing price of our common shares on the NYSE Amex on December 31, 2009, which was $3.42 per share.
| Option Awards | Stock Awards | ||||||||||||||
| Name |
Grant Date |
Number of Securities Underlying Unexercised Options (#) |
Number of Securities Underlying Unexercised Options (#) |
Option Exercise Price ($) |
Option Expiration Date |
Number of Shares or Units of Stock That Have Not Vested (#) |
Market Value of Shares or Units of Stock That Have Not Vested ($) | ||||||||
| Exercisable | Unexercisable | ||||||||||||||
| Matthew W. McCann |
6/11/08 | (2) | 33,333 | 16,667 | 1.23 | 6/11/13 | |||||||||
| 6/16/09 | (4) | 125,000 | 427,500 | ||||||||||||
| 8/10/09 | (5) | 14,451 | 49,422 | ||||||||||||
| Hilda Kouvelis |
10/11/05 | (1) | 25,000 | 0 | 0.90 | 10/11/10 | |||||||||
| 4/5/06 | (1) | 50,000 | 0 | 1.10 | 4/5/11 | ||||||||||
| 1/10/07 | (3) | 75,000 | 0 | 1.00 | 1/10/12 | ||||||||||
| 6/11/08 | (2) | 50,000 | 25,000 | 1.23 | 6/11/13 | ||||||||||
| 6/16/09 | (4) | 50,000 | 171,000 | ||||||||||||
| 8/10/09 | (5) | 26,561 | 90,839 | ||||||||||||
| Scott C. Larsen |
10/11/05 | (1) | 100,000 | 0 | 0.90 | 10/11/10 | |||||||||
| 4/5/06 | (1) | 70,000 | 0 | 1.10 | 4/5/11 | ||||||||||
| 1/10/07 | (2) | 400,000 | 0 | 1.00 | 1/10/12 | ||||||||||
| 12/4/07 | (2) | 250,000 | 0 | 0.31 | 12/4/12 | ||||||||||
| 6/16/09 | (4) | 150,000 | 513,000 | ||||||||||||
| 8/10/09 | (5) | 18,064 | 61,779 | ||||||||||||
| Jeffrey S. Mecom |
4/17/06 | (1) | 25,000 | 0 | 1.12 | 4/17/11 | |||||||||
| 1/10/07 | (3) | 125,000 | 0 | 1.00 | 1/10/12 | ||||||||||
| 12/4/07 | (2) | 100,000 | 0 | 0.31 | 12/4/12 | ||||||||||
| 6/11/08 | (2) | 50,000 | 25,000 | 1.23 | 6/11/13 | ||||||||||
| 6/16/09 | (4) | 50,000 | 171,000 | ||||||||||||
| 8/10/09 | (5) | 25,838 | 88,366 | ||||||||||||
| (1) | Vested on the date of grant. |
| (2) | Vested one-third on the date of grant, and vests one-third upon the first anniversary of the date of grant and one-third upon the second anniversary of the date of grant. |
| (3) | Vested one-half on the date of grant and vests one-half upon the first anniversary of the date of grant. |
| (4) | Vested one-third on January 15, 2010, and vests one-third on January 15, 2011 and one-third on January 15, 2012. |
| (5) | Vests one-third on July 15, 2010, one-third on July 15, 2011 and one-third on July 15, 2012. |
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Fiscal Year 2009 Option Exercises and Stock Vested Table
The following table summarizes stock option exercises and vesting of stock awards for each named executive officer during 2009.
| Name |
Option Awards | Stock Awards | ||||||
| Number of Shares Acquired on Exercise (#) |
Value Realized on Exercise ($)(1) |
Number of Shares Acquired on Vesting (#) |
Value Realized on Vesting ($) | |||||
| Matthew W. McCann |
0 | 0 | 0 | 0 | ||||
| Hilda Kouvelis |
0 | 0 | 0 | 0 | ||||
| Scott C. Larsen |
75,000 | 159,000 | 0 | 0 | ||||
| Jeffrey S. Mecom |
0 | 0 | 0 | 0 | ||||
| (1) | Amounts shown reflect the difference between the closing price of our common shares on the date of exercise and the exercise price of the stock options, multiplied by the number of shares shown in the column entitled “Number of Shares Acquired on Exercise.” |
Potential Payments Upon Termination or Change of Control
Employment Agreements. Pursuant to our employment agreements, if Messrs. Larsen or Mecom or Ms. Kouvelis is terminated (i) by us at any time without “cause” or (ii) by such named executed officer within sixty days of an event that constitutes “constructive dismissal”, then we will pay such named executed officer a lump sum amount (the “termination amount”). The termination amount for Mr. Larsen is equal to Mr. Larsen’s annual salary plus $15,000. The termination amount for Mr. Mecom and Ms. Kouvelis is equal to one-half of their respective annual salary plus $7,500.
Pursuant to our employment agreements, if a “change in control” results in either (i) the termination of employment of Mr. Larsen without cause within thirty days prior to or within one year after the change in control, or Mr. Mecom or Ms. Kouvelis without cause within thirty days prior to or within six months after the change in control, or (ii) a constructive dismissal of Mr. Larsen within one year, or of Mr. Mecom or Ms. Kouvelis within six months, of the change in control and such named executive officer elects to terminate his or her employment, we will pay Messrs. Larsen or Mecom or Ms. Kouvelis a lump sum amount equal to their respective termination amounts.
Under the employment agreements, Messrs. Larsen and Mecom and Ms. Kouvelis agreed to certain confidentiality and non-solicitation obligations during their employment and for a period of six months after their date of termination, and in order to receive the termination amount set forth in the agreements, they must first sign a release in the form set forth in their respective agreements.
For purposes of the employment agreements with Messrs. Larsen and Mecom and Ms. Kouvelis, termination for “cause” is deemed to exist if: (i) we determine in good faith and following a reasonable investigation that such named executive officer has committed fraud, theft or embezzlement from us; (ii) such named executive officer pleads guilty or nolo contendere to or is convicted of any felony or other crime involving moral turpitude, fraud, theft or embezzlement; (iii) such named executive officer substantially fails to perform his or her duties according to the terms of his or her employment (other than any such failure resulting from his or her disability) after we have given such named executive officer written notice setting forth the nature of the failure to perform the duties and a reasonable opportunity to correct it; (iv) a breach of any of the non-solicitation or confidentiality provisions of the employment agreement (provided that we act in good faith in determining that such a breach constitutes “cause”) or a material breach of any other provision of the employment agreement; or (v) such named executive officer has engaged in on-the-job conduct that materially violates our code of conduct or other policies, as determined in our sole discretion. Such named executive officer’s resignation in advance of an anticipated termination for “cause” also constitutes a termination for “cause.”
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A “constructive dismissal” is defined in the employment agreement as the occurrence of a material diminution in title and/or duties, responsibilities or authority or the implementation of a requirement that such named executive officer relocate from his or her present city of residence, not including: (i) a change consistent with our splitting a position into one or more positions in conjunction with a corporate reorganization based on the demands of such position so long as there is no reduction in such named executive officer’s annual salary or other remuneration or responsibilities taken as a whole; (ii) a change in such named executive officer’s position, duties or title with any of our subsidiaries, affiliates or associates; (iii) the occurrence of any of the aforesaid events with the consent of such named executive officer or termination of the employment of such named executive officer for just cause, death or disability, or (iv) in the case of Mr. Larsen, having the positions of chief executive officer and president held by two different individuals so long as Mr. Larsen occupies one or the other position.
A “change of control” is defined in the employment agreements as the occurrence of any of: (i) the purchase or acquisition of our common shares and/or securities convertible into our common shares or carrying the right to acquire our common shares (“Convertible Securities”) as a result of which a person, group of persons or persons acting jointly or in concert, or any affiliates or associates of any such person, group of persons or any of such persons acting jointly or in concert (collectively, the “Holders”) beneficially own or exercise control or direction over our common shares and/or Convertible Securities such that, assuming the conversion of the Convertible Securities beneficially owned by the Holders thereof, the Holders would have the right to cast more than 50% of the votes attached to all of our common shares; provided that, the acquisition of our common shares or Convertible Securities pursuant to the issuance of securities by us which results in a Holder beneficially owning or exercising control or direction over 50% of the votes attached to all of our common shares (assuming conversion of the Convertible Securities beneficially owned by Holders thereof) which is approved by our board of directors prior to the issuance of securities shall not constitute a “change of control;” or (ii) approval by our shareholders of: (A) an amalgamation, arrangement, merger or other consolidation or combination of us with another entity as a result of which our shareholders immediately prior to the transaction will not, immediately after the transaction, own securities of the successor or continuing entity which would entitle them to cast more than 50% of the votes attaching to all of the voting securities of the successor or continuing entity, (B) a liquidation, dissolution or winding-up of us, (C) the sale, lease or other disposition of all or substantially all of our assets, (D) the election at a meeting of our shareholders of a number of directors, who were not included in the slate for election as directors approved by the prior board of directors, and would represent a majority of the board of directors, or (E) the appointment of a number of directors which would represent a majority of the board of directors and which were nominated by any holder of our voting shares or by any group of holders of our voting shares acting jointly or in concert and not approved by the prior board of directors.
See “—Discussion Regarding Fiscal Year 2009, 2008 and 2007 Summary Compensation Table and Fiscal Year 2009 Grants of Plan-Based Awards Table—Employment Agreements” for additional discussion of the material terms of the employment agreements.
Option Plan. Pursuant to our Option Plan, upon the death of a named executive officer or if the named executive officer ceases to be an employee, officer or director within six months following a change of control of us, all unvested stock options held by such named executive officer would vest immediately. A change of control under the Option Plan includes, without limitation, the acquisition by any person (other than current largest registered shareholder) or group of related persons of more than 35% of our outstanding common shares.
Incentive Plan. Pursuant to our Incentive Plan, upon the occurrence of (i) a termination of service for any reason within six months of a change in control, or (ii) a termination of service due to death or total and permanent disability, all unvested restricted stock units would vest immediately. A change in control under the Incentive Plan occurs upon a change in ownership of us, our effective control or the ownership of a substantial portion of our assets, as follows:
| (a) | a change in ownership occurs on the date that any person, other than (i) us or any of our subsidiaries, (ii) a trustee or other fiduciary holding securities under an employee benefit plan of us or any of our affiliates, (iii) an underwriter temporarily holding stock pursuant to an offering of such stock, or (iv) a corporation owned, directly or indirectly, by our shareholders in substantially the same proportions as their ownership of our shares, acquires ownership of our shares that, together with shares held by such person, constitutes more than 50% of the total fair market value or total voting power of our shares. However, if any person is considered to own already more than 50% of the total fair market value or total voting power of our shares, the acquisition of additional shares by the same person is not considered to be a change of control. In addition, if any person has effective control of us through ownership of 30% or more of the total voting power of our shares, as discussed in paragraph (b), the acquisition of additional control of us by the same person is not considered to cause a change in control pursuant to this paragraph (a); or |
| (b) | a change in the effective control of us occurs on either (x) the date that any person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person) ownership of our shares possessing 30% or more of the total voting power of our |
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| shares. However, if any person owns 30% or more of the total voting power of our shares, the acquisition of additional control of us by the same person is not considered to cause a change in control pursuant to this subparagraph (b)(x); or (y) the date during any twelve (12) month period when a majority of members of the board is replaced by directors whose appointment or election is not endorsed by a majority of the board before the date of the appointment or election; provided, however, that any such director shall not be considered to be endorsed by the board if his or her initial assumption of office occurs as a result of an actual or threatened solicitation of proxies or consents by or on behalf of a person other than the board; or (z) the date that Mr. Mitchell ceases to serve as chairman of the board as a direct or indirect result of his sale of our common shares; or |
| (c) | a change in the ownership of a substantial portion of our assets occurs on the date that a person acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by such person) our assets, that have a total gross fair market value equal to at least 40% of the total gross fair market value of all of our assets immediately before such acquisition or acquisitions. However, there is no change in control when there is such a transfer to (i) our shareholder (immediately before the asset transfer) in exchange for or with respect to our shares; (ii) an entity, at least 50% of the total value or voting power of the stock of which is owned, directly or indirectly, by us; (iii) a person that owns directly or indirectly, at least 50% of the total value or voting power of our outstanding shares; or (iv) an entity, at least 50% of the total value or voting power of the stock of which is owned by a person that owns, directly or indirectly, at least 50% of the total value or voting power of our outstanding shares. |
Set forth below are the amounts that our named executive officers would have received if specified events had occurred on December 31, 2009. In calculating the amounts in the table, we based the stock distribution values on a price of $3.42 per share, which was the closing price of our common shares on December 31, 2009.
| Name |
Payment |
Termination Following a Change in Control ($) |
Termination Without Cause ($) |
Death ($) |
Disability ($) | |||||
| Matthew W. McCann |
Cash Severance Stock Options (1) Restricted Stock Units (2) |
— 36,501 476,922 |
— — — |
— 36,501 476,922 |
— — 476,922 | |||||
| Hilda Kouvelis |
Cash Severance Stock Options (1) Restricted Stock Units (2) |
87,500 54,750 261,839 |
87,500 — — |
— 54,750 261,839 |
— — 261,839 | |||||
| Scott C. Larsen |
Cash Severance Stock Options (1) Restricted Stock Units (2) |
265,000 — 574,779 |
265,000 — — |
— — |
— — 574,779 | |||||
| Jeffrey S. Mecom |
Cash Severance Stock Options (1) Restricted Stock Units (2) |
82,500 54,750 259,366 |
82,500 — — |
— 54,750 259,366 |
— — 259,366 |
| (1) | Represents the acceleration of vesting of unvested stock options as of December 31, 2009. The value shown is equal to the number of shares underlying unvested stock options multiplied by the difference between the share price as of December 31, 2009 and the exercise price of the options. |
| (2) | Represents the acceleration of vesting of unvested restricted stock units as of December 31, 2009. The value shown is equal to the number of restricted stock units multiplied by the share price as of December 31, 2009. |
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Fiscal Year 2009 Director Compensation Table
The following table provides information regarding director compensation during 2009. Messrs. Larsen and McCann do not receive any compensation for their services as directors because we compensate them as employees. Compensation for Messrs. Larsen and McCann is described in “— Fiscal Year 2009, 2008 and 2007 Summary Compensation Table” and the accompanying text.
| Name |
Fees Earned or Paid in Cash ($) |
Stock Awards ($)(1)(2)(3) |
Option Awards ($)(4) |
All Other Compensation ($) |
Total ($) | ||||||
| N. Malone Mitchell |
25,000 | 28,223 | 0 | 5,305,000 | (5) | 5,358,223 | |||||
| Brian E. Bayley |
25,000 | 28,223 | 0 | 0 | 53,223 | ||||||
| Alan C. Moon |
25,000 | 28,223 | 0 | 0 | 53,223 | ||||||
| Mel. G. Riggs |
25,000 | 0 | 0 | 0 | 25,000 | ||||||
| Michael D. Winn |
25,000 | 28,223 | 0 | 0 | 53,223 | ||||||
| (1) | Amounts shown do not reflect compensation actually received by the directors. Rather, the amounts represent the aggregate grant date fair value computed in accordance with ASC 718. The assumptions used in the calculation of the aggregate grant date fair value of restricted stock units are set forth under “Note 11—Stockholder’s equity” to our consolidated financial statements. |
| (2) | The stock awards vested in full on January 15, 2010. |
| (3) | The chart below reflects the aggregate number of outstanding stock awards held by each non-employee director as of December 31, 2009. |
| Director |
Number of Common Shares Subject to Stock Awards | |
| Mitchell |
37,802 | |
| Bayley |
37,802 | |
| Moon |
37,802 | |
| Riggs |
0 | |
| Winn |
37,802 |
| (4) | The directors did not receive any stock option awards during 2009. The chart below reflects the aggregate number of outstanding options held by each non-employee director as of December 31, 2009. |
| Director |
Number of Common Shares Subject to Option Awards | |
| Mitchell |
33,334 | |
| Bayley |
110,000 | |
| Moon |
110,000 | |
| Riggs |
0 | |
| Winn |
285,000 |
| (5) | This amount includes $5.3 million reimbursed to Riata pursuant to the Service Agreement, which includes payments to Riata for salaries and benefits for employees of Riata who provided technical and administrative services to us under the Service Agreement, other than our named executive officers, and an allocation of Riata’s overhead to us. Such amounts do not reflect actual payments made to Mr. Mitchell for his services as a director. See “Item 13. Certain Relationships and Related Transactions, and Director Independence—Certain Relationships and Related Transactions—Service Agreement” for a description of the material terms of the Service Agreement. |
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Elements of Director Compensation
Effective January 1, 2009, all non-employee directors, including the chairman, receive an annual fee of $50,000, one-half of which is paid in cash and one-half of which is paid in the form of restricted stock units issued under the Incentive Plan. Effective July 21, 2009, the chairman of our audit committee receives an additional annual fee of $25,000 in cash. Non-employee directors do not receive extra compensation for serving on the audit, compensation or corporate governance committees of our board or for serving as chairman of the compensation committee or corporate governance committee. Non-employee directors are reimbursed for travel and other expenses directly associated with company business.
Prior to 2009, directors were granted stock options upon their election to the board of directors, and in 2007 Messrs. Winn, Bayley and Moon received grants of 185,000, 85,000 and 85,000 stock options, respectively. Messrs. Mitchell and McCann received awards of stock options in connection with their appointments as director in 2009. Beginning in 2009, directors are awarded restricted stock units and no longer receive annual stock option awards as part of their compensation.
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. |
Equity Compensation Plan Information
The following table sets forth the number of common shares to be issued upon exercise of outstanding options issued pursuant to the Plans, the weighted average exercise price of such outstanding options and the number of common shares remaining available for future issuance under the Plans, at December 31, 2009.
| Plan Category |
Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants, and Rights |
Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights(1) |
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) |
||||
| Equity compensation plans approved by security holders |
5,686,289 | $0.88 | 24,640,256 | (2) | |||
| Equity compensation plans not approved by security holders |
0 | — | 0 | ||||
| Total |
5,686,289 | $0.88 | 24,640,256 |
Note:
| (1) | The weighted average exercise price does not take into account the shares issuable upon vesting of outstanding awards of restricted stock units, which have no exercise price. |
| (2) | Pursuant to the Incentive Plan, the maximum aggregate number of common shares reserved for issuance under both Plans may not exceed 10% of our common shares outstanding from time to time. As of December 31, 2009, there were 303,265,456 common shares outstanding. The number of common shares issuable pursuant to the Plans automatically increases as the number of issued and outstanding common shares increases. As of March 15, 2010, there were 303,565,456 common shares outstanding, 3,023,334 common shares (approximately 1.0% of the outstanding common shares) to be issued upon exercise of outstanding options under the Option Plan and 3,089,489 common shares (approximately 1.0% of the outstanding common shares) underlying restricted stock units awarded pursuant to the Incentive Plan. As of March 15, 2010, there were 24,243,722 common shares remaining available for future issuances under the Incentive Plan. |
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Security Ownership of Certain Beneficial Owners and Management
Our only outstanding class of equity securities is our common shares, par value $0.01 per share. The following table sets forth information known to us about the beneficial ownership of our common shares on March 15, 2010 by (i) each person or entity known to us to own beneficially more than five percent (5%) of our common shares, (ii) each director; (iii) each named executive officer; and (iv) all of our present executive officers and directors as a group.
Unless otherwise indicated in the footnotes, each person or entity listed in the following table has sole voting power and investment power over the common shares listed as beneficially owned by that person or entity. Percentages of beneficial ownership are based on 303,565,456 common shares outstanding on March 15, 2010. Unless otherwise indicated in the footnotes, the address for each listed person is c/o TransAtlantic Petroleum Ltd., 5910 N. Central Expressway, Suite 1755, Dallas, Texas 75206.
| Shares Beneficially Owned(1) | ||||||
| Name of Beneficial Owner |
Number | Percent | ||||
| N. Malone Mitchell, 3rd |
152,722,869 | (2) | 48.7 | % | ||
| Hilda Kouvelis |
236,666 | (3) | * | |||
| Scott C. Larsen |
1,259,506 | (4) | * | |||
| Matthew W. McCann |
1,424,999 | (5) | * | |||
| Jeffrey S. Mecom |
366,666 | (6) | * | |||
| Gary T. Mize |
0 | * | ||||
| Brian E. Bayley |
307,802 | (7) | * | |||
| Alan C. Moon |
366,415 | (8) | * | |||
| Mel G. Riggs |
60,000 | * | ||||
| Michael D. Winn |
687,802 | (9) | * | |||
| All executive officers and directors as a group (10 persons) |
157,432,725 | (10) | 49.9 | % | ||
| Dalea Partners, LP |
101,935,039 | (11) | 33.6 | % | ||
| 4801 Gaillardia Parkway |
||||||
| Suite 350 |
||||||
| Oklahoma City, OK 73142 |
||||||
| Longfellow Energy, LP |
49,583,333 | (12) | 15.8 | % | ||
| 4801 Gaillardia Parkway |
||||||
| Suite 350 |
||||||
| Oklahoma City, OK 73142 |
||||||
| FMR LLC |
19,673,851 | (13) | 6.5 | % | ||
| 82 Devonshire Street |
||||||
| Boston, MA 02109 |
||||||
| MSD Energy Investments, L.P. |
15,900,000 | (14) | 5.2 | % | ||
| 645 Fifth Avenue, 21st Floor |
||||||
| New York, NY 10022 |
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Notes:
| * | Less than 1% of the outstanding common shares. |
| (1) | Beneficial ownership as reported in the above table has been determined in accordance with Rule 13d-3 under the Exchange Act and is not necessarily indicative of beneficial ownership for any other purpose, including under Canadian securities laws. The number of common shares shown as beneficially owned includes common shares which for Canadian securities law purposes may not be beneficially owned but over which a person would be deemed to exercise control or direction. The number of common shares shown as beneficially owned includes common shares subject to options, common share purchase warrants, and restricted stock units (“RSUs”) that are currently exercisable or vested (in the case of RSUs) or that will become exercisable or vested within 60 days of March 15, 2010. Restricted stock units that are vested within 60 days and common shares subject to options or common share purchase warrants exercisable within 60 days after March 15, 2010 are deemed outstanding for computing the percentage of the person or entity holding such securities but are not outstanding for computing the percentage of any other person or entity. |
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| (2) | Based on Amendment No. 6 to Schedule 13D filed on December 3, 2009. According to the Amendment No. 6 to Schedule 13D, Dalea shares voting and dispositive power over 101,935,039 common shares, Dalea Management, LLC (“Dalea Management”) shares voting and dispositive power over 101,935,039 common shares, Riata TransAtlantic shares voting and dispositive power over 1,150,028 common shares, Longfellow shares voting and dispositive power over 49,583,333 common shares, Duet 8, LLC shares voting and dispositive power over 49,583,333 common shares and Mr. Mitchell has sole voting and dispositive power over 16,666 common shares and shared voting and dispositive power over 152,668,400 common shares. Dalea Management, LLC is the general partner of Dalea. Mr. Mitchell is a partner of Dalea and a manager of Dalea Management. Riata TransAtlantic is managed by Mr. Mitchell, and Mr. Mitchell is a manager of Duet 8, LLC. Also includes 10,000,000 common share purchase warrants that are held by Longfellow. Mr. Mitchell, his wife and children indirectly own 100% of Longfellow and may be deemed to beneficially own these shares. Mr. Mitchell is our chairman. Also includes 16,667 common shares subject to options and 37,802 common shares subject to RSUs. |
| (3) | Includes 200,000 common shares subject to options and 16,666 common shares subject to RSUs. |
| (4) | Includes 820,000 common shares subject to options and 50,000 common shares subject to RSUs. |
| (5) | Includes 33,000 common shares subject to options and 41,666 common shares subject to RSUs. |
| (6) | Includes 300,000 common shares subject to options and 16,666 common shares subject to RSUs. |
| (7) | Includes 110,000 common shares subject to options and 37,802 common shares subject to RSUs. |
| (8) | Includes 110,000 common shares subject to options and 37,802 common shares subject to RSUs. |
| (9) | Includes 285,000 common shares subject to options and 37,802 common shares subject to RSUs. Also includes 180,000 common shares held by MDW & Associates LLC. As the manager of MDW & Associates LLC, Mr. Winn may be deemed to beneficially own these shares. |
| (10) | Reflects the information in footnotes (1) through (9) above. |
| (11) | Based on Amendment No. 6 to Schedule 13D filed on December 3, 2009. Based on the Amendment No. 6 to Schedule 13D, Dalea shares voting and dispositive power over 101,935,039 common shares. Mr. Mitchell is a partner of Dalea and a manager of Dalea Management, the general partner of Dalea. Mr. Mitchell is our chairman. |
| (12) | Based on Amendment No. 6 to Schedule 13D filed on December 3, 2009. Based on the Amendment No. 6 to Schedule 13D, Longfellow shares voting and dispositive power over 49,583,333 common shares. Includes 10,000,000 common share purchase warrants. Mr. Mitchell, his wife and children indirectly own 100% of Longfellow. Mr. Mitchell is our chairman. |
| (13) | Based on a Schedule 13G filed on February 16, 2010. FMR LLC, acting through its subsidiaries, is the beneficial owner of 19,673,851 common shares. Fidelity Management & Research Company (“Fidelity”), a wholly-owned subsidiary of FMR LLC and an investment adviser registered under Section 203 of the Investment Advisers Act of 1940, is the beneficial owner of 10,385,151 of our common shares as a result of acting as investment adviser to various investment companies registered under Section 8 of the Investment Company Act of 1940. Edward C. Johnson 3d and FMR LLC, through its control of Fidelity, and the funds each has sole power to dispose of the 10,385,151 shares owned by the funds. Members of the family of Edward C. Johnson 3d, Chairman of FMR LLC, are the predominant owners, directly or through trusts, of Series B voting common shares of FMR LLC, representing 49% of the voting power of FMR LLC. The Johnson family group and all other Series B shareholders have entered into a shareholders’ voting agreement under which all Series B voting common shares will be voted in accordance with the majority vote of Series B voting common shares. Accordingly, through their ownership of voting common shares and the execution of the shareholders’ voting agreement, members of the Johnson family may be deemed, under the Investment Company Act of 1940, to form a controlling group with respect to FMR LLC. Neither FMR LLC nor Edward C. Johnson 3d, Chairman of FMR LLC, has the sole power to vote or direct the voting of shares owned directly by the Fidelity funds, which power resides with the funds’ Boards of Trustees. Fidelity carries out the voting of the shares under written guidelines established by the funds’ Boards of Trustees. Pyramis Global Advisors, LLC (“PGALLC”), an indirect wholly-owned subsidiary of FMR LLC and an investment adviser registered under Section 203 of the Investment Advisers Act of 1940, is the beneficial owner of 8,822,000 of our common shares as a result of it serving as investment adviser to institutional accounts, non-U.S. mutual funds or investment companies registered under Section 8 of the |
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| Investment Company Act of 1940 owning such shares. Edward C. Johnson 3d and FMR LLC, through its control of PGALLC, each has sole dispositive power over 8,822,000 shares and sole power to vote or to direct the voting of 8,822,000 shares owned by the institutional accounts or funds advised by PGALLC as reported above. Pyramis Global Advisors Trust Company (“PGATC”), an indirect wholly-owned subsidiary of FMR LLC and a bank as defined in Section 3(a)(6) of the Exchange Act, is the beneficial owner of 448,600 of our common shares as a result of it serving as investment adviser to institutional accounts owning such shares. Edward C. Johnson 3d and FMR LLC, through its control of PGATC, each has sole dispositive power over 448,600 shares and sole power to vote or to direct the voting of 280,200 shares owned by the institutional accounts managed by PGATC as reported above. FIL Limited (“FIL”) and various foreign-based subsidiaries provide investment advisory and management services to a number of non-U.S. investment companies and certain institutional investors. FIL, which is a qualified institution under section 240.13d-1(b)(1)(ii) of the Exchange Act, is the beneficial owner of 18,100 shares. Partnerships controlled predominantly by members of the family of Edward C. Johnson 3d, Chairman of FMR LLC and FIL, or trusts for their benefit, own shares of FIL voting stock with the right to cast approximately 47% of the total votes which may be cast by all holders of FIL voting stock. FMR LLC and FIL are separate and independent corporate entities and their boards of directors are generally composed of different individuals. FMR LLC and FIL are of the view that they are not acting as a “group” for purposes of Section 13(d) under the Exchange Act. |
| (14) | Based on a Schedule 13G/A filed on February 8, 2010. MSD Capital, L.P. is the general partner of MSD Energy Investments, L.P. and may be deemed to have or share voting and dispositive power over, and/or beneficially own, the common shares held by MSD Energy Investments, L.P. MSD Capital Management LLC is the general partner of MSD Capital, L.P. and may be deemed to have or share voting and/or dispositive power over, and beneficially own, the common shares held by MSD Capital, L.P. Michael S. Dell is the controlling member of, and may be deemed to beneficially own securities owned by MSD Capital Management LLC. |
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| Item 13. | Certain Relationships and Related Transactions, and Director Independence. |
Certain Relationships and Related Transactions
Service Agreement
Effective May 1, 2008, we entered into the Service Agreement with Longfellow, Viking, Longe, MedOil Supply, LLC and Riata (collectively, the “Service Entities”), under which we and the Service Entities agreed to provide technical and administrative services to each other from time to time on an as-needed basis. Under the terms of the Service Agreement, the Service Entities agreed to provide us upon our request certain computer services, payroll and benefits services, insurance administration services and entertainment services, and we and the Service Entities agreed to provide to each other certain management consulting services, oil and gas services and general accounting services (collectively, the “Services”). Under the terms of the Service Agreement, we pay, or are paid, for the actual cost of the Services rendered plus the actual cost of reasonable expenses on a monthly basis. We or the Service Entities may terminate the Service Agreement at any time by providing advance notice of termination to the other party.
Pursuant to the Service Agreement, the salary, bonus and benefits earned by each of our named executive officers are paid by Riata and we reimburse Riata for the actual cost thereof. In 2009, we reimbursed Riata $543,000 for the salary, bonus and benefits provided to the named executive officers. In addition, Barbara Pope, sister-in-law of Mr. Mitchell, and Terry Pope, brother-in-law of Mr. Mitchell, are employees of Riata and provide services to us under the Service Agreement. In 2009, we reimbursed Riata $56,597 and $36,352 for services provided by Ms. Pope and Mr. Pope, respectively, pursuant to the Service Agreement.
We recorded expenditures for the year ended December 31, 2009 of $15.8 million for goods and Services provided by the Service Entities pursuant to the Service Agreement or other arrangements, including salary, bonus and benefits reimbursements identified in the prior paragraph, of which $1.1 million was payable at December 31, 2009 and settled in cash during the first quarter of 2010. There were no amounts due to us from the Service Entities at December 31, 2009.
The following table provides a breakdown of reimbursements of actual costs and expenses made by us to the Service Entities under the Service Agreement:
| Service Agreement Category |
For the Year Ended December 31, 2009 | ||
| (in thousands) | |||
| Salaries and benefits for named executive officers |
$ | 543 | |
| Salaries and benefits for non-named executive officers |
5,206 | ||
| Inventory relating to drilling operations |
3,100 | ||
| Shipping |
200 | ||
| Travel, hotels and meals, excluding the use of Riata-owned aircraft |
539 | ||
| Computer equipment and software |
187 | ||
| Third party legal and professional fees |
104 | ||
| Equipment relating to drilling operations |
4,693 | ||
| Office and field expenses and supplies |
230 | ||
| Allocated overhead |
99 | ||
| Other |
243 | ||
| Leases |
516 | ||
| Total |
$ | 15,660 | |
Aircraft Reimbursements
In addition, we and Riata have an arrangement whereby our executive officers, employees, or consultants, or other persons providing Services to us under the Service Agreement, are permitted to use aircraft owned by Riata for company-related business travel. For the use of this aircraft, we reimburse Riata an amount per passenger equal to the cost of a business class ticket on a commercial airline for comparable travel. Riata bears 100% of the cost of fuel, landing fees and all other expenses incurred in connection with such flights in excess of the amount reimbursed by us. In each case, the actual cost of the flight exceeded the amount of the reimbursement by us. For 2009, we reimbursed Riata $164,000 for the use of this aircraft.
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Because this reimbursement is only for company-related business travel of persons providing Services to us and is integrally and directly related to the performance of such persons’ duties, our reimbursement is not compensation nor a perquisite to any of our directors or executive officers.
Transactions with Mr. Mitchell
Since the beginning of 2009, we have entered into various transactions with our chairman, Mr. Mitchell, and various companies formed and owned or controlled by Mr. Mitchell that are primarily focused on investing in international energy opportunities.
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.
Effective January 1, 2009, our wholly-owned subsidiary, TransAtlantic Turkey, Ltd., entered into a lease agreement under which it leases rooms, flats and office space at a resort hotel owned by Gundem Turizm Yatirim ve Isletme A.S. (“Gundem”), a Turkish company controlled by Mr. Mitchell. Under the lease agreement, TransAtlantic Turkey, Ltd. paid the Turkish Lira equivalent of $5,000 per month base rent and up to 45,000 Turkish Lira per month (approximately $30,000 per month) in operating expense reimbursement. The lease agreement expired December 31, 2009. Effective January 1, 2010, TransAtlantic Turkey, Ltd. and Gundem entered into an accommodation agreement under which it leases ten rooms at the hotel. Under the accommodation agreement, TransAtlantic Turkey pays the Turkish Lira equivalent of $10,000 per month. The amounts formerly paid under the lease agreement and paid under the accommodation agreement are included in amounts paid under the Service Agreement.
On March 20, 2009, our wholly-owned subsidiary, TransAtlantic Australia, purchased 15,025,528 shares of Incremental from Mr. Mitchell at a price of AUD $1.085 per share, the same price per share and pursuant to the same terms as the shares acquired from Incremental’s other shareholders, none of whom had any relationship with us. Mr. Mitchell had purchased the Incremental shares between October 27, 2008 and December 23, 2008 at an average price of AUD $0.99 per share. The total consideration paid by TransAtlantic Australia for Mr. Mitchell’s Incremental shares was $11.2 million.
On June 22, 2009, Dalea purchased 41,818,000 common shares at a price of Cdn$1.65 per share in a private placement of our common shares in the U.S. In addition, on June 22, 2009, we entered into a registration rights agreement with Canaccord Capital Corporation and Dalea, pursuant to which we agreed to register for resale under the Securities Act the 41,818,000 common shares purchased by Dalea and 56,559,300 common shares held by certain other investors. Under the registration rights agreement, we filed a registration statement with the SEC on July 20, 2009 to register 55,544,300 common shares for resale, which did not include the common shares held by Dalea. The registration statement was declared effective on September 29, 2009.
On July 27, 2009, our wholly-owned subsidiary, Viking International, purchased the I-13 drilling rig and associated equipment from Viking. Viking International paid $1.5 million in cash for the drilling rig and entered into a note payable to Viking 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, we amended and restated the terms of the note with Viking in connection with the purchase of the I-14 drilling rig and associated equipment from Viking. On February 19, 2010, Viking International purchased the I-14 drilling rig and associated equipment from Viking. Viking International paid $1.5 million in cash for the drilling rig and entered into an amended and restated note payable to Viking 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 in July 2009. 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. We paid $0 in principal under this note in 2009. Interest expense in 2009 under this note was $254,000, of which $99,000 was included in accrued liabilities at December 31, 2009. As of March 15, 2010, $11.5 million was outstanding under this note.
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On November 24, 2009, Dalea purchased 4,255,400 common shares at a price of Cdn$2.35 per share in a private placement of our common shares in the U.S. In addition, on November 24, 2009, we entered into a registration rights agreement with Canaccord Capital Corporation and Dalea, pursuant to which we agreed to register for resale under the Securities Act the 4,255,400 common shares purchased by Dalea and 44,043,390 common shares held by certain other investors. Under the registration rights agreement, we filed a registration statement with the SEC on December 23, 2009 to register 42,838,451 common shares for resale, which did not include the common shares held by Dalea. The registration statement was declared effective on January 7, 2010.
On December 15, 2009, Viking International entered into an Agreement for Management Services (“Management Services Agreement”) with Viking. Pursuant to the Management Services Agreement, Viking International agreed to provide management, marketing, storage and personnel services (collectively, the “Rig Services”) from time to time as requested by Viking for the operation of certain rigs (the “Rigs”) owned by Viking that are located in Turkey. Under the terms of the Management Services Agreement, Viking will pay Viking International for all actual costs and expenses associated with the provision of the Rig Services. In addition, Viking will pay Viking International a distribution equal to 5% of the net profits of each Rig, which is calculated as the gross revenues of each Rig less any and all expenses attributable to such Rig, including, but not limited to, the payment for services and insurance under the Management Services Agreement and depreciation. As of March 15, 2010, Viking International has not performed any services under the Management Services Agreement and has received no payments or distributions.
Mr. Mitchell and his wife own 100% of Riata and Dalea, and Mr. Mitchell is a manager of Riata TransAtlantic. In addition, Mr. Mitchell is a partner of Dalea and a manager of Dalea Management, the general partner of Dalea. Mr. Mitchell, his wife and children indirectly own 100% of Longfellow. Prior to our acquisition of Longe, Longe was owned by Longfellow. Riata owns 100% of MedOil Supply, LLC. Dalea owns 85% of Viking.
Policies and Procedures for Approving Related Party Transactions
Our board of directors adopted a Related Party Transactions Policy in December 2009. In accordance with our Related Party Transactions Policy, all Related Party Transactions and any material amendments to such Related Party Transactions must be reviewed and approved by our audit committee and, if necessary, recommended to our board of directors for its approval. Alternatively, the board may determine that a particular Related Party Transaction or a material amendment thereto shall instead be reviewed and approved by a majority of directors disinterested in the Related Party Transaction. If advance audit committee approval of a Related Party Transaction is not feasible, then the Related Party Transaction may be considered and, if the audit committee determines to be appropriate, ratified at the audit committee’s next regularly scheduled meeting. In determining whether to approve, recommend or ratify a Related Party Transaction, the audit committee will take into account, among other factors it deems appropriate, (i) whether the transaction is fair to us, (ii) whether the audit committee has all of the material facts regarding the transaction or parties involved, (iii) whether the transaction is generally available to an unaffiliated third-party under the same or similar circumstances and cost, and (iv) the extent of the Related Party’s interest in the transaction.
A “Related Party Transaction” means a transaction (including any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness)), or a series of transactions, or any material amendment to any such transaction, between us and any Related Party, other than (i) transactions available to all employees generally; (ii) transactions involving compensation of a director or executive officer or involving an employment agreement, severance agreement, change in control provision or agreement or special supplemental benefit of a director or executive officer; (iii) transactions in which the interest of the Related Party arises solely from the ownership of a class of our equity securities and all holders of that class receive the same benefit on a pro rata basis; or (iv) transactions in which the rates or charges involved therein are determined by competitive bids.
A “Related Party” means the following persons, or an entity owned by any such person: (i) an “executive officer” of us (as defined in Rule 405 under the Securities Act and Rule 3b-7 under the Exchange Act); (ii) a director of us or a nominee for director of us; (iii) a person (including any entity or group) known to us to be the beneficial owner of more than 5% of any class of our voting securities (a “5% shareholder”); or (iv) a person who is an “immediate family member” of an executive officer, director, nominee for director or 5% shareholder of us.
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Prior to the adoption of the Related Party Transactions Policy, we did not have a written policy. All related party transactions were subject to review and approval by the non-interested directors and were subject to procedures substantially similar to those adopted in our Related Party Transactions Policy.
Director Independence
The standards relied upon by the board of directors in affirmatively determining whether a director is “independent” are those set forth in the rules of the NYSE Amex Company Guide and National Instrument 52-110 of the Canadian Securities Regulators (“NI 52-110”), which generally provide that independent directors are persons other than our executive officers or employees. In addition, the following persons are not considered independent: (a) a director who is, or during the past three years was, employed by us, other than prior employment as an interim executive officer (provided the interim employment did not last longer than one year); (b) a director who accepted or has an immediate family member who accepted any compensation from us in excess of $120,000 (Cdn $75,000 under NI-52-110) during any period of twelve consecutive months within the three years preceding the determination of independence, other than compensation for board or board committee service, compensation paid to an immediate family member who is an employee (other than an executive officer), compensation received for former service as an interim executive officer (provided the interim employment did not last longer than one year), or benefits under a tax-qualified retirement plan, or non-discretionary compensation; (c) a director who is an immediate family member of an individual who is, or at any time during the past three years was, employed by us as an executive officer; (d) a director who is, or has an immediate family member who is, a partner in, or a controlling shareholder or an executive officer of, any organization to which we made, or from which we received, payments (other than those arising solely from investments in our securities or payments under non-discretionary charitable contribution matching programs) that exceed 5% of the organization’s consolidated gross revenues for that year, or $200,000, whichever is more, in any of the most recent three fiscal years; (e) a director who is, or has an immediate family member who is, employed as an executive officer of another entity where at any time during the most recent three fiscal years any of the issuer’s executive officers served on the compensation committee of such other entity; or (f) a director who is, or has an immediate family member who is, a current partner of our outside auditor, or was a partner or employee of our outside auditor who worked on our audit at any time during any of the past three years.
The NYSE Amex rules provide that members of the audit committee must also comply with the independence standards under Rule 10A-3 of the Exchange Act, which provide that a member of an audit committee of a company, other than an investment company, may not, other than in his or her capacity as a member of the audit committee, the board of directors, or any other board committee: (i) accept directly or indirectly any consulting, advisory, or other compensatory fee from the company or any subsidiary thereof, provided that compensatory fees do not include the receipt of fixed amounts of compensation under a retirement plan (including deferred compensation) for prior service with the company (provided that such compensation is not contingent in any way on continued service); or (ii) be an affiliated person of the company or any subsidiary thereof. NI 52-110 provides substantially similar independence standards for audit committee members.
In accordance with the NYSE Amex and NI 52-110 independence definitions, the board of directors also makes an affirmative determination that each potential independent director does not have any relationship which, in the board’s opinion, would interfere with the exercise of independent judgment in carrying out the responsibilities of a director.
The board of directors, in applying the above-referenced standards, has affirmatively determined that at least 50% of its members are “independent” within the meaning of the NYSE Amex rules and NI 52-110. Specifically, the board of directors has determined that each of Messrs. Bayley, Moon, Winn and Riggs are “independent” under these rules. In addition, the board has affirmatively determined that each of Messrs. Bayley, Moon, Winn and Riggs, who comprise our audit committee, meet the additional independence requirements applicable to audit committee members under the NYSE Amex rules and Rule 10A-3 under the Exchange Act. As part of the board’s process in making such determination, each such director provided written assurances that (a) all of the above-cited objective criteria for independence are satisfied and (b) he has no other “material relationship” with us that could interfere with his ability to exercise independent judgment.
In determining that the above directors are “independent,” the board considered the relationship of Mr. Bayley with Quest. We entered into a $3.0 million short term standby bridge loan with Quest in April 2007. We then increased the loan facility to $4.0 million in August of 2007 and issued 503,823 common shares to Quest as we drew down the loan. In November 2007 we paid down $2.0 million of principal on the loan, and then we repaid the loan in full on April 8, 2008. At the time of the Quest transactions, we had two directors in common with Quest and Mr. Bayley served as Quest’s chief executive officer. Mr. Bayley was not directly involved in the transaction and had no direct or indirect material interest in the transaction. This relationship does not disqualify Mr. Bayley from being deemed an independent director under the NYSE Amex and NI 52-110 rules, and the board has determined that this relationship does not interfere with his ability to exercise independent judgment.
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Mr. McCann, who serves as chief executive officer, and Mr. Larsen, who serves as president, are not independent. Mr. Mitchell, who serves as chairman of the board of directors, is not independent due to a combination of his indirect shareholdings and commercial relationships with us.
In May 2008, Mr. Mitchell was appointed as chairman of the board of directors. Mr. Mitchell is not an independent director but is not an officer of our company. Although historically the board has not held regularly scheduled meetings of the independent directors, the independent directors meet separately during a portion of the meetings for the compensation committee and corporate governance committee. Also, individual directors may engage an outside adviser at our expense, subject to the approval of the chairperson of the corporate governance committee. The board relies upon the foregoing processes and the level of experience and qualifications of its independent directors, particularly the chairperson of its corporate governance committee, to compensate for having a non-independent chairman of the board of directors. The board does not believe that any further leadership for its independent directors is required at this time.
| Item 14. | Principal Accountant Fees and Services. |
Fees paid to KPMG LLP
KPMG LLP is our principal accountant for our audit of annual financial statements included in this Annual Report on Form 10-K and served as our independent registered public accounting firm for 2009 and 2008. The following table shows the aggregate fees for professional services provided to us by KPMG LLP for 2009 and 2008.
| 2009 | 2008 | |||||
| Audit Fees |
$ | 700,697 | 166,000 | |||
| Audit-Related Fees |
370,056 | 131,000 | ||||
| Tax Fees |
62,665 | 121,000 | ||||
| All Other Fees |
15,000 | 0 | ||||
| Total |
$ | 1,148,418 | $ | 418,000 | ||
Audit Fees. This category includes the audit of our annual consolidated financial statements, reviews of our financial statements included in our Form 10-Qs and services that are normally provided by the independent auditors in connection with their engagements for those years. This category also includes advice on audit and accounting matters that arose during, or as a result of, the audit or the review of our interim financial statements.
Audit-Related Fees. This category consists of assurance and related services by the independent auditors that are reasonably related to the performance of the audit or review of our financial statements and are not reported above under “Audit Fees.” The services for the fees disclosed under this category include consents regarding acquisitions and equity issuances.
Tax Fees. This category consists of professional services rendered by our independent auditors for tax compliance and tax advice. The services for the fees disclosed under this category include tax return preparation and technical tax advice.
All Other Fees. This category consists of fees for other miscellaneous items.
Our board of directors has adopted a procedure for pre-approval of all fees charged by its independent auditors. Under the procedure, the audit committee of our board of directors approves the engagement letter with respect to audit, tax and review services. Other fees are subject to pre-approval by the audit committee. The audit, audit-related fees and tax fees paid to KPMG LLP with respect to 2009 were pre-approved by the audit committee.
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PART IV
| Item 15. | Exhibits and Financial Statement Schedules. |
| (a) | Documents filed as part of Report. |
| 1. | Report of Independent Registered Public Accounting Firm |
Consolidated Balance Sheets as of December 31, 2008 and 2009
Consolidated Statements of Operations and Comprehensive Loss for the years ended December 31, 2007, 2008 and 2009
Consolidated Statement of Stockholders’ Equity (Deficit) for the years ended December 31, 2007, 2008 and 2009.
Consolidated Statements of Cash Flows for the years ended December 31, 2007, 2008 and 2009
Notes to Consolidated Financial Statements
| 2. | Financial Statement Schedule: Schedule I, Condensed Financial Information of Registrant |
| 3. | Exhibits required to be filed by Item 601 of Regulation S-K |
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EXHIBIT INDEX
| 2.1 | Purchase Agreement, dated September 19, 2008, by and between Longfellow Energy, LP and TransAtlantic Petroleum Corp. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K dated September 19, 2008, filed with the SEC on September 25, 2008). | |
| 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 October 1, 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 | 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). | |
| 4.3 | Registration Rights Agreement, dated June 22, 2009, by and between TransAtlantic Petroleum Corp., Dalea Partners, LP and Canaccord Capital Corporation (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated June 22, 2009, filed with the SEC on June 25, 2009). | |
| 4.4 | Registration Rights Agreement, dated November 5, 2009, by and between TransAtlantic Petroleum Ltd., Dalea Partners, LP and Canaccord Capital Corporation (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated November 24, 2009, filed with the SEC on November 24, 2009). | |
| 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† | 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). | |
| 10.4† | 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). | |
| 10.5† | 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). | |
| 10.6† | 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). | |
| 10.7 | 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). | |
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| 10.8 | Investment Agreement, dated March 28, 2008, by and between TransAtlantic Petroleum Corp. and Riata Management, LLC (incorporated by reference to Exhibit 4.6 to the Company’s Annual Report on Form 20-F, filed with the SEC on May 14, 2008). | |
| 10.9† | 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). | |
| 10.10† | 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). | |
| 10.11 | 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). | |
| 10.12† | TransAtlantic Petroleum Corp. 2009 Long-Term Incentive Plan (incorporated by reference from Appendix B to the Definitive Proxy Statement filed by TransAtlantic Petroleum Corp. with the SEC on April 30, 2009). | |
| 10.13† | 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). | |
| 10.14† | 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). | |
| 10.15 | Credit Agreement 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 LC issuer, administrative agent, collateral agent and technical agent, dated as of December 21, 2009 (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). | |
| 21.1* | Subsidiaries of the Company. | |
| 23.1* | Consent of KPMG. | |
| 23.2* | Consent of DeGolyer and MacNaughton. | |
| 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 2, 2010. | |
| † | 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.
March 30, 2010
| TRANSATLANTIC PETROLEUM LTD. |
| /S/ MATTHEW MCCANN |
| Matthew 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 MCCANN |
Chief Executive Officer (Principal | March 30, 2010 | ||
| Matthew McCann | Executive Officer) |
|||
| /S/ HILDA KOUVELIS |
Chief Financial Officer | March 30, 2010 | ||
| Hilda Kouvelis | (Principal Financial Officer and Principal Accounting Officer/Controller) |
|||
| /S/ N. MALONE MITCHELL, 3RD |
Chairman | March 30, 2010 | ||
| N. Malone Mitchell, 3rd | ||||
| /S/ BRIAN E. BAYLEY |
Director | March 30, 2010 | ||
| Brian E. Bayley | ||||
| /S/ SCOTT C. LARSEN |
Director | March 30, 2010 | ||
| Scott C. Larsen | ||||
| /S/ ALAN C. MOON |
Director | March 30, 2010 | ||
| Alan C. Moon | ||||
| /S/ MEL G. RIGGS |
Director | March 30, 2010 | ||
| Mel G. Riggs | ||||
| /S/ MICHAEL D. WINN |
Director | March 30, 2010 | ||
| Michael D. Winn | ||||
Table of Contents
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULES
| Page | ||
| F-2 | ||
| F-3 | ||
| F-4 | ||
| Consolidated Statements of Operations and Comprehensive Loss |
F-5 | |
| F-6 | ||
| F-7 | ||
| F-8 |
F-1
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS OF TRANSATLANTIC PETROLEUM LTD.
We have audited TransAtlantic Petroleum Ltd.’s (the “Company”) internal control over financial reporting as of December 31, 2009, based on Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, 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 the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified and included in management’s assessment:
| • | The Company did not maintain adequate controls to facilitate the flow of information used in financial reporting throughout the organization. |
| • | The Company did not maintain an effective period-end financial statement closing process. |
| • | The Company did not design procedures to ensure detailed reviews and verification of inputs related to the analysis of accounts or transactions and schedules supporting financial statement amounts and disclosures. |
| • | The Company did not maintain effective monitoring controls over foreign operations in Istanbul. |
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Company. These material weaknesses were considered in determining the nature, timing, and extent of audit tests applied in our audit of the 2009 consolidated financial statements, and this report does not affect our report dated March 30, 2010, 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, the Company has not maintained effective internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).-
“KPMG LLP” (signed)
Calgary, Canada
March 30, 2010
F-2
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TO THE BOARD OF DIRECTORS AND STOCKHOLDERS OF TRANSATLANTIC PETROLEUM LTD.
We have audited the accompanying consolidated balance sheets of TransAtlantic Petroleum Ltd. and subsidiaries (the “Company”) as of December 31, 2009 and 2008, and the related consolidated statements of operations and comprehensive loss, stockholders’ equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2009. 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 the Company and subsidiaries as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 30, 2010 expressed an adverse opinion on the effectiveness of the Company’s internal control over financial reporting.
“KPMG LLP” (signed)
Calgary, Canada
March 30, 2010
F-3
Table of Contents
Consolidated Balance Sheets
As of December 31, 2009 and 2008
(in thousands of U.S. dollars, except share data)
| 2009 | 2008 | |||||||
| ASSETS |
||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 90,484 | $ | 30,052 | ||||
| Accounts receivable |
||||||||
| Oil and gas sales, net |
6,926 | — | ||||||
| Other |
2,827 | 1,327 | ||||||
| Prepaid and other current assets |
8,251 | 3,861 | ||||||
| Deferred income taxes (note 12) |
1,580 | — | ||||||
| Total current assets |
110,068 | 35,240 | ||||||
| Property and equipment (note 7): |
||||||||
| Oil and gas properties (successful efforts method) |
||||||||
| Mineral interests: |
||||||||
| Proved |
66,313 | — | ||||||
| Unproved |
12,363 | 1,732 | ||||||
| Drilling services and other equipment |
106,641 | 40,886 | ||||||
| 185,317 | 42,618 | |||||||
| Less accumulated depreciation, depletion and amortization |
(8,053 | ) | (53 | ) | ||||
| Property and equipment, net |
177,264 | 42,565 | ||||||
| Other assets: |
||||||||
| Restricted cash (note 5) |
7,780 | 3,268 | ||||||
| Deferred charges (notes 4 and 5) |
1,904 | 181 | ||||||
| Goodwill (note 4) |
10,067 | — | ||||||
| Total other assets |
19,751 | 3,449 | ||||||
| Total assets |
$ | 307,083 | $ | 81,254 | ||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY |
||||||||
| Current liabilities: |
||||||||
| Accounts payable |
$ | 7,385 | $ | 3,962 | ||||
| Accounts payable—related party (note 17) |
1,075 | 1,517 | ||||||
| Accrued liabilities |
12,172 | 581 | ||||||
| Settlement provision |
240 | 240 | ||||||
| Loans payable (note 10) |
1,595 | — | ||||||
| Loan payable—related party (notes 10 and 17) |
5,906 | — | ||||||
| Derivative liabilities (note 8) |
762 | — | ||||||
| Total current liabilities |
29,135 | 6,300 | ||||||
| Long-term liabilities: |
||||||||
| Asset retirement obligations (note 9) |
3,125 | 14 | ||||||
| Deferred income taxes (note 12) |
9,056 | — | ||||||
| Derivative liabilities (note 8) |
1,160 | — | ||||||
| Total long-term liabilities |
13,341 | 14 | ||||||
| Total liabilities |
42,476 | 6,314 | ||||||
| Commitments and Contingencies (notes 10, 15 and 16) |
||||||||
| Stockholders’ equity (note 11): |
||||||||
| Common shares, $0.01 par value, 1,000,000,000 shares authorized, issued and outstanding 303,265,456 as of December 31, 2009 and 154,957,781 as of December 31, 2008 |
3,033 | — | ||||||
| Additional paid in capital |
371,905 | 133,062 | ||||||
| Additional paid in capital—warrants |
5,435 | 5,228 | ||||||
| Accumulated other comprehensive income |
9,601 | — | ||||||
| Accumulated deficit |
(125,367 | ) | (63,350 | ) | ||||
| Total stockholders’ equity |
264,607 | 74,940 | ||||||
| Total liabilities and stockholders’ equity |
$ | 307,083 | $ | 81,254 | ||||
The accompanying notes are an integral part of these consolidated financial statements.
F-4
Table of Contents
Consolidated Statements of Operations and Comprehensive Loss
For the years ended December 31, 2009, 2008 and 2007
(U.S. dollars and shares in thousands, except per share amounts)
| 2009 | 2008 | 2007 | ||||||||||
| Revenues: |
||||||||||||
| Oil and gas sales |
$ | 27,681 | $ | 111 | $ | 653 | ||||||
| Oilfield services |
1,588 | — | — | |||||||||
| Total revenues |
29,269 | 111 | 653 | |||||||||
| Costs and expenses: |
||||||||||||
| Production |
10,168 | 73 | 1,167 | |||||||||
| Exploration, abandonment and impairment |
24,791 | — | — | |||||||||
| Seismic and other exploration |
10,538 | 7,901 | — | |||||||||
| International oil and gas activities |
12,349 | 5,183 | 2,312 | |||||||||
| General and administrative |
16,129 | 3,592 | 2,673 | |||||||||
| Depreciation, depletion and amortization |
7,942 | 53 | 80 | |||||||||
| Settlement provision |
— | — | (313 | ) | ||||||||
| Accretion of asset retirement obligations (note 9) |
164 | 6 | 72 | |||||||||
| Total costs and expenses |
82,081 | 16,808 | 5,991 | |||||||||
| Operating loss |
52,812 | 16,697 | 5,338 | |||||||||
| Other (income) expense: |
||||||||||||
| Interest and other expense |
2,748 | 116 | 728 | |||||||||
| Interest and other income |
(213 | ) | (338 | ) | (240 | ) | ||||||
| Loss on write-down of assets (note 6) |
— | — | 447 | |||||||||
| Loss on commodity derivative contracts (note 8) |
1,922 | — | — | |||||||||
| Foreign exchange loss |
3,449 | — | 45 | |||||||||
| Total other (income) expense |
7,906 | (222 | ) | 980 | ||||||||
| Loss before income taxes |
60,718 | 16,475 | 6,318 | |||||||||
| Income taxes, current |
2,142 | — | — | |||||||||
| Income tax recovery, deferred |
(843 | ) | — | — | ||||||||
| Net loss |
$ | 62,017 | $ | 16,475 | $ | 6,318 | ||||||
| Non controlling interest, net of tax |
129 | — | — | |||||||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
$ | 62,146 | $ | 16,475 | $ | 6,318 | ||||||
| Other comprehensive gain |
||||||||||||
| Foreign currency translation adjustment |
(9,601 | ) | — | — | ||||||||
| Comprehensive loss |
$ | 52,545 | $ | 16,475 | $ | 6,318 | ||||||
| Net loss per common share attributable to TransAtlantic Petroleum Ltd.: |
||||||||||||
| Basic and diluted net loss per common share attributable to TransAtlantic Petroleum Ltd. |
$ | 0.29 | $ | 0.25 | $ | 0.15 | ||||||
| Basic and diluted weighted average number of shares outstanding |
212,320 | 66,524 | 43,047 | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
Table of Contents
Consolidated Statement of Stockholders’ Equity (Deficit)
For the years ended December 31, 2009, 2008 and 2007
(U.S. dollars and shares in thousands)
| Common Shares |
Warrants (Shares) |
Common Shares ($) |
Additional Paid-in Capital |
Additional Paid-in Capital Warrants |
Accumulated Other Comprehensive Income (loss) |
Accumulated Deficit |
Non- Controlling Interest |
Total Stockholders’ Equity |
|||||||||||||||||||||||
| Balance at December 31, 2006 |
42,557 | 7,976 | — | $ | 45,851 | $ | 2,017 | — | $ | (40,557 | ) | $ | — | $ | 7,311 | ||||||||||||||||
| Issuance of common shares |
504 | — | — | 359 | — | — | — | — | 359 | ||||||||||||||||||||||
| Exercise of stock options |
185 | — | — | 138 | — | — | — | — | 138 | ||||||||||||||||||||||
| Exercise of warrants |
25 | (25 | ) | — | 33 | (7 | ) | — | — | — | 26 | ||||||||||||||||||||
| Expiration of warrants |
— | (3,232 | ) | — | 902 | (902 | ) | — | — | — | — | ||||||||||||||||||||
| Stock-based compensation |
— | — | — | 554 | — | — | — | — | 554 | ||||||||||||||||||||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
— | — | — | — | — | — | (6,318 | ) | — | (6,318 | ) | ||||||||||||||||||||
| 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 | ) | — | — | — | — | ||||||||||||||||||||
| Stock-based compensation |
— | — | — | 583 | — | — | — | — | 583 | ||||||||||||||||||||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
— | — | — | — | — | — | (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 |
— | — | — | — | — | — | — | — | — | ||||||||||||||||||||||
| Stock-based compensation |
— | — | — | 1,640 | — | — | — | — | 1,640 | ||||||||||||||||||||||
| Non-controlling interest |
— | — | — | — | — | — | — | 129 | 129 | ||||||||||||||||||||||
| Foreign currency translation adjustments |
— | — | — | — | — | 9,601 | — | — | 9,601 | ||||||||||||||||||||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
— | — | — | — | — | — | (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 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
Table of Contents
Consolidated Statements of Cash Flows
For the years ended December 31, 2009, 2008 and 2007
(in thousands of U.S. dollars)
| 2009 | 2008 | 2007 | ||||||||||
| Operating Activities: |
||||||||||||
| Net loss |
$ | (62,017 | ) | $ | (16,475 | ) | $ | (6,318 | ) | |||
| Adjustments to reconcile net loss to net cash used in operating activities: |
||||||||||||
| Impairment of assets |
290 | — | 447 | |||||||||
| Non-cash financing expense |
— | — | 359 | |||||||||
| Share-based compensation |
1,640 | 583 | 554 | |||||||||
| Foreign currency loss |
(492 | ) | — | — | ||||||||
| Unrealized loss on commodity derivative contracts |
1,922 | — | — | |||||||||
| Deferred tax recovery and other charges |
(843 | ) | — | — | ||||||||
| Depreciation, depletion and amortization |
7,942 | 53 | 80 | |||||||||
| Accretion of asset retirement obligations |
164 | 6 | 72 | |||||||||
| Changes in operating assets and liabilities, net of effect of acquisition: |
||||||||||||
| Accounts receivable |
(2,905 | ) | (761 | ) | (144 | ) | ||||||
| Prepaid expenses and other assets |
(2,384 | ) | (1,180 | ) | 39 | |||||||
| Settlement provision |
— | — | (721 | ) | ||||||||
| Accounts payable and accrued liabilities |
5,841 | 4,101 | (1,201 | ) | ||||||||
| Net cash used in operating activities |
(50,842 | ) | (13,673 | ) | (6,833 | ) | ||||||
| Investing activities: |
||||||||||||
| Acquisition of Incremental Petroleum Limited, net of cash (note 4) |
(37,934 | ) | — | — | ||||||||
| Acquisition of Incremental Petroleum Limited shares – related party (notes 4 and 17) |
(11,182 | ) | — | — | ||||||||
| Acquisition of Energy Operations Turkey, LLC (note 4) |
(6,192 | ) | — | — | ||||||||
| Additions to oil and gas properties |
(14,238 | ) | 3,760 | (4,126 | ) | |||||||
| Addition to drilling services and other equipment |
(46,471 | ) | (14,028 | ) | — | |||||||
| Proceeds from sale of assets |
— | — | 4,264 | |||||||||
| Deferred charges |
— | (181 | ) | — | ||||||||
| Restricted cash |
(4,512 | ) | (996 | ) | 2,067 | |||||||
| Net cash provided by (used in) investing activities |
(120,529 | ) | (11,445 | ) | 2,205 | |||||||
| Financing activities: |
||||||||||||
| Exercise of stock options and warrants |
575 | 1,661 | 164 | |||||||||
| Issuance of common shares |
181,481 | 53,769 | — | |||||||||
| Issuance of common shares – related party (note 11) |
70,167 | — | — | |||||||||
| Issuance costs |
(12,058 | ) | (484 | ) | — | |||||||
| Loan proceeds |
95 | — | 4,000 | |||||||||
| Loan proceeds – related party (note 10) |
64,621 | — | — | |||||||||
| Loan repayment |
(4,722 | ) | (2,000 | ) | (2,000 | ) | ||||||
| Loan repayment – related party (note 10) |
(64,621 | ) | — | — | ||||||||
| Senior credit facility placement costs |
(1,834 | ) | — | — | ||||||||
| Acquisition of non-controlling interest in Incremental Petroleum Limited (note 4) |
(2,761 | ) | — | — | ||||||||
| Net cash provided by financing activities |
230,943 | 52,946 | 2,164 | |||||||||
| Effect of exchange rate changes on cash |
860 | — | — | |||||||||
| Net increase (decrease) in cash and cash equivalents |
60,432 | 27,828 | (2,464 | ) | ||||||||
| Cash and cash equivalents, beginning of year |
30,052 | 2,224 | 4,688 | |||||||||
| Cash and cash equivalents, end of year |
$ | 90,484 | $ | 30,052 | $ | 2,224 | ||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-7
Table of Contents
Notes to Consolidated Financial Statements
1. General
Nature of operations
TransAtlantic Petroleum Ltd. (together with its subsidiaries, the “Company” or “TransAtlantic”) is a vertically integrated international oil and gas company engaged in the acquisition, exploration for and the development and production of crude oil and natural gas in Morocco, Romania, Turkey and California. Approximately 48.7% of the Company’s outstanding common shares are beneficially owned by N. Malone Mitchell, 3rd. Mr. Mitchell is the Chairman of the Company’s board of directors.
In 2008, the Company changed its operating strategy from that of a prospect generator to a vertically integrated project developer. To execute this new strategy:
| 1. | in December 2008, the Company acquired 100% of the issued and outstanding shares of Longe Energy Limited (“Longe”), in consideration for the issuance of 39,583,333 common shares of the Company and 10,000,000 common share purchase warrants (see note 4); |
| 2. | in December 2008, the Company closed a concurrent 35,416,667 common share private placement pursuant to which Dalea Partners, LP (“Dalea”), an entity 100% owned by Mr. Mitchell and his wife, and others invested $42.5 million in the Company. Both the Longe acquisition and the private placement were approved by the Company’s shareholders and closed in December 2008 (see note 4); |
| 3. | in April 2009, the Company acquired 100% of the issued and outstanding shares of Incremental Petroleum Limited (“Incremental”), an international oil and gas company that was publicly traded on the Australian Stock Exchange (see note 4); |
| 4. | in June 2009, the Company closed a Regulation S offering of common shares outside the United States and a concurrent Regulation D private placement inside the United States in which the Company sold an aggregate of 98,377,300 common shares at a price of Cdn $1.65 per common share, raising gross proceeds of approximately $143.1 million (see note 11); and |
| 5. | in November 2009, the Company 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 in which the Company sold an aggregate of 48,298,790 common shares at a price of Cdn $2.35 per share, raising gross proceeds of approximately $106.9 million (see note 11). |
Basis of presentation
The Company’s consolidated financial statements are expressed in U.S. Dollars and have been prepared by management in accordance with accounting principles generally accepted in the U.S. (“GAAP”). All amounts in these notes to the consolidated financial statements are in U.S. Dollars unless otherwise indicated. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews estimates, including those related to the impairment of long-lived assets and goodwill, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
F-8
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
2. Significant accounting policies
Basis of preparation
The Company’s reporting standard for the presentation of its consolidated financial statements is U.S. GAAP. The consolidated financial statements include the accounts of the Company and all majority-owned, controlled subsidiaries. All significant inter-company balances and transactions have been eliminated on consolidation.
Cash and cash equivalents
Cash and cash equivalents include term deposits and investments with original maturities of three months or less at the date of acquisition. The Company considers all highly-liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. The Company determines the appropriate classification of its investments in cash and cash equivalents and marketable securities at the time of purchase and reevaluates such designation at each balance sheet date.
Commodity derivative instruments
Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging (“ASC 815”) (formerly Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities), requires derivative instruments to be recognized as either assets or liabilities in the balance sheet at fair value. The accounting for changes in the fair value of derivative instruments depends on their intended use and resulting hedge designation. For derivative instruments designated as hedges, the changes in fair value are recorded in the balance sheet as a component of accumulated other comprehensive income (loss). Changes in the fair value of derivative instruments not designated as hedges are recorded as a gain or loss in the consolidated statements of operations. The Company does not designate its derivative financial instruments as hedging instruments and, as a result, recognizes the change in a derivative’s fair value currently in earnings as a component of other (income) expense.
Fair value measurements
The Company follows ASC 820, Fair Value Measurements and Disclosures (“ASC 820”) (formerly SFAS No. 157, Fair Value Measurements), which became effective for financial assets and liabilities of the Company on January 1, 2008 and non-financial assets and liabilities of the Company on January 1, 2009. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 does not require any new fair value measurements, but applies to assets and liabilities that are required to be recorded at fair value under other accounting standards. The impact to the Company from the adoption of ASC 820 in 2009 was not material.
Foreign currency translation
Effective January 1, 2009, the Company determined that the functional currency of its 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. 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. The Company has 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, the Company determined the appropriate functional currency was the local currency for each of these subsidiaries.
ASC 830, Foreign Currency Matters (“ASC 830”) (formerly SFAS No. 52, Foreign Currency Translation), requires the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation. Because the functional currency is now the local currency, translation adjustments will result from the process of translating subsidiary financial statements into the U.S. Dollar reporting currency. These translation adjustments will be 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. The change in functional currency will have no impact on the Company’s actual foreign-based revenues and expenditures in these countries.
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. These capitalized costs are amortized using the unit-of-production method based on estimated proved reserves. Proceeds from sales 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.
F-9
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
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 non-productive. 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.
Drilling services and other equipment
Drilling services and other equipment are stated at cost. Depreciation is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 7 years) of the respective assets. The costs of normal maintenance and repairs are charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of equipment sold, or otherwise disposed of, and the related accumulated depreciation are removed from the accounts and any gain or loss is reflected in current operations.
Impairment of long-lived assets
The Company follows the provisions of ASC 360, Property, Plant, and Equipment (“ASC 360”) (formerly SFAS No. 144, Accounting for Impairment or Disposal of Long-Lived Assets). ASC 360 requires that the Company’s long-lived assets, including drilling services 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.
Joint interest activities
Certain of the Company’s exploration, development and production activities are conducted jointly with other entities and accordingly the consolidated financial statements reflect only the Company’s proportionate interest in such activities.
Asset retirement obligations
The Company recognizes a liability for the present value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalizes an equal amount as a cost of the asset. The cost associated with the abandonment obligation is included in the computation of depreciation, depletion and amortization. The liability accretes until the Company settles the obligation. The Company uses a credit-adjusted risk-free interest rate in its calculation of asset retirement obligations.
Revenue recognition
Revenue from the sale of crude oil is recognized upon delivery to the purchaser when title passes. Drilling services revenues are recognized when the related service is performed.
Share-based compensation
The Company follows ASC 718, Compensation – Stock Compensation (“ASC 718”) (formerly SFAS No. 123R, Share-Based Payment), which requires the measurement and recognition of compensation expense for all share-based payment awards,
F-10
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
including employee stock options, based on estimated fair values. The value of the portion of the award that is ultimately expected to vest is recognized as an expense on a straight-line basis over the requisite vesting period. ASC 718 requires the Company to estimate the fair value of stock option awards on the date of grant using an option-pricing model. The Company uses the Black-Scholes option-pricing model (“Black-Scholes Model”) as its method of valuation for share-based awards. The Company’s determination of fair value of share-based payment awards on the date of grant using the Black-Scholes Model is affected by the Company’s stock price, as well as assumptions regarding a number of subjective variables. These variables include, but are not limited to, the Company’s expected stock price volatility over the term of the awards, as well as actual and projected exercise and forfeiture activity. The fair value of options granted to consultants, to the extent unvested due to required services not having been fully performed, are determined on subsequent reporting dates.
Income taxes
The Company follows the asset and liability method prescribed by ASC 740, Income Taxes (“ASC 740”) (formerly SFAS No. 109, Accounting for Income Taxes). Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under ASC 740, the effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in income in the period that includes the enactment date.
Pursuant to ASC 740, the Company does not have any unrecognized tax benefits other than those for which a valuation allowance has been provided thereon. The Company does not believe there will be any material changes in its unrecognized tax positions over the next twelve months. The Company’s policy is that it recognizes interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense. The Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any tax-related interest expense recognized during 2009, 2008 or 2007.
Comprehensive (gain) loss
ASC 220, Comprehensive Income (“ASC 220”) (formerly SFAS No. 130, Reporting Comprehensive Income), establishes standards for reporting and displaying comprehensive income and its components (revenue, expenses, gains and losses) in a full set of general-purpose financial statements. For the year ended December 31, 2009, the Company recorded an unrealized gain on foreign currency translation as other comprehensive gain. There were no differences between net loss and comprehensive loss in 2008 or 2007.
Business combinations
The Company follows ASC 805, Business Combinations (“ASC 805”) (formerly SFAS No. 141R, Business Combinations), and ASC 810-10-65, Consolidation (“ASC 810-10-65”) (formerly SFAS No. 160, Non-controlling Interests in Consolidated Financial Statements). 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 805 is effective for periods beginning on or after December 15, 2008 and has been applied to the Incremental and Energy Operations Turkey, LLC (“EOT”) acquisitions. ASC 810-10-65 requires 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.
Per share information
Basic per share amounts are calculated using the weighted average common shares outstanding during the year. The Company uses the treasury stock method to determine the dilutive effect of stock options and other dilutive instruments. Under the treasury stock method, only “in the money” dilutive instruments impact the diluted calculations in computing diluted earnings per share. Diluted calculations reflect the weighted average incremental common shares that would be issued upon exercise of dilutive options assuming the proceeds would be used to repurchase shares at average market prices for the period.
F-11
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
3. Accounting changes and recent pronouncements
Recent accounting pronouncements
In December 2008, the SEC adopted release no. 34-59192, Modernization of Oil and Gas Reporting, which revised the Regulation S-K and Regulation S-X oil and gas reporting requirements to align them with current industry practices and technological advances. The release revises a number of definitions relating to oil and gas reserves, permits the disclosure in filings with the SEC of probable and possible reserves and permits the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. In addition, the new disclosure requirements require a company to (i) disclose its internal control over reserves estimation and report the independence and qualification of its reserves preparer or auditor, (ii) file a report of a third party if the Company represents that the third party prepared reserves estimates or conducted a reserves audit, (iii) report oil and gas reserves using an average price based upon the prior 12-month period rather than period-end prices, and (iv) disclose, in narrative form, the status of proved undeveloped reserves and changes in status of these from period to period. The provisions of this release became effective for disclosures in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.
The FASB issued ASC 855, Subsequent Events (“ASC 855”) (formerly SFAS No. 165, Subsequent Events), on May 28, 2009. ASC 855 establishes general standards of accounting for, and disclosure of, events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Although there is new terminology, the standard is based on the same principles as those that currently exist in the auditing standards.
The Company has reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on its consolidated results of operations, financial position and cash flows. Based on that review, the Company believes that none of these pronouncements will have a significant effect on current or future earnings or operations.
4. Acquisitions
Energy Operations Turkey
On July 23, 2009, the Company’s wholly-owned subsidiary, TransAtlantic Worldwide Ltd., acquired all of the ownership interests in EOT for total consideration of approximately $7.7 million. EOT’s assets include interests in exploration licenses in southern and southeastern Turkey, inventory and seismic data. In connection with the purchase of EOT, TransAtlantic Worldwide Ltd. entered into an unsecured promissory note with the sellers in the amount of $1.5 million due July 23, 2010. The note bears interest at a fixed rate of 3% per annum.
The following tables summarize the consideration paid in the EOT acquisition, and the preliminary purchase price allocation of assets acquired and liabilities assumed recognized at the acquisition dates.
Consideration:
| (in thousands) | |||
| Cash consideration, net of purchase price adjustments |
$ | 6,215 | |
| Promissory note (note 10) |
1,500 | ||
| Fair value of total consideration transferred |
$ | 7,715 | |
Acquisition-Related Costs:
| Included in general and administrative expenses on the Company’s consolidated statement of operations for the year ended December 31, 2009 |
$ | 170 | |
F-12
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed at Acquisition:
| Financial assets: |
||||
| Cash, consisting of approximately 33,000 Turkish Lira |
$ | 23 | ||
| Accounts receivable |
96 | |||
| Total financial assets |
119 | |||
| Other current assets, consisting primarily of deposits |
807 | |||
| Oil and gas properties: |
||||
| Unproved properties |
1,900 | |||
| Materials and supplies inventories |
1,217 | |||
| Total oil and gas properties |
3,117 | |||
| Financial liabilities: |
||||
| Accounts payable, consisting of normal trade obligations |
(106 | ) | ||
| Other liabilities |
(37 | ) | ||
| Asset retirement obligations |
(37 | ) | ||
| Total financial liabilities |
(180 | ) | ||
| Total identifiable net assets |
$ | 3,863 | ||
| Goodwill |
$ | 3,852 | ||
Goodwill represents the excess of the purchase price of a business over the estimated fair value of the assets acquired and liabilities assumed. The Company recorded $3.9 million in goodwill for the acquisition of EOT. The goodwill relates to access to potential exploration and production opportunities in foreign jurisdictions.
EOT has historically generated significant losses, which resulted in approximately 37 million Turkish Lira in accumulated tax losses in Turkey at acquisition. The accumulated tax losses are fully reserved by a valuation allowance and no value was attributed at the acquisition date.
EOT’s results of operations are included in the Company’s consolidated results of operations beginning July 23, 2009. The amounts of EOT’s revenue and earnings included in the Company’s consolidated statement of operations for the twelve months ended December 31, 2009 is shown below:
| (in thousands) | ||||||
| Revenue | Loss | |||||
| Actual from July 23, 2009 through December 31, 2009 |
$ | 358 | $ | 464 | ||
Incremental Petroleum
On October 27, 2008, the Company announced its intention to make a cash takeover offer (the “Offer”) through TransAtlantic Australia Pty. Ltd. (“TransAtlantic Australia”), a wholly-owned subsidiary of the Company, for all of the outstanding common shares of Incremental, an international oil and gas company that was publicly traded on the Australian Stock Exchange. The Offer expired on March 6, 2009. As of March 6, 2009, the Company owned common shares of Incremental representing approximately 65.4% of Incremental’s outstanding common shares, and had received offers to acquire an additional approximately 11.6% of Incremental’s outstanding common shares. On March 20, 2009, the Company purchased 15,025,528 common shares of Incremental from Mr. Mitchell (see note 17). The Company acquired these shares from Mr. Mitchell for cash at a price of AUD $1.085 per share, the same price per share and pursuant to the same terms as the shares acquired from Incremental’s other shareholders, none of whom had any relationship with the Company. Incremental was delisted from the Australian Stock Exchange on March 26, 2009. At March 31, 2009, the Company had paid for and owned approximately 96% of the common shares of Incremental. On April 20, 2009, the Company paid for and completed the acquisition of the remaining 4% of Incremental’s common shares through an Australian statutory procedure. These shares were acquired at the same price per share as the previous share purchases. In addition, the Company agreed to purchase all of the outstanding options to acquire common shares of Incremental. On April 8, 2009, in exchange for the assignment of the Incremental options to the Company, the Company paid the Incremental option holders an aggregate of $721,000 in cash and issued them an aggregate of 101,585 common shares of the Company and 829,960 common share purchase warrants of the Company. Each warrant is exercisable through April 2, 2012 and entitles the holder to purchase one common share of the Company at an exercise price of $1.20 per
F-13
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
share. The common shares and common share purchase warrants were issued pursuant to an exemption from registration under Regulation S of the Securities Act of 1933, as amended (the “Securities Act”). The acquisition of Incremental was accounted for as a business combination.
The following tables summarize the consideration paid in the Incremental acquisition, and the preliminary purchase price allocation of assets acquired and liabilities assumed recognized at the acquisition dates, as well as the acquisition-date fair value of the non-controlling interests in Incremental:
Consideration:
| (in thousands) | |||
| Payment of cash amounting to AUD $83,036,483 for the acquisition of 76,532,473 shares of Incremental, translated into U.S. Dollars based on the exchanges rates in effect on the dates of the transactions, ranging from February 18, 2009 through March 20, 2009 |
$ | 53,942 | |
| Payment of cash to retire share-based payment arrangements of Incremental |
721 | ||
| Total cash consideration |
54,663 | ||
| Issuance of 101,585 common shares of the Company to retire share-based payment arrangements of Incremental |
71 | ||
| Issuance of 829,960 warrants to purchase the Company’s common shares to retire share-based payment arrangements of Incremental |
207 | ||
| Fair value of total consideration transferred |
$ | 54,941 | |
The fair value of the 101,585 common shares of the Company issued as part of the consideration paid in the Incremental acquisition was determined on the basis of the closing market price of the Company’s common shares on the acquisition date, or $0.70 per share. The fair value of the 829,960 warrants of the Company issued as part of the consideration paid in the Incremental acquisition was determined using the Black-Scholes Model using the following assumptions: strike price of $1.20 per share, expected life of three years based on management’s expectation that the warrants will not be exercised until near the end of the 36 month contractual term of the warrants, volatility of 40% based on a third party independent valuation of the warrants offered to the Incremental option holders, a 3.5% risk-free interest rate, and a forecasted dividend rate of 0% based on the Company’s historic dividends and future plans for paying dividends. The assumptions used in the Black-Scholes Model yielded a fair value of $0.25 per warrant.
Acquisition-Related Costs:
| Included in general and administrative expenses on the Company’s consolidated statement of operations for the year ended December 31, 2009, of which $181,000 was incurred in 2008 and recorded as a deferred charge as at December 31, 2008 |
$ | 817 | |
Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed at Acquisition:
| Financial assets: |
||||
| Cash, consisting of approximately $1.3 million, AUD $3.6 million and 3.5 million Turkish Lira |
$ | 5,547 | ||
| Accounts receivable |
4,317 | |||
| Total financial assets |
9,864 | |||
| Deferred income tax assets |
626 | |||
| Other current assets, consisting primarily of prepaid expenses |
1,022 | |||
| Oil and gas properties |
||||
| Unproved properties |
2,290 | |||
| Proved properties |
50,970 | |||
| Rigs and related equipment |
2,802 | |||
| Materials and supplies inventories |
1,313 | |||
| Total oil and gas properties |
57,375 | |||
| Financial liabilities: |
||||
| Accounts payable, consisting of normal trade obligations |
(1,773 | ) | ||
| Accrued liabilities, consisting primarily of accrued compensated employee absences |
(679 | ) | ||
| Current portion of long-term debt |
(2,765 | ) | ||
| Deferred income taxes |
(7,925 | ) | ||
| Long-term debt |
(1,217 | ) | ||
| Asset retirement obligations, consisting of future plugging and abandonment liabilities on Incremental’s developed wellbores as of March 5, 2009, based on internal and third-party estimates of such costs, adjusted for a historic Turkish inflation rate of approximately 7.9%, and discounted to present value using the Company’s credit-adjusted risk-free rate of 7.2% |
(3,025 | ) | ||
| Total financial liabilities |
(17,384 | ) | ||
| Total identifiable net assets |
$ | 51,503 | ||
| Fair value of non-controlling interest in Incremental, based on the Company’s acquisition of such interest on April 20, 2009 for AUD $3,475,399 |
$ | 2,761 | ||
| Goodwill |
$ | 6,199 | ||
F-14
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
Goodwill represents the excess of the purchase price of a business over the estimated fair value of the assets acquired and liabilities assumed. The Company recorded $6.2 million in goodwill on the acquisition of Incremental. The goodwill relates to access to potential exploration and production opportunities in foreign jurisdictions.
Incremental’s results of operations are included in the Company’s consolidated results of operations beginning March 5, 2009, which is the date the Company first acquired more than 50% of Incremental’s outstanding common shares. The amounts of Incremental’s revenue and earnings included in the Company’s consolidated statement of operations for the twelve months ended December 31, 2009 is shown below:
| (in thousands) | ||||||
| Revenue | Earnings | |||||
| Actual from March 5, 2009 through December 31, 2009 |
$ | 27,335 | $ | 560 | ||
The following table presents pro forma comparative data that reflects the Company’s revenue, income (loss) before income taxes, net income (loss) and income (loss) per share for the twelve months ended December 31, 2009 and 2008 as if the Incremental acquisition had occurred as of January 1, 2008:
| Unaudited | ||||||||
| December 31, 2009 (in thousands) |
December 31, 2008 (in thousands) |
|||||||
| Revenue |
$ | 33,764 | $ | 38,868 | ||||
| Income (loss) before income taxes |
(66,584 | ) | (16,895 | ) | ||||
| Net income (loss) |
(68,179 | ) | (20,786 | ) | ||||
| Basic and diluted income (loss) per share |
$ | (0.32 | ) | $ | (0.17 | ) | ||
Longe Energy
On September 19, 2008, the Company entered into a purchase agreement for the acquisition of all of the issued and outstanding shares of Longe from Longfellow Energy, LP (“Longfellow”), an entity indirectly owned by Mr. Mitchell, his wife and children, and agreed to make a concurrent private placement of common shares of the Company. The transactions closed on December 30, 2008 (the “Closing Date”). Longe became an indirect wholly-owned subsidiary of the Company on December 30, 2008. Pursuant to the terms of the purchase agreement, the Company acquired all of the issued and outstanding shares of Longe in consideration for the issuance of 39,583,333 common shares of the Company and 10,000,000 common share purchase warrants. Each warrant entitles the holder to purchase one common share of the Company at an exercise price of $3.00 per share through December 30, 2011. Concurrently with the acquisition, the Company issued 35,416,667 common shares at a price of $1.20 per share in a private placement with Dalea, Riata TransAtlantic, LLC (“Riata TransAtlantic”), Matthew McCann and other purchasers with business or familial relationships with Mr. Mitchell, resulting in gross proceeds of $42.5 million to the Company. Mr. Mitchell manages Riata TransAtlantic. Mr. McCann currently serves as the chief executive officer and a director of the Company and, at the time of the private placement, was a director of the Company. The Company recorded $1.1 million in transaction costs for the Longe acquisition and the concurrent private placement.
F-15
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
The purchase price of the Longe acquisition is as follows:
| (in thousands) | |||
| Fair value of TransAtlantic common shares |
$ | 28,104 | |
| Fair value of TransAtlantic common share purchase warrants—net |
5,228 | ||
| Transaction costs |
484 | ||
| Total purchase price |
$ | 33,816 | |
The fair value of the Company’s common shares used in determining the purchase price was $0.71 per share based on the closing price of the Company’s common shares on December 30, 2008. The fair value of the 10 million common share purchase warrants was determined using the Black-Scholes Model with the following assumptions: stock price of $0.71; volatility of 169%; dividend rate of 0%; risk-free interest rate of 1.67%; and term of three years.
The allocation of net assets acquired is as follows:
| (in thousands) | ||||
| Property and equipment |
$ | 32,350 | ||
| Deposits on equipment |
2,508 | |||
| Other |
128 | |||
| Accounts payable |
(1,170 | ) | ||
| Total net assets acquired |
$ | 33,816 | ||
Under the terms of the purchase agreement, the Company assumed Longe’s existing work commitments for drilling and other exploratory activities under its exploration permits in Morocco.
5. Restricted cash
Restricted cash represents cash placed in escrow accounts or in certificates of deposit that are pledged for the satisfaction of liabilities or performance guarantees. At December 31, 2009 and 2008, restricted cash included:
| December 31, | ||||||
| 2009 | 2008 | |||||
| (in thousands) | ||||||
| Non-current: |
||||||
| Work programs in Morocco – bank guarantees expiring in one year or less |
$ | 4,012 | $ | — | ||
| Work programs in Morocco – bank guarantees expiring in more than one year |
3,500 | 3,000 | ||||
| Settlement provision for Nigerian liabilities. |
240 | 240 | ||||
| Operator bond |
28 | 28 | ||||
| Total restricted cash |
$ | 7,780 | $ | 3,268 | ||
6. Discontinued operations and assets held for sale
In 2007, the Company designated certain oil and gas properties as held for sale in conjunction with its plan to sell its proved and undeveloped interests in the U.S, primarily in Texas. The Company recorded a write-down in 2007 of approximately $447,000. In November 2007, the Company sold certain properties in the U.S. for $4.3 million, and the buyer assumed an estimated $2 million in plugging and abandonment liability associated with the units. Two properties in Oklahoma have not been sold. In connection with the acquisition of Incremental, the Company acquired interests in non-operated properties in California. As a result of acquiring these properties in California, previously reported U.S. discontinued operations are now continuing and the results of operations in 2008 and 2007 previously reported as discontinued have been reclassified to operating revenues, costs and expenses.
F-16
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
7. Property and equipment
| (a) | Oil and gas properties. The following table sets forth the capitalized costs under the successful efforts method for oil and gas properties: |
| December 31, | |||||||
| 2009 | 2008 | ||||||
| (in thousands) | |||||||
| Oil and gas properties, proved |
|||||||
| Turkey |
$ | 66,313 | $ | — | |||
| Accumulated depreciation, depletion and amortization |
(2,483 | ) | — | ||||
| Oil and gas properties, unproved |
|||||||
| Morocco |
$ | 4,776 | $ | 103 | |||
| Romania |
3,072 | 402 | |||||
| U.S |
1,322 | — | |||||
| Turkey |
3,193 | 1,227 | |||||
| Net oil and natural gas properties |
$ | 76,193 | $ | 1,732 | |||
At December 31, 2009, the Company excluded $10.8 million from depletion for development wells currently in progress and for fields currently not in production. At December 31, 2008, the Company did not have any proved properties.
During the year ended December 31, 2009, the Company incurred approximately $32.2 million in exploratory drilling costs, of which $24.3 million was charged to earnings (included in exploration, abandonments and impairment expense) and $7.9 million remained capitalized at year end. The Company did not reclassify any of its exploratory well costs to proved properties during 2009.
Uncertainties affect the recoverability of these costs as the recovery of the costs outlined above are dependent upon the Company obtaining government approvals, obtaining and maintaining licenses in good standing and achieving commercial production or sale.
| (b) | Drilling services and other equipment. The historical cost of drilling services and other equipment, presented on a gross basis with accumulated depreciation is summarized as follows: |
| December 31, | ||||||||
| 2009 | 2008 | |||||||
| (in thousands) | ||||||||
| Drilling services equipment |
$ | 66,874 | $ | 35,924 | ||||
| Inventory |
22,001 | 4,293 | ||||||
| Gas gathering system and facilities |
7,612 | — | ||||||
| Seismic equipment |
6,786 | — | ||||||
| Vehicles |
1,822 | 301 | ||||||
| Office equipment and furniture |
1,546 | 368 | ||||||
| Accumulated depreciation |
(5,570 | ) | (53 | ) | ||||
| Net drilling services and other property and equipment |
$ | 101,071 | $ | 40,833 | ||||
At December 31, 2009, the Company excluded $7.6 million for the gas gathering system and facilities, $1.3 million of seismic equipment and $22.0 million of inventory from depreciation as the equipment had not been placed into service. At December 31, 2008, the Company excluded $40.0 million of equipment from depreciation as the equipment had not been placed into service.
8. Commodity derivative instruments
The Company utilizes collar derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of its future oil production. The Company has not designated the derivative financial instruments to which it is a party as hedges, and accordingly, records such contracts at fair value and recognizes changes in such fair value in current earnings as they occur.
The Company’s commodity derivative contracts are carried at their fair value on its consolidated balance sheet under either the caption “Derivative liabilities” or “Derivative assets.” The Company recognizes unrealized and realized gains and losses related to these contracts on a mark-to-market basis in its consolidated statement of operations under the caption “Gain (loss) on commodity derivative contracts.” Settlements of derivative contracts are included in operating cash flows on its consolidated statement of cash flows.
F-17
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
At December 31, 2009, the Company had outstanding contracts with respect to its future crude oil production as set forth in the table below:
| 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, 2010 — December 31, 2010 |
800 | $ | 61.50 | $ | 89.13 | $ | (762 | ) | |||||
| Collar |
January 1, 2011 — December 31, 2011 |
700 | $ | 61.50 | $ | 102.00 | (682 | ) | ||||||
| Collar |
January 1, 2012 — December 31, 2012 |
600 | $ | 61.50 | $ | 109.83 | (478 | ) | ||||||
| $ | (1,922 | ) | ||||||||||||
As of December 31, 2009, the Company recorded a net unrealized loss on commodity derivative contracts of $1.9 million on the above open derivative contracts. The Company was not party to any derivative contracts for the comparable periods of 2008 or 2007.
9. Asset retirement obligations
As part of its development of oil and gas properties, the Company incurs asset retirement obligations (“ARO”). The Company’s ARO results from its responsibility to abandon and reclaim its net share of all working interest properties and facilities. At December 31, 2009, the net present value of the Company’s total ARO is estimated to be $3.1 million, with the undiscounted value being $8.6 million. Total ARO at December 31, 2009 shown in the table below consists of amounts for future plugging and abandonment liabilities on the Company’s wellbores and facilities based on internal and third-party estimates of such costs, adjusted for inflation rate of approximately 6.5% per annum, and discounted to present value using the Company’s credit-adjusted risk-free rate of 7.2% per annum.
| 2009 | 2008 | ||||||
| (in thousands) | |||||||
| Asset retirement obligation January 1 |
$ | 14 | $ | 8 | |||
| Incremental acquisition (note 4) |
3,025 | — | |||||
| EOT acquisition (note 4) |
37 | — | |||||
| Change in estimates |
(1,163 | ) | — | ||||
| Foreign exchange change effect |
485 | — | |||||
| Additions |
563 | — | |||||
| Accretion expense |
164 | 6 | |||||
| Asset retirement obligation at December 31 |
$ | 3,125 | $ | 14 | |||
10. Loans payable
Senior credit facility
On December 21, 2009, the Company’s wholly-owned subsidiaries, DMLP, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd. (“TEMI”), Talon Exploration, Ltd. and TransAtlantic Turkey, Ltd. (collectively, the “Borrowers”) entered into a three year senior secured credit facility with Standard Bank Plc and BNP Paribas (Suisse) SA. The credit facility is guaranteed by the Company and each of Incremental Petroleum (Selmo) Pty. Ltd., TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (collectively, the “Guarantors”). The credit facility is secured by (i) receivables due 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 DMLP, Ltd., Talon Exploration, Ltd., TEMI and TransAtlantic Turkey, Ltd.; and (iv) substantially all of the present and future assets of the Borrowers. The initial borrowing base under the credit facility is $30 million, and the borrowing base will be re-determined at least semi-annually based on the Company’s hydrocarbon reserves in Turkey at December 31st and June 30th of each year. The lenders have aggregate commitments of $30 million. On June 21, 2011 and each three month anniversary thereof, the lenders’ commitments under the credit facility are subject to reduction by 14.3% of their commitments existing on March 21, 2011.
Loans under the credit facility will 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 credit facility will bear an additional interest rate of 2.0% per annum. As of December 31, 2009, the Company had not drawn on the facility. The Company has deferred $1.9 million in placement fees and issuance costs associated with the credit facility that will be amortized over the three-year contractual period, using the effective yield method.
Pursuant to the credit facility, TEMI entered into zero cost collars with Standard Bank Plc and BNP Paribas, which hedge the price of oil during 2010, 2011 and 2012 under the terms set forth below.
| Year |
Quantity (Bbl/day) |
Weighted Average Minimum Price (per Bbl) |
Weighted Average Maximum Price (per Bbl) | |||||
| 2010 |
800 | $ | 61.50 | $ | 89.13 | |||
| 2011 |
700 | $ | 61.50 | $ | 102.00 | |||
| 2012 |
600 | $ | 61.50 | $ | 109.83 | |||
F-18
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
Incremental loan
On November 28, 2008, the Company entered into a credit agreement (the “Credit Agreement”) with Dalea. The purpose of the Credit Agreement was to fund the cash takeover Offer by TransAtlantic Australia for all of the outstanding shares of Incremental (see notes 4 and 17).
Pursuant to the Credit Agreement, as amended, until June 30, 2009, the Company could request advances from Dalea of (i) up to $62 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 million for general corporate purposes. Advances under the Credit Agreement related to the Incremental acquisition were denominated in U.S. Dollars, but were advanced in Australian Dollars at an agreed upon currency exchange rate of AUD $1.00 to US $0.7024. Advances under the Credit Agreement for general corporate purposes were denominated and advanced in U.S. Dollars.
The aggregate unpaid principal balance, together with all accrued but unpaid interest was immediately due and payable by the Company upon the earliest of (i) April 20, 2010; (ii) the date of any change in ownership of or control or direction over, directly or indirectly, 20% or more of the outstanding voting securities of the Company; and (iii) the occurrence of an event of default.
The total outstanding balance of the advances made under the Credit Agreement accrued interest at a rate of 10% per annum, calculated daily and compounded quarterly. Interest was payable by the Company on the first day of each March, June, September, and December during the term of the loan. Following an event of default, the outstanding balance would accrue additional interest at a rate of 4% per annum until the event of default was cured or waived. The Company could prepay the loan at any time before maturity without penalty.
The Credit Agreement was secured by all of the personal property or assets of the Company’s wholly-owned subsidiary, TransAtlantic (Holdings) Australia Pty. Ltd., including all of the ordinary shares in the capital of TransAtlantic Australia.
The Company borrowed an aggregate of $64.6 million under the Credit Agreement and paid $2.0 million in interest during 2009. The loan was repaid in full on June 23, 2009, at which time the Credit Agreement was terminated.
TEMI loans
Upon the acquisition of Incremental, the Company became party to a loan which TEMI had entered into (the “TEMI Credit Agreement”) with Turkiye Garanti Bankasi. TEMI borrowed $5.5 million under the TEMI Credit Agreement in order to fund drilling and development activity in the Selmo oil field. The amortizing loan had a fixed interest rate of 7.6% per annum, and all outstanding principal and interest under the TEMI Credit Agreement was due August 6, 2010. The TEMI Credit Agreement was repaid in full during December 2009, at which time the TEMI Credit Agreement was terminated.
In addition, TEMI has entered into unsecured non-interest bearing stand-by credit agreements with a local bank. At December 31, 2009, there were outstanding borrowings of $95,000, bank guarantees totaling 540,000 Turkish Lira (approximately $350,000), and a $324,000 bank guarantee issued in September 2009 related to TEMI’s Istanbul office lease under these lines.
The following table details the Company’s outstanding fixed-rate debt:
| Fixed Rate Debt |
Amount | Rate | Principal Due In | ||||||||||
| (in thousands) | |||||||||||||
| 2010 | 2011 | Thereafter | |||||||||||
| At December 31, 2008 |
— | — | — | — | |||||||||
| Current |
|||||||||||||
| TEMI – unsecured line of credit |
$ | 95 | — | % | $ | 95 | — | — | |||||
| Related party promissory note (notes 17 and 19) |
$ | 5,906 | 10.0 | % (1) | $ | 5,906 | — | ||||||
| EOT acquisition promissory note (note 4) |
$ | 1,500 | 3.0 | % | $ | 1,500 | — | — | |||||
| At December 31, 2009 |
$ | 7,501 | $ | 7,501 | — | — | |||||||
| (1) | On February 19, 2010, the related party note was amended. See note 19. |
The Company uses the negotiated rates in determining the fair value of the debt.
F-19
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
11. Stockholders’ equity
November 2009 share issuance
On November 24, 2009, the Company 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, the Company sold 48,298,790 common shares at a price of Cdn $2.35 per common share, raising gross proceeds of approximately Cdn $113.5 million (approximately $106.9 million). Of the 48,298,790 common shares sold, the Company offered and sold 4,255,400 common shares to Dalea. The Company intends to use the proceeds from the offering for its 2010 capital expenditures program and for general corporate purposes. Concurrently with the offerings, the Company 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 of approximately Cdn $1.76 million (approximately $1.66 million). In connection with these offerings, the Company entered into a registration rights agreement providing for the registration of up to 48,298,790 common shares issued in these offerings (the “Registrable Securities”), of which 42,838,451 shares have been registered for resale under the Securities Act.
Pursuant to the registration rights agreement, on December 23, 2009, the Company filed a registration statement on Form S-1 registering the resale of 42,838,451 common shares. The registration statement was declared effective on January 7, 2010. The Company is required to use its commercially reasonable efforts to keep the registration statement effective until all of the Registrable Securities have been sold or may be sold pursuant to Rule 144 of the Securities Act by non-affiliates of the Company. The Company will pay the holders of the Registrable Securities liquidated damages in cash equal to 1% of the purchase price of the Registrable Securities held by them on May 24, 2010 (approximately Cdn $1 million or $975,000), if the Company (a) is not on such date subject to the reporting requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”); (b) has not been for a period of at least 90 days immediately before such date, subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act; or (c) has not filed all required reports under Section 13 or 15(d) of the Exchange Act, as applicable, during the twelve months preceding such date, other than Form 8-K reports, as a result of which the holders of Registrable Securities who are not affiliates of the Company would not be able to sell their Registrable Securities under Rule 144.
Notwithstanding the foregoing, in no event will Dalea, an entity controlled by the Company’s chairman, Mr. Mitchell, be entitled to receive any liquidated damages under the registration rights agreement. The Company has not recorded a liability for liquidated damage payments under the registration rights agreement.
June 2009 share issuance
On June 22, 2009, the Company closed a Regulation S offering of common shares outside the United States and a concurrent Regulation D private placement inside the United States to accredited investors. In the aggregate, the Company sold 98,377,300 common shares at a price of Cdn $1.65 per common share, raising gross proceeds of approximately Cdn $162.3 million (approximately $143.1 million). Of the 98,377,300 common shares sold, the Company offered and sold 41,818,000 common shares to Dalea. In connection with these offerings, the Company entered into a registration rights agreement providing for the registration of up to 98,377,300 common shares issued in these offerings, of which 55,544,300 shares have been registered for resale under the Securities Act.
April 2009 equity issuance in connection with the Incremental acquisition
In April 2009, the Company issued 101,585 common shares of the Company and 829,960 common share purchase warrants of the Company to retire share-based payment arrangements of Incremental. Each warrant is exercisable through April 2, 2012 and entitles the holder to purchase one common share of the Company at an exercise price of $1.20 per share (see note 4).
December 2008 private placement of shares and Longe acquisition
In December 2008, the Company acquired 100% of the issued and outstanding shares of Longe from Longfellow in consideration for the issuance of 39,583,333 common shares of the Company and 10,000,000 common share purchase warrants. Each warrant entitles the holder to purchase one common share at an exercise price of $3.00 per share through December 30, 2011. Concurrently, the Company issued 35,416,667 common shares at a price of $1.20 per share in a private placement with Dalea, Riata TransAtlantic, Matthew McCann and other purchasers with business or familial relationships with Mr. Mitchell, resulting in gross proceeds of $42.5 million. Mr. Mitchell manages Riata TransAtlantic. Mr. McCann currently serves as the chief executive officer and a director of the Company and, at the time of the private placement, was a director of the Company. The Company recorded $1.1 million in transaction costs for the Longe acquisition and the concurrent private placement.
F-20
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
April and May 2008 private placement of shares
In April and May 2008, the Company issued 10,000,000 common shares and 25,000,000 common shares, respectively, to Riata TransAtlantic, Dalea and certain friends and family of Mr. Mitchell in connection with a two-stage private placement transaction announced in March 2008. The private placements resulted in gross proceeds of Cdn $12 million.
Restricted stock units
On February 9, 2009, the Company’s board of directors approved the Company’s 2009 Long-Term Incentive Plan (the “Incentive Plan”), pursuant to which the Company can award restricted stock units (“RSUs”) and other share-based compensation to certain of its directors, officers, employees and consultants. In addition, on February 9, 2009, the Company’s board of directors approved awards of RSUs to certain directors, officers, employees and consultants. The Incentive Plan was approved at the Company’s annual and special meeting of shareholders on June 16, 2009. Share-based compensation expense of $1.2 million, $0, and $0 with respect to RSU awards was recorded for the years ended December 31, 2009, 2008 and 2007, respectively.
Under the Incentive Plan, RSUs vest over specified periods of time ranging from immediately to four years. RSUs are deemed full value awards and their value is equal to the market price of the Company’s common shares on the grant date. ASC 718 requires that the Incentive Plan be approved in order to establish a grant date. Under ASC 718, the approval date for the Incentive Plan was February 9, 2009, the date the board of directors approved the Incentive Plan.
Each RSU is equal in value to one common share of the Company on the grant date. Upon vesting, an employee is entitled to a number of common shares of the Company equal to the number of vested RSUs. The RSU awards can only be settled in common shares. As a result, RSUs are classified as equity. At the grant date, the Company makes an estimate of the forfeitures expected to occur during the vesting period and adjusts its compensation cost accordingly. The current forfeiture rate is estimated to be 10%. The following table sets forth RSU activity for year ended December 31, 2009:
| Number of Units (in thousands) |
Weighted Average Grant Date Fair Value | |||||
| Unvested restricted stock units outstanding at December 31, 2008 |
— | — | ||||
| Granted |
2,363 | $ | 1.23 | |||
| Unissued grants |
(3 | ) | $ | 2.64 | ||
| Vested |
(248 | ) | $ | 1.02 | ||
| Unvested restricted stock units outstanding at December 31, 2009 |
2,112 | $ | 1.25 | |||
As of December 31, 2009, the Company had approximately $1.3 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over 2.5 years.
Stock option plan
The Company’s Amended and Restated Stock Option Plan (2006) (the “Option Plan”) terminated on June 16, 2009. All outstanding awards issued under the Option Plan remained in full force and effect. All options presently outstanding under the Option Plan have a five-year term.
Under the Black-Scholes Model, the fair value of all outstanding options under the Option Plan is calculated at approximately $383,000, $583,000 and $554,000 and is recognized as share-based compensation expense for the year ended December 31, 2009, 2008 and 2007, respectively. At December 31, 2009, the unamortized amount of share-based compensation expense was $70,000, which is expected to be recognized over a weighted average period of less than one year. The Company did not grant any stock options during the year ended December 31, 2009. The estimated average grant date fair value of options issued during 2008 and 2007 was $1.16 and $0.40, respectively, determined using the Black-Scholes Model with the following assumptions:
| Option Value Inputs |
2008 | 2007 | ||||
| Risk free interest rate |
1.7 | % | 4.2 | % | ||
| Expected option life |
5 Years | 5 Years | ||||
| Volatility in the price of the Company’s shares |
74-77 | % | 71-172 | % | ||
| Forfeiture |
10 | % | 10 | % |
F-21
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
Details of the Option Plan at December 31, 2009, 2008 and 2007 are presented below.
| 2009 | 2008 | 2007 | |||||||||||||||||||
| Number of Options |
Weighted Average Exercise Price |
Number of Options |
Weighted Average Exercise Price |
Number of Options |
Weighted Average Exercise Price |
||||||||||||||||
| Outstanding at January 1, |
4,413 | $ | 0.85 | 4,285 | $ | 0.80 | 2,280 | $ | 0.87 | ||||||||||||
| Granted |
— | — | 440 | 1.25 | 2,270 | 0.72 | |||||||||||||||
| Expired |
(310 | ) | (0.90 | ) | (65 | ) | (0.93 | ) | (80 | ) | (0.82 | ) | |||||||||
| Exercised |
(780 | ) | (0.74 | ) | (247 | ) | (0.60 | ) | (185 | ) | (0.74 | ) | |||||||||
| Outstanding at December 31, |
3,323 | 0.88 | 4,413 | $ | 0.85 | 4,285 | $ | 0.80 | |||||||||||||
| Exercisable at December 31, |
3,177 | 0.86 | 3,553 | $ | 0.83 | 2,957 | $ | 0.83 | |||||||||||||
The following table summarizes information about stock options as of December 31, 2009:
| Options Outstanding |
Options Exercisable |
||||||||||||||||
| Range of Prices |
Shares | Weighted- Average |
Intrinsic Value- | Shares | Weighted- Average |
Intrinsic Value- | Weighted- Average Options Exercisable Life | ||||||||||
| Low | High | (in thousands) |
Exercise Price |
(in thousands) |
(in thousands) |
Exercise Price |
(in thousands) |
(years) | |||||||||
| $0.31 | $ | 0.74 | 745 | $0.31 | $2,317 | 745 | $0.31 | $2,317 | 2.93 | ||||||||
| $0.75 | $ | 0.99 | 475 | $0.90 | $1,197 | 475 | $0.90 | $1,197 | 0.78 | ||||||||
| $1.00 | $ | 1.20 | 1,680 | $1.03 | $4,015 | 1,680 | $1.03 | $4,015 | 1.88 | ||||||||
| $1.23 | $ | 1.32 | 423 | $1.25 | $918 | 277 | $1.25 | $601 | 3.48 | ||||||||
| 3,323 | $0.88 | $8,447 | 3,177 | $0.86 | $8,130 | 2.16 | |||||||||||
12. Income taxes
On October 1, 2009, the Company continued out of Canada into Bermuda. Based upon a preliminary valuation, the Company believes its estimated value is below its tax basis. The income tax provision differs from the amount that would be obtained by applying the Bermuda income tax rate of 0% (for 2009) and the Canadian basic federal and provincial income tax rate (for 2008 and 2007) to net loss for the year as follows:
| (in thousands) | 2009 | 2008 | 2007 | |||||||||
| (in thousands) | ||||||||||||
| Statutory tax rate |
0.00 | % | 29.50 | % | 32.12 | % | ||||||
| Loss before tax |
$ | (60,718 | ) | $ | (16,475 | ) | $ | (6,318 | ) | |||
| Expected income tax reduction |
— | (4,860 | ) | (2,029 | ) | |||||||
| Increase (decrease) resulting from |
||||||||||||
| Stock-based compensation |
85 | 172 | 178 | |||||||||
| Change in tax rate due to operating jurisdiction |
(4,696 | ) | (366 | ) | 787 | |||||||
| Expiration of tax deductions |
— | 102 | 95 | |||||||||
| Change in valuation allowance |
(3,519 | ) | 5,160 | 1,154 | ||||||||
| Continuance out of Canada |
8,601 | — | — | |||||||||
| Other |
828 | (208 | ) | (185 | ) | |||||||
| Total |
$ | 1,299 | $ | — | $ | — | ||||||
F-22
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
The components of the net deferred income tax liability at December 31, 2009, 2008 and 2007 are as follows:
| (in thousands) | 2009 | 2008 | 2007 | |||||||||
| Deferred income tax liabilities |
||||||||||||
| Property and equipment |
$ | (11,725 | ) | $ | — | $ | — | |||||
| Foreign exchange losses |
(28 | ) | $ | — | $ | — | ||||||
| Deferred income tax assets |
||||||||||||
| Property and equipment |
563 | 260 | 268 | |||||||||
| Operating loss carry-forwards |
24,021 | 18,849 | 13,844 | |||||||||
| Capital loss carry-forwards |
— | 1,112 | 959 | |||||||||
| Unrealized derivative loss |
395 | — | — | |||||||||
| Inventories |
423 | — | — | |||||||||
| Accrued liabilities & other |
1,064 | — | — | |||||||||
| Share issue costs |
— | 54 | 112 | |||||||||
| Provision for asset retirement |
698 | — | — | |||||||||
| Debt financing fees |
— | 68 | — | |||||||||
| Valuation allowance |
(22,887 | ) | (20,343 | ) | (15,183 | ) | ||||||
| Net deferred tax asset (liability) |
$ | (7,476 | ) | $ | — | $ | — | |||||
The Company has accumulated losses or resource-related deductions available for income tax purposes in Turkey, Romania and the U.S. No recognition has been given in these consolidated financial statements to the future benefits that may result from the utilization of losses for income tax purposes. The Company has non-capital tax losses in Turkey of approximately 77.6 million Turkish Lira (approximately $51.3 million), which expire commencing in 2011; non-capital losses in Romania of approximately 22.2 million Romanian New Leu (approximately $7.5 million), which expire commencing in 2011; and non-capital losses in the U.S. of approximately $32.5 million, which expire commencing in 2010.
Effective October 1, 2009, the Company continued to the jurisdiction of Bermuda. The Company has determined that no taxes were payable upon the continuance. However, the Company’s tax filing positions can still be subject to review by taxation authorities who may successfully challenge the Company’s interpretation of the applicable tax legislation and regulations, with the result that additional taxes could be payable by the Company.
F-23
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
13. Segment information
In accordance with ASC 280, Segment Reporting (“ASC 280”) (formerly SFAS No. 131, Disclosures about Segments of an Enterprise and Related Information), the Company has two reportable operating segments, exploration and production of oil and natural gas (“E&P”) and drilling services, within three reportable geographic segments: Romania, Turkey and Morocco. Summarized financial information concerning the Company’s geographic segments is shown in the following tables:
| Corporate | Romania | Turkey | Morocco | Total | ||||||||||||||||
| (in thousands) | ||||||||||||||||||||
| For the year ended December 31, 2009 |
||||||||||||||||||||
| Net revenues |
$ | 135 | $ | — | $ | 30,450 | $ | — | $ | 30,585 | ||||||||||
| Inter-segment revenue |
— | — | (1,316 | ) | — | (1,316 | ) | |||||||||||||
| Total revenues |
135 | — | 29,134 | — | 29,269 | |||||||||||||||
| Production |
211 | 34 | 9,854 | 69 | 10,168 | |||||||||||||||
| Exploration, abandonment and impairment |
2,305 | 6,586 | 4,944 | 10,956 | 24,791 | |||||||||||||||
| Seismic and other exploration |
463 | 98 | 7,234 | 2,743 | 10,538 | |||||||||||||||
| International oil and gas activities |
2,684 | 586 | 4,594 | 4,485 | 12,349 | |||||||||||||||
| General and administrative |
12,126 | 342 | 3,286 | 375 | 16,129 | |||||||||||||||
| Depreciation, depletion and amortization |
133 | 24 | 5,074 | 2,711 | 7,942 | |||||||||||||||
| Accretion of ARO |
— | — | 164 | — | 164 | |||||||||||||||
| Total costs and expenses |
17,922 | 7,670 | 35,150 | 21,339 | 82,081 | |||||||||||||||
| Operating loss |
17,787 | 7,670 | 6,016 | 21,339 | 52,812 | |||||||||||||||
| Loss on commodity derivative contracts |
— | — | 1,922 | — | 1,922 | |||||||||||||||
| Interest and other expense |
5,411 | 10 | 588 | 188 | 6,197 | |||||||||||||||
| Interest income |
(100 | ) | (7 | ) | (65 | ) | (41 | ) | (213 | ) | ||||||||||
| Loss before income taxes |
23,098 | 7,673 | 8,461 | 21,486 | 60,718 | |||||||||||||||
| Provision for income taxes |
— | — | 1,299 | — | 1,299 | |||||||||||||||
| Net loss |
23,098 | 7,673 | 9,760 | 21,486 | 62,017 | |||||||||||||||
| Non-controlling interest, net of tax |
129 | — | — | — | 129 | |||||||||||||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
$ | 23,227 | $ | 7,673 | $ | 9,760 | $ | 21,486 | $ | 62,146 | ||||||||||
| Segment assets |
$ | 92,726 | $ | 6,278 | $ | 162,560 | $ | 45,519 | $ | 307,083 | ||||||||||
F-24
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TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
| Corporate | Romania | Turkey | Morocco | Total | ||||||||||||||
| (in thousands) | ||||||||||||||||||
| For the year ended December 31, 2008 |
||||||||||||||||||
| Total revenues |
$ | 111 | $ | — | $ | — | $ | — | $ | 111 | ||||||||
| Production |
73 | — | — | — | 73 | |||||||||||||
| Seismic and other exploration |
— | — | — | 7,901 | 7,901 | |||||||||||||
| International oil and gas activities |
1,287 | 762 | 917 | 2,217 | 5,183 | |||||||||||||
| General and administrative |
3,592 | — | — | — | 3,592 | |||||||||||||
| Depreciation, depletion and amortization |
26 | 6 | — | 21 | 53 | |||||||||||||
| Accretion of ARO |
6 | — | — | — | 6 | |||||||||||||
| Total costs and expenses |
4,984 | 768 | 917 | 10,139 | 16,808 | |||||||||||||
| Operating loss |
4,873 | 768 | 917 | 10,139 | 16,697 | |||||||||||||
| Interest and other expense |
78 | — | — | 38 | 116 | |||||||||||||
| Interest income |
(276 | ) | — | — | (62 | ) | (338 | ) | ||||||||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
$ | 4,675 | $ | 768 | $ | 917 | $ | 10,115 | $ | 16,475 | ||||||||
| Segment assets |
$ | 39,480 | $ | 2,381 | $ | 10,230 | $ | 29,163 | $ | 81,254 | ||||||||
| Corporate | Romania | Turkey | Morocco | Total | ||||||||||||||
| (in thousands) | ||||||||||||||||||
| For the year ended December 31, 2007 |
||||||||||||||||||
| Total revenues |
$ | 653 | $ | — | $ | — | $ | — | $ | 653 | ||||||||
| Production |
1,167 | — | — | — | 1,167 | |||||||||||||
| International oil and gas activities |
517 | 811 | 239 | 745 | 2,312 | |||||||||||||
| General and administrative |
2,673 | — | — | — | 2,673 | |||||||||||||
| Depreciation, depletion and amortization |
80 | — | — | — | 80 | |||||||||||||
| Settlement provision |
(313 | ) | — | — | — | (313 | ) | |||||||||||
| Accretion of ARO |
72 | — | — | 72 | ||||||||||||||
| Total costs and expenses |
4,196 | 811 | 239 | 745 | 5,991 | |||||||||||||
| Operating loss |
3,543 | 811 | 239 | 745 | 5,338 | |||||||||||||
| Loss on write-down of assets |
447 | — | — | — | 447 | |||||||||||||
| Interest and other expense |
711 | — | — | 62 | 773 | |||||||||||||
| Interest income |
(144 | ) | — | — | (96 | ) | (240 | ) | ||||||||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
$ | 4,557 | $ | 811 | $ | 239 | $ | 711 | $ | 6,318 | ||||||||
| Segment assets |
$ | 2,539 | $ | 309 | $ | 63 | $ | 2,196 | $ | 5,107 | ||||||||
F-25
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TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
Summarized financial information concerning the Company’s operating segments is shown in the following tables:
| E&P | Drilling | Corporate | Total | |||||||||||||
| (in thousands) | ||||||||||||||||
| For the year ended December 31, 2009 |
||||||||||||||||
| Net revenues |
$ | 27,681 | $ | 2,904 | — | $ | 30,585 | |||||||||
| Inter-segment revenues |
— | (1,316 | ) | — | (1,316 | ) | ||||||||||
| Total revenues |
27,681 | 1,588 | — | 29,269 | ||||||||||||
| Production |
10,168 | — | — | 10,168 | ||||||||||||
| Exploration, abandonment and impairment |
24,791 | — | — | 24,791 | ||||||||||||
| Seismic and other exploration |
10,538 | — | — | 10,538 | ||||||||||||
| International oil and gas activities |
5,239 | 4,426 | 2,684 | 12,349 | ||||||||||||
| General and administrative |
3,508 | 495 | 12,126 | 16,129 | ||||||||||||
| Depreciation, depletion and amortization |
4,587 | 3,222 | 133 | 7,942 | ||||||||||||
| Accretion of ARO |
164 | — | — | 164 | ||||||||||||
| Total costs and expenses |
58,995 | 8,143 | 14,943 | 82,081 | ||||||||||||
| Operating loss |
31,314 | 6,555 | 14,943 | 52,812 | ||||||||||||
| Loss on commodity derivative contracts |
1,922 | — | — | 1,922 | ||||||||||||
| Interest and other expense |
518 | 268 | 5,411 | 6,197 | ||||||||||||
| Interest income |
(93 | ) | (20 | ) | (100 | ) | (213 | ) | ||||||||
| Loss before income taxes |
33,661 | 6,803 | 20,254 | 60,718 | ||||||||||||
| Provision for income taxes |
1,080 | 219 | — | 1,299 | ||||||||||||
| Net loss |
34,741 | 7,022 | 20,254 | 62,017 | ||||||||||||
| Non-controlling interest, net of tax |
— | — | 129 | 129 | ||||||||||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
$ | 34,741 | $ | 7,022 | $ | 20,383 | $ | 62,146 | ||||||||
| Segment assets |
$ | 158,856 | $ | 55,501 | $ | 92,726 | $ | 307,083 | ||||||||
F-26
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
| E&P | Drilling | Corporate | Total | ||||||||||||
| (in thousands) | |||||||||||||||
| For the year ended December 31, 2008 |
|||||||||||||||
| Total revenues |
$ | 111 | $ | — | $ | — | $ | 111 | |||||||
| Production |
73 | — | — | 73 | |||||||||||
| Seismic and other exploration |
7,901 | — | — | 7,901 | |||||||||||
| International oil and gas activities |
3,896 | — | 1,287 | 5,183 | |||||||||||
| General and administrative |
— | — | 3,592 | 3,592 | |||||||||||
| Depreciation, depletion and amortization |
27 | — | 26 | 53 | |||||||||||
| Accretion of ARO |
6 | — | — | 6 | |||||||||||
| Total costs and expenses |
11,903 | — | 4,905 | 16,808 | |||||||||||
| Operating loss |
11,792 | — | 4,905 | 16,697 | |||||||||||
| Interest and other expense |
38 | — | 78 | 116 | |||||||||||
| Interest income |
(276 | ) | — | (62 | ) | (338 | ) | ||||||||
| Loss before income taxes |
11,554 | — | 4,921 | 16,475 | |||||||||||
| Benefit (provision) for income taxes |
— | — | — | — | |||||||||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
$ | 11,554 | $ | — | $ | 4,921 | $ | 16,475 | |||||||
| Segment assets |
$ | 14,334 | $ | 35,749 | $ | 31,171 | $ | 81,254 | |||||||
| E&P | Drilling | Corporate | Total | ||||||||||||
| (in thousands) | |||||||||||||||
| For the year ended December 31, 2007 |
|||||||||||||||
| Total revenues |
$ | 653 | $ | — | $ | — | $ | 653 | |||||||
| Production |
1,167 | — | — | 1,167 | |||||||||||
| International oil and gas activities |
1,795 | — | 517 | 2,312 | |||||||||||
| General and administrative |
— | — | 2,673 | 2,673 | |||||||||||
| Depreciation, depletion and amortization |
80 | — | — | 80 | |||||||||||
| Settlement provision |
(313 | ) | — | — | (313 | ) | |||||||||
| Accretion of ARO |
72 | — | — | 72 | |||||||||||
| Total costs and expenses |
2,801 | — | 3,190 | 5,991 | |||||||||||
| Operating loss |
2,148 | — | 3,190 | 5,338 | |||||||||||
| Loss on write-down of assets |
447 | — | — | 447 | |||||||||||
| Interest and other expense |
62 | — | 711 | 773 | |||||||||||
| Interest income |
(144 | ) | — | (96 | ) | (240 | ) | ||||||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
$ | 2,513 | $ | — | $ | 3,805 | $ | 6,318 | |||||||
| Segment assets |
$ | 2,568 | $ | — | $ | 2,539 | $ | 5,107 | |||||||
F-27
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
14. Financial instruments
Cash and cash equivalents, receivables, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount at December 31, 2009 and 2008, due to the short maturity of those instruments.
Interest rate risk
The Company is exposed to interest rate risk as a result of its fixed rate notes and its variable rate short-term cash holdings. Interest rate changes would result in gains or losses in the market value of the Company’s fixed rate debt due to differences between the current market interest rates and the rates governing its notes.
Foreign currency risk
The Company has underlying foreign currency exchange rate exposure. The Company’s currency exposures relate to transactions denominated in the Australian Dollar, Canadian Dollar, British Pound, European Union Euro, Romanian New Leu, Moroccan Dirham and Turkish Lira. Foreign currency forward contracts have not been used to manage exchange rate fluctuations. The Company agreed to a fixed currency exchange rate of AUD $1.00 to US $0.7024 in the Credit Agreement with Dalea (see note 10). During the year ended December 31, 2009, the loan was repaid in its entirety and the Credit Agreement was terminated. The resulting realized exchange loss was $4.2 million. At December 31, 2009, the Company had Cdn $55.7 million (approximately $53 million), 9.8 million Euros (approximately $14.0 million) and 460,000 Turkish Lira (approximately $305,000) in cash and cash equivalents, which exposes the Company to exchange rate risk based on fluctuations in the value of the Canadian Dollar, Euro and Turkish Lira.
Commodity price risk
The Company is exposed to fluctuations in commodity prices for crude oil. Commodity prices are affected by many factors including but not limited to supply and demand. At December 31, 2009 the Company was a party to commodity derivative contracts. See note 8.
Concentration of credit risk
The majority of the Company’s receivables are within the oil and gas industry, primarily from its industry partners and from government agencies. Included in receivables are amounts due from the national oil company of Turkey, which purchases all of the Company’s oil production in Turkey. The receivables are not collateralized. To date, the Company has experienced minimal bad debts, and has no allowance for doubtful accounts. The majority of the Company’s cash and cash equivalents are held by three financial institutions in the U.S. and Turkey.
The Company has adopted ASC 820, which became effective for financial assets and liabilities of the Company on January 1, 2008 and non-financial assets and liabilities of the Company on January 1, 2009. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 does not require any new fair value measurements, but applies to assets and liabilities that are required to be recorded at fair value under other accounting standards.
ASC 820 characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value measurement hierarchy are as follows:
| Level 1: |
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. | |
| Level 2: |
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. | |
| Level 3: |
Measured based on prices or valuation models that required inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity). | |
F-28
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
As required by ASC 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values, stated below, takes into account the market for the Company’s financial assets and liabilities, the associated credit risk and other factors as required ASC 820. The Company considers active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
The following table summarizes the valuation of the Company’s financial assets and liabilities as of December 31, 2009:
| Fair Value Measurement Classification | ||||||||||||||
| Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1) |
Significant Other Observable Inputs (Level 2) |
Significant Unobservable Inputs (Level 3) |
Total | |||||||||||
| (in thousands) | ||||||||||||||
| Assets (liabilities): |
||||||||||||||
| Fixed rate debt |
$ | — | $ | (7,501 | ) | $ | — | $ | (7,501 | ) | ||||
| Senior credit facility |
— | — | — | — | ||||||||||
| Crude oil derivative contracts |
— | (1,922 | ) | — | (1,922 | ) | ||||||||
| Total |
$ | — | $ | (9,423 | ) | $ | — | $ | (9,423 | ) | ||||
15. Commitments
The Company has remaining work program commitments in Morocco of the following amounts based upon fully-funded bank guarantees: $2 million under its Guercif exploration permits, $3 million under its Ouezzane-Tissa exploration permits, $1 million under its Tselfat exploration permit and $1.5 million under its Asilah exploration permit. The bank guarantees are reduced periodically based on work performed. In the event the Company fails to perform the required work commitments, the remaining amount of the bank guarantees would be forfeited.
On March 3, 2009, the Company amended the lease for its Dallas, Texas office space extending the term to December 31, 2013. In Morocco, the Company has entered into three-year leases for two offices and an apartment, along with one-year leases for an apartment and an operations yard. In Romania, the Company has one-year leases for an office and an apartment. In Turkey, the Company has entered into a three-year lease for the office space in Istanbul, short term leases of two apartments in Istanbul, a five-year lease (4 years remaining) for an operations yard in Diyarbakir and a one-year lease for apartments and office space at a hotel in Turkey. The Company’s aggregate annual commitments as of December 31, 2009 are as follows:
| Payments Due by Year | |||||||||||||||||||||
| Total | 2010 | 2011 | 2012 | 2013 | 2014 | Thereafter | |||||||||||||||
| (in thousands) | |||||||||||||||||||||
| Leases and other |
$ | 5,135 | $ | 1,610 | $ | 1,385 | $ | 1,170 | $ | 619 | $ | — | $ | 351 | |||||||
| Contracts |
17,000 | 13,200 | 3,800 | — | — | — | — | ||||||||||||||
| Permits |
5,655 | 705 | 4,950 | — | — | — | — | ||||||||||||||
| $ | 27,790 | $ | 15,515 | $ | 10,135 | $ | 1,170 | $ | 619 | $ | — | $ | 351 | ||||||||
Normal purchase arrangements are excluded from the table as they are discretionary and/or being performed under contracts which are cancelable immediately or with a 30-day notice period.
F-29
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
The Company’s commitments under its permits and contracts require the Company to complete certain work projects on the relevant permit or license within a specified period of time. The Company’s current commitments under its permits and contracts are due in 2010 and 2011. If the Company fails to complete a work project by the specified deadline, the Company would lose its rights in such license or permit, and in the case of the Asilah, Tselfat, Ouezzane-Tissa and Guercif permits, any remaining amount of the bank guarantees would be forfeited.
The Company’s commitments for permits as of December 31, 2009 included commitments to:
| • | Drill one well on the Tselfat permit in Morocco in 2010; |
| • | Drill one well on the Izvoru permit in Romania in 2010; |
| • | Drill one well on one of the Midyat permits in Turkey in 2010; |
| • | Drill one well on one of the Tuz Golu permits in Turkey in 2011; and |
| • | Conduct miscellaneous exploratory activities on several of the Company’s Turkish licenses. |
The Company’s commitments for contracts as of December 31, 2009 included commitments to:
| • | Complete drilling of one well on one of the Ouezzane-Tissa permits, drill a second well on one of the Ouezzane-Tissa permits and drill one well on the Asilah permits in Morocco in 2010 in accordance with the Company’s farm-out agreement with Direct Petroleum Morocco, Inc. and Anschutz Morocco Corporation; |
| • | Drill one well on license 4325 in Turkey in 2011 in accordance with the Company’s agreement with Selsinsan Petrol Maden; |
| • | Drill one well on one of the Malatya licenses in Turkey in 2011 in accordance with the Company’s agreement with Selsinsan Petrol Maden; and |
| • | Drill one well on one of the Guercif licenses in Morocco in 2010 in accordance with the Company’s agreement with Stratic Energy Corporation. |
16. Contingent liability
Incremental has been involved in litigation with persons who claim ownership of a portion of the surface at the Selmo field in Turkey. These cases are being vigorously defended by Incremental and Turkish governmental authorities. The Company does not have enough information to estimate the potential additional operating costs the Company would incur in the event the purported surface owners’ claims are ultimately successful. Any adjustment arising out of the claims will be recorded when it becomes known.
17. Related party transactions
Debt transactions
In April 2007, the Company entered into a $3 million short-term standby bridge loan from Quest Capital Corp. (“Quest”). The Company drew down $3 million on the loan in the second quarter of 2007. In August 2007, the Company increased the loan facility to $4 million and drew down the additional $1 million. The Company issued 503,823 common shares to Quest at an aggregate value of approximately $359,000 as it drew on the loan. In November 2007, the Company paid down $2 million in principal on the loan and extended the maturity date on the outstanding principal balance of $2 million to March 31, 2008. Quest extended the maturity date to April 30, 2008 to facilitate the closing of the loan with Riata Management, LLC (“Riata Management”), as described below. The Company repaid the loan in full on April 8, 2008. The Quest loan incurred interest at a rate of twelve percent (12%) per annum, calculated daily and compounded monthly, and the Company paid an aggregate of $392,461 in interest and fees on the loan. The Company currently has one director in common with Quest, Mr. Brian Bayley, who currently serves as Quest’s president and chief executive officer. At the time of the Quest transactions, the Company had two directors in common with Quest and Mr. Bayley served as Quest’s chief executive officer. Transactions with Quest were conducted on an arm’s length basis. The loans were made by Quest in the ordinary course of business and were made on substantially the same terms, including interest rates, as those prevailing at the time for comparable loans with persons not related to Quest.
F-30
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
On April 8, 2008, the Company entered into a $2.0 million short-term loan at an interest rate of twelve percent (12%) per annum with Riata Management and used the proceeds to repay the Quest loan in full. The Company repaid the Riata Management loan in full on May 30, 2008 and all interest under the Riata Management loan was waived.
On November 28, 2008, the Company entered into a Credit Agreement with Dalea for the purpose of funding the all cash takeover offer by TransAtlantic Australia, for all of the outstanding shares of Incremental. Pursuant to the Credit Agreement, as amended, until June 30, 2009, the Company 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. The Company borrowed an aggregate of $64.6 million under the loan and paid a total of $2.0 million in interest in 2009 (see note 10).
Equity transactions
On April 8, 2008, Dalea purchased 10,000,000 common shares from the Company at Cdn $0.30 per share pursuant to the first stage of a private placement announced in March 2008 and, on May 30, 2008, Dalea and Riata TransAtlantic purchased a further 12,630,000 common shares from the Company at Cdn $0.36 per share pursuant to the second stage of the private placement. Mr. McCann, at that time a member of the Company’s board of directors, also participated in the second stage of the private placement, purchasing 1,100,000 common shares. However, neither Mr. Mitchell nor Mr. McCann were related parties of the Company on March 28, 2008, the date that Dalea and Riata TransAtlantic first agreed that they or their associates would participate in the private placement and provide the short-term loan.
The Company entered into a registration rights agreement, as of April 8, 2008, as amended and restated as of December 30, 2008, with Riata Management (the “Riata Registration Rights Agreement”). Pursuant to the Riata Registration Rights Agreement, Riata Management has the right to request that the Company effect the qualification under Canadian securities laws of all or part of the Company’s common shares (and any of its securities issued on conversion of, in exchange for or in replacement of such common shares) owned or controlled by Riata Management, certain entities affiliated with Riata Management, the purchasers that participated in the Company’s December 2008 private placement, and Longfellow (the “Qualifiable Securities”), to permit the distribution of such Qualifiable Securities to the public in any or all of the provinces and territories of Canada (a “Demand Qualification”). The Company will not be obligated to effect any Demand Qualification for less than Cdn $5,000,000 or to effect more than two Demand Qualifications in any twelve-month period or until a period of at least 90 days has elapsed from the effective date of the most recent previous qualification. In addition to the Demand Qualification rights, subject to certain limitations, if the Company proposes to file a prospectus under Canadian securities laws in order to permit the qualification of securities that are to be sold by the Company or by any of its shareholders, the Company will use all reasonable efforts to include in the proposed distribution such number of Qualifiable Securities as Riata Management shall request upon the same terms as such distribution.
On December 30, 2008, the Company acquired 100% of the issued and outstanding shares of Longe from Longfellow in consideration for the issuance of 39,583,333 common shares and 10,000,000 common share purchase warrants. Each common share purchase warrant entitles the holder to purchase one common share at an exercise price of $3.00 per share through December 30, 2011. Concurrently, the Company issued 35,416,667 common shares at a price of $1.20 per share in a private placement with Dalea, Riata TransAtlantic, Mr. McCann and other purchasers that have business or familial relationships with Mr. Mitchell, resulting in gross proceeds of $42.5 million. Dalea and Riata TransAtlantic purchased an aggregate of 34,381,667 common shares, and Mr. McCann purchased 250,000 common shares. In addition, the Company paid $740,000 to Longfellow for additional drilling equipment delivered at closing of the Longe acquisition.
On March 20, 2009, the Company’s wholly-owned subsidiary, TransAtlantic Australia, purchased 15,025,528 shares of Incremental from Mr. Mitchell at a price of AUD $1.085 per share, the same price per share and pursuant to the same terms as the shares acquired from Incremental’s other shareholders, none of whom had any relationship with the Company. Mr. Mitchell had purchased the Incremental shares between October 27, 2008 and December 23, 2008 at an average price of AUD $0.99 per share. The total consideration paid by TransAtlantic Australia for Mr. Mitchell’s Incremental shares was $11.2 million.
On June 22, 2009, Dalea purchased 41,818,000 common shares at a price of Cdn $1.65 per share in a private placement of the Company’s common shares in the U.S. In addition, on June 22, 2009, the Company entered into a registration rights agreement with Canaccord Capital Corporation and Dalea (the “Registration Rights Agreement”), pursuant to which the Company agreed to register for resale under the Securities Act the 41,818,000 common shares purchased by Dalea and 56,559,300 common shares held by certain other investors. Under the registration rights agreement, the Company filed a registration statement with the SEC on July 20, 2009 to register 55,544,300 common shares for resale, which did not include the common shares held by Dalea. The registration statement was declared effective on September 29, 2009.
F-31
Table of Contents
TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
On November 24, 2009, Dalea purchased 4,255,400 common shares at a price of Cdn $2.35 per share in a private placement of the Company’s common shares in the U.S. In addition, on November 24, 2009, the Company entered into a registration rights agreement with Canaccord Capital Corporation and Dalea, pursuant to which the Company agreed to register for resale under the Securities Act the 4,255,400 common shares purchased by Dalea and 44,043,390 common shares held by certain other investors. Under the registration rights agreement, the Company filed a registration statement with the SEC on December 23, 2009 to register 42,838,451 common shares for resale, which did not include the common shares held by Dalea. The registration statement was declared effective on January 7, 2010.
Equipment purchase transactions
On December 31, 2008, certain of the Company’s wholly-owned subsidiaries entered into bills of sale and assignment with Viking Drilling, LLC (“Viking”). Under the terms of the bills of sale and assignment, the Company’s wholly-owned subsidiaries purchased at Viking’s cost certain drilling and service equipment and other assets from Viking for use in Turkey, Morocco and Romania. The Company paid $8.3 million to Viking for the drilling and service equipment and other assets.
On July 27, 2009, the Company’s wholly-owned subsidiary, Viking International Limited (“Viking International”), purchased the I-13 drilling rig and associated equipment from Viking, an entity in which Dalea owns 85%. Viking International paid $1.5 million in cash for the drilling rig and entered into a note payable to Viking 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. The Company paid interest under the note on November 1, 2009 and February 1, 2010. On February 19, 2010, Viking International amended and restated the terms of the note with Viking in connection with the purchase of the I-14 drilling rig and associated equipment from Viking (see note 19). On February 19, 2010, Viking International purchased the I-14 drilling rig and associated equipment from Viking. Viking International paid $1.5 million in cash for the drilling rig and entered into an amended and restated note payable to Viking 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 in July 2009. 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. Interest expense for the twelve months ended December 31, 2009 pursuant to the Viking note was $254,000 of which $99,000 was included in accrued liabilities at December 31, 2009.
Service transactions
Effective May 1, 2008, the Company entered into a service agreement, as amended (the “Service Agreement”), with Longfellow, Viking, Longe, MedOil Supply, LLC and Riata Management. Mr. Mitchell and his wife own 100% of Riata Management. In addition, Mr. Mitchell, his wife and children indirectly own 100% of Longfellow. Prior to the Company’s acquisition of Longe, Longe was owned 100% by Longfellow. Riata Management owns 100% of MedOil Supply, LLC. Dalea owns 85% of Viking. Under the terms of the Service Agreement, the Company pays, or is paid, for the actual cost of the services rendered plus the actual cost of reasonable expenses on a monthly basis. The Company recorded expenditures for the year ended December 31, 2009 and 2008 of $15.8 million and $4.6 million, respectively, for goods and services provided to it under the Service Agreement, of which $1.1 million and $1.5 million was payable at December 31, 2009 and 2008, respectively.
In November 2008, in connection with the pending acquisition of Longe, the Company agreed with Longe that the Company would suspend billing Longe for work that the Company was conducting for its Moroccan operations. As a result, the Company recorded approximately $1 million in related expenses that it would have billed to Longe had the Longe acquisition not been completed.
Effective January 1, 2009, the Company’s wholly-owned subsidiary, TransAtlantic Turkey, Ltd., entered into a lease agreement under which it leased rooms, flats and office space at a resort hotel owned by Gundem Turizm Yatirim ve Isletme A.S. (“Gundem”), a Turkish company controlled by Mr. Mitchell. Under the lease agreement, TransAtlantic Turkey, Ltd. paid the Turkish Lira equivalent of $5,000 per month base rent and up to 45,000 Turkish Lira per month (approximately $30,000 per month) in operating expense reimbursement. The lease agreement expired December 31, 2009. Effective January 1, 2010, TransAtlantic Turkey, Ltd. and Gundem entered into an accommodation agreement under which it leases ten rooms at the hotel. Under the accommodation agreement, TransAtlantic Turkey, Ltd. pays the Turkish Lira equivalent of $10,000 per month. The amounts formerly paid under the lease agreement and paid under the accommodation agreement are included in amounts paid under the Service Agreement.
On December 15, 2009, Viking International entered into an Agreement for Management Services (“Management Services Agreement”) with Viking. Pursuant to the Management Services Agreement, Viking International agreed to provide management, marketing, storage and personnel services (collectively, the “Rig Services”) from time to time as requested by Viking for the operation of certain rigs (the “Rigs”) owned by Viking that are located in Turkey. Under the terms of the Management Services Agreement, Viking will pay Viking International for all actual costs and expenses associated with the
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TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
provision of the Rig Services. In addition, Viking will pay Viking International a distribution equal to 5% of the net profits of each Rig, which is calculated as the gross revenues of each Rig less any and all expenses attributable to such Rig, including, but not limited to, the payment for services and insurance under the Management Services Agreement and depreciation. As of December 31, 2009, Viking International had not performed any services under the Management Services Agreement and has received no payments or distributions.
Other transactions
In July 2008, Longfellow guaranteed the obligations of the Company and Longe under a farm-out agreement concerning the Company’s Ouezzane-Tissa and Asilah exploration permits in Morocco up to a maximum of $25 million. In addition, in July 2008, the Company received a reimbursement of expenses in the amount of $832,000 from Longe related to Longe’s participation in its Moroccan exploration permits.
Mr. Mitchell and his wife own 100% of Riata and Dalea, and Mr. Mitchell is a manager of Riata TransAtlantic. In addition, Mr. Mitchell is a partner of Dalea and a manager of Dalea Management, the general partner of Dalea. Mr. Mitchell, his wife and children indirectly own 100% of Longfellow. Prior to the Company’s acquisition of Longe, Longe was owned by Longfellow. Riata owns 100% of MedOil Supply, LLC. Dalea owns 85% of Viking.
18. Quarterly results of operations (unaudited)
The results of operations by quarter for the years ended December 31, 2009 and 2008 are as follows:
| Three Months Ended | |||||||||||||||
| March 31, | June 30, | September 30, | December 31, | Full year | |||||||||||
| (in thousands, except per share data) | |||||||||||||||
| For the year ended December 31, 2009: |
|||||||||||||||
| Revenues |
$ | 1,362 | $ | 7,425 | $ | 9,258 | $ | 11,224 | $ | 29,269 | |||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
13,294 | 7,093 | 13,143 | 28,616 | 62,146 | ||||||||||
| Basic and diluted net loss per common share attributable to TransAtlantic Petroleum Ltd.(1) |
$ | 0.09 | $ | 0.04 | $ | 0.05 | $ | 0.10 | $ | 0.29 | |||||
| For the year ended December 31, 2008: |
|||||||||||||||
| Revenues |
$ | 14 | $ | 47 | $ | 34 | $ | 16 | $ | 111 | |||||
| Net loss attributable to TransAtlantic Petroleum Ltd. |
1,075 | 920 | 1,483 | 12,997 | 16,475 | ||||||||||
| Basic and diluted net loss per common share attributable to TransAtlantic Petroleum Ltd.(1) |
$ | 0.02 | $ | 0.01 | $ | 0.02 | $ | 0.19 | $ | 0.25 | |||||
| (1) | The sum of the individual quarterly earnings (loss) per share may not agree with year-to-date earnings per share as each quarterly computation is based on the income or loss for that quarter and the weighted-average number of shares outstanding during that quarter. |
| • | The first through fourth quarters of 2009 reflect the Company’s acquisition of Incremental effective March 5, 2009. |
| • | The first quarter of 2009 includes a foreign exchange loss of $4.2 million related to the Dalea credit agreement. |
| • | The third quarter of 2009 includes $5.3 million in abandonment and impairment expense. |
| • | The fourth quarter of 2009 includes $19.0 million in abandonment and impairment expense, a $1.9 million loss on commodity derivative contracts and an $800,000 foreign exchange gain on cash balances. |
| • | The fourth quarter of 2009 reflects the final purchase accounting adjustments for the acquisition of Incremental. |
19. Subsequent events
Effective January 1, 2010, TransAtlantic Turkey, Ltd. and Gundem entered into an accommodation agreement under which it leases ten rooms at a hotel owned by Gurdem. Under the accommodation agreement, TransAtlantic Turkey, Ltd. pays the Turkish Lira equivalent of $10,000 per month.
On February 19, 2010, in connection with Viking International’s purchase of the I-14 drilling rig and associated equipment from Viking, Viking International amended and restated the terms of the note payable to Viking for the I-13 drilling rig and associated equipment. Viking International paid $1.5 million in cash for the drilling rig and entered into an amended and restated note payable to Viking in the amount of $11.8 million, which is comprised of $5.9 million payable related to the I-14
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TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
drilling rig and $5.9 million payable related to the purchase of the I-13 drilling rig in July 2009. The amortizing note is due and payable on August 1, 2012, bears interest at a floating rate of LIBOR plus 6.25% per month and is secured by the two drilling rigs and associated equipment. Interest under the note is payable monthly. As of March 15, 2010, $11.5 million was outstanding under the amended and restated note.
20. Supplemental disclosure for cash flow information
Non-cash transactions resulting from acquisitions not reflected in the consolidated statements of cash flows include the following:
| Year Ended December 31, | |||||||||||
| 2009 | 2008 | 2007 | |||||||||
| (in thousands) | |||||||||||
| Noncash operating cash flows transactions: |
|||||||||||
| Prepaid and other assets |
$ | — | $ | 2,636 | $ | — | |||||
| Accounts payable |
$ | — | $ | (1,170 | ) | $ | — | ||||
| Noncash investing cash flows transactions: |
|||||||||||
| Property and equipment |
$ | 1,500 | $ | 32,350 | $ | — | |||||
| Noncash financing cash flows transactions: |
|||||||||||
| Promissory note |
$ | (1,500 | ) | $ | — | $ | — | ||||
| Common shares issued |
$ | 71 | $ | 28,104 | $ | — | |||||
| Common share warrants issued |
$ | 207 | $ | 5,228 | $ | — | |||||
| Year Ended December 31, | |||||||||||
| 2009 | 2008 | 2007 | |||||||||
| (in thousands) | |||||||||||
| Supplemental disclosure of cash paid for interest and income taxes: |
|||||||||||
| Cash paid during the year for interest |
$ | 2,578 | $ | 144 | $ | 349 | |||||
| Cash paid during the year for income taxes |
$ | 2,073 | $ | — | $ | — | |||||
21. Supplemental oil and natural gas reserves and standard measure information (unaudited)
In December 2009, the Company adopted revised oil and gas reserve estimation and disclosure requirements. The primary impact of the new disclosures is to conform the definition of proved reserves with “Modernization of Oil and Gas Reporting”, which was adopted by the SEC in December of 2008. The new rules revised the definition of proved oil and gas reserves to require that the average, first-day-of-the-month price during the 12-month period before the end of the year rather than the year-end price, must be used when estimating whether reserve quantities are economical to produce. This same 12-month average price is also used in calculating the aggregate amount of (and changes in) future cash inflows related to the standardized measure of discounted future net cash flows. The following table sets forth the Company’s net proved reserves, including changes therein, and proved developed reserves:
| Crude Oil (MBbls) |
Natural Gas (MMcf) |
|||||
| Total proved reserves |
||||||
| December 31, 2006 |
10 | 649 | ||||
| Revisions of previous estimates |
— | — | ||||
| Extensions, discoveries and other additions |
— | — | ||||
| Sale of reserves |
(10 | ) | (649 | ) | ||
| Production |
— | — | ||||
| December 31, 2007 |
— | — | ||||
| Revisions of previous estimates |
— | — | ||||
| Extensions, discoveries and other additions |
— | — | ||||
| Sale of reserves |
— | — | ||||
| Production |
— | — | ||||
| December 31, 2008 |
— | — | ||||
| Incremental acquisition |
9,253 | 784 | ||||
| Extensions and discoveries |
— | 5,948 | ||||
| Revisions of previous estimates |
1,584 | 607 | ||||
| Purchases of minerals in place |
— | — | ||||
| Production |
(412 | ) | — | |||
| December 31, 2009 |
10,426 | 7,339 | ||||
| Proved developed reserves |
||||||
| Proved developed producing |
3,777 | — | ||||
| Proved developed non-producing |
1,872 | 4,787 | ||||
| Total |
5,649 | 4,787 | ||||
| Proved developed reserves |
||||||
| As of December 31, 2006 |
10 | 649 | ||||
| As of December 31, 2007 |
— | — | ||||
| As of December 31, 2008 |
— | — | ||||
| As of December 31, 2009 |
5,649 | 4,787 | ||||
| Proved undeveloped reserves |
||||||
| As of December 31, 2006 |
— | — | ||||
| As of December 31, 2007 |
— | — | ||||
| As of December 31, 2008 |
— | — | ||||
| As of December 31, 2009 |
4,777 | 2,552 | ||||
The Company has summarized the standardized measure of discounted future net cash flows related to its proved oil and natural gas reserves. The Company has based the following summary on a valuation of proved reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. The additions to proved reserves from purchase of reserves in place and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of proved reserves in prior years could also be significant. Accordingly, investors should not view the information presented below as an estimate of the fair value of the Company’s oil and natural gas properties, nor should investors consider the information indicative of any trends.
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TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
The prices of oil and natural gas at December 31, 2009 used to estimate reserves in the table shown below, were $95.72 per Bbl of oil and $8.91 per MMcf of natural gas, respectively. For the comparable periods ended December 31, 2008 and 2007, the Company did not have proved reserves.
| Total | ||||
| (in thousands) | ||||
| As of and for the year ended December 31, 2009 |
||||
| Future cash inflows |
$ | 700,003 | ||
| Future production costs |
(161,173 | ) | ||
| Future development costs |
(46,234 | ) | ||
| Future income tax expense |
(94,468 | ) | ||
| Future net cash flows |
398,128 | |||
| 10% annual discount for estimated timing of cash flows |
(148,119 | ) | ||
| Standardized measure of discounted future net cash flows related to proved reserves |
$ | 250,009 | ||
The following are the principal sources of changes in the standardized measure of discounted future net cash flows applicable to proved oil and natural gas reserves:
| Total | ||||
| (in thousands) | ||||
| Balance at December 31, 2008 |
— | |||
| Acquisition of Incremental Petroleum Limited |
83,586 | |||
| Net change in sales and transfer prices and in production (lifting) costs related to future production |
137,280 | |||
| Changes in future estimated development costs |
(10,019 | ) | ||
| Sales and transfers of oil and natural gas during the period |
(17,803 | ) | ||
| Net change due to extensions and discoveries |
29,090 | |||
| Net change due to purchases of minerals in place |
— | |||
| Net change due to revisions in quantity estimates |
49,450 | |||
| Previously estimated development costs incurred during the period |
6,361 | |||
| Accretion of discount |
10,449 | |||
| Other |
95 | |||
| Net change in income taxes |
(38,480 | ) | ||
| Balance at December 31, 2009 |
$ | 250,009 | ||
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TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
Capitalized costs related to crude oil and natural gas producing activities
The Company’s capitalized costs consisted of the following (in thousands):
| United States | Turkey | Total | |||||||||
| (in thousands) | |||||||||||
| For the year ended December 31, 2009 |
|||||||||||
| Crude oil and natural gas properties |
|||||||||||
| Proved |
$ | — | $ | 66,313 | $ | 66,313 | |||||
| Unproved |
1,322 | 3,193 | 4,515 | ||||||||
| Total crude oil and natural gas properties |
1,322 | 69,506 | 70,828 | ||||||||
| Less accumulated depreciation, depletion and impairment |
— | (2,483 | ) | (2,483 | ) | ||||||
| Net crude oil and natural gas properties capitalized costs |
$ | 1,322 | $ | 67,023 | $ | 68,345 | |||||
| For the year ended December 31, 2008 |
|||||||||||
| Crude oil and natural gas properties |
|||||||||||
| Proved |
$ | — | $ | — | $ | — | |||||
| Unproved |
— | 1,227 | 1,227 | ||||||||
| Total crude oil and natural gas properties |
— | 1,227 | 1,227 | ||||||||
| Less accumulated depreciation, depletion and impairment |
— | — | — | ||||||||
| Net crude oil and natural gas properties capitalized costs |
$ | — | $ | 1,227 | $ | 1,227 | |||||
| For the year ended December 31, 2007 |
|||||||||||
| Crude oil and natural gas properties |
|||||||||||
| Proved |
$ | — | $ | — | $ | — | |||||
| Unproved |
— | — | — | ||||||||
| Total crude oil and natural gas properties |
— | — | — | ||||||||
| Less accumulated depreciation, depletion and impairment |
— | — | — | ||||||||
| Net crude oil and natural gas properties capitalized costs |
$ | — | $ | — | $ | — | |||||
Costs incurred in crude oil and natural gas property acquisition, exploration and development
Costs incurred in crude oil and natural gas property acquisition, exploration and development activities are summarized as follows:
| United States | Turkey | Total | |||||||
| (in thousands) | |||||||||
| For the year ended December 31, 2009 |
|||||||||
| Acquisitions of properties |
|||||||||
| Proved |
$ | — | $ | 66,313 | $ | 66,313 | |||
| Unproved |
1,322 | 3,193 | 4,515 | ||||||
| Exploration |
2,305 | 4,944 | 7,249 | ||||||
| Development |
463 | 7,234 | 7,697 | ||||||
| Total costs incurred |
$ | 4,090 | $ | 81,684 | $ | 85,774 | |||
| For the year ended December 31, 2008 |
|||||||||
| Acquisitions of properties |
|||||||||
| Proved |
$ | — | $ | — | $ | — | |||
| Unproved |
— | 1,227 | 1,227 | ||||||
| Exploration |
— | — | — | ||||||
| Development |
— | — | — | ||||||
| Total costs incurred |
$ | — | $ | 1,227 | $ | 1,227 | |||
| For the year ended December 31, 2007 |
|||||||||
| Acquisitions of properties |
|||||||||
| Proved |
$ | — | $ | — | $ | — | |||
| Unproved |
— | — | — | ||||||
| Exploration |
— | — | — | ||||||
| Development |
— | — | — | ||||||
| Total costs incurred |
$ | — | $ | — | $ | — | |||
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TRANSATLANTIC PETROLEUM LTD.
Notes to Consolidated Financial Statements—(Continued)
Results of operations for crude oil and natural gas producing activities (unaudited)
The Company’s results of operations from crude oil and natural gas producing activities for each of the years 2007, 2008 and 2009 are shown in the following table (in thousands):
| United States | Turkey | Total | ||||||||||
| (in thousands) | ||||||||||||
| For the year ended December 31, 2009 |
||||||||||||
| Revenues |
$ | 135 | $ | 27,546 | $ | 27,681 | ||||||
| Expenses: |
||||||||||||
| Production costs |
211 | 9,814 | 10,025 | |||||||||
| Exploration, abandonment and impairment |
2,305 | 191 | 2,496 | |||||||||
| Seismic and other exploration |
463 | 4,948 | 5,411 | |||||||||
| Depreciation, depletion and amortization expenses |
124 | 3,094 | 3,218 | |||||||||
| Total expenses |
3,103 | 18,047 | 21,150 | |||||||||
| Loss (income) before income taxes |
2,968 | (9,499 | ) | (6,531 | ) | |||||||
| Provision for income taxes |
— | 1,079 | 1,079 | |||||||||
| Results of operations for crude oil and natural gas producing activities (excluding corporate overhead and interest costs) |
$ | 2,968 | $ | (8,420 | ) | $ | (5,452 | ) | ||||
| For the year ended December 31, 2008 |
||||||||||||
| Revenues |
$ | 111 | — | $ | 111 | |||||||
| Expenses: |
||||||||||||
| Production costs |
73 | — | 73 | |||||||||
| Exploration, abandonment and impairment |
— | — | — | |||||||||
| Seismic and other exploration |
— | — | — | |||||||||
| Depreciation, depletion and amortization expenses |
— | — | — | |||||||||
| Total expenses |
73 | — | 73 | |||||||||
| (Income) before income taxes |
(38 | ) | — | (38 | ) | |||||||
| Provision for income taxes |
— | — | — | |||||||||
| Results of operations for crude oil and natural gas producing activities (excluding corporate overhead and interest costs) |
$ | (38 | ) | — | $ | (38 | ) | |||||
| For the year ended December 31, 2007 |
||||||||||||
| Revenues |
$ | 653 | — | $ | 653 | |||||||
| Expenses: |
||||||||||||
| Production costs |
1,167 | — | 1,167 | |||||||||
| Exploration, abandonment and impairment |
— | — | — | |||||||||
| Seismic and other exploration |
— | — | — | |||||||||
| Depreciation, depletion and amortization expenses |
— | — | — | |||||||||
| Total expenses |
1,167 | — | 1,167 | |||||||||
| Loss before income taxes |
514 | — | 514 | |||||||||
| Provision for income taxes |
— | — | — | |||||||||
| Results of operations for crude oil and natural gas producing activities (excluding corporate overhead and interest costs) |
$ | 514 | — | $ | 514 | |||||||
F-37