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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

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

For the quarterly period ended: June 30, 2012

OR

 

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

For the transition period from                  to                 

Commission file number: 001-34574

 

 

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

 

 

 

Bermuda		None
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
Akmerkez B Blok Kat 6 Nispetiye Caddesi 34330 Etiler, Istanbul, Turkey		None
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s Telephone Number, Including Area Code: +90 212 317 25 00

 

 

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant is required to submit and post such files).    Yes  x    No  ¨

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 the 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

As of August 10, 2012, the registrant had 368,167,826 common shares outstanding.

 

 

 

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TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

 

Item 1.		Financial Statements
		Consolidated Balance Sheets as of June 30, 2012 (Unaudited) and December 31, 2011			1
		Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2012 and 2011 (Unaudited)			2
		Consolidated Statements of Equity for the Six Months Ended June 30, 2012 (Unaudited)			3
		Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011 (Unaudited)			4
		Notes to Consolidated Financial Statements (Unaudited)			5
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			17
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			28
Item 4.		Controls and Procedures			29
PART II. OTHER INFORMATION
Item 1.		Legal Proceedings			30
Item 1A.		Risk Factors			30
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			40
Item 3.		Defaults Upon Senior Securities			40
Item 4.		Mine Safety Disclosures			40
Item 5.		Other Information			40
Item 6.		Exhibits			41

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PART I. FINANCIAL INFORMATION

 

Item 1.

Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

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

 

		June 30, 2012				December 31, 2011
		(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	27,879			$	15,116
Accounts receivable
Oil and natural gas sales, net			28,649				23,459
Joint interest			11,628				12,243
Other			7,377				6,992
Related party			430				—
Prepaid and other current assets			9,665				8,810
Deferred income taxes			1,712				2,124
Assets held for sale			2,098				128,117
Total current assets			89,438				196,861
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved			198,090				174,577
Unproved			79,456				70,180
Equipment and other property			34,510				40,403
			312,056				285,160
Less accumulated depreciation, depletion and amortization			(69,143	)			(49,436	)
Property and equipment, net			242,913				235,724
Other long-term assets:
Other assets			3,336				4,673
Note receivable – related party			11,500				—
Goodwill			8,902				8,514
Total other assets			23,738				13,187
Total assets		$	356,089			$	445,772
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	16,929			$	25,733
Accounts payable — related party			17,217				323
Accrued liabilities			28,851				16,450
Loans payable			—				7,732
Loan payable — related party			—				73,000
Derivative liabilities			1,180				3,716
Asset retirement obligations			3,303				3,031
Liabilities held for sale — related party			—				3,677
Liabilities held for sale			9,372				23,037
Total current liabilities			76,852				156,699
Long-term liabilities:
Asset retirement obligations			10,438				10,503
Accrued liabilities			5,181				5,503
Deferred income taxes			17,485				15,508
Loan payable			32,766				78,000
Derivative liabilities			1,775				3,355
Total long-term liabilities			67,645				112,869
Total liabilities			144,497				269,568
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.01 par value, 1,000,000,000 shares authorized; 366,541,572 shares issued and outstanding as of June 30, 2012 and 365,790,492 shares issued and outstanding as of December 31, 2011			3,665				3,658
Additional paid-in capital			536,663				534,117
Accumulated other comprehensive loss			(35,896	)			(50,615	)
Accumulated deficit			(292,840	)			(310,956	)
Total shareholders’ equity			211,592				176,204
Total liabilities and shareholders’ equity		$	356,089			$	445,772

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

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

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

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2012				2011				2012				2011
Revenues:
Oil and natural gas sales		$	31,876			$	30,755			$	66,537			$	59,431
Other			652				844				926				1,247
Total revenues			32,528				31,599				67,463				60,678
Costs and expenses:
Production			5,032				4,156				8,667				8,258
Exploration, abandonment and impairment			6,884				4,463				9,680				11,695
Seismic and other exploration			768				1,725				1,432				3,977
Revaluation of contingent consideration			—				1,250				—				1,250
General and administrative			9,613				9,319				19,361				18,404
Depreciation, depletion and amortization			9,434				8,477				18,603				13,107
Accretion of asset retirement obligations			163				338				415				552
Total costs and expenses			31,894				29,728				58,158				57,243
Operating income			634				1,871				9,305				3,435
Other income (expense):
Interest and other expense			(2,018	)			(3,560	)			(5,277	)			(7,157	)
Interest and other income			348				177				621				334
Gain (loss) on commodity derivative contracts			14,304				154				1,869				(9,157	)
Foreign exchange (loss) gain			(1,344	)			165				2,928				169
Total other income (expense)			11,290				(3,064	)			141				(15,811	)
Income (loss) from continuing operations before income taxes			11,924				(1,193	)			9,446				(12,376	)
Current income tax expense			(422	)			(1,124	)			(2,442	)			(3,662	)
Deferred income tax (expense) benefit			(3,642	)			461				(1,783	)			2,335
Net income (loss) from continuing operations			7,860				(1,856	)			5,221				(13,703	)
Loss from discontinued operations before income taxes			(5,969	)			(17,293	)			(6,146	)			(26,377	)
Gain on disposal of discontinued operations			27,214				—				27,214				—
Income tax provision			(6,193	)			(666	)			(8,173	)			(890	)
Net income (loss) from discontinued operations			15,052				(17,959	)			12,895				(27,267	)
Net income (loss)		$	22,912			$	(19,815	)		$	18,116			$	(40,970	)
Other comprehensive income (loss):
Foreign currency translation adjustment			345				(14,812	)			14,719				(12,513	)
Comprehensive income (loss)		$	23,257			$	(34,627	)		$	32,835			$	(53,483	)
Net income (loss) per common share:
Basic net income (loss) per common share:
Continuing operations		$	0.02			$	(0.01	)		$	0.01			$	(0.04	)
Discontinued operations		$	0.04			$	(0.05	)		$	0.04			$	(0.08	)
Weighted average common shares outstanding			366,536				351,165				366,486				346,181
Diluted net income (loss) per common share:
Continuing operations		$	0.02			$	(0.01	)		$	0.01			$	(0.04	)
Discontinued operations		$	0.04			$	(0.05	)		$	0.04			$	(0.08	)
Weighted average common and common equivalent shares outstanding			368,855				351,165				368,288				346,181

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

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Equity

(Unaudited)

(U.S. dollars and shares in thousands)

 

		Common Shares				Common Shares ($)				Additional Paid-in Capital				Accumulated Other Comprehensive Loss				Accumulated Deficit				Total Shareholders’ Equity
Balance at December 31, 2011			365,790			$	3,658			$	534,117			$	(50,615	)		$	(310,956	)		$	176,204
Exercise of stock options			600				6				594				—				—				600
Issuance of restricted stock units			152				1				(1	)			—				—				—
Tax withholding on restricted stock units			—				—				(158	)			—				—				(158	)
Share-based compensation			—				—				2,111				—				—				2,111
Foreign currency translation adjustments			—				—				—				14,719				—				14,719
Net income attributable to common shareholders			—				—				—				—				18,116				18,116
Balance at June 30, 2012			366,542			$	3,665			$	536,663			$	(35,896	)		$	(292,840	)		$	211,592

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

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands of U.S. dollars)

 

		For the Six Months Ended June 30,
		2012				2011
Operating activities:
Net income (loss)		$	18,116			$	(40,970	)
Adjustment for net (income) loss from discontinued operations			(12,895	)			27,267
Net income (loss) from continuing operations			5,221				(13,703	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-based compensation			1,103				957
Foreign currency loss (gain)			1,972				(552	)
Unrealized (gain) loss on commodity derivative contracts			(4,116	)			6,564
Amortization of loan financing costs			645				1,252
Deferred income tax expense (benefit)			1,783				(2,335	)
Amortization of warrants — related party			—				1,971
Exploration, abandonment and impairment			7,464				8,457
Depreciation, depletion and amortization			18,603				13,107
Accretion of asset retirement obligations			415				552
Loss on revaluation of contingent consideration			—				1,250
Changes in operating assets and liabilities, net of effect of acquisitions:
Accounts receivable			(11,527	)			8,904
Prepaid expenses and other assets			2,060				(5,180	)
Accounts payable and accrued liabilities			23,336				14,019
Net cash provided by operating activities from continuing operations			46,959				35,263
Net cash used in operating activities from discontinued operations			(34,638	)			(17,173	)
Net cash provided by operating activities			12,321				18,090
Investing activities:
Acquisitions, net of cash			—				(747	)
Additions to oil and natural gas properties			(27,937	)			(30,332	)
Additions to equipment and other properties			(2	)			(958	)
Restricted cash			1,059				—
Net cash used in investing activities from continuing operations			(26,880	)			(32,037	)
Net cash provided by (used in) investing activities from discontinued operations			154,871				(792	)
Net cash provided by (used in) investing activities			127,991				(32,829	)
Financing activities:
Exercise of stock options and warrants			600				446
Tax withholding on restricted stock units			(158	)			—
Loan proceeds			9,974				11,228
Loan proceeds—related party			11,000				—
Loan repayment			(62,923	)			(3,044	)
Loan financing costs			(250	)			—
Loan repayment—related party			(84,000	)			—
Net cash (used in) provided by financing activities from continuing operations			(125,757	)			8,630
Net cash used in financing activities from discontinued operations			(2,180	)			(2,214	)
Net cash (used in) provided by financing activities			(127,937	)			6,416
Effect of exchange rate changes on cash			388				(49	)
Net increase (decrease) in cash and cash equivalents			12,763				(8,372	)
Cash and cash equivalents, beginning of year			15,116				34,676
Cash and cash equivalents, end of period		$	27,879			$	26,304
Supplemental disclosures:
Cash paid for interest		$	4,459			$	4,083
Cash paid for income taxes		$	2,485			$	2,259
Supplemental non-cash investing and financing activities:
Note receivable—related party from sale of oilfield services business			11,500				—
Issuance of common shares for acquisitions			—				66,037
Repayment of short-term credit facility from refinancing			—				30,000

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

 

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TRANSATLANTIC PETROLEUM LTD.

Notes to Consolidated Financial Statements

1. General

 

Nature of operations

TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the “Company” or “TransAtlantic”) is an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey, Bulgaria and Romania. As of June 30, 2012, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell, 3rd, the chairman of our board of directors and chief executive officer.

Basis of presentation

Our consolidated financial statements are expressed in U.S. Dollars and have been prepared by management in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). All amounts in these notes to the consolidated financial statements are in U.S. Dollars unless otherwise indicated. We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and in the opinion of management, such financial statements reflect all adjustments necessary to present fairly the consolidated financial position of TransAtlantic at June 30, 2012 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2011. Certain prior period amounts have been reclassified to conform to the current period presentation.

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.

Out-of-period adjustments

During the three months ended June 30, 2012, we identified and corrected errors that originated in prior periods that were not material to our consolidated financial statements for the three and six months ended June 30, 2012, the three months ended March 31, 2012 and the year ended December 31, 2011.

These errors consisted mainly of accrued liabilities that should have been recorded in prior periods of approximately $2.4 million ($1.7 million related to our continuing operations and $0.7 million related to our discontinued operations) and approximately $3.3 million ($2.6 million related to our continuing operations and $0.7 million related to our discontinued operations) for the three and six months periods ended June 30, 2012.

2. Change to going concern assumption

As a result of recurring losses from operations and a working capital deficiency at March 31, 2012, we stated in our Quarterly Report on Form 10-Q for the three months ended March 31, 2012 that there was substantial doubt regarding our ability to continue as a going concern. At that time, we stated that should we be unable to consummate the sale of our oilfield services business, raise additional financing or extend the maturity date of our credit agreement with Dalea Partners, LP (“Dalea”, an affiliate of Mr. Mitchell), we would not have sufficient funds to continue operations beyond June 30, 2012.

On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”), to a joint venture owned by Dalea and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $167.2 million, consisting of approximately $155.7 million in cash, subject to a net working capital adjustment, and a $11.5 million promissory note from Dalea. We used a portion of the net proceeds from the sale to pay off our $73.0 million credit agreement with Dalea, our $11.0 million credit facility with Dalea, our $0.9 million promissory note with Viking Drilling, LLC (“Viking Drilling”), and our $1.8 million credit agreement with a Turkish bank. In addition, we used a portion of the net proceeds from the sale to pay down approximately $45.2 million in outstanding indebtedness under our amended and restated senior secured credit facility with Standard Bank Plc and BNP Paribas (Suisse) SA (the “Amended and Restated Credit Facility”).

As of June 30, 2012, we had no short-term debt and availability of $44.7 million under our Amended and Restated Credit Facility. In addition, at June 30, 2012, we had net working capital of $19.9 million, excluding assets and liabilities held for sale. As a result, management believes that the conditions that led to the substantial doubt about our ability to continue as a going concern at December 31, 2011 no longer exist at June 30, 2012.

3. Recent accounting policies

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”). ASU 2011-04 amends Accounting Standards Codification (“ASC”) 820 Fair Value Measurements and Disclosures (“ASC 820”), providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurement and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. We adopted ASU 2011-04 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In June 2011, FASB issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. In December 2011, FASB issued ASU 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU 2011-05 (“ASU 2011-12”). ASU 2011-12 deferred the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. The amendments will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted ASU 2011-05 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In September 2011, FASB issued ASU 2011-08, Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”). ASU 2011-08 allows both public and nonpublic entities an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity would no longer be required to calculate the fair value of a reporting unit unless the entity determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. ASU 2011-08 allows early adoption and will be effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted ASU 2011-08 on January 1, 2012. The adoption did not have a material effect on our financial statements.

 

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In December 2011, FASB issued ASU No. 2011-11, Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of ASU 2011-11 is required for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We are currently evaluating the effects of adopting ASU 2011-11.

We have reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our 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.

4. Pro forma results of operations

The following table presents our unaudited pro forma results of operations as though the acquisitions of Direct Petroleum Morocco, Inc. (“Direct Morocco”), Anschutz Morocco Corporation (“Anschutz”), Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”) and Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) had occurred as of January 1, 2011 (see our Annual Report on Form 10-K for the year ended December 31, 2011 for a discussion of these acquisitions):

 

		For the Three Months Ended June 30, 2011				For the Six Months Ended June 30, 2011
		(in thousands, except per share data)
Total revenues		$	38,935			$	74,587
Income (loss) from continuing operations before income taxes			741				(9,049	)
Loss from continuing operations			(309	)			(11,041	)
Loss from discontinued operations			(18,577	)			(28,472	)
Net loss			(18,886	)			(39,513	)
Net loss per common share from continuing operations:
Basic		$	(0.01	)		$	(0.03	)
Diluted		$	(0.01	)		$	(0.03	)
Net loss per common share from discontinued operations:
Basic		$	(0.05	)		$	(0.08	)
Diluted		$	(0.05	)		$	(0.08	)

5. Discontinued operations

Discontinued operations in Morocco

On June 27, 2011, we decided to discontinue our operations in Morocco. We have transferred our oilfield services equipment from Morocco to Turkey and have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for all periods presented.

Discontinued operations of oilfield services business

On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International and Viking Geophysical, to a joint venture owned by Dalea and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $167.2 million, consisting of approximately $155.7 million in cash, subject to a net working capital adjustment, and a $11.5 million promissory note from Dalea. The transaction was approved by a special committee of our board of directors after the receipt of a fairness opinion solely for the benefit of the special committee, which was subject to certain assumptions and limitations as provided in such opinion. The promissory note is payable five years from the date of issuance or earlier upon the occurrence of certain specified events, including an initial public offering by the joint venture. Upon the consummation of an initial public offering by the joint venture and the prior approval of Dalea, we can elect to convert the outstanding balance of the promissory note, including accrued interest, into the number of shares offered in the initial public offering equal to such outstanding balance divided by the per share purchase price paid by the public in the initial public offering. The promissory note bears interest at a rate of 3.0% per annum and is guaranteed by Mr. Mitchell. We used a portion of the net proceeds from the sale to pay off our $73.0 million credit agreement with Dalea, our $11.0 million credit facility with Dalea, our $0.9 million promissory note with Viking Drilling and our $1.8 million credit agreement with a Turkish bank. In addition, we used a portion of the net proceeds from the sale of our oilfield services business to pay down approximately $45.2 million in outstanding indebtedness under our Amended and Restated Credit Facility. We have presented the oilfield services segment operating results as discontinued operations for all periods presented.

The assets and liabilities held for sale at June 30, 2012 and December 31, 2011 were as follows:

 

		June 30, 2012				December 31, 2011
		(in thousands)
Cash		$	164			$	1,185
Receivables, net			—				8,098
Property and equipment, net			408				114,523
Other assets			1,526				4,311
Total assets held for sale		$	2,098			$	128,117
Accrued expenses and other liabilities		$	9,372			$	23,037
Liabilities held for sale—related party			—				3,677
Total liabilities held for sale		$	9,372			$	26,714

 

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Our operating results from discontinued operations for the three and six months ended June 30, 2012 and 2011 are summarized as follows:

 

		For the Three Months Ended June 30,								For the Six Months Ended June 30,
		2012				2011				2012				2011
		(in thousands)
Total revenues		$	9,620			$	4,049			$	19,904			$	7,214
Total costs and expenses			(15,757	)			(20,894	)			(25,283	)			(32,439	)
Total other income (expense)			168				(448	)			(767	)			(1,152	)
Loss from discontinued operations before income taxes			(5,969	)			(17,293	)			(6,146	)			(26,377	)
Gain on disposal of discontinued operations			27,214				—				27,214				—
Income tax provision			(6,193	)			(666	)			(8,173	)			(890	)
Net income (loss) from discontinued operations		$	15,052			$	(17,959	)		$	12,895			$	(27,267	)

6. Goodwill

Goodwill represents the excess of the purchase price of a business over the estimated fair value of the assets acquired and liabilities assumed. We record goodwill from acquisitions where we anticipate access to potential exploration and production opportunities. All of our goodwill is attributable to our Turkey operating segment. Our goodwill at June 30, 2012 and December 31, 2011 was as follows:

 

		June 30, 2012				December 31, 2011
		(in thousands)
Goodwill at beginning of period		$	8,514			$	10,341
Foreign exchange change effect			388				(1,827	)
Goodwill at end of period		$	8,902			$	8,514

7. Property and equipment

Oil and natural gas properties

 

The	following table sets forth the capitalized costs under the successful efforts method for our oil and natural gas properties:

 

		June 30, 2012				December 31, 2011
		(in thousands)
Oil and natural gas properties, proved:
Turkey		$	195,827			$	172,886
Bulgaria			2,263				1,691
Total oil and natural gas properties, proved			198,090				174,577
Oil and natural gas properties, unproved:
Turkey			79,456				70,180
Gross oil and natural gas properties			277,546				244,757
Accumulated depletion			(63,101	)			(45,327	)
Net oil and natural gas properties		$	214,445			$	199,430

At June 30, 2012 and December 31, 2011, we excluded $13.3 million and $7.1 million, respectively, from the depletion calculation for proved development wells currently in progress and for fields currently not in production.

 

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At June 30, 2012, our oil and natural gas properties were comprised of $53.6 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $68.1 million relating to exploratory well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.

At December 31, 2011, our oil and natural gas properties were comprised of $61.8 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $60.4 million relating to exploratory well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.

During the six months ended June 30, 2012, we incurred approximately $10.3 million in exploratory drilling costs, of which $3.5 million was charged to earnings (included in exploration, abandonment and impairment expense) and $6.8 million remained capitalized at June 30, 2012. No exploratory well costs were reclassified to proved properties in the second quarter of 2012. Uncertainties affect the recoverability of costs of our oil and natural gas properties, as the recovery of the costs are dependent upon us maintaining licenses in good standing and achieving commercial production or sale.

We recorded $1.5 million in impairment charges on our proved properties during the six months ended June 30, 2012 primarily due to downward revisions in natural gas reserves in our Alpullu field. No impairment was recorded during the six months ended June 30, 2011.

As of June 30, 2012, we had $5.5 million of exploratory well costs capitalized for the Pancarkoy-1 well, which we began drilling in the fourth quarter of 2010. After the second fracture stimulation of the Pancarkoy-1 well, commercial natural gas production could not be sustained due to the high amount of water production. A third fracture stimulation of the Pancarkoy-1 well was performed in April 2012, but commercial production could not be sustained due to high water production. We expect to further test the Pancarkoy-1 well in the third quarter of 2012, and further fracture stimulation will depend on the outcome of the conventional test results. In June 2012, a partial write-off of exploratory well costs was made, with only the sidetrack wellbore costs remaining capitalized. The following table summarizes the costs related to this well:

 

		Year Ended December 31,								Six Months Ended June 30, 2012				Partial Write-Off				Total at June 30, 2011
		2010				2011
						(in thousands)
Pancarkoy-1 well initial re-entry and fracture stimulation (Ceylan and Mezardere formations)		$	788			$	4,867			$	1,917			$	(2,052	)		$	5,520
Total capitalized costs		$	788			$	4,867			$	1,917			$	(2,052	)		$	5,520

Equipment and other property

The historical cost of equipment and other property, presented on a gross basis with accumulated depreciation, is summarized as follows:

 

		June 30, 2012				December 31, 2011
		(in thousands)
Other equipment		$	3,290			$	6,351
Inventory			19,400				20,471
Gas gathering system and facilities			5,299				6,822
Vehicles			163				1,001
Office equipment and furniture			6,358				5,758
Gross equipment and other property			34,510				40,403
Accumulated depreciation			(6,042	)			(4,109	)
Net equipment and other property		$	28,468			$	36,294

We classify our materials and supply inventory, including steel tubing and casing, as long-term assets because such materials will ultimately be classified as long-term assets when the material is used in the drilling of a well. During the six months ended June 30, 2012, we recorded a write-down of inventory of $1.2 million as a result of book to physical variances identified in inventory counts at June 30, 2012.

At June 30, 2012, we excluded $0.1 million of other equipment and $19.4 million of inventory from depreciation, as the equipment and inventory had not been placed into service.

At December 31, 2011, we excluded $0.5 million of other equipment, $20.5 million of inventory and $1.8 million of gas gathering system and facilities from depreciation as the equipment, inventory and system had not been placed into service.

 

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8. Commodity derivative instruments

We use collar derivative contracts to economically hedge against the variability in cash flows associated with the forecasted sale of our future oil production. We have not designated the derivative financial instruments as hedges for accounting purposes and, accordingly, we record the contracts at fair value and recognize changes in fair value in earnings as they occur.

To the extent that a legal right-of-offset exists, we net the value of our derivative instruments with the same counterparty in our consolidated balance sheets. All of our oil derivative contracts are settled based upon Brent oil pricing. We recognize unrealized and realized gains and losses related to these contracts on a fair value basis in our consolidated statements of operations and comprehensive income (loss) under the caption “Gain (loss) on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows. We are required under our Amended and Restated Credit Facility to hedge between 30% and 75% of our anticipated production volumes in the Selmo and Arpatepe oil fields in Turkey.

For the three months ended June 30, 2012, we recorded a net gain on commodity derivative contracts of approximately $14.3 million consisting of a $15.1 million unrealized gain related to changes in fair value and a $0.8 million realized loss for settled contracts. For the six months ended June 30, 2012, we recorded a net gain on commodity derivative contracts of $1.9 million, consisting of a $4.1 million unrealized gain related to changes in fair value and a $2.2 million realized loss for settled contracts.

For the three months ended June 30, 2011, we recorded a net gain on commodity derivative contracts of approximately $0.1 million consisting of a $2.0 million unrealized gain related to changes in fair value and a $1.9 million realized loss for settled contracts. For the six months ended June 30, 2011, we recorded a net loss on commodity derivative contracts of $9.2 million, consisting of a $6.6 million unrealized loss related to changes in fair value and a $2.6 million realized loss for settled contracts.

At June 30, 2012 and December 31, 2011, we had outstanding contracts with respect to our future crude oil production as set forth in the tables below:

Fair Value of Derivative Instruments as of June 30, 2012

 

Type		Period		Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Asset (Liability)
																(in thousands)
Collar		July 1, 2012—December 31, 2012			960			$	64.69			$	106.98			$	(278	)
Collar		January 1, 2013—December 31, 2013			400			$	75.00			$	125.50				148
Collar		January 1, 2014—December 31, 2014			380			$	75.00			$	124.25				172
																$	42

 

				Collars												Additional Call
Type		Period		Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Liability
																				(in thousands)
Three-way collar contract		July 1, 2012—December 31, 2012			240			$	70.00			$	100.00			$	129.50			$	(127	)
Three-way collar contract		July 1, 2012—December 31, 2012			205			$	85.00			$	97.13			$	162.13				(119	)
Three-way collar contract		January 1, 2013—December 31, 2013			831			$	85.00			$	97.13			$	162.13				(1,297	)
Three-way collar contract		January 1, 2014—December 31, 2014			726			$	85.00			$	97.13			$	162.13				(662	)
Three-way collar contract		January 1, 2015—December 31, 2015			1,016			$	85.00			$	91.88			$	151.88				(792	)
																				$	(2,997	)

 

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Fair Value of Derivative Instruments as of December 31, 2011

 

Type		Period				Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Asset (Liability)
																		(in thousands)
Collar			January 1, 2012—December 31, 2012				960			$	64.69			$	106.98			$	(2,529	)
Collar			January 1, 2013—December 31, 2013				400			$	75.00			$	125.50				(116	)
Collar			January 1, 2014—December 31, 2014				380			$	75.00			$	124.25				12
																		$	(2,633	)

 

				Collars												Additional Call
Type		Period		Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Liability
																				(in thousands)
Three-way collar contract		January 1, 2012—December 31, 2012			240			$	70.00			$	100.00			$	129.50			$	(764	)
Three-way collar contract		January 1, 2012—March 31, 2012			350			$	85.00			$	118.88			$	138.13				(7	)
Three-way collar contract		April 1, 2012—June 30, 2012			350			$	85.00			$	116.25			$	137.38				(35	)
Three-way collar contract		July 1, 2012—December 31, 2012			205			$	85.00			$	97.13			$	162.13				(381	)
Three-way collar contract		January 1, 2013—December 31, 2013			831			$	85.00			$	97.13			$	162.13				(1,985	)
Three-way collar contract		January 1, 2014—December 31, 2014			726			$	85.00			$	97.13			$	162.13				(626	)
Three-way collar contract		January 1, 2015—December 31, 2015			1,016			$	85.00			$	91.88			$	151.88				(640	)
																				$	(4,438	)

9. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations for the six months ended June 30, 2012 and for the year ended December 31, 2011:

 

 

		June 30, 2012				December 31, 2011
		(in thousands)
Asset retirement obligations at beginning of period		$	13,534			$	6,943
Acquisitions			—				6,480
Change in estimates			(1,226	)			512
Liabilities settled			—				(195	)
Foreign exchange change effect			603				(2,524	)
Additions			415				1,176
Accretion expense			415				1,142
Asset retirement obligations at end of period			13,741				13,534
Less: current portion			3,303				3,031
Long-term portion		$	10,438			$	10,503

 

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10. Third party loans payable

As of the indicated dates, our third-party debt consisted of the following:

 

		June 30,  2012				December 31, 2011
		(in thousands)
Third-Party Floating Rate Debt
Amended and Restated Credit Facility		$	32,766			$	78,000
Third-Party Fixed Rate Debt
TBNG credit agreement			—				7,732
Viking International equipment loan			—				—	(1)
Total third-party debt			32,766				85,732
Less: short-term third-party debt			—				7,732
Long-term third-party debt		$	32,766			$	78,000

 

 

(1)

$2.1 million outstanding at December 31, 2011 was classified as “Liabilities held for sale”.

Amended and restated senior secured credit facility

On May 18, 2011, DMLP, Ltd. (“DMLP”), TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Ltd. (“TAT”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayive Ticaret A.Ş. (“Petrogas”) (collectively, and together with Amity Oil International Pty Ltd (“Amity”), the “Borrowers”) entered into the amended and restated credit facility. Each of the Borrowers is our wholly owned subsidiary. In July 2011, Amity executed a joinder agreement and became a borrower under the Amended and Restated Credit Facility. The Amended and Restated Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”).

The borrowing base is re-determined semi-annually on April 1st and October 1st of each year prior to September 30, 2012, and quarterly on January 1st, April 1st, July 1st and October 1st of each year after September 30, 2012. Our borrowing base is currently $77.5 million. In June 2012, we used a portion of the net proceeds from the sale of our oilfield services business to pay down approximately $45.2 million in outstanding indebtedness under the Amended and Restated Credit Facility.

At June 30, 2012, we had borrowed $32.8 million and were in compliance with all material covenants under the Amended and Restated Credit Facility.

TBNG credit agreement

TBNG was a party to an unsecured credit agreement with a Turkish bank. In April 2012, we repaid this loan and terminated the TBNG credit agreement.

Viking International equipment loan

In June 2010, Viking International entered into a secured credit agreement with a Turkish bank. In June 2012, we repaid this loan with proceeds from the sale of our oilfield services business.

11. Related party loans payable

As of the indicated dates, our related-party debt consisted of the following:

 

 

		June 30, 2012				December 31, 2011
		(in thousands)
Related Party Floating Rate Debt
Dalea credit agreement		$	—			$	73,000
Dalea credit facility			—				—
Viking Drilling note			—				—	(1)
Total related party debt			—				73,000
Less: short-term related party debt			—				73,000
Long-term related party debt		$	—			$	—

 

 

(1)

$2.9 million outstanding at December 31, 2011 was classified as “Liabilities held for sale—related party”.

 

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Dalea credit agreement

On June 28, 2010, we entered into a credit agreement with Dalea. The purpose of the Dalea credit agreement was (i) to fund the acquisition of all of the shares of Amity and Petrogas, and (ii) for general corporate purposes. On May 18, 2011, we entered into a first amendment to the Dalea credit agreement to extend the maturity date and increase the interest rate to match the interest rate payable under our Amended and Restated Credit Facility. On November 7, 2011, we entered into a second amendment to the Dalea credit agreement to extend the maturity date to the earlier of (i) March 31, 2012 or (ii) the sale of Viking International and Viking Geophysical. On March 15, 2012, we entered into a third amendment to the Dalea credit agreement to extend the maturity date until the earlier of (i) June 30, 2012 or (ii) the later of (x) the closing of the sale of our oilfield services business or (y) two business days after demand by Dalea. In June 2012, we repaid the Dalea credit agreement with proceeds from the sale of our oilfield services business.

Dalea credit facility

On March 15, 2012, TransAtlantic Worldwide, TBNG and TransAtlantic Petroleum Ltd. entered into a $15.0 million credit facility with Dalea to provide us with additional liquidity for general corporate purposes until we completed the sale of Viking. In June 2012, we repaid the Dalea credit facility with proceeds from the sale of our oilfield services business.

Viking Drilling note

In June 2012, we repaid this note with proceeds from the sale of our oilfield services business.

12. Contingencies relating to exploration permits

In the second quarter of 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. We have a $1.0 million bank guarantee in place to ensure our performance of the Tselfat exploration permit work program. Although we plan to pursue a settlement with the Moroccan government for a lesser amount, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during the second quarter of 2012 for this contractual obligation.

In the second quarter of 2012, we were notified that the Bulgarian government may seek to recover approximately $2.0 million in contractual obligations under our Aglen exploration permit work program. Due to the Bulgarian government’s January 2012 ban on fracture stimulation and related activities, we declared force majeure under the terms of the exploration permit. Although we invoked force majeure, we have recorded $2.0 million in general and administrative expense relating to our Aglen exploration permit during the second quarter of 2012 for this contractual obligation.

13. Shareholders’ equity

June 2011 share issuance

On June 7, 2011, we issued 18,500,000 common shares at the acquisition date closing price of $2.05 per share in a private placement to an accredited investor in connection with the acquisition of TBNG.

February 2011 share issuance

On February 18, 2011, we issued 8,924,478 common shares at the acquisition date closing price of $3.15 per share in a private placement to an accredited investor in connection with the acquisition of Direct Morocco, Anschutz and Direct Bulgaria.

Restricted stock units

In connection with the sale of our oilfield services business, we accelerated the vesting of restricted stock units (“RSUs”) for employees of this business. We recognized $1.0 million in share-based compensation expense related to this acceleration during the three and six months ended June 30, 2012. Total share-based compensation expense of approximately $1.6 million and $2.1 million with respect to awards of RSUs was recorded for the three and six months ended June 30, 2012, respectively. We recorded share-based compensation expense of $0.4 million and $1.0 million for the three and six months ended June 30, 2011, respectively.

As of June 30, 2012, we had approximately $2.5 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 2.0 years.

Stock option plan

Our 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 that are presently outstanding under the Option Plan have a five-year term. We did not grant any stock options during the six months ended June 30, 2012 or 2011. At June 30, 2012, all stock options have been fully amortized.

 

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Earnings per share

We account for earnings per share in accordance with ASC Subtopic 260-10, Earnings Per Share (“ASC 260-10”). ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted. Basic earnings per common share for the three and six months ended June 30, 2012 and 2011 equals net income divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding RSUs. Diluted earnings per common share for the three and six months ended June 30, 2012 and 2011 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes stock options, RSUs and warrants, whether exercisable or not. The computation of diluted earnings per common share excluded 7,455,206 and 22,213,144 antidilutive common share equivalents from the three months ended June 30, 2012 and 2011, respectively, and 7,464,463 and 22,293,408 antidilutive common share equivalents from the six months ended June 30, 2012 and 2011, respectively.

The following table presents the basic and diluted earnings per common share computations:

 

 

		Three Months Ended June 30,								Six Months Ended June 30,
(in thousands, except per share amounts)		2012				2011				2012				2011
Net income (loss) from continuing operations		$	7,860			$	(1,856	)		$	5,221			$	(13,703	)
Net income (loss) from discontinued operations		$	15,052			$	(17,959	)		$	12,895			$	(27,267	)
Basic net income (loss) per common share:
Shares:
Weighted average shares outstanding			366,536				351,165				366,486				346,181
Basic net income (loss) per common share:
Continuing operations		$	0.02			$	(0.01	)		$	0.01			$	(0.04	)
Discontinued operations		$	0.04			$	(0.05	)		$	0.04			$	(0.08	)
Diluted net income (loss) per common share:
Shares:
Weighted average number of common shares outstanding			366,536				351,165				366,486				346,181
Dilutive effect of:
Restricted stock units			2,169				—				1,645				—
Stock options			150				—				157				—
Weighted average common and common equivalent shares outstanding			368,855				351,165				368,288				346,181
Diluted net income (loss) per common share:
Continuing operations		$	0.02			$	(0.01	)		$	0.01			$	(0.04	)
Discontinued operations		$	0.04			$	(0.05	)		$	0.04			$	(0.08	)

Additionally, we had a contingent liability at June 30, 2012 of approximately $10.0 million that is payable in our common shares. At the June 29, 2012 closing price of our common shares, this liability represented 9,259,259 common shares that could be potentially dilutive to future earnings per share calculations.

 

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14. Segment information

In accordance with ASC 280, Segment Reporting (“ASC 280”), we have three reportable geographic segments: Romania, Turkey and Bulgaria. Summarized financial information from continuing operations concerning our geographic segments is shown in the following table:

 

		Corporate				Romania				Turkey				Bulgaria				Total
		(in thousands)
For the three months ended June 30, 2012
Total revenues		$	—			$	—			$	32,444			$	84			$	32,528
Income (loss) from continuing operations before income taxes			(1,913	)			(357	)			16,394				(2,200	)			11,924
Capital expenditures		$	—			$	—			$	13,760			$	—			$	13,760
For the three months ended June 30, 2011
Total revenues		$	45			$	—			$	31,427			$	127			$	31,599
Income (loss) from continuing operations before income taxes			(6,287	)			(300	)			6,686				(1,292	)			(1,193	)
Capital expenditures		$	22			$	—			$	14,137			$	59			$	14,218
For the six months ended June 30, 2012
Total revenues		$	—			$	—			$	67,314			$	149			$	67,463
Income (loss) from continuing operations before income taxes			(7,352	)			(655	)			19,853				(2,400	)			9,446
Capital expenditures		$	—			$	—			$	27,771			$	168			$	27,939
For the six months ended June 30, 2011
Total revenues		$	92			$	—			$	60,331			$	255			$	60,678
Income (loss) from continuing operations before income taxes			(13,834	)			(613	)			3,382				(1,311	)			(12,376	)
Capital expenditures		$	43			$	—			$	29,846			$	2,148			$	32,037
Segment assets
June 30, 2012		$	23,412			$	178			$	326,313			$	4,088			$	353,991	(1)
December 31, 2011		$	2,940			$	881			$	309,670			$	4,164			$	317,655	(1)
Goodwill
June 30, 2012		$	—			$	—			$	8,902			$	—			$	8,902
December 31, 2011		$	—			$	—			$	8,514			$	—			$	8,514

 

(1) Excludes assets from our discontinued Moroccan operations and oilfield services business of $2.1 million and $128.1 million at June 30, 2012 and December 31, 2011, respectively.

15. Financial instruments

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount at June 30, 2012 and December 31, 2011, due to the short maturity of those instruments.

Interest rate risk

We are exposed to interest rate risk as a result of our variable rate short-term cash holdings and borrowings under the Amended and Restated Credit Facility.

Foreign currency risk

We have underlying foreign currency exchange rate exposure. Our currency exposures relate to transactions denominated in the Canadian Dollar, Bulgarian Lev, European Union Euro, Romanian New Leu, Moroccan Dirham and New Turkish Lira. We are also subject to foreign currency exposures resulting from translating the functional currency of our foreign subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At June 30, 2012, we had 27.3 million New Turkish Lira (approximately $15.1 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the New Turkish Lira.

 

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Commodity price risk

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including but not limited to, supply and demand. At June 30, 2012 and December 31, 2011, we were a party to commodity derivative contracts.

Concentration of credit risk

The majority of our receivables are within the oil and natural gas industry, primarily from our industry partners and from government agencies. Included in receivables are amounts due from Turkiye Petrolleri Anonim Ortakligi, the national oil company of Turkey, Zorlu Dogal Daz Ithalat Ihracat ve Toptan Ticaret A.Ş., a privately owned natural gas distributor in Turkey, and Turkiye Petrol Rafinerileri A.Ş., a privately owned oil refinery in Turkey, which purchase the majority of our oil and natural gas production. The receivables are not collateralized. To date, we have experienced minimal bad debts and have no allowance for doubtful accounts. Other accounts receivable relating to value added taxes are due from various government agencies and are expected to be collected during 2012. The majority of our cash and cash equivalents are held by three financial institutions in the United States and Turkey.

Fair value measurements

The following table summarizes the valuation of our financial assets and liabilities as of June 30, 2012:

 

		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)
Liabilities:
Amended and Restated Credit Facility		$	—			$	(32,766	)		$	—			$	(32,766	)
Derivative financial instruments (commodity)			—				(2,955	)			—				(2,955	)
Total		$	—			$	(35,721	)		$	—			$	(35,721	)

The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2011:

 

		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)
Liabilities:
Related party floating rate debt		$	—			$	(73,000	)		$	—			$	(73,000	)
Amended and Restated Credit Facility			—				(78,000	)			—				(78,000	)
TBNG credit agreement			—				(7,732	)			—				(7,732	)
Derivative financial instruments (commodity)			—				(7,071	)			—				(7,071	)
Total		$	—			$	(165,803	)		$	—			$	(165,803	)

We remeasure our derivative contracts on a recurring basis, with changes flowing through earnings. All other financial instruments are recorded at carrying value. The carrying value of these other financial instruments approximates fair value, as they are subject to short-term floating interest rates that approximate the rates available to us.

 

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16. Related party transactions

The following table summarizes related party accounts receivable and accounts payable as of June 30, 2012 and December 31, 2011:

 

		June 30, 2012				December 31, 2011
		(in thousands)
Related party accounts receivable:
Viking International		$	430			$	—
Total related party accounts receivable		$	430			$	—
Related party accounts payable:
Viking International master services agreement		$	12,694			$	—
Viking Geophysical master services agreement			4,523				—
Riata Management service agreement			—				323
Total related party accounts payable		$	17,217			$	323

The following table summarizes related party accounts receivable held for sale and related party accounts payable held for sale as of June 30, 2012 and December 31, 2011:

 

		June 30, 2012				December 31, 2011
		(in thousands)
Related party accounts receivable:
Maritas services agreement		$	—			$	251
Viking Oilfield Services services agreement			—				116
Total related party accounts receivable held for sale		$	—			$	367
Related party accounts payable:
Viking Drilling services agreement		$	—			$	92
Viking Oilfield Services services agreement			—				617
Gundem lease agreements			—				36
Total related party accounts payable held for sale		$	—			$	745

On June 13, 2012, we entered into separate master services agreements with each of Viking International, Viking Petrol Sahasi Hizmetleri A.S. (“VOS”) and Viking Geophysical in connection with the sale of our oilfield services business. Pursuant to the master services agreements with Viking International and VOS, we are entitled to receive certain oilfield services and materials, including, but not limited to, drilling rigs and fracture stimulation that are needed for our operations in Bulgaria, Romania and Turkey. Pursuant to the master services agreement with Viking Geophysical, we are also entitled to receive geophysical services and materials that are needed for our operations in those countries. Each of these master services agreement are for a five-year term and are divided into two separate phases. For the first four months of these agreements, Viking International, VOS and Viking Geophysical are required to provide us with any and all services and materials that they have available and we have the right of first refusal for any services that they offer to third parties. For the remainder of the agreements, we can contract for services and materials on a firm basis and, to the extent that we do not contract for all of their services or materials, Viking International, VOS and Viking Geophysical are allowed to contract with third parties for any remaining capacity. As of June 30, 2012, there was approximately $12.7 million due to Viking International and $4.5 million due to Viking Geophysical under these master services agreements.

On June 13, 2012, we entered into a transition services agreement with Viking Services Management, Ltd. (“Viking Management”) in connection with the sale of our oilfield services business. Pursuant to the transition services agreement, we agreed to provide certain administrative services, including, but not limited to, continued use of certain of our employees and independent contractors, a guarantee of a lease for flats in Turkey, Turkish tax or legal advice and services, office space in Istanbul, Turkey, information technology support and certain software or licenses to Viking Management. The transition services agreement has a two-year term. Viking Management agreed to use commercially reasonable efforts to eliminate its need for such services as soon as practicable following the entry into the agreement. As of June 30, 2012, we had not issued nor received billings under the transition services agreement.

 

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Item 2.

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

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

Executive Overview

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing and royalty and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey, Bulgaria and Romania. As of June 30, 2012, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell, 3rd, the chairman of our board of directors and chief executive officer.

Financial and Operational Performance Highlights. Highlights of our financial performance and operational performance for the second quarter of 2012 include:

 

•

During the quarter ended June 30, 2012, we derived 69.8% of our revenues from the production of oil and 28.2% of our revenues from the production of natural gas.

 

•

Total oil and natural gas revenues increased 3.6% to $31.9 million for the quarter ended June 30, 2012 from $30.8 million realized in the same period in 2011. The increase was the result of an increase in volumes of 51 thousand barrels of oil equivalent (“Mboe”), resulting in increased revenues of approximately $4.3 million, which was partially offset by a decrease of approximately $3.2 million from lower average prices received.

 

•

Production increased to approximately 233 net thousand barrels (“Mbbls”) of oil and approximately 1,081 net million cubic feet (“Mmcf”) of natural gas for the second quarter of 2012, as compared to approximately 219 net Mbbls of oil and 862 net Mmcf of natural gas for the same period in 2011.

 

•

As of June 30, 2012, we produced an aggregate of approximately 2,628 net barrels (“Bbls”) of oil per day and approximately 10.4 net Mmcf of natural gas per day.

 

•

For the quarter ended June 30, 2012, we incurred $13.8 million in capital expenditures, as compared to capital expenditures of $14.2 million for the quarter ended June 30, 2011.

 

•

As of June 30, 2012, we had $32.8 million in outstanding debt and no short-term borrowings, as compared to $158.7 million in outstanding debt and short-term borrowings of $80.7 million as of December 31, 2011, excluding liabilities held for sale.

Recent Developments

Appointment of New Director. On June 28, 2012, Charles J. Campise was appointed to our board of directors. Mr. Campise brings more than 20 years of international oil and natural gas financial and accounting expertise to our board, including serving as senior vice president and chief financial officer of Toreador Resources Corporation from May 2006 to March 2010 and as corporate controller for Transmeridian Exploration Incorporated from December 2003 until May 2005.

Closing of Sale of Oilfield Services Business. On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”), to a joint venture owned by Dalea Partners, LP (“Dalea”, an affiliate of Mr. Mitchell) and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $167.2 million, consisting of approximately $155.7 million in cash, subject to a net working capital adjustment, and a $11.5 million promissory note from Dalea. The transaction was approved by a special committee of our board of directors after the receipt of a fairness opinion solely for the benefit of the special committee, which was subject to certain assumptions and limitations as provided in such opinion. The promissory note is payable five years from the date of issuance or earlier upon the occurrence of certain specified events, including an initial public offering by the joint venture. Upon the consummation of an initial public offering by the joint venture and the prior approval of Dalea, we can elect to convert the outstanding balance of the promissory note, including accrued interest, into the number of shares offered in the initial public offering equal to such outstanding balance divided by the per share purchase price paid by the public in the initial public offering. The promissory note bears interest at a rate of 3.0% per annum and is guaranteed by Mr. Mitchell. We used a portion of the net proceeds from the sale to pay off our $73.0 million credit agreement with Dalea, our $11.0 million credit facility with Dalea, our $0.9 million promissory note with Viking Drilling, LLC (“Viking Drilling”) and our $1.8 million credit agreement with a Turkish bank. In addition, we used a portion of the net proceeds from the sale to pay down approximately $45.2 million in outstanding indebtedness under our amended and restated senior secured credit facility (the “Amended and Restated Credit Facility”) with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”).

Entry Into Master Services Agreements. On June 13, 2012, we also entered into separate master services agreements with each of Viking International, Viking Petrol Sahasi Hizmetleri A.S. (“VOS”) and Viking Geophysical in connection with the sale of our oilfield services business. Pursuant to the master services agreements with Viking International and VOS, we are entitled to receive certain oilfield services and materials, including, but not limited to, drilling rigs and fracture stimulation, that are needed for our operations in Bulgaria, Romania and Turkey. Pursuant to the master services agreement with Viking Geophysical, we are also

 

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entitled to receive geophysical services and materials that are needed for our operations in those countries. Each of these master services agreement are for a five-year term and are divided into two separate phases. For the first four months of these agreements, Viking International, VOS and Viking Geophysical are required to provide us with any and all services and materials that they have available and we have the right of first refusal for any services that they offer to third parties. For the remainder of the agreements, we can contract for services and materials on a firm basis and, to the extent that we do not contract for all of their services or materials, Viking International, VOS and Viking Geophysical are allowed to contract with third parties for any remaining capacity.

Entry Into Transition Services Agreement. On June 13, 2012, we also entered into a transition services agreement with Viking Services Management, Ltd. (“Viking Management”) in connection with the sale of our oilfield services business. Pursuant to the transition services agreement, we agreed to provide certain administrative services, including, but not limited to, continued use of certain of our employees and independent contractors, a guarantee of a lease for flats in Turkey, Turkish tax or legal advice and services, office space in Istanbul, Turkey, information technology support and certain software or licenses to Viking Management. The transition services agreement has a two-year term. Viking Management agreed to use commercially reasonable efforts to eliminate its need for such services as soon as practicable following the entry into the agreement.

Amendment to Ban on Fracture Stimulation in Bulgaria. In January 2012, the Bulgarian Parliament enacted legislation that was intended to ban fracture stimulation in the Republic of Bulgaria. The legislation also prevented conventional drilling and completion activities. The Bulgarian Parliament has since amended the legislation, and as a result we expect our conventional natural gas exploration, development and production activity in the country to resume after we receive a production license for our Koynare concession area. As long as the current legislation remains in effect, our unconventional natural gas exploration, development and production activities in Bulgaria will be significantly constrained.

Second Quarter 2012 Operational Update

During the second quarter of 2012, we continued to develop our Selmo and Arpatepe oil fields in southeastern Turkey and our Thrace Basin natural gas fields in northwestern Turkey, including the natural gas fields acquired in the acquisition of Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”). In addition, we continued to expand our inventory of exploration opportunities with new prospects identified on recently completed 3D seismic surveys.

Production. For the quarter ended June 30, 2012, we produced an average of approximately 2,564 net Bbls of oil per day and approximately 11.9 net Mmcf of natural gas per day.

Turkey-Thrace Basin. In the second quarter of 2012, we spud 18 wells, completed seven new wells, and performed three re-entry fracture stimulations on our TBNG acreage. Three of the seven new well completions were fracture stimulations.

As of June 30, 2012, we had $5.5 million of exploratory well costs capitalized for the Pancarkoy-1 well, which we began drilling in the fourth quarter of 2010. We have identified at least two more sands within the Mezardere formation that we expect to initially test by conventional means.

Turkey-Southeast.

 

•

Selmo. We completed three wells and began drilling four additional wells during the second quarter of 2012.

 

•

Arpatepe. In the second quarter of 2012, we spud the Bati-Arpatepe-1 well and completed the Arpatepe-5 well. We expect to complete the Arpatepe-6 well in the third quarter of 2012. This license is operated by Aladdin Middle East, Ltd.

 

•

Molla. We drilled the Bahar-1 well to a total depth of 10,522 feet and are currently testing the natural gas shows encountered in the Bedinan sands formation. The Bahar-1 well also encountered oil and natural gas shows in the Mardin, Hazro and Dadas formations, which we expect to test in this well or future offset wells. In addition, we were awarded the West Molla exploration license covering approximately 62,000 acres adjacent to our existing Molla exploration license. This acreage is prospective for the Mardin and Bedinan formations as well as the Dadas shale formation. We have committed to drill one well on this license by June 2013.

Turkey-Central Basins. We began acquiring 1,000 kilometers of 2D seismic data and approximately 8,000 kilometers of airborne gravity gradiometry and magnetic data on our Sivas Basin exploration licenses covering approximately 1.6 million acres. We expect to complete the acquisition of the Sivas Basin data in the third quarter of 2012. Shell Upstream Turkey B.V. is co-funding the Sivas Basin data acquisition costs.

 

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Planned Operations

We continue to actively explore and develop our existing oil and natural gas properties in Turkey and evaluate opportunities for further activities in Bulgaria and Romania. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. For the remainder of 2012, we are focused on accomplishing the following objectives:

 

•

Commence Tekirdag Field Area Development. We expect to begin drilling our infield tight gas development program in the Tekirdag field area in the Thrace Basin based upon our projected 50-acre drainage wells.

 

•

Explore New Fault Blocks Identified by Recently Acquired Seismic Data. We plan to begin exploration drilling of new fault blocks identified by recently acquired 3D seismic data on our Hayrabolu and Gocerler licenses in the Thrace Basin and by recently acquired 2D seismic data on our Gurun license in southeastern Turkey.

 

•

Expand Fracture Stimulation Program. During the third quarter of 2012, we plan to move fracture stimulation equipment to our Selmo oil field. We have approximately 14 wells scheduled for fracture stimulation at Selmo and anticipate the Selmo fracture stimulation program will take approximately 45 days. We plan to further refine and improve our Thrace Basin frac design and formation evaluation methods in order to optimize future fracture stimulations, and we plan to resume fracture stimulation activity in the Thrace Basin after the Selmo frac program is completed.

 

•

Develop Southeastern Turkey Licenses. In the third quarter of 2012, we plan to complete the Alibey-1H well and drill the Goksu-3H well. Those wells will be our first horizontal wells to test the fractured Mardin carbonate formations found in southeastern Turkey. In addition, we plan to commence the acquisition of approximately 100 kilometers of 2D seismic data over our recently acquired West Molla exploration license.

 

•

Reduce Exploration Risk Through Partnerships. In an effort to increase the pace of exploration activity, share exploration risk, and reduce our share of the capital commitments necessary to carry forward the exploration of our extensive acreage positions, we are currently seeking joint venture partners for our exploration acreage in Bulgaria, Romania and Turkey and plan to continue this effort during the remainder of 2012.

Capital expenditures for the remainder of 2012 are expected to range between $50.0 million and $75.0 million. Approximately 50% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Most of the remaining 50% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling, completing and stimulating developmental and exploratory oil wells at Selmo, Arpatepe, Molla, Idil and Gurun.

We currently plan to execute the following drilling and exploration activities during the remainder of 2012:

Turkey. We plan to drill approximately 21 gross wells, eight of which we expect to fracture stimulate. In addition, we plan to perform up-hole recompletions in 18 wells in the Thrace Basin and fracture stimulate 14 wells at our Selmo oilfield. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill.

Bulgaria. We expect to receive a production license in the Koynare concession area during 2012, after which conventional operating activity in the region is expected to resume. We plan to complete our evaluation of the Peshtene-R11 exploration well core data and develop a conventional completion program for the well.

Romania. We plan to participate in a 200-kilometer 2D seismic survey on the Sud Craiova license by the end of 2012.

Discontinued Operations in Morocco

On June 27, 2011, we decided to discontinue our Moroccan operations. We have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for all periods presented, and they are not included in results from continuing operations.

Discontinued Operations of Oilfield Services Business

On June 13, 2012, we closed the sale of our oilfield services business to a joint venture owned by Dalea and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $167.2 million, consisting of approximately $155.7 million in cash, subject to a net working capital adjustment, and a $11.5 million promissory note from Dalea. We have presented the oilfield services segment operating results as discontinued operations for all periods presented, and they are not included in results from continuing operations.

Significant Accounting Policies and Estimates

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 generally accepted accounting principles in the United States (“U.S. GAAP”). The preparation of these consolidated financial statements requires management to make estimates and judgments

 

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that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3. Significant accounting policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011 and are of particular importance to the portrayal of our financial position and results of operations and 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. There have been no changes to the significant accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”). ASU 2011-04 amends Accounting Standards Codification (“ASC”) 820 Fair Value Measurements and Disclosures (“ASC 820”), providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurement and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. We adopted ASU 2011-04 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In June 2011, FASB issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. In December 2011, FASB issued ASU 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU 2011-05 (“ASU 2011-12”). ASU 2011-12 deferred the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. The amendments will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted ASU 2011-05 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In September 2011, FASB issued ASU 2011-08, Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”). ASU 2011-08 allows both public and nonpublic entities an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity would no longer be required to calculate the fair value of a reporting unit unless the entity determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. ASU 2011-08 allows early adoption and will be effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted ASU 2011-08 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In December 2011, FASB issued ASU No. 2011-11, Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of ASU 2011-11 is required for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We are currently evaluating the effects of adopting ASU 2011-11.

We have reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our 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 our current or future earnings or operations.

Results of Operations—Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011

Our results of operations for the three months ended June 30, 2012 and 2011 were as follows:

 

		Three Months Ended June 30,								Change
		2012				2011				2012-2011
		(in thousands of U.S. dollars, except per unit prices and production  volumes) (as adjusted)
Production:
Oil (Mbbl)			233				219				14
Natural gas (Mmcf)			1,081				862				219
Total production (Mboe)			413				362				51
Average prices:
Oil (per Bbl)		$	97.45			$	109.28			$	(11.83	)
Natural gas (per Mcf)		$	8.48			$	7.34			$	1.14
Oil equivalent (per Boe)		$	77.18			$	84.96			$	(7.78	)

 

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		Three Months Ended June 30,								Change
		2012				2011				2012-2011
		(in thousands of U.S. dollars, except per unit prices and production  volumes) (as adjusted)
Revenues:
Oil and natural gas sales		$	31,876			$	30,755			$	1,121
Costs and expenses:
Production			5,032				4,156				876
Exploration, abandonment and impairment			6,884				4,463				2,421
Seismic and other exploration			768				1,725				(957	)
General and administrative			9,613				9,319				294
Depreciation, depletion and amortization			9,434				8,477				957
Interest and other expense			2,018				3,560				(1,542	)
Gain on commodity derivative contracts:
Cash settlements on commodity derivative contracts			(773	)			(1,890	)			1,117
Non-cash change in fair value on commodity derivative contracts			15,077				2,044				13,033
Total gain on commodity derivative contracts			14,304				154				14,150

Oil and Natural Gas Sales. Total oil and natural gas revenues increased $1.1 million to $31.9 million for the three months ended June 30, 2012 from $30.8 million realized in the same period in 2011. Of this increase, $4.3 million was the result of increased production volumes of 51 Mboe, which was partially offset by a $3.2 million decrease in revenues from lower average prices received. Production volumes increased primarily due to the June 2011 acquisition of TBNG, which contributed approximately 65 Mboe of production. This was partially offset by a decrease in production due to the natural decline of our reserve base. For the three months ended June 30, 2012, our average price received was $77.18 per Boe, as compared to $84.96 per Boe for the same period in 2011.

Production. Production expenses for the three months ended June 30, 2012 increased to $5.0 million from $4.2 million for the same period in 2011. The increase was primarily attributable to a write-off of inventory of approximately $1.2 million resulting from a physical count of inventory, which was partially offset by a reduction in workover expenses.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended June 30, 2012 increased approximately $2.4 million to $6.9 million, from $4.5 million for the same period in 2011. During the three months ended June 30, 2012, there was a partial write-off of one well for $2.1 million, a complete write-off of one well for $1.7 million and complete write-offs of three wells at an average of approximately $0.4 million per well. During the three months ended June 30, 2011, there was a partial write-off of one well for $2.6 million and complete write-offs of six wells at an average of approximately $0.3 million per well. Additionally, during the three months ended June 30, 2012, we recorded $1.5 million of impairment charges on our proved properties, primarily due to downward revisions in natural gas reserves in our Alpullu field, as compared to no impairment in the three months ended June 30, 2011.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $0.8 million for the three months ended June 30, 2012, as compared to $1.7 million for the same period in 2011. This decrease was due primarily to fewer seismic projects for the three months ended June 30, 2012, as compared to the same period in 2011.

General and Administrative. General and administrative expense was $9.6 million for the three months ended June 30, 2012, as compared to $9.3 million for the same period in 2011. The increase was primarily due a $2.0 million accrual for a contingency related to the Aglen exploration permit in Bulgaria and to including the TBNG acquisition for the entire second quarter of 2012, which accounted for $0.8 million of the increase. The increases were partially offset by decreases in our legal and accounting expenses of approximately $1.2 million and employee-related costs of $1.1 million. Legal and accounting expenses were higher in the same period of 2011 due to the late filing of our Annual Report on Form 10-K for the year ended December 31, 2010 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2011. Employee-related costs also decreased due to reductions in headcount. An additional decrease of $0.2 million was due to our overall efforts to reduce general and administrative expenses.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $9.4 million for the three months ended June 30, 2012, as compared to $8.5 million in the same period of 2011. The increase was primarily due to an increase in our production over the same period in 2011.

 

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Interest and Other Expense. Interest and other expense decreased to $2.0 million for the three months ended June 30, 2012, as compared to $3.6 million for the same period in 2011. The decrease was due to a decrease in warrant expense of approximately $0.7 million associated with our Dalea credit agreement, which was fully amortized in 2011. The remaining decrease was due to a decrease in interest on the Dalea credit agreement, which ceased accruing interest in April 2012 and was repaid in June 2012.

Gain on Commodity Derivative Contracts. During the three months ended June 30, 2012, we recorded a gain on commodity derivative contracts of approximately $14.3 million, as compared to a gain of $0.1 million for the same period in 2011. We recorded a $15.1 million unrealized gain and a $0.8 million realized loss on our derivative contracts for the three months ended June 30, 2012, as compared to a $2.0 million unrealized gain and a $1.9 million realized loss for the three months ended June 30, 2011. Unrealized gains and losses are attributable to changes in oil and natural gas prices and volumes hedged from one period end to another. We are required under our Amended and Restated Credit Facility to hedge a portion of our oil production in the Selmo and Arpatepe oil fields in Turkey.

Other Comprehensive Income. We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. dollar reporting currency. Foreign currency translation adjustment for the three months ended June 30, 2012 increased to a gain of $0.3 million from a loss of $14.8 million for the same period in 2011 due to the strengthening of the New Turkish Lira against the U.S. Dollar quarter over quarter, as compared to the same period in 2011.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations and oilfield services business for the three months ended June 30, 2012 and 2011 have been included in discontinued operations.

The results of operations for our Moroccan operations and oilfield services business were as follows:

 

		Three Months Ended June 30,
		2012				2011
		(in thousands)
Revenues:
Oil and natural gas sales		$	—			$	139
Oilfield services			9,620				3,910
Total revenues		$	9,620			$	4,049
Costs and expenses:
Production			361				1,249
Exploration, abandonment and impairment			—				9,100
Oilfield services costs			6,664				4,978
General and administrative			8,732				1,066
Depreciation, depletion and amortization			—				4,500
Accretion of asset retirement obligations			—				1
Total costs and expenses			15,757				20,894
Operating loss			(6,137	)			(16,845	)
Other income (expense):
Interest and other expense			(111	)			(177	)
Interest and other income			154				23
Foreign exchange gain (loss)			125				(294	)
Total other income (expense)			168				(448	)
Loss from discontinued operations before income taxes			(5,969	)			(17,293	)
Gain on disposal of discontinued operations			27,214				—
Income tax provision			(6,193	)			(666	)
Net income (loss) from discontinued operations		$	15,052			$	(17,959	)

 

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Results of Operations—Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

Our results of operations for the six months ended June 30, 2012 and 2011 were as follows:

 

		Six Months Ended June 30,								Change
		2012				2011				2012-2011
		(in thousands of U.S. dollars, except per unit prices and production  volumes) (as adjusted)
Production:
Oil (Mbbl)			457				438				19
Natural gas (Mmcf)			2,448				1,673				775
Total production (Mboe)			865				717				148
Average prices:
Oil (per Bbl)		$	103.28			$	108.64			$	(5.36	)
Natural gas (per Mcf)		$	7.90			$	7.31			$	0.59
Oil equivalent (per Boe)		$	76.92			$	82.89			$	(5.97	)
Revenues:
Oil and natural gas sales		$	66,537			$	59,431			$	7,106
Costs and expenses:
Production			8,667				8,258				409
Exploration, abandonment and impairment			9,680				11,695				(2,015	)
Seismic and other exploration			1,432				3,977				(2,545	)
General and administrative			19,361				18,404				957
Depreciation, depletion and amortization			18,603				13,107				5,496
Interest and other expense			5,277				7,157				(1,880	)
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts			(2,247	)			(2,593	)			346
Non-cash change in fair value on commodity derivative contracts			4,116				(6,564	)			10,680
Total gain (loss) on commodity derivative contracts			1,869				(9,157	)			11,026

Oil and Natural Gas Sales. Total oil and natural gas revenues increased $7.1 million to $66.5 million for the six months ended June 30, 2012 from $59.4 million realized in the same period in 2011. Of this increase, $12.3 million was due to an increase in production volumes of 148 Mboe. Production volumes increased primarily due to the June 2011 acquisition of TBNG, which contributed approximately 176 Mboe of production. This was partially offset by a decrease in production due to the natural decline of our reserve base. This increase was also offset by a decrease in prices received, resulting in lower revenues of $5.2 million. For the six months ended June 30, 2012, our average price received was $76.92 per Boe, as compared to $82.89 per Boe for the same period in 2011.

Production. Production expenses for the six months ended June 30, 2012 increased to $8.7 million from $8.3 million for the same period in 2011. The increase was primarily attributable to a write-off of inventory of approximately $1.2 million resulting from a physical count of inventory, which was partially offset by a reduction in workover expenses.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the six months ended June 30, 2012 decreased approximately $2.0 million to $9.7 million, from $11.7 million for the same period in 2011. During the six months ended June 30, 2012, there was a partial write-off of one well for $2.1 million and complete write-offs of three wells at an average of approximately $1.6 million per well and three additional wells at an average of approximately $0.4 million per well. In the first half of 2011, there were write-offs of three wells for $6.4 million, $2.6 million and $1.4 million in addition to six wells that were written off at an average of approximately $0.2 million per well. Additionally, during the six months ended June 30, 2012, we recorded $1.5 million of impairment charges on our proved properties, primarily due to downward revisions in natural gas reserves in our Alpullu field, as compared to no impairment in the six months ended June 30, 2011.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $1.4 million for the six months ended June 30, 2012, as compared to $4.0 million for the same period in 2011. This decrease was due primarily to fewer seismic projects for the six months ended June 30, 2012, as compared to the same period in 2011.

General and Administrative. General and administrative expense was $19.4 million for the six months ended June 30, 2012, as compared to $18.4 million for the same period in 2011. The increase was due to the $2.0 million accrual for the contingency related

 

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to our Aglen exploration permit in Bulgaria and to including TBNG for the full first six months of 2012, which accounted for an increase of approximately $2.0 million. These increases were partially offset by decreases in our legal and accounting expenses of approximately $1.8 million and employee-related costs of approximately $1.4 million. Legal and accounting expenses were higher in the comparable period in 2011 due to the late filing of our Annual Report on Form 10-K for the year ended December 31, 2010 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2011. Employee-related costs also decreased due to reductions in headcount. The remaining increase was primarily due to an increase in our share-based compensation expense.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $18.6 million for the six months ended June 30, 2012, as compared to $13.1 million in the same period of 2011. The increase was primarily due to an increase in our production over the same period in 2011.

Interest and Other Expense. Interest and other expense decreased to $5.3 million for the six months ended June 30, 2012, as compared to $7.2 million for the same period in 2011. The decrease was primarily due to warrant expenses of approximately $2.0 million associated with our Dalea credit agreement, which were fully amortized in 2011.

Gain (Loss) on Commodity Derivative Contracts. During the six months ended June 30, 2012, we recorded a gain on commodity derivative contracts of approximately $1.9 million, as compared to a loss of $9.2 million for the same period in 2011. We recorded a $4.1 million unrealized gain and a $2.2 million realized loss on our derivative contracts for the six months ended June 30, 2012, as compared to a $6.6 million unrealized loss and a $2.6 million realized loss for the six months ended June 30, 2011. Unrealized gains and losses are attributable to changes in oil and natural gas prices and volumes hedged from one period end to another. We are required under our Amended and Restated Credit Facility to hedge a portion of our oil production in the Selmo and Arpatepe oil fields in Turkey.

Other Comprehensive Income. We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. Dollar reporting currency. Foreign currency translation adjustment for the six months ended June 30, 2012 increased to a gain of $14.7 million from a loss of $12.5 million for the same period in 2011 due to the strengthening of the New Turkish Lira against the U.S. Dollar at June 30, 2012.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations and oilfield services business for the six months ended June 30, 2012 and 2011 have been included in discontinued operations.

The results of operations for our Moroccan operations and oilfield services business were as follows:

 

		Six Months Ended June 30,
		2012				2011
		(in thousands)
Revenues:
Oil and natural gas sales		$	—			$	187
Oilfield services			19,904				7,027
Total revenues		$	19,904			$	7,214
Costs and expenses:
Production			649				1,254
Exploration, abandonment and impairment			—				11,666
Seismic and other exploration			—				27
Oilfield services costs			13,736				9,716
General and administrative			10,898				2,342
Depreciation, depletion and amortization			—				7,433
Accretion of asset retirement obligations			—				1
Total costs and expenses			25,283				32,439
Operating loss			(5,379	)			(25,225	)
Other income (expense):
Interest and other expense			(176	)			(430	)
Interest and other income			172				62
Foreign exchange loss			(763	)			(784	)
Total other expense			(767	)			(1,152	)
Loss from discontinued operations before income taxes			(6,146	)			(26,377	)
Gain on disposal of discontinued operation			27,214				—
Income tax provision			(8,173	)			(890	)
Net income (loss) from discontinued operations		$	12,895			$	(27,267	)

 

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Capital Expenditures

For the quarter ended June 30, 2012, we incurred $13.8 million in capital expenditures compared to capital expenditures from continuing operations of $14.2 million for the quarter ended June 30, 2011.

For the remainder of 2012, we expect our capital expenditures to range between approximately $50.0 million and $75.0 million. Approximately 50% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Most of the remaining 50% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling, completing and stimulating developmental and exploratory oil wells at Selmo, Arpatepe, Molla, Idil and Gurun.

Liquidity and Capital Resources

Our primary sources of liquidity for the second quarter of 2012 were our cash and cash equivalents, cash flow from operations, cash from the sale of our oilfield services business and borrowings under our various debt agreements. At June 30, 2012, we had cash and cash equivalents of $27.9 million, no short-term debt associated with our continuing operations, no short-term debt associated with our discontinued operations, $32.8 million in long-term debt associated with our continuing operations, no long-term debt associated with our discontinued operations, and excluding assets held for sale of $2.1 million and liabilities held for sale of $9.4 million, working capital of $19.9 million, compared to cash and cash equivalents of $15.1 million, $80.7 million in short-term debt associated with our continuing operations, $5.0 million in short-term debt associated with our discontinued operations, $78.0 million in long-term debt associated with our continuing operations, and excluding assets held for sale of $128.1 million and liabilities held for sale of $26.7 million, a working capital deficit of $61.2 million at December 31, 2011. Net cash provided by operating activities for the six months ended June 30, 2012 decreased to $12.3 million, as compared to net cash provided by operating activities of $18.1 million for the six months ended June 30, 2011, primarily as a result of lower oil prices.

As of June 30, 2012, the outstanding principal amount of our debt was $32.8 million. In addition to cash, cash equivalents and cash flow from operations, at June 30, 2012, we had an Amended and Restated Credit Facility, which is discussed below.

Amended and Restated Credit Facility. DMLP, Ltd., TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Amity Oil International Pty Ltd (“Amity”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Ltd. and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”) (collectively, the “Borrowers”) are parties to the Amended and Restated Credit Facility. Each of the Borrowers is a wholly owned subsidiary. The Amended and Restated Credit Facility is guaranteed by TransAtlantic Petroleum Ltd. and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) (collectively, the “Guarantors”).

The amount drawn under the Amended and Restated Credit Facility may not exceed the lesser of (i) $250.0 million, (ii) the borrowing base amount at such time, (iii) the aggregate commitments of all lenders at such time and (iv) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment. At June 30, 2012, the lenders had aggregate commitments of $120.0 million, with individual commitments of $60.0 million each. In July 2012, we voluntarily reduced the aggregate commitment amount to $78.0 million, with each lender having a commitment of $39.0 million. On the last day of each fiscal quarter commencing September 30, 2012 and at the maturity date, the lenders’ commitments are subject to reduction by 6.25% of their commitments existing on such commitment reduction date.

The borrowing base is re-determined semi-annually on April 1st and October 1st of each year prior to September 30, 2012, and quarterly on January 1st, April 1st, July 1st and October 1st of each year after September 30, 2012. Our borrowing base is currently $77.5 million.

The borrowing base amount equals, for any calculation date, the lowest of:

 

•

the debt value which results in the field life coverage ratio for such calculation date being 1.50 to 1.00;

 

•

the debt value which results in the loan life coverage ratio for such calculation date being 1.30 to 1.00; and

 

•

the debt value which results in a debt service coverage ratio for any calculation period being 1.25 to 1.00.

The Amended and Restated Credit Facility matures on the earlier of (i) May 18, 2016 or (ii) the last date of the borrowing base calculation period that immediately precedes the date that the semi-annual report of Standard Bank and the Borrowers determines that

 

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the aggregate amount of hydrocarbons to be produced from the borrowing base assets in Turkey are less than 25% of the amount of hydrocarbons to be produced from the borrowing base assets shown in the initial report prepared by Standard Bank and the Borrowers. The Amended and Restated Credit Facility bears various letter of credit sub-limits, including, among other things, sub-limits of up to (i) $10.0 million, (ii) the aggregate available unused and uncancelled portion of the lenders’ commitments or (iii) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment.

Loans under the Amended and Restated Credit Facility accrue interest at a rate of three-month LIBOR plus 5.50% per annum. The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.75% per annum of the unused and uncancelled portion of the aggregate commitments that is less than or equal to the maximum available amount under the Amended and Restated Credit Facility, and (b) 1.65% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available amount under the Amended and Restated 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 to be drawn under such letter of credit and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to Standard Bank or (b) 5.50% for all other letters of credit.

The Amended and Restated Credit Facility is secured by a pledge of (i) the local collection accounts and offshore collection accounts of each of the Borrowers, (ii) the receivables payable to each of the Borrowers, (iii) the shares of each Borrower, and (iv) substantially all of the present and future assets of the Borrowers.

The Borrowers are required to comply with certain financial and non-financial covenants under the Amended and Restated Credit Facility, including maintaining the following financial ratios:

 

•

ratio of combined current assets to combined current liabilities of not less than 1.10 to 1.00;

 

•

ratio of EBITDAX (less non-discretionary capital expenditures) to aggregate amounts payable under the Amended and Restated Credit Facility of not less than 1.50 to 1.00;

 

•

ratio of EBITDAX (less non-discretionary capital expenditures) to interest expense of not less than 4.00 to 1.00; and

 

•

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

The non-financial covenants limit the ability of the Borrowers to, among other things, incur indebtedness or create any liens, merge or consolidate, liquidate or dissolve, dispose of any property or business, pay dividends, distributions or similar payments, make certain types of investments, enter into transactions with an affiliate and engage in certain businesses or business activities.

The Amended and Restated Credit Facility is also subject to customary events of default, such as the failure to pay principal or interest when due, the breach of certain covenants and obligations, a cross default to other indebtedness, our bankruptcy or insolvency, the failure to meet the required financial covenant ratios, the occurrence of a material adverse effect and the occurrence of a change in control. If an event of default shall occur and be continuing, all loans under the Amended and Restated Credit Facility will bear an additional interest rate of 2.00% per annum. In the case of an event of default upon bankruptcy or insolvency, all amounts payable under the Amended and Restated Credit Facility become immediately due and payable. In the case of any other event of default, all amounts due under the Amended and Restated 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 fixed charge coverage ratio or the interest coverage ratio by obtaining cash equity or loans from us.

At June 30, 2012, the Borrowers had borrowed $32.8 million under the Amended and Restated Credit Facility, had availability of $44.7 million under the Amended and Restated Credit Facility and were in compliance with all material covenants under the Amended and Restated Credit Facility. For additional information concerning the ratios, financial and non-financial covenants, events of default and other material terms of our Amended and Restated Credit Facility, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in our Annual Report on Form 10-K for the year ended December 31, 2011.

Dalea Credit Agreement. We also had a credit agreement with Dalea. The purpose of the Dalea credit agreement was (i) to fund the acquisition of all of the shares of Amity and Petrogas and (ii) for general corporate purposes. Amounts due under the Dalea credit agreement accrued interest at a rate of three-month LIBOR plus 5.50% per annum beginning on May 1, 2011, to be adjusted monthly on the first day of each month. Prior to May 1, 2011, amounts due under the Dalea credit agreement accrued interest at a rate of three-month LIBOR plus 2.50% per annum. Interest on the Dalea credit agreement ceased to accrue on April 1, 2012.

Under the terms of the Dalea credit agreement, we were required to issue Dalea 100,000 common share purchase warrants for each $1.0 million in principal amount advanced under the credit agreement. We borrowed an aggregate of $73.0 million under the Dalea credit agreement, and on September 1, 2010, we issued 7,300,000 common share purchase warrants to Dalea. The common share purchase warrants are exercisable until September 1, 2013 and have an exercise price of $6.00 per share.

 

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We repaid the loan in full on June 13, 2012 with proceeds from the sale of our oilfield services business.

Viking Drilling Note. On July 27, 2009, Viking International purchased the I-13 drilling rig and associated equipment from Viking Drilling. Dalea owns 85% of Viking Drilling. On February 19, 2010, Viking International purchased the I-14 drilling rig and associated equipment from Viking Drilling and entered into an amended and restated note payable to Viking Drilling in the amount of $11.8 million, which was comprised of $5.9 million payable related to the I-14 drilling rig and $5.9 million payable related to the purchase of the I-13 drilling rig. Under the terms of the amended and restated note, interest was payable monthly at a floating rate of LIBOR plus 6.25%, and secured by the I-13 and I-14 drilling rigs and associated equipment. We repaid the note in full on June 13, 2012 with proceeds from the sale of our oilfield services business.

Viking International Equipment Loan. In 2010, Viking International entered into a secured credit agreement with a Turkish bank to fund the purchase of vehicles. The credit agreement bore interest at an annual rate of 3.84% and was secured by the vehicles purchased with the proceeds of the loan. We repaid this loan in full on June 13, 2012 with proceeds from the sale of our oilfield services business.

TBNG Credit Agreement. TBNG was a party to an unsecured credit agreement with a Turkish bank. In April 2012, we repaid this loan and terminated the TBNG credit agreement.

Dalea Credit Facility. On March 15, 2012, TransAtlantic Worldwide, TBNG and TransAtlantic Petroleum Ltd. entered into a $15.0 million credit facility with Dalea to provide us with additional liquidity for general corporate purposes until completing the sale of our oilfield services business. Loans under the credit facility accrued interest at a rate of three-month LIBOR plus 5.5% per annum, to be adjusted monthly on the first day of each month.

For the initial advance, we were required to pay Dalea an arrangement fee of $250,000. Under the credit facility, we were also required to pay Dalea a commitment fee equal to 2.75% per annum of the difference between the $15.0 million committed amount and the outstanding balance measured and payable on the last day of each fiscal quarter. We repaid the loan in full on June 13, 2012 with proceeds from the sale of our oilfield services business.

Contingencies Relating to Exploration Permits

In the second quarter of 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. We have a $1.0 million bank guarantee in place to ensure our performance of the Tselfat exploration permit work program. Although we plan to pursue a settlement with the Moroccan government for a lesser amount, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during the second quarter of 2012 for this contractual obligation.

In the second quarter of 2012, we were notified that the Bulgarian government may seek to recover approximately $2.0 million in contractual obligations under our Aglen exploration permit work program. Due to the Bulgarian government’s January 2012 ban on fracture stimulation and related activities, we declared force majeure under the terms of the exploration permit. Although we invoked force majeure, we have recorded $2.0 million in general and administrative expense relating to our Aglen exploration permit during the second quarter of 2012 for this contractual obligation.

Contractual Obligations

The following table presents our contractual obligations at June 30, 2012:

 

 

						Payments Due by Year
		Total				2012				2013				2014				2015				2016				Thereafter
		(in thousands)
Debt		$	32,766			$	—			$	—			$	—			$	—			$	32,766			$	—
Leases and other			14,564				2,862				3,180				2,540				2,080				936				2,966
Contracts			1,000				1,000				—				—				—				—				—
		$	48,330			$	3,862			$	3,180			$	2,540			$	2,080			$	33,702			$	2,966

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at June 30, 2012.

Forward-Looking Statements

Certain statements contained in this Quarterly Report on Form 10-Q are “forward-looking statements” and are prospective. Forward-looking statements are typically identified by words such as “anticipate,” “believe,” “expect,” “plan,” “intend,” “may,” “project,” “forecast,” “estimate,” “continue,” “would,” “could” or similar words suggesting future outcomes or statements regarding an outlook. Such forward-looking statements are subject to risks, uncertainties and other factors which could cause actual results to differ materially from future results expressed or implied by such forward-looking statements.

 

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The following factors, among others, could cause actual results to differ from those set forth in the forward-looking statements: market prices for natural gas, natural gas liquids and oil products; estimates of reserves and economic assumptions; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which we carry on business, especially economic slowdowns; actions by governmental authorities, receipt of required approvals, increases in taxes, legislative and regulatory initiatives relating to fracture stimulation activities, 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; shortages of drilling rigs, equipment or oilfield services; and the other factors discussed in other documents that we file with or furnish to the Securities and Exchange Commission (“SEC”). 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. 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; collectability 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.

Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other things contemplated by the forward-looking statements will not occur.

Forward-looking statements in this Quarterly Report on Form 10-Q are based on management’s beliefs and opinions at the time the statements are made. The forward-looking statements contained in this Quarterly Report on Form 10-Q are expressly qualified in their entirety by this cautionary statement. The forward-looking statements included in this Quarterly Report on Form 10-Q are made as of the date of this Quarterly Report on Form 10-Q and we undertake no obligation to publicly update or revise any forward-looking statements to reflect new information, future events or otherwise, except as required by applicable securities laws.

 

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

During the second quarter of 2012, there were no material changes in market risk exposures that would affect the Quantitative and Qualitative Disclosures About Market Risk disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011. The following tables set forth our outstanding derivatives contracts with respect to future crude oil production as of June 30, 2012:

 

 

Type		Period		Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Asset (Liability)
																(in thousands)
Collar		July 1, 2012—December 31, 2012			960			$	64.69			$	106.98			$	(278	)
Collar		January 1, 2013—December 31, 2013			400			$	75.00			$	125.50				148
Collar		January 1, 2014—December 31, 2014			380			$	75.00			$	124.25				172
																$	42

 

 

				Collars												Additional Call
Type		Period		Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Liability
																				(in thousands)
Three-way collar contract		July 1, 2012—December 31, 2012			240			$	70.00			$	100.00			$	129.50			$	(127	)
Three-way collar contract		July 1, 2012—December 31, 2012			205			$	85.00			$	97.13			$	162.13				(119	)
Three-way collar contract		January 1, 2013—December 31, 2013			831			$	85.00			$	97.13			$	162.13				(1,297	)
Three-way collar contract		January 1, 2014—December 31, 2014			726			$	85.00			$	97.13			$	162.13				(662	)
Three-way collar contract		January 1, 2015—December 31, 2015			1,016			$	85.00			$	91.88			$	151.88				(792	)
																				$	(2,997	)

 

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Item 4.

Controls and Procedures

Acquisition of TBNG

In June 2011, we acquired TBNG. For purposes of determining the effectiveness of our disclosure controls and procedures and our internal control over financial reporting as of June 30, 2012, management has excluded the internal control over financial reporting of TBNG from its evaluation of these matters. The acquired business represents approximately 21.0% of our consolidated total assets at June 30, 2012 and 15.1% of our consolidated net income for the six months ended June 30, 2012.

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”) is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

As of June 30, 2012, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon the evaluation, and as a result of the material weaknesses in internal control over financial reporting described in our Annual Report on Form 10-K for the year ended December 31, 2011, our chief executive officer and chief financial officer concluded that, as of June 30, 2012, our disclosure controls and procedures were not effective at the reasonable assurance level.

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.

Changes in Internal Control Over Financial Reporting

The following change in our internal control over financial reporting occurred during the second quarter of 2012 and has affected, or is reasonably likely to materially affect, our internal control over financial reporting:

 

•

On June 13, 2012, we completed the sale of our oilfield services business, which was substantially comprised of Viking International and Viking Geophysical.

 

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PART II. OTHER INFORMATION

 

Item 1.

Legal Proceedings

On June 27, 2012, the Kozluk Civil Court of First Instance dismissed the underlying litigation regarding persons who claimed ownership of a portion of the surface at our Selmo oil field in southeastern Turkey. We expect the court to issue its formal decision in the third quarter of 2012, after which the plaintiffs will have thirty days to file an appeal with the Court of Appeal. In the event of an appeal, we will continue to vigorously defend our interests.

 

Item 1A.

Risk Factors

During the second quarter of 2012, we completed the sale of our oilfield services business. We have amended and restated the Risk Factors included in “Part I, Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011 in their entirety to reflect the sale of our oilfield services business.

Risks Related to Our Business

We have a history of losses and may not achieve consistent profitability in the future.

We have incurred substantial losses in prior years. For the six months ended June 30, 2012, however, we generated comprehensive income of approximately $32.8 million and had $12.3 million of cash provided by operating activities. We will need to generate and sustain increased revenue levels in future periods in order to become consistently profitable, and even if we do, we may not be able to maintain or increase our level of profitability. We may incur losses in the future for a number of reasons, including risks described herein, unforeseen expenses, difficulties, complications and delays and other unknown risks.

Our exploration, development and production activities may not be profitable or achieve our expected returns.

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

Drilling for and producing oil and natural gas 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 oil or natural gas 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;

 

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•

adverse weather conditions;

 

•

lack of market demand for oil and natural gas;

 

•

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

 

•

declines in oil and natural gas prices; and

 

•

shortages or delays in the availability of drilling rigs, equipment and qualified personnel.

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.

Shortages of drilling rigs, equipment, oilfield services and qualified personnel could delay our exploration and development activities and increase the prices we pay to obtain such drilling rigs, equipment, oilfield services and personnel.

Our industry is cyclical and, from time to time, there may be a shortage of drilling rigs, equipment, oilfield services and qualified personnel in the countries in which we operate. Shortages of drilling and workover rigs, pipe and other equipment may occur as demand for drilling rigs and equipment increases, along with the number of wells being drilled increases. These factors can also cause significant increases in costs for equipment, oilfield services and qualified personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. These types of shortages or price increases could significantly decrease our net income, cash provided by operating activities and results of operations, or restrict our ability to conduct the exploration and development activities we currently have planned and budgeted or which we may plan in the future. In addition, the availability of drilling rigs can vary significantly from region to region at any particular time. An undersupply of rigs in any of the regions where we operate may result in drilling delays and higher drilling costs for the rigs that are available in that region.

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

We depend on the performance of Mr. Mitchell, our chairman and chief executive officer. The loss of Mr. Mitchell could negatively impact our ability to execute our strategy. We do not maintain a key person life insurance policy on Mr. Mitchell.

We have concentrated current production of crude oil.

We derive substantially all of our crude oil production from the Selmo field in southeastern Turkey. Turkiye Petrolleri Anonim Ortakligi, the national oil company of Turkey, and Turkiye Petrol Rafinerileri A.Ş., a privately owned oil refinery in Turkey, purchase all of our crude oil production from the Selmo field, which represented 66.4% of our total revenues in 2011. If either of these companies fails to purchase our production, our results of operations could be materially and adversely affected.

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

Our international operations are mainly performed in emerging markets such as Turkey, Bulgaria and Romania, which may expose us to greater risks than those associated with more developed markets. In total, these markets accounted for 99.9% and 99.8% of our operating revenue in 2011 and 2010, respectively. Due to our foreign operations, we are subject to the following issues and uncertainties that can adversely affect our operations:

 

•

the risk of, and disruptions due to, expropriation, nationalization, war, revolution, election outcomes, economic instability, political instability, border disputes;

 

•

the uncertainty of local contractual terms, renegotiation or modification of existing contracts and enforcement of contractual terms in disputes before local courts;

 

•

the risk of import, export and transportation regulations and tariffs, including boycotts and embargoes;

 

•

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

 

•

the requirements or regulations imposed by local governments upon local suppliers or subcontractors, or being imposed in an unexpected and rapid manner;

 

•

taxation and revenue policies, including royalty and tax increases, retroactive tax claims and the imposition of unexpected taxes or other payments on revenues;

 

•

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

 

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•

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.

To manage these risks, we sometimes form joint ventures and/or strategic partnerships with local private and/or governmental entities. Local partners provide us with local market knowledge. However, there can be no assurance that changes in conditions or regulations in the future will not affect our profitability or ability to operate in such markets.

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

We currently derive substantially all of our oil revenue from the Selmo oil field in southeastern Turkey. Historically, the southeastern area of Turkey and nearby countries such as Iran, Iraq and Syria have experienced political, social or economic problems, terrorist attacks, insurgencies or civil unrest. Recently, tensions between Turkey and Syria increased when Syria shot down a Turkish fighter jet, raising the possibility of conflict between the countries. If any of these events, conditions or conflicts 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.

Our Amended and Restated 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 Amended and Restated Credit Facility may adversely affect our ability to finance future operations or capital needs or to engage in other business activities. Our Amended and Restated Credit Facility contains various covenants that restrict our ability to, among other things:

 

•

incur additional debt;

 

•

create liens;

 

•

enter into any hedge agreement for speculative purposes;

 

•

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

 

•

enter into sale and leaseback transactions;

 

•

enter into any merger, consolidation or amalgamation;

 

•

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

 

•

redeem or purchase any shares; or

 

•

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

In addition, the Amended and Restated Credit Facility requires us to maintain specified financial ratios and tests. 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 Amended and Restated Credit Facility and could result in an event of default under the Amended and Restated Credit Facility.

An event of default under the Amended and Restated Credit Facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios 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 any of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide; (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 Amended and Restated Credit Facility; 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 or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner, directly or

 

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indirectly, 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 an event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event.

In the event of a default and acceleration of indebtedness under the Amended and Restated Credit Facility, our business, financial condition and results of operations may be materially and adversely affected.

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 material weaknesses in our internal control over financial reporting as of December 31, 2011, as disclosed in “Item 9A. Controls and Procedures” of our Annual Report on Form 10-K for the year ended December 31, 2011. 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 processes 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.

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

As of June 30, 2012, none of our employees were represented by collective bargaining agreements. However, approximately 55 of our employees at one of our Turkish subsidiaries were previously represented by collective bargaining agreements with the Employers Association of Chemical, Oil and Plastic Industries and the Petroleum, Chemical and Rubber Workers Union of Turkey that expired on January 31, 2012. We have continued to honor the terms of the expired agreements. Potential work disruptions from labor disputes with these employees could disrupt our business and adversely affect our financial condition and results of operations.

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

For Canadian tax purposes, we were deemed, immediately before the completion of our continuance under the Bermuda Companies Act 1981, to have disposed of each property owned by us for proceeds equal to the fair market value of that property, and will be subject to tax on any resulting net income. In addition, we were 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. However, management, together with its professional advisors, has determined that the paid-up capital of our common shares and our liabilities exceeded the fair market value of our property, resulting in no “branch tax” being payable. The Canada Revenue Agency (“CRA”) may not accept our determination of the fair market value of our property. In the event that CRA’s determination of fair market value is significantly higher than our valuation and such determination is final, we may be subject to material amounts of tax resulting from the deemed disposition.

We could be subject to Bermuda corporate taxes in the future.

We are a Bermuda exempted company and under current law, we are not subject to tax on profits, income or dividends, nor is there any capital gains tax applicable to us in Bermuda. Furthermore, we have received assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966, as amended, that in the event that Bermuda enacts any legislation imposing tax computed on profits, income, any capital asset, gain or appreciation we and any of our operations or shares, debentures or other obligations shall be exempt from the imposition of such tax until March 28, 2016. If the Ministry of Finance of

 

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Bermuda changes the tax treatment afforded to exempted companies, allows the terms of the assurance to expire or does not extend the term of assurance beyond 2016, we could be subject to Bermuda corporate taxes in the future, which could have a material adverse effect on our business, financial condition or results of operations.

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

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

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

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

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

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

In general, production from oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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 oil and natural gas 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, oil and natural gas. Lower oil and natural gas prices may also reduce the amount of oil and natural gas that we can produce economically. Historically, oil and natural gas prices and markets have been volatile, and they are likely to continue to be volatile in the future.

 

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A decrease in oil or natural gas 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 oil or natural gas 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. Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of, and demand for, oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. Among the factors that could cause fluctuations are:

 

•

market expectations regarding supply and demand for oil and natural gas;

 

•

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

 

•

market expectations about future prices;

 

•

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

 

•

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

 

•

the price and availability of alternative fuels.

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

If oil and natural gas prices decline, we may be required to write-down the carrying values of our oil and natural gas properties.

There is a risk that we could be required to write down the carrying value of our oil and natural gas properties, which would reduce our earnings and shareholders’ equity. We follow the successful efforts method of accounting for our oil and natural gas properties. Under this method, the costs of productive wells, developmental dry holes and productive leases are capitalized. 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. 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 capitalized costs of our oil and natural gas properties may not exceed their estimated fair market value. When evaluating our proved properties, we are required to test for potential write-downs at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets, which is typically on a field-by-field basis. If capitalized costs exceed future cash flows, we write down the costs of proved properties to our estimate of fair market value, which is generally estimated using a discounted cash flow approach. When evaluating our unproved properties, we write down the capitalized costs of the unproved properties if it is determined that the costs are not likely to be recoverable. Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and shareholders’ equity.

The development of proved undeveloped reserves is uncertain. In addition, there are no assurances that our probable and possible reserves will be converted to proved reserves.

At December 31, 2011, approximately 47% of our total estimated net proved reserves were proved undeveloped reserves. Undeveloped reserves, by their nature, are significantly less certain than developed reserves. We also had a significant amount of unproved reserves at December 31, 2011. There is significant uncertainty attached to unproved reserve estimates, which include probable and possible reserves. The discovery, determination and exploitation of undeveloped or unproved reserves requires significant capital expenditures and successful drilling and exploration programs. We may not be able to raise the additional capital that we need to develop these reserves. There is no certainty that we will be able to convert undeveloped reserves to developed reserves or unproved reserves into proved reserves or that our undeveloped or unproved reserves will be economically viable or technically feasible to produce.

Legislative and regulatory initiatives and increased public scrutiny relating to fracture simulation activities could result in increased costs and additional operating restrictions or delays.

Fracture stimulation is an important and commonly used process for the completion of oil and natural gas wells and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate production. Recently, there has been increased public concern regarding the potential environmental impact of fracture stimulation activities. Most of these concerns have raised questions regarding the drilling fluids used in the fracturing process, their effect on drinking water supplies, the use of water in connection with completion operations, and the potential for impact to surface water, groundwater and the environment generally.

The increased attention regarding fracture stimulation could lead to greater opposition, including litigation, to oil and natural gas production activities using fracture stimulation techniques. Increased public scrutiny may also lead to additional levels of regulation in

 

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the countries in which we operate that could cause operational restrictions or delays, make it more difficult to perform fracture stimulation or could increase our costs of compliance and doing business. Additional legislation or regulation, such as a requirement to disclose the chemicals used in fracture stimulation, could make it easier for third parties opposing fracture stimulation to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. A substantial portion of our operations rely on fracture stimulation and the adoption of legislative or regulatory initiatives placing restrictions on fracture stimulation activities, especially in Turkey, could impose operational delays, increased operations costs and additional related burdens on our exploration and production activities which could make it more difficult to perform fracture stimulation, cause a material decrease in the drilling of new wells and related servicing activities and increase our costs of compliance and doing business, which could materially impact our business and profitability.

We are subject to operating hazards.

The oil and natural gas exploration and production business involves a variety of operating risks, including the risk of fire, explosion, blowout, pipe failure, casing collapse, stuck tools, uncontrollable flows of oil or natural gas, abnormally pressured formations and environmental hazards such as oil spills, surface cratering, natural gas leaks, pipeline ruptures, discharges of toxic gases, underground migration, surface spills, mishandling of fracture stimulation fluids, including chemical additives, and natural disasters, 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.

Drilling for oil and natural gas is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.

Our future financial condition and results of operations will depend on the success of our exploitation, exploration, development and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil or natural gas production. Our 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 uneconomical. Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:

 

•

shortages of or delays in obtaining drilling rigs, equipment and qualified personnel;

 

•

facility or equipment malfunctions;

 

•

unexpected operational events;

 

•

pressure or irregularities in geological formations;

 

•

adverse weather conditions, such as flooding;

 

•

reductions in oil and natural gas prices;

 

•

delays imposed by or resulting from compliance with regulatory requirements;

 

•

proximity to and capacity of transportation facilities;

 

•

title problems; and

 

•

limitations in the market for oil and natural gas.

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

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

In addition, exploration for, and exploitation, production and sale of, oil and natural gas in each country in which we operate is subject to extensive national and local laws and regulations requiring various licenses, permits and approvals from various

 

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governmental agencies. If these licenses or permits are not issued or unfavorable restrictions or conditions are imposed on our exploration or drilling activities, we might not be able to conduct our operations as planned. Alternatively, failure to comply with these laws and regulations, including the requirements of any licenses or permits, might result in the suspension or termination of operations and subject us to penalties. Our costs to comply with these numerous laws, regulations, licenses and permits are significant.

Specifically, our oil and natural gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the imposition of administrative, civil and/or criminal penalties; incurring investigatory or remedial obligations; and the imposition of injunctive relief.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to comply in all material respects with applicable environmental laws and regulations, we cannot assure you that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability. We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.

Under certain environmental laws that impose strict, joint and several liability, we may be required to remediate our contaminated properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Therefore, the costs to comply with environmental, health or safety laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results of operations.

In addition, many countries have agreed to regulate emissions of “greenhouse gases.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning of oil and natural gas, are greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations and demand for some of our services or products in the future.

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 oil and natural gas operations.

We do not intend to insure against all risks. Our oil and natural gas exploration and production activities are subject to numerous hazards and risks associated with drilling for, producing and transporting oil and natural gas, and storing, transporting and using explosive materials, and any of the following risks can cause substantial losses:

 

•

environmental hazards, such as uncontrollable flows of natural gas, oil, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination, underground migration and surface spills or mishandling of fracture stimulation fluids, including chemical additives;

 

•

abnormally pressured formations;

 

•

leaks of oil, natural gas and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations, including fracture stimulation activities, or from the gathering and transportation of oil, natural gas and other hydrocarbons, malfunctions of pipelines, processing or other facilities in our operations or at delivery points to third parties;

 

•

spillage or mishandling of oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by third-party service providers;

 

•

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.

As is customary in the oil and natural gas industry, we maintain insurance against some, but not all, of our operating risks. Our insurance may not be adequate to cover potential losses or liabilities and insurance coverage may not continue to be available at commercially acceptable premium levels or at all. We might not elect to obtain insurance if we believe that the cost of available

 

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insurance is excessive relative to the risks presented. Losses and liabilities arising from uninsured or under-insured events could require us to make large unbudgeted cash expenditures that could adversely impact our business, financial condition or results of operations.

We currently carry general liability insurance and excess liability insurance with a combined annual limit of $20.0 million per occurrence and $30.0 million in the aggregate. These insurance policies contain maximum policy limits and are subject to customary exclusions and limitations. Our general liability insurance covers us and our subsidiaries for third-party claims and liabilities arising out of lease operations and related activities. The excess liability insurance is in addition to, and is triggered if, the general liability insurance per occurrence limit is reached.

We also maintain control of well insurance and pollution insurance. Our control of well insurance has a per occurrence and combined single limit of $15.0 million and is subject to deductibles ranging from $150,000 to $500,000 per occurrence. Our pollution insurance has a per occurrence limit of $1.0 million and aggregate annual limit of $2.0 million.

We require our third-party service providers, including Viking International and Viking Geophysical, to sign master service agreements with us pursuant to which they agree to indemnify us for the personal injury and death of the service provider’s employees as well as subcontractors that are hired by the service provider. Similarly, we generally agree to indemnify our third-party service providers against similar claims regarding our employees and our other contractors.

We also require our third-party service providers that perform fracture stimulation operations for us to sign master service agreements containing the indemnification provisions noted above. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to fracture stimulation operations. We believe that our general liability, excess liability and pollution insurance policies would cover third-party claims related to fracture stimulation operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. However, these policies may not cover fines, penalties or costs and expenses related to government-mandated environmental clean-up responsibilities.

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 may assume environmental and other risks and liabilities in connection with acquired properties.

Competition in the oil and natural 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 natural 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 natural gas companies in each of the following areas:

 

•

seeking oil and natural gas exploration licenses and production licenses;

 

•

acquiring desirable producing properties or new leases for future exploration;

 

•

marketing oil and natural gas 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 natural 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 oil and natural gas 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.

 

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

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

We may not be able to complete the exploration, development or production of any, or a significant portion of, the oil and natural 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 could prevent us from, or limit us in, continuing to explore, develop or produce a significant portion of the oil and natural gas interests covered by the license or lease. The determination of the amount of acreage to be covered by the production license or lease is in the discretion of the respective governments.

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

Our foreign property interests and foreign operations may be affected by political and economic risks. These risks include war and civil disturbances, political instability, currency restrictions and exchange rate fluctuations, labor problems and high rates of inflation. In addition, local, regional and world events could cause the jurisdictions in which we operate to change the petroleum laws, tax laws, foreign investment laws, or to revise their policies in a manner that renders our current and future projects unprofitable. Further, we are subject to risks in the foreign jurisdictions in which we operate of the nationalization of the oil and natural 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 June 30, 2012, Mr. Mitchell beneficially owned approximately 40% 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 our other shareholders.

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

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

 

•

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

 

•

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

 

•

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

 

•

fluctuation in foreign exchange or interest rates;

 

•

liabilities inherent in oil and natural gas operations;

 

•

geological, technical, drilling and processing problems;

 

•

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

 

•

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

 

•

stock market volatility and market valuations;

 

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•

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, oil and natural gas;

 

•

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

 

•

political conditions in oil and natural gas 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;

 

•

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

 

•

the sale of assets;

 

•

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 shares 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 the shareholder’s investment in us.

 

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

 

Item 3.

Defaults Upon Senior Securities

None.

 

Item 4.

Mine Safety Disclosures

Not applicable.

 

Item 5.

Other Information

None.

 

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Item 6. Exhibits

 

2.1		Stock Purchase Agreement, dated March 15, 2012, by and among TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Longe Energy Limited, TransAtlantic Petroleum (USA) Corp., TransAtlantic Pertroleum Cyprus Limited, Viking International Limited, Viking Geophysical Services, Ltd., Viking Oilfield Services SRL and Dalea Partners, LP (incorporated by reference to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 10, 2012).
3.1		Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.2		Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated August 20, 2009 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.3		Bye-Laws of TransAtlantic Petroleum Ltd., dated July 14, 2009 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
10.1		Management Services Agreement, effective February 1, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Petrol Sahasi Hizmetleri A.S. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated April 20, 2012, filed with the SEC on April 26, 2012).
10.2		Master Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking International Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated June 13, 2012, filed with the SEC on June 19, 2012).
10.3		Master Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Petrol Sahasi Hizmetleri A.S. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated June 13, 2012, filed with the SEC on June 19, 2012).
10.4		Master Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Geophysical Services, Ltd. (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K dated June 13, 2012, filed with the SEC on June 19, 2012).
10.5		Transition Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Services Management, Ltd. (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K dated June 13, 2012, filed with the SEC on June 19, 2012).
10.6		Convertible Promissory Note, dated June 13, 2012, made by Dalea Partners, LP for the benefit of TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K dated June 13, 2012, filed with the SEC on June 19, 2012).
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 and Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

*	Filed herewith.

 

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Signatures

Pursuant to the requirements 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.

 

 

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INDEX TO EXHIBITS

 

2.1		Stock Purchase Agreement, dated March 15, 2012, by and among TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Longe Energy Limited, TransAtlantic Petroleum (USA) Corp., TransAtlantic Pertroleum Cyprus Limited, Viking International Limited, Viking Geophysical Services, Ltd., Viking Oilfield Services SRL and Dalea Partners, LP (incorporated by reference to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 10, 2012).
3.1		Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.2		Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated August 20, 2009 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.3		Bye-Laws of TransAtlantic Petroleum Ltd., dated July 14, 2009 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
10.1		Management Services Agreement, effective February 1, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Petrol Sahasi Hizmetleri A.S. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated April 20, 2012, filed with the SEC on April 26, 2012).
10.2		Master Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking International Limited (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated June 13, 2012, filed with the SEC on June 19, 2012).
10.3		Master Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Petrol Sahasi Hizmetleri A.S. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated June 13, 2012, filed with the SEC on June 19, 2012).
10.4		Master Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Geophysical Services, Ltd. (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K dated June 13, 2012, filed with the SEC on June 19, 2012).
10.5		Transition Services Agreement, dated June 13, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Services Management, Ltd. (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K dated June 13, 2012, filed with the SEC on June 19, 2012).
10.6		Convertible Promissory Note, dated June 13, 2012, made by Dalea Partners, LP for the benefit of TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K dated June 13, 2012, filed with the SEC on June 19, 2012).
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 and Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

*	Filed herewith.

 

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