TransAtlantic Petroleum (TAT) 10-Q 2011 Q2 Quarterly report

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, 2011

OR

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

For the transition period from                  to                 

Commission file number: 001-34574

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

Bermuda	None
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
Akmerkez B Blok Kat 5-6 Nisbetiye Caddesi 34330 Etiler, Istanbul, Turkey	None
(Address of principal executive offices)	(Zip Code)

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

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  ¨    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 5, 2011, the registrant had 365,409,722 common shares outstanding.

TABLE OF CONTENTS

Part I. Financial Information
Item 1.	Financial Statements
		Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010	1
		Consolidated Statements of Operations and Comprehensive Loss for the Three and Six Months Ended June 30, 2011 and 2010	2
		Consolidated Statements of Equity for the Six Months Ended June 30, 2011	3
		Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010	4
		Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		40
Item 4.	Controls and Procedures		40
Part II. Other Information
Item 1.	Legal Proceedings		42
Item 1A.	Risk Factors		42
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		42
Item 3.	Defaults Upon Senior Securities		42
Item 4.	Reserved		42
Item 5.	Other Information		42
Item 6.	Exhibits		43

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

(Unaudited)

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

	June 30, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	26,304		$	34,676
Accounts receivable
Oil and gas sales, net		34,535			23,077
Related party		1,811			3,783
Other		14,966			6,326
Prepaid and other current assets		13,849			6,376
Deferred income taxes		2,479			991
Assets held for sale		2,420			—
Total current assets		96,364			75,229
Property and equipment:
Oil and gas properties (successful efforts method)
Proved		192,519			157,508
Unproved		98,116			73,203
Drilling services and other equipment		199,469			174,654
		490,104			405,365
Less accumulated depreciation, depletion and amortization		(60,571	)		(38,140	)
Property and equipment, net		429,533			367,225
Other long-term assets:
Restricted cash		7,710			7,956
Deposit on acquisition		—			10,000
Deferred charges		3,881			1,596
Goodwill		9,865			10,341
Total other assets		21,456			29,893
Total assets	$	547,353		$	472,347
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	23,026		$	15,842
Accounts payable — related party		1,358			969
Accrued and other liabilities		23,573			10,329
Loans payable		15,046			30,869
Loan payable — related party		77,932			75,804
Derivative liabilities		5,837			1,612
Total current liabilities		146,772			135,425
Long-term liabilities:
Asset retirement obligations		14,079			6,943
Accrued liabilities		4,690			724
Deferred income taxes		20,589			22,641
Loan payable		67,931			27,147
Loans payable — related party		426			2,932
Derivative liabilities		4,225			1,905
Total long-term liabilities		111,940			62,292
Total liabilities		258,712			197,717
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.01 par value, 1,000,000,000 shares authorized; 365,037,542 issued and outstanding as of June 30, 2011 and 336,442,984 as of December 31, 2010		3,650			3,364
Additional paid in capital		533,127			465,973
Accumulated other comprehensive income (loss)		(8,415	)		1,812
Accumulated deficit		(239,721	)		(196,519	)
Total shareholders’ equity		288,641			274,630
Total liabilities and shareholders’ equity	$	547,353		$	472,347

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

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Operations and Comprehensive Loss

(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,
	2011			2010			2011			2010
Revenues:
Oil and natural gas sales	$	30,755		$	15,836		$	59,431		$	27,153
Oilfield services		4,754			2,768			8,274			3,843
Total revenues		35,509			18,604			67,705			30,996
Costs and expenses:
Production		4,156			4,697			8,258			8,886
Exploration, abandonment and impairment		4,463			4,149			11,695			8,422
Seismic and other exploration		939			2,273			2,428			2,668
Oilfield services costs		5,725			1,701			10,786			4,416
Revaluation of contingent consideration		1,250			—			1,250			—
General and administrative		10,246			6,774			20,502			12,553
Depreciation, depletion and amortization		12,797			4,243			21,088			7,232
Accretion of asset retirement obligations		338			59			552			105
Total costs and expenses		39,914			23,896			76,559			44,282
Operating loss		(4,405	)		(5,292	)		(8,854	)		(13,286	)
Other income (expense):
Interest and other expense		(3,695	)		(654	)		(7,471	)		(1,180	)
Interest and other income		200			126			396			140
Gain (loss) on commodity derivative contracts		154			3,034			(9,157	)		3,637
Foreign exchange loss		(75	)		(348	)		(560	)		(481	)
Total other income (expense)		(3,416	)		2,158			(16,792	)		2,116
Loss before income taxes		(7,821	)		(3,134	)		(25,646	)		(11,170	)
Current income tax expense		(2,268	)		(1,943	)		(4,979	)		(3,003	)
Deferred income tax benefit		1,141			468			3,321			686
Loss from continuing operations		(8,948	)		(4,609	)		(27,304	)		(13,487	)
Loss from discontinued operations, net of taxes		(11,648	)		(11,825	)		(15,898	)		(14,287	)
Net loss	$	(20,596	)	$	(16,434	)	$	(43,202	)	$	(27,774	)
Other comprehensive loss
Foreign currency translation adjustment		(12,526	)		(5,504	)		(10,227	)		(7,461	)
Comprehensive loss	$	(32,122	)	$	(21,938	)	$	(53,429	)	$	(35,235	)
Net loss per common share:
Basic and diluted net loss per common share
From continuing operations	$	(0.03	)	$	(0.02	)	$	(0.08	)	$	(0.04	)
From discontinued operations	$	(0.03	)	$	(0.04	)	$	(0.05	)	$	(0.05	)
Basic and diluted weighted average shares outstanding		351,165			304,597			346,181			303,989

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 Income (Loss)			Accumulated Deficit			Total Shareholders’ Equity
Balance at December 31, 2010		336,443		3,364		465,973			1,812			(196,519	)		274,630
Issuance of common shares		27,424		274		65,763			—			—			66,037
Exercise of warrants		80		1		95			—			—			96
Exercise of stock options		395		4		346			—			—			350
Issuance of restricted stock units		695		7		(7	)		—			—			—
Share-based compensation		—		—		957			—			—			957
Foreign currency translation adjustments		—		—		—			(10,227	)		—			(10,227	)
Net loss		—		—		—			—			(43,202	)		(43,202	)
Balance at June 30, 2011		365,037	$	3,650	$	533,127		$	(8,415	)		(239,721	)	$	288,641

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

3

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands of U.S. dollars)

	For the Six Months  Ended June 30,
	2011			2010
Operating activities:
Net loss	$	(43,202	)	$	(27,774	)
Adjustment for loss from discontinued operations		15,898			14,287
Net loss from continuing operations		(27,304	)		(13,487	)
Adjustments to reconcile net loss to net cash used in operating activities:
Share-based compensation		957			870
Foreign currency loss		907			145
Unrealized loss (gain) on commodity derivative contracts		6,564			(3,637	)
Amortization of debt issuance costs		1,252			233
Deferred income tax benefit		(3,321	)		(686	)
Amortization of warrants — related party		1,971			—
Exploration, abandonment and impairment		8,457			3,142
Depreciation, depletion and amortization		21,088			7,232
Accretion of asset retirement obligations		552			105
Loss on revaluation of contingent consideration		1,250			—
Changes in operating assets and liabilities, net of effect of acquisitions:
Accounts receivable		4,337			(16,127	)
Prepaid expenses and other assets		(5,379	)		(4,588	)
Accounts payable and accrued liabilities		13,353			3,698
Net cash provided by (used in) operating activities from continuing operations		24,684			(23,100	)
Net cash used in operating activities from discontinued operations		(6,594	)		(8,554	)
Net cash provided by (used in) operating activities		18,090			(31,654	)
Investing activities:
Acquisitions net of cash		(747	)		—
Additions to oil and gas properties		(30,332	)		(23,039	)
Additions to drilling services and other equipment		(4,141	)		(29,956	)
Net cash used in investing activities of continuing operations		(35,220	)		(52,995	)
Net cash provided by (used in) investing activities of discontinued operations		2,391			(2,347	)
Net cash used in investing activities		(32,829	)		(55,342	)
Financing activities:
Exercise of stock options and warrants		446			1,034
Issuance costs		—			(1	)
Loan proceeds		12,854			5,000
Loan proceeds — related party		—			68,500
Loan repayment		(4,535	)		(1,509	)
Loan repayment — related party		(2,349	)		(1,840	)
Net cash provided by financing activities		6,416			71,184
Effect of exchange rate changes on cash and cash equivalents		(49	)		(540	)
Net decrease in cash and cash equivalents		(8,372	)		(16,352	)
Cash and cash equivalents, beginning of period		34,676			90,484
Cash and cash equivalents, end of period	$	26,304		$	74,132
Supplemental disclosures:
Cash paid for interest	$	4,083		$	1,306
Cash paid for income taxes	$	2,259		$	1,446
Supplemental non-cash investing and financing activities:
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

(Unaudited)

1. General

Nature of operations

TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the “Company” or “TransAtlantic”) is a vertically integrated international oil and gas company engaged in the acquisition, exploration, development and production of oil and natural gas. We hold interests in developed and undeveloped oil and gas properties in Turkey, Morocco, Bulgaria and Romania. We own our own drilling rigs and oilfield service equipment, which we use to develop our properties in Turkey. In addition, our drilling services business provides oilfield services and drilling services to third parties in Turkey and Iraq. As of August 5, 2011, approximately 42% of our outstanding common shares were beneficially owned by N. Malone Mitchell, 3rd, our current chief executive officer and chairman of the board of directors.

Significant events and transactions which have occurred since January 1, 2011 include the following:

• on February 18, 2011, our wholly owned subsidiary, TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”), acquired Direct Petroleum Morocco, Inc. (“Direct Morocco”) and Anschutz Morocco Corporation (“Anschutz”), and our wholly owned subsidiary TransAtlantic Petroleum Cyprus Limited (“TransAtlantic Cyprus”), acquired Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”). In addition, TransAtlantic Worldwide purchased from the seller, Direct Petroleum Exploration, Inc. (“Direct”), all of Direct’s right, title and interest in the amounts due to Direct by each of Direct Morocco, Anschutz and Direct Bulgaria. As consideration for the acquisition, TransAtlantic Worldwide paid $2.4 million in cash to Direct and we issued 8.9 million of our common shares (at a deemed price of $3.15 per common share), for total consideration of $34.5 million. At the time of the acquisition, Direct Morocco and Anschutz owned a 50% working interest in the Ouezzane-Tissa and Asilah exploration permits in Morocco, and Direct Bulgaria owned 100% of the working interests in the A-Lovech and Aglen exploration permits in Bulgaria;

• effective May 6, 2011, our board of directors appointed Mr. Mitchell to serve as our chief executive officer in addition to his duties as chairman of our board of directors. Matthew McCann, our former chief executive officer, tendered his resignation on May 5, 2011;

• on May 18, 2011, we amended and restated our senior secured credit facility with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”) to extend the maturity date to May 18, 2016, to include our wholly owned subsidiaries Amity Oil International Pty. Ltd. (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”) as borrowers, and to increase the borrowing base to $75.0 million, which further increased to $95.0 million following the joinder of Amity as a borrower. As of August 5, 2011, we had borrowed $72.5 million and had $22.5 million available for borrowing under this credit facility;

• on May 18, 2011, we entered into a first amendment to our credit agreement with Dalea Partners, LP (“Dalea”) to extend the maturity date of the credit agreement to December 31, 2011 and to increase the interest rate to match the interest rate payable under our amended and restated credit facility with Standard Bank and BNP Paribas;

• on May 24, 2011, we used a portion of the amounts borrowed under the amended and restated credit facility to repay the $30.0 million short-term secured credit agreement, dated as of August 25, 2010, between TransAtlantic Worldwide and Standard Bank, which was scheduled to mature on May 25, 2011;

• on June 7, 2011, TransAtlantic Worldwide acquired all of the shares of Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) in exchange for (i) the issuance of 18.5 million of our common shares, (ii) the transfer of certain overriding royalty interests (ranging from 1.0% to 2.5% of the working interests) owned by TBNG on specified exploration licenses to the seller, Mustafa Mehmet Corporation (“MMC”) or an affiliate, and (iii) the payment of $10.5 million in cash. Through the acquisition of TBNG, we acquired interests ranging from 25% to 62.5% in 11 exploration licenses and four production leases as well as drilling rigs and oilfield service assets;

• on June 27, 2011, we announced a decision to discontinue our operations in Morocco; and

• on August 4, 2011, our board of directors appointed Wil F. Saqueton to serve as our vice president and chief financial officer.

Basis of presentation

Our consolidated financial statements are expressed in U.S. Dollars and have been prepared by management pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”), and reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the interim periods, on a basis consistent with the annual audited consolidated financial statements. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with accounting principles

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generally accepted in the United States of America (“U.S. GAAP”) have been omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the summary of significant accounting policies and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2010. All amounts in these notes to the consolidated financial statements are in U.S. Dollars unless otherwise indicated. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews estimates, including those related to fair value measurements associated with acquisitions, the impairment of long-lived assets and goodwill, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

The consolidated financial statements include the accounts of the Company and all controlled subsidiaries. All significant inter-company balances and transactions have been eliminated on consolidation.

2. Going concern

These unaudited consolidated financial statements have been prepared on the basis of accounting principles applicable to a going concern. These principles assume that we will be able to realize our assets and discharge our obligations in the normal course of operations for the foreseeable future.

We incurred a net loss of $43.2 million during the six months ended June 30, 2011. At June 30, 2011, the outstanding principal amount of our debt was $161.3 million, and we had a working capital deficiency of $50.4 million and significant commitments. Of our outstanding debt, $73.0 million under the Dalea credit agreement is due December 31, 2011. We forecast that we will need to either extend the maturity date of the Dalea credit agreement or raise additional debt or equity to fund our repayment of the Dalea credit agreement and to fund our operations, including our planned exploration and development activities. To obtain these funds, we are considering the issuance of common shares, public debt, private debt or the sale of assets. However, there is no assurance that our forecast will prove to be accurate or our efforts to raise additional debt or equity financing or consummate the sale of assets will prove to be successful. Should we be unable to raise additional financing, we will not have sufficient funds to continue operations beyond December 31, 2011. As a result, there is significant doubt regarding our ability to continue as a going concern. The continuing application of the going concern assumption is dependent upon our continuing ability to obtain the necessary financing to discharge our existing obligations, fund ongoing exploration, development and operations and ultimately achieve profitable operations.

Management believes the going concern assumption to be appropriate for these financial statements. If the going concern assumption was not appropriate, adjustments would be necessary to the carrying values of assets and liabilities, reported revenues and expenses and in the balance sheet classifications used in these consolidated financial statements.

3. Recent accounting policies

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

In December 2010, FASB issued ASU No. 2010-28Intangibles—Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts(“ASU 2010-28”). ASU 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. The update is effective for interim and annual reporting periods beginning after December 15, 2010. This update will be considered on an interim and annual basis when we review and perform our goodwill impairment test.

In December 2010, FASB issued ASU No. 2010-29Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations(“ASU 2010-29”). ASU 2010-29 specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The update also expands the supplemental pro forma disclosures under ASC Topic 805 to include a description of

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the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The update is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption of ASU 2010-29 did not have a material impact on our financial statements.

In May 2011, FASB issued 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 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 will be effective for interim and annual periods beginning after December 15, 2011. The adoption of ASU 2011-04 is not expected to have a material effect on our financial statements, but may require certain additional disclosures.

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. ASU 2011-05 will be effective for fiscal years and interim periods within those years, beginning after December 15, 2011. The adoption of ASU 2011-05 is not expected to have a material effect on our financial statements.

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

4. Acquisitions

TBNG

On June 7, 2011, we acquired TBNG for cash consideration of $10.5 million and the issuance of 18.5 million of our common shares (at a deemed price of $2.05 per common share). Of the $10.5 million cash consideration, $10.0 million was paid in November 2010 as an option fee and applied to the purchase price. We engaged independent valuation experts to assist in the determination of the fair value of the assets and liabilities acquired in the acquisition. The following tables summarize the consideration paid in the acquisition and the preliminary recognized amounts of assets acquired and liabilities assumed which have been recognized at the acquisition date:

Consideration:

	(in thousands)
Cash consideration, net of purchase price adjustments	$	10,504
Issuance of 18.5 million common shares		37,925
Fair value of total consideration transferred	$	48,429

Acquisition-Related Costs:

Included in general and administrative expenses on our consolidated statement of operations for the six months ended June 30, 2011 $       634

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Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed at Acquisition:

Assets:
Cash	$	1,845
Accounts receivable		24,359
Restricted cash		4,931
Total financial assets		31,135
Other current assets, consisting primarily of prepaid expenses		3,273
Oil and gas properties:
Proved properties		14,526
Unproved properties		9,439
Land and buildings		2,601
Drilling services equipment and vehicles		19,406
Total oil and gas properties and other equipment		45,972
Deferred tax asset		1,533
Liabilities:
Accounts payable, consisting of normal trade obligations		8,538
Other current liabilities		1,886
Asset retirement obligation		6,480
Deferred tax liability		2,130
Bank loans		14,450
Total liabilities		33,484
Total identifiable net assets	$	48,429

As of the date of acquisition, the fair value of the receivables acquired was $24.4 million, consisting of a gross amount of $27.9 million, with $3.5 million not expected to be collected.

The fair value of identifiable assets acquired and liabilities assumed are preliminary and subject to changes which may be material on the finalization of the properties and other equipment valuation reports and final determination of valuation amounts. The results of operations of TBNG are included in our consolidated results of operations beginning June 7, 2011, the closing date of the acquisition. The amounts of revenue and income of TBNG included in our consolidated statement of operations for the six months ended June 30, 2011 are shown below:

	(in thousands)
	Revenue		Income
Actual from June 7, 2011 through June 30, 2011	$	1,911	$	419

Direct

On February 18, 2011, TransAtlantic Worldwide acquired Direct Morocco and Anschutz and TransAtlantic Cyprus acquired Direct Bulgaria, for cash consideration of $2.4 million and the issuance of 8.9 million of our common shares (at a deemed price of $3.15 per common share), for total consideration of $34.5 million. At the time of the acquisition, Direct Morocco and Anschutz owned a 50% working interest in the Ouezzane-Tissa and Asilah exploration permits in Morocco and Direct Bulgaria owned 100% of the working interests in the A-Lovech and Aglen exploration permits in Bulgaria.

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The following tables summarize the consideration paid in the acquisition of Direct Morocco, Anschutz and Direct Bulgaria and the preliminary recognized amounts of assets acquired and liabilities assumed which have been recognized at the acquisition date:

Consideration:

	(in thousands)
Cash consideration, net of purchase price adjustments	$	2,408
Issuance of 8,924,478 common shares		28,112
Liability classified contingent consideration		4,000
Fair value of total consideration transferred	$	34,520

If certain post-closing milestones are achieved, we will issue additional consideration to Direct equal to: (i) $10.0 million worth of our common shares if the Deventci-R2 well in Bulgaria is a commercial success and (ii) $10.0 million worth of our common shares if Direct Bulgaria receives a production concession for a specified area in Bulgaria. Of this additional consideration, $5.0 million would be due if we have not commenced drilling the Deventci-R2 well by November 18, 2011, and $5.0 million would be due if the Deventci-R2 well has not cored the Etropole formation by February 18, 2012. The fair value of this contingent consideration represents our best estimate of the amounts to be paid for each of the milestones, based on the probability of commercial success for each of these milestones. Subsequent changes in the fair value of the liability will be recorded in earnings. As of June 30, 2011, we have determined that the likelihood of payment for the failure to timely drill the Deventci-R2 well has increased. As a result, we recorded an additional $1.3 million, which is included under the caption “Revaluation of contingent consideration” on the consolidated statements of operations and comprehensive loss.

Acquisition-Related Costs:

Included in general and administrative expenses on our consolidated statement of operations for the six months ended June 30, 2011 $       117

Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed at Acquisition:

Assets:
Cash	$	320
Accounts receivable		57
Total financial assets		377
Other current assets, consisting primarily of prepaid expenses		146
Oil and gas properties:
Proved properties		5,000
Unproved properties		29,040
Other equipment		79
Total oil and gas properties, and other equipment		34,119
Liabilities:
Accounts payable, consisting of normal trade obligations		122
Total liabilities		122
Total identifiable net assets	$	34,520

The fair value of identifiable assets acquired and liabilities assumed are preliminary and subject to changes which may be material upon the receipt of final oil and gas properties valuation reports and tax records. The results of operations of Direct Morocco, Anschutz and Direct Bulgaria are included in our consolidated results of operations beginning February 18, 2011, the closing date of the acquisition.

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The amounts of revenue and loss of Direct Morocco, Anschutz and Direct Bulgaria included in our consolidated statement of operations for the six months ended June 30, 2011 are shown below:

	Revenue		Loss
	(in thousands)
Continuing operations	$	255	$	1,312
Discontinued operations		—		21
Total from February 18, 2011 through June 30, 2011	$	255	$	1,333

Amity and Petrogas

On August 25, 2010, TransAtlantic Worldwide acquired all of the shares of Amity and Petrogas in exchange for total cash consideration of $96.5 million. Through the acquisition of Amity and Petrogas, TransAtlantic Worldwide acquired interests ranging from 50% to 100% in 18 exploration licenses, one production lease and equipment. We funded $66.5 million of the purchase price from borrowings under our credit agreement with Dalea and $30.0 million of the purchase price from borrowings under our former short-term secured credit agreement with Standard Bank.

We engaged independent valuation experts to assist in the determination of the fair value of the assets and liabilities acquired in the acquisition. The following tables summarize the consideration paid in the Amity and Petrogas acquisition and the preliminary recognized amounts of assets acquired and liabilities assumed which have been recognized at the acquisition date:

Consideration:

	(in thousands)
Payment of cash for the acquisition of all the shares of Amity and 99.6% of the shares of Petrogas	$	96,347
Payment of cash for the acquisition of 0.4% of the shares of Petrogas from non-controlling interest in Petrogas		200
Fair value of total consideration transferred	$	96,547

Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed at Acquisition:

Assets:
Cash	$	299
Accounts receivable		295
Total financial assets		594
Other current assets, consisting primarily of prepaid expenses		1,721
Oil and gas properties:
Unproved properties		49,758
Proved properties		54,813
Drilling services and related equipment		4,256
Inventory		3,032
Total oil and gas properties, drilling services and other equipment		111,859
Liabilities:
Accounts payable, consisting of normal trade obligations		198
Accrued liabilities, consisting primarily of accrued compensated employee absences		677
Deferred income taxes		16,200
Asset retirement obligations, consisting of future plugging and abandonment liabilities on Amity’s and Petrogas’ developed wellbores as of August 25, 2010, based on internal and third-party estimates of such costs, adjusted for a historic Turkish inflation rate of approximately 6.5%, and discounted to present value using the Company’s credit-adjusted risk-free rate of 7.2%		552
Total liabilities		17,627
Total identifiable net assets	$	96,547

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The fair value of oil and gas properties acquired and liabilities assumed are preliminary and subject to changes which may be material upon the receipt of final evaluation reports.

Pro Forma Results of Operations

The following table presents the unaudited pro forma results of operations as though the acquisitions of Amity and Petrogas, Direct and TBNG acquisitions had occurred as of January 1, 2010:

	For the Three Months Ended June 30,						For the Six Months  Ended June 30,
	2011			2010			2011			2010
Total revenues	$	42,529		$	32,833		$	83,496		$	59,770
(Loss) income from continuing operations before income taxes		(2,654	)		6,406			(13,457	)		6,868
(Loss) income from continuing operations		(4,898	)		3,132			(17,637	)		950
Loss from discontinued operations		(11,648	)		(11,825	)		(15,898	)		(14,287	)
Net loss		(16,546	)		(8,693	)		(33,535	)		(13,337	)
(Loss) income per share from continuing operations
Basic	$	(0.01	)	$	0.01		$	(0.05	)	$	—
Diluted	$	(0.01	)	$	0.01		$	(0.05	)	$	—
Loss per share from discontinued operations
Basic	$	(0.03	)	$	(0.04	)	$	(0.04	)	$	(0.04	)
Diluted	$	(0.03	)	$	(0.04	)	$	(0.04	)	$	(0.04	)

5. Discontinued operations

In June 2011, we announced our intention to sell our existing operations in Morocco and transfer our drilling services equipment from Morocco to Turkey. All revenues and expenses associated with the Moroccan operations for the three and six months ended June 30, 2011 and 2010 have been included in discontinued operations.

The following presents the summary operating results for Morocco:

	For the Three Months Ended June 30,					For the Six Months  Ended June 30,
	2011		2010			2011		2010
	(in thousands)
Total revenues	$	139	$	—		$	187	$	—
Costs and expenses		11,691		11,846			15,914		14,292
Operating loss		11,552		11,846			15,727		14,292
Other expense (income)		96		(21	)		171		(5	)
Loss before income taxes		11,648		11,825			15,898		14,287
Total income tax expense		—		—			—		—
Loss from discontinued operations	$	11,648	$	11,825		$	15,898	$	14,287

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The assets of discontinued operations presented under the caption “Assets held for sale” in the balance sheet for the period June 30, 2011 are valued at the lower of cost or fair value less the cost of selling.

6. Property and equipment

(a) Oil and gas properties. The following table sets forth the capitalized costs under the successful efforts method for oil and gas properties:

	June 30, 2011			December 31, 2010
	(in thousands)
Oil and gas properties, proved:
Turkey	$	187,245		$	157,508
Bulgaria		5,274			—
Total oil and gas properties, proved	$	192,519		$	157,508
Oil and gas properties, unproved:
Turkey	$	65,841		$	66,698
Bulgaria		30,631			—
Morocco		—			5,036
Other		1,644			1,469
Total oil and gas properties, unproved		98,116			73,203
Accumulated depletion		(28,395	)		(16,118	)
Net oil and gas properties	$	262,240		$	214,593

At June 30, 2011 and December 31, 2010, we excluded $5.3 million and $11.7 million, respectively, from the depletion calculation for proved development wells currently in progress and for fields currently not in production.

At June 30, 2011, our oil and gas properties were comprised of $89.5 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $69.3 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, 2010, our oil and gas properties were comprised of $92.4 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $37.3 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, 2011, we incurred approximately $5.8 million in exploratory drilling costs, of which $2.6 million was charged to earnings (included in exploration, abandonment and impairment expense) and $3.2 million remained capitalized at June 30, 2011. We reclassified $1.1 million of our exploratory well costs to proved properties during the six months ended June 30, 2011. No amount of our exploratory well costs as of June 30, 2011 had been capitalized for a period of greater than one year after completion of drilling.

The recovery of the costs noted above are dependent upon us obtaining government approvals, obtaining and maintaining licenses in good standing and achieving commercial production or sale.

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(b) Drilling services and other equipment. The historical cost of drilling services and other equipment is summarized as follows:

	June 30, 2011			December 31, 2010
	(in thousands)
Drilling services equipment	$	99,376		$	83,916
Inventory		38,617			37,569
Gas gathering system and facilities		7,989			7,960
Fracture stimulation equipment		15,288			16,410
Seismic equipment		14,723			14,882
Vehicles		13,307			9,324
Office equipment and furniture		10,169			4,593
Gross drilling services and other property and equipment		199,469			174,654
Accumulated depreciation		(32,176	)		(22,022	)
Net drilling services and other property and equipment	$	167,293		$	152,632

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 wells.

At June 30, 2011, we excluded $2.0 million of gas gathering system and facilities, $0.9 million from drilling services equipment and $38.6 million of inventory from depreciation, as the facilities, equipment and inventory had not been placed into service.

At December 31, 2010, we excluded $0.4 million of drilling services equipment and $37.6 million of inventory from depreciation, as the equipment and inventory had not been placed into service.

7. 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 to which we are a party as hedges for accounting purposes, and accordingly, record such contracts at fair value and recognize changes in such fair value in current earnings as they occur.

Our commodity derivative contracts are carried at their fair value on our consolidated balance sheet under either the caption “Derivative liabilities” or “Derivative assets.” 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 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.

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 $6.5 million unrealized loss related to changes in fair value and a $2.7 million realized loss for settled contracts.

For the three and six months ended June 30, 2010, we recorded an unrealized gain on commodity derivative contracts of $3.0 million and $3.6 million, respectively.

At June 30, 2011 and December 31, 2010, we had outstanding contracts with respect to our future oil production as set forth in the tables below:

Fair Value of Derivative Instruments as of June 30, 2011

Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value  of Liability
									(in thousands)
Collar		July 1, 2011 — December 31, 2011		1,060	$	64.39	$	101.32	$	(2,450	)
Collar		January 1, 2012 — December 31, 2012		960	$	64.69	$	106.98		(4,757	)
Collar		January 1, 2013 — December 31, 2013		400	$	75.00	$	125.50		(701	)
Collar		January 1, 2014 — December 31, 2014		380	$	75.00	$	124.25		(568	)
									$	(8,476	)

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			Collars						Additional Call
Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
											(in thousands)
Three-way collar contract		July 1, 2011—December 31, 2011		240	$	70.00	$	100.00	$	129.50	$	(558	)
Three-way collar contract		January 1, 2012—December 31, 2012		240	$	70.00	$	100.00	$	129.50		(1,028	)
											$	(1,586	)

Fair Value of Derivative Instruments as of December 31, 2010

Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value  of Liability
									(in thousands)
Collar		January 1, 2011—December 31, 2011		1,060	$	64.39	$	101.32	$	(1,342	)
Collar		January 1, 2012—December 31, 2012		960	$	64.69	$	106.98		(1,571	)
									$	(2,913	)

			Collars						Additional Call
Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
											(in thousands)
Three-way collar contract		January 1, 2011—December 31, 2011		240	$	70.00	$	100.00	$	129.50	$	(270	)
Three-way collar contract		January 1, 2012—December 31, 2012		240	$	70.00	$	100.00	$	129.50		(334	)
											$	(604	)

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8. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations for the six months ended June 30, 2011 and for the year ended December 31, 2010:

	June 30, 2011			December 31, 2010
	(in thousands)
Asset retirement obligations at January 1, 2011 and January 1, 2010	$	6,943		$	3,125
Acquisitions		6,480			552
Change in estimates		11			2,220
Foreign exchange change effect		(588	)		(251	)
Additions		680			827
Accretion expense		553			470
Asset retirement obligations at June 30, 2011 and December 31, 2010	$	14,079		$	6,943

9. Third Party Loans payable

Our third-party debt consisted of the following:

	June 30, 2011		December 31, 2010
	(in thousands)
Third-Party Floating Rate Debt
Senior secured credit facility	$	66,000	$	25,000
Short-term secured credit agreement		—		30,000
Unsecured lines of credit		303		126
TBNG credit agreement		9,159		—
TBNG loan payable		4,754		—
Third-Party Fixed Rate Debt
Viking International equipment loan		2,761		2,890
Total debt		82,977		58,016
Less: short-term debt		15,046		30,869
Total long-term debt	$	67,931	$	27,147

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 (collectively, and together with Amity, the “Borrowers”) entered into the amended and restated senior secured credit facility with Standard Bank and BNP Paribas (the “amended and restated credit facility”). Each of the Borrowers are wholly owned subsidiaries. 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 (collectively, the “Guarantors”).

On May 24, 2011, we used a portion of the amounts borrowed under the amended and restated credit facility to repay the $30.0 million short-term secured credit agreement, dated as of August 25, 2010, between TransAtlantic Worldwide and Standard Bank, which was scheduled to mature on May 25, 2011. We plan to use the remainder of the amounts borrowed under the amended and restated credit facility to finance a portion of the development of our oil and gas properties in Turkey and for working capital purposes in Turkey.

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, 2011, the lenders had aggregate commitments of $120.0 million, with individual commitments of $60.0 million each. 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 amount under the amended and restated credit facility was increased to $95.0 million from $75.0 million following the joinder of Amity as a borrower. 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. 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;

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• 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 field life coverage ratio means, for any calculation date, the ratio of (i) the net present value of cash flow available for debt service from the calculation date until the last abandonment date, to (ii) the aggregate outstanding principal amount of the loans, plus the aggregate undrawn maximum face amount of letters of credit, plus the aggregate unpaid drawings on such calculation date, minus the aggregate credit balance of the cash collateral account on such calculation date. The loan life coverage ratio means, for any calculation date, the ratio of (i) the net present value of the cash flow available for debt service from the calculation date until the maturity date, to (ii) the aggregate principal amount of the loans, plus the aggregate undrawn maximum face amount of letters of credit, plus the aggregate unpaid drawings on such calculation date, minus the aggregate credit balance of the cash collateral account on such calculation date. The debt service coverage ratio means, for any calculation date, the ratio of (i) the cash flow available for debt service for such calculation period, to (ii) the aggregate amount of all principal, interest and fees due and payable under the loan documents during such calculation period.

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 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 London Interbank Offered Rate (“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, (iv) the hydrocarbon licenses owned by the Borrowers in Turkey and (v) substantially all of the present and future assets of the Borrowers.

The Borrowers are required to maintain certain ratios under the amended and restated credit facility’s financial covenants during the four most recently completed fiscal quarters occurring on or after March 31, 2011. These financial covenants require each of the Borrowers to maintain a:

• 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 amended and restated credit facility defines EBITDAX as net income (excluding extraordinary items) plus, to the extent deducted in calculating such net income, (i) interest expense (excluding interest paid-in-kind, or non cash interest expense and interest incurred on certain subordinated intercompany debt or interest on equity recapitalized into subordinated debt), (ii) income tax expense, (iii) depreciation, depletion and amortization expense, (iv) amortization of intangibles and organization costs, (v) any extraordinary, unusual or non-recurring non-cash expenses or losses, (vi) expenses incurred in connection with oil

16

and gas exploration activities entered into in the ordinary course of business (including related drilling, completion, geological and geophysical costs), (vii) transaction costs, expenses and fees incurred in connection with the negotiation, execution and delivery of the amended and restated credit facility and the related loan documents, and (vii) any other non-cash charges (including dry hole expenses and seismic expenses, to the extent such expenses would be capitalized), minus, to the extent included in calculating net income, (a) any extraordinary, unusual or non-recurring income or gains (including, gains on the sales of assets outside of the ordinary course of business) and (b) any other non-cash income or gains.

Pursuant to the terms of the amended and restated credit facility, until amounts under the amended and restated credit facility are repaid, each of the Borrowers shall not, and shall cause each of its subsidiaries not to, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to create any liens, (iii) enter into any merger, consolidation or amalgamation, liquidate or dissolve, (iv) dispose of any property or business, (v) pay any dividends, distributions or similar payments to shareholders, (vi) make certain types of investments, (vii) enter into any transactions with an affiliate, (viii) enter into a sale and leaseback arrangement, (ix) engage in any business or business activity, own any assets or assume any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and gas exploration and production company or operate or carry on business in any jurisdiction outside of Turkey or its jurisdiction of formation, (x) change its organizational documents, (xi) permit its fiscal year to end on a day other than December 31st or change its method of determining fiscal quarters, or alter the accounting principles it uses, (xii) modify certain hydrocarbon licenses and agreements or material contracts, (xiii) enter into any hedge agreement for speculative purposes or (xiv) open or maintain new deposit, securities or commodity accounts.

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 Guarantor or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or Guarantor; (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 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.

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.

Short-Term Secured Credit Agreement

On August 25, 2010, TransAtlantic Worldwide entered into a short-term secured credit agreement with Standard Bank pursuant to which TransAtlantic Worldwide borrowed $30.0 million from Standard Bank. The short-term secured credit agreement was guaranteed by us and each of TransAtlantic Petroleum (USA) Corp., Amity and Petrogas. TransAtlantic Worldwide used the proceeds of the short-term secured credit agreement to finance a portion of the purchase price for the shares of Amity and Petrogas. Borrowings under the short-term secured credit agreement accrued interest at a rate of LIBOR plus the applicable margin. The applicable margin equaled 3.75% for interest that accrued before November 23, 2010, 4.00% for interest that accrued on or after November 23, 2010 and before February 20, 2011 and 4.25% for interest that accrued on or after February 20, 2011 and before May 25, 2011. In addition, TransAtlantic Worldwide paid an arrangement fee of $750,000.

The short-term secured credit agreement was scheduled to mature on May 25, 2011. TransAtlantic Worldwide repaid the loan in full on May 24, 2011, at which time the short-term secured credit agreement was terminated.

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Viking International Equipment Loan

On July 21, 2010 and December 30, 2010, Viking International Limited (“Viking International”), our wholly owned subsidiary, entered into a secured credit agreement with a Turkish bank to fund the purchase of vehicles. The credit agreement has a term of 48 months, matures on July 20, 2014, bears interest at an annual rate of 3.84% and is secured by the vehicles purchased with the proceeds of the loan. There is no further availability under the credit agreement.

As of June 30, 2011, the outstanding balance under the secured credit agreement was $2.8 million.

TBNG Credit Agreement

TBNG is a party to an unsecured credit agreement with a Turkish bank. At June 30, 2011, there were outstanding borrowings of approximately 19.4 million Turkish Lira (approximately $14.0 million) under the credit agreement. Borrowings under the credit agreement bear interest at a rate of 11.65% per annum, and interest is payable quarterly. The credit facility matures on September 13, 2011 and may be renewed for an additional period on the same terms.

10. Related party loans payable

Related-party debt consisted of the following:

Related Party Floating Rate Debt	June 30, 2011		December 31, 2010
	(in thousands)
Dalea credit agreement	$	73,000	$	73,000
Dalea credit agreement discount – warrants		—		(1,972	)
		73,000		71,028
Viking Drilling note		5,358		7,708
Total related party debt		78,358		78,736
Less: Short-term related party debt		77,932		75,804
Total long-term related party debt	$	426	$	2,932

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 (see note 4), 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 with Standard Bank and BNP Paribas.

Pursuant to the Dalea credit agreement, as amended, the aggregate unpaid principal balance, together with all accrued but unpaid interest and other costs, expenses or charges payable under the Dalea credit agreement are due and payable by us upon the earlier of (i) December 31, 2011, or (ii) the occurrence of an event of default and a demand for payment by Dalea. Events of default include, but are not limited to, payment defaults, defaults in the performance of any terms, covenants or conditions of the Dalea credit agreement or collateral documents, material misrepresentations by us or any subsidiary, we or any subsidiary ceases or threatens to cease to carry on business, the prohibition in trading in our shares or the suspension or delisting of our common shares from any stock exchange, any material adverse change occurs in us or any of our subsidiaries, Dalea believes in good faith that our ability to pay or perform any of the covenants contained in the Dalea credit agreement is materially impaired, our insolvency or the insolvency of any subsidiary, or a change in control of the Company. A change of control is defined as the change of ownership of, or control or direction over, directly or indirectly, 20% or more of our outstanding voting securities. If an event of default occurs and is continuing, Dalea may demand immediate payment of all monies owing under the Dalea credit agreement; provided, that with respect to certain specified events of default, all monies due under the Dalea credit agreement shall automatically become due and payable without any demand or any other action by Dalea or any other person.

Amounts due under the Dalea credit agreement accrue 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. In addition, we are required to pay all accrued interest in arrears on the last day of each month until the date of repayment and at any time that the principal balance is due and payable. We may prepay the amounts due under the Dalea credit agreement at any time before maturity without penalty.

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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 Dalea credit agreement. We borrowed an aggregate of $73.0 million under the Dalea credit agreement, and on September 1, 2010, we issued 7.3 million common share purchase warrants to Dalea. The common share purchase warrants are exercisable until September 1, 2013 and have an exercise price of $6.00 per share.

As of June 30, 2011, we had borrowed $73.0 million under the Dalea credit agreement. No further borrowings are permitted under the Dalea credit agreement.

Viking Drilling Note

On July 27, 2009, Viking International purchased the I-13 drilling rig and associated equipment from Viking Drilling, LLC (“Viking Drilling”). Dalea owns 85% of Viking Drilling. Viking International paid $1.5 million in cash for the drilling rig and entered into a note payable with Viking Drilling in the amount of $5.9 million. The note was due and payable on August 1, 2010, bore interest at a fixed rate of 10% per annum and was secured by the drilling rig and associated equipment. We paid interest under the note on November 1, 2009 and February 1, 2010. On February 19, 2010, Viking International purchased the I-14 drilling rig and associated equipment from Viking Drilling. Viking International paid $1.5 million in cash for the I-14 drilling rig 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 in July 2009. Under the terms of the amended and restated note, interest is payable monthly at a floating rate of LIBOR plus 6.25%, and the amended and restated note is due and payable August 1, 2012. The amended and restated note is secured by the I-13 and I-14 drilling rigs and associated equipment. As of June 30, 2011, the outstanding balance under the note was $5.4 million.

11. Shareholders’ equity

June 2011 share issuance

On June 7, 2011, we issued 18.5 million common shares at a deemed price of $2.05 per share in a Regulation D private placement to an accredited investor in connection with the acquisition of TBNG.

February 2011 share issuance

On February 18, 2011, we issued 8.9 million common shares at a deemed price of $3.15 per share in a Regulation D private placement to an accredited investor in connection with the acquisition of Direct Morocco, Anschutz and Direct Bulgaria.

Restricted stock units

Share-based compensation expense of approximately $0.4 million and $1.0 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three and six months ended June 30, 2011, respectively. We recorded share-based compensation expense of $0.4 million and $0.8 million for the three and six months ended June 30, 2010, respectively.

As of June 30, 2011, we had approximately $3.2 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 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, 2011. At June 30, 2011, all stock options have been fully amortized.

Earnings per share

Because we reported a net loss for the three and six months ended June 30, 2011 and 2010, we excluded the following share based awards from the computation of earnings per share, as their effect would have been antidilutive:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
	2011		2010		2011		2010
Unvested RSUs		2,935,257		2,060,760		2,938,965		2,085,819
Stock options		1,959,167		2,715,134		2,012,298		2,986,107
Warrants		17,318,720		10,627,157		17,342,145		10,729,119

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12. Segment information

We have two reportable operating segments, exploration and production of oil and natural gas (“E&P”) and drilling services, within three geographic areas: Bulgaria, Romania and Turkey. Summarized financial information concerning our operating segments is shown in the following table:

	E&P			Drilling			Corporate			Total
	(in thousands)
For the three months June 30, 2011
Net revenues	$	30,755		$	22,123		$	—		$	52,878
Inter-segment revenues		—			(17,369	)		—			(17,369	)
Total revenues		30,755			4,754			—			35,509
(Loss) income from continuing operations	$	2,466		$	(5,219	)	$	(6,195	)	$	(8,948	)
For the three months June 30, 2010
Net revenues	$	15,855		$	10,250		$	—		$	26,105
Inter-segment revenues		—			(7,501	)		—			(7,501	)
Total revenues		15,855			2,749			—			18,604
(Loss) income from continuing operations	$	685		$	(752	)	$	(4,542	)	$	(4,609	)
For the six months June 30, 2011
Net revenues	$	59,431		$	39,345		$	—		$	98,776
Inter-segment revenues		—			(31,071	)		—			(31,071	)
Total revenues		59,431			8,274			—			67,705
(Loss) income from continuing operations	$	(2,610	)	$	(11,023	)	$	(13,671	)	$	(27,304	)
For the six months June 30, 2010
Net revenues	$	27,172		$	12,839		$	—		$	40,011
Inter-segment revenues		—			(9,015	)		—			(9,015	)
Total revenues		27,172			3,824			—			30,996
(Loss) income from continuing operations	$	(2,333	)	$	(3,596	)	$	(7,558	)	$	(13,487	)
Segment Assets
As of June 30, 2011	$	392,481		$	145,287		$	7,165		$	544,933	*
As of December 31, 2010	$	295,352		$	132,957		$	44,038		$	472,347	*
Goodwill
As of June 30, 2011	$	9,865		$	—		$	—		$	9,865
As of December 31, 2010	$	10,341		$	—		$	—		$	10,341

* Excludes assets from our discontinued Moroccan operations of $2,420 at June 30, 2011 and includes assets from our discontinued Moroccan operations of $41,200 at December 31, 2010.

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Summarized financial information concerning our geographic areas is shown in the following table:

	Corporate			Bulgaria			Romania			Turkey			Total
	(in thousands)
For the three months ended June 30, 2011
Net revenues	$	45		$	127		$	—		$	52,706		$	52,878
Inter-segment revenues		—			—			—			(17,369	)		(17,369	)
Total revenues		45			127			—			35,337			35,509
(Loss) income from continuing operations	$	(6,287	)	$	(1,292	)	$	(300	)	$	(1,069	)	$	(8,948	)
For the three months ended June 30, 2010
Net revenues	$	83		$	—		$	—		$	26,022		$	26,105
Inter-segment revenues		—			—			—			(7,501	)		(7,501	)
Total revenues		83			—			—			18,521			18,604
(Loss) income from continuing operations	$	(4,527	)	$	—		$	(1,688	)	$	1,606		$	(4,609	)
For the six months ended June 30, 2011
Net revenues	$	92		$	255		$	—		$	98,429		$	98,776
Inter-segment revenues		—			—			—			(31,071	)		(31,071	)
Total revenues		92			255			—			67,358			67,705
(Loss) from continuing operations	$	(13,834	)	$	(1,311	)	$	(613	)	$	(11,546	)	$	(27,304	)
For the six months ended June 30, 2010
Net revenues	$	101		$	—		$	—		$	39,910		$	40,011
Inter-segment revenues		—			—			—			(9,015	)		(9,015	)
Total revenues		101			—			—			30,895			30,996
(Loss) income from continuing operations	$	(7,807	)	$	—		$	(5,961	)	$	281		$	(13,487	)
Segment assets
June 30, 2011	$	7,165		$	37,028		$	3,559		$	497,181		$	544,933	*
December 31, 2010	$	44,038		$	—		$	3,465		$	383,644		$	431,147	*
Goodwill
June 30, 2011	$	—		$	—		$	—		$	9,865		$	9,865
December 31, 2010	$	—		$	—		$	—		$	10,341		$	10,341

* Excludes assets from our discontinued Moroccan operations of $2,420 and $41,200 at June 30, 2011 and December 31, 2010, respectively.

13. 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, 2011 and December 31, 2010, 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 our senior secured credit facility and the Dalea credit agreement. At June 30, 2011 and December 31, 2010, interest rate changes would have resulted in gains or losses in the market value of our senior secured credit facility, short-term secured credit agreement (which terminated May 24, 2011) and Dalea credit agreement due to differences between the current market interest rates and the rates governing these instruments.

Foreign currency risk

We have underlying foreign currency exchange rate exposure. Our currency exposures relate to transactions denominated in the Australian Dollar, Canadian Dollar, British Pound, Bulgarian Lev, European Union Euro, Romanian New Leu, Moroccan Dirham and Turkish Lira. We have not used foreign currency forward contracts to manage exchange rate fluctuations.

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, 2011 and December 31, 2010, we were a party to commodity derivative contracts (see note 7).

Concentration of credit risk

The majority of our receivables are within the oil and gas industry, primarily from our industry partners and from government agencies. Included in receivables are amounts due from Turkiye Petrolleri Anonim Ortakligi (“TPAO”), the national oil company of Turkey, and Turkiye Petrol Refinerileri A.Ş. (“TUPRAS”), a privately owned oil refinery in Turkey, which purchase substantially all of our oil 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 prior to December 31, 2011. The majority of our cash and cash equivalents are held by three financial institutions in the U.S. and Turkey.

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Fair value measurements

The following table summarizes the valuation of our financial assets and liabilities as of June 30, 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:
Floating rate debt	$	—	$	(78,358	)	$	—	$	(78,358	)
Senior secured credit facility		—		(66,000	)		—		(66,000	)
TBNG credit agreement		—		(9,159	)		—		(9,159	)
TBNG loan payable		—		(4,754	)		—		(4,754	)
Oil derivative contracts		—		(10,062	)		—		(10,062	)
Contingent consideration on acquisition		—		(5,250	)		—		(5,250	)
Total	$	—	$	(173,583	)	$	—	$	(173,583	)

The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2010:

	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:
Short-term secured credit agreement	$	—	$	(30,000	)	$	—	$	(30,000	)
Floating rate debt		—		(78,736	)		—		(78,736	)
Senior secured credit facility		—		(25,000	)		—		(25,000	)
Oil derivative contracts		—		(3,517	)		—		(3,517	)
Total	$	—	$	(137,253	)	$	—	$	(137,253	)

14. Related party transactions

The following table summarizes related party accounts receivable and accounts payable as of June 30, 2011 and December 31, 2010:

	June 30, 2011		December 31, 2010
	(in thousands)
Related party accounts receivable:
Riata Management service agreement	$	—	$	4
Maritas services agreement		1,798		3,700
VOS services agreement		13		79
Total related party accounts receivable	$	1,811	$	3,783
Related party accounts payable:
Riata Management service agreement	$	899	$	863
Viking Drilling services agreement		—		21
Maritas services agreement		—		85
VOS services agreement		—		—
Gundem lease agreement		31		—
Viking Drilling note		428		—
Total related party accounts payable	$	1,358	$	969

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Other transactions

In July 2008, Longfellow guaranteed the obligations of us and Longe Energy Limited under a farm-out agreement with Direct Morocco and Anschutz concerning the Ouezzane-Tissa and Asilah exploration permits in Morocco up to a maximum of $25.0 million. This guarantee was terminated on February 18, 2011 upon the acquisition of Direct Morocco and Anschutz.

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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 stated otherwise, all sums of money stated in this Form 10-Q are expressed in U.S. Dollars.

Executive Overview

General. We are a vertically integrated, international oil and gas company engaged in the acquisition, exploration, development and production of oil and natural gas. We hold interests in developed and undeveloped oil and gas properties in Turkey, Morocco, Romania, and Bulgaria. We own our own drilling rigs and oilfield service equipment, which we use to develop our properties in Turkey. In addition, our drilling services business provides oilfield services and drilling services to third parties in Turkey and Iraq. As of August 5, 2011, approximately 42% of our outstanding common shares were beneficially owned by N. Malone Mitchell, 3^rd, our chairman of the board of directors and chief executive officer.

Financial and Operational Performance Highlights. Highlights of our financial and operational performance from continuing operations for the second quarter of 2011 include:

• During the quarter ended June 30, 2011, we derived 68% of our revenues from the production of oil, 18% of our revenues from the production of natural gas and 14% of our revenues from oilfield services.

• Total oil and natural gas sales increased 94.2%, to $30.8 million for the quarter ended June 30, 2011 from $15.8 million realized in the same period in 2010. The increase was the result of an increase in production volumes and higher average prices.

• Oilfield services revenue increased 71.7%, to $4.8 million for the quarter ended June 30, 2011 from $2.8 million in same period in 2010.

• Production increased to approximately 219 net thousand barrels (Mbbls) of oil and approximately 862 net million cubic feet (Mmcf) of natural gas for the quarter ended June 30, 2011, compared to approximately 170 net Mbbls of oil and 355 net Mmcf of natural gas for the same period in 2010.

• For the three months ended June 30, 2011, we were producing an average of approximately 2,400 net barrels (Bbls) of oil per day and approximately 7.5 net Mmcf of natural gas per day from our producing gas fields, excluding production from Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”). On June 30, 2011, we produced approximately 2,520 net Bbls of oil and 15.2 net Mmcf of natural gas.

• For the quarter ended June 30, 2011, we incurred $49.7 million in capital expenditures, of which $37.9 million was a non-cash capital expenditure incurred in the acquisition of TBNG, compared to capital expenditures of $33.7 million for the same period in 2010. The decrease in cash capital expenditures was primarily due to significant purchases of drilling services equipment in 2010.

• As of June 30, 2011, our short-term borrowings decreased to $93.0 million, compared to short-term borrowings of $106.7 million as of December 31, 2010.

Revision to Year-End 2011 Production Estimate.We have reduced our estimated net producing rate for year-end 2011 from 10,000 barrels of oil equivalent per day (“Boepd”) to a range of 7,000 Boepd to 7,500 Boepd, due primarily to deferred drilling in Turkey. The drilling deferrals include a late start on a 3D seismic survey at the Gocerler production lease, on which four development locations are dependent. We have moved one of our drilling rigs from Selmo to initiate our Arpatepe license drilling program. Also, civil unrest in southeastern Turkey caused the deferral of planned drilling at our Bakuk license until the first quarter of 2012. In the Thrace Basin, several drilling programs were suspended due to poor results on lead program wells. However, we anticipate the addition of an expanded drilling inventory to support additional Thrace Basin drilling programs beginning in the fourth quarter of 2011, primarily from five seismic programs totaling 912 square kilometers that are either completed or underway. Our objective is to continue to adjust the mix of our exploration programs based upon results and to re-deploy capital to higher return projects.

Recent Developments

Appointment of New Chief Financial Officer. On August 4, 2011, our board of directors appointed Wil F. Saqueton to serve as our vice president and chief financial officer. Mr. Saqueton had served as our controller since joining us in May 2011. Prior to joining us, Mr. Saqueton served as the vice president and chief financial officer of BCSW, LLC, the owner of Just Brakes in Dallas, Texas, from 2006 to 2010. From 1995 until 2006, he held a variety of positions, including strategic controller, at the Chipset Group of Intel Corporation. Prior to 1995, Mr. Saqueton was a senior associate at Price Waterhouse, LP. Mr. Saqueton holds a masters degree in business administration from the University of California, Davis.

Exit from Morocco Operations.On June 27, 2011, we announced our decision to discontinue our operations in Morocco. We intend to sell our existing interests in Morocco and transfer our drilling services equipment from Morocco to Turkey.

TBNG Acquisition. On June 7, 2011, our wholly owned subsidiary, TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) acquired all of the shares of TBNG from Mustafa Mehmet Corporation (“MMC”) in exchange for (i) the issuance of 18.5 million of our common shares, (ii) the transfer of certain overriding royalty interests (ranging from 1.0% to 2.5% of the working interests) owned by TBNG on specified exploration licenses to MMC or an affiliate and (iii) the payment of $10.5 million in cash. TransAtlantic Worldwide applied the $10.0 million option fee it paid to MMC in November 2010 towards the purchase price at closing. Through the acquisition of TBNG, we acquired interests ranging from 25% to 62.5% in 11 exploration licenses and four production leases as well as drilling rigs and oilfield service assets. TBNG currently produces an average of approximately 7.0 Mmcf of natural gas per day in the Thrace Basin region of northwestern Turkey.

Repayment of Short-Term Secured Credit Agreement. On May 24, 2011, we used a portion of the amounts borrowed under our amended and restated credit facility with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”) to repay the $30.0 million short-term secured credit agreement between TransAtlantic Worldwide and Standard Bank, which was scheduled to mature on May 25, 2011.

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Amendment and Restatement of Senior Secured Credit Facility.On May 18, 2011, our wholly owned subsidiaries, DMLP, Ltd. (“DMLP”), Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Exploration Mediterranean International Pty. Ltd. (“TEMI”) and TransAtlantic Turkey, Ltd. (“TAT”) (collectively, and together with Amity Oil International Pty. Ltd. (“Amity”), the “Borrowers”) amended and restated our senior secured credit facility with Standard Bank and BNP Paribas (“the amended and restated credit facility”) to extend the maturity date to May 18, 2016, to include our wholly owned subsidiaries Amity and Petrogas as Borrowers, and to increase the borrowing base to $75.0 million, which further increased to $95.0 million following the joinder of Amity. We plan to use the amounts borrowed under the amended and restated credit facility to finance a portion of the development of our oil and gas properties in Turkey and for working capital purposes in Turkey. See “—Liquidity and Capital Resources—Amended and Restated Senior Secured Credit Facility.”

Amendment of Dalea Credit Agreement.On May 18, 2011, we entered into a first amendment to our credit agreement, dated as of June 28, 2010, with Dalea Partners, LP (“Dalea”) to extend the maturity date of the credit agreement to December 31, 2011 and to increase the interest rate payable under the credit agreement from three-month London Interbank Offered Rate (“LIBOR”) plus 2.50% per annum to three-month LIBOR plus 5.50% per annum, to match the interest rate payable under our amended and restated credit facility with Standard Bank and BNP Paribas. Mr. Mitchell, our chairman of the board of directors and chief executive officer, and his wife own 100% of Dalea. See “—Liquidity and Capital Resources —Dalea Credit Agreement.”

Appointment of New Chief Executive Officer. Effective May 6, 2011, our board of directors appointed Mr. Mitchell to serve as our chief executive officer in addition to his duties as chairman of our board of directors. Matthew McCann, our former chief executive officer, tendered his resignation on May 5, 2011.

Direct Petroleum Acquisition. On February 18, 2011, TransAtlantic Worldwide acquired Direct Petroleum Morocco, Inc. (“Direct Morocco”), Anschutz Morocco Corporation (“Anschutz”) and our wholly owned subsidiary, TransAtlantic Petroleum Cyprus Limited acquired Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”). In addition, TransAtlantic Worldwide purchased from the seller, Direct Petroleum Exploration, Inc. (“Direct”), all of Direct’s right, title and interest in the amounts due to Direct by each of Direct Morocco, Anschutz and Direct Bulgaria. As consideration for the acquisition, TransAtlantic Worldwide paid $2.4 million in cash to Direct, and we issued 8.9 million of our common shares (at a deemed price of $3.15 per common share) to Direct in a private placement, for total consideration of $34.5 million. In addition, if certain post-closing milestones are achieved, we will issue additional consideration to Direct equal to: (i) $10.0 million worth of our common shares if the Deventci-R2 well in Bulgaria is a commercial success; and (ii) $10.0 million worth of our common shares if Direct Bulgaria receives a production concession for a specified area in Bulgaria. Of this additional consideration, $5.0 million would be due if we have not commenced drilling the Deventci-R2 well by November 18, 2011, and $5.0 million would be due if the Deventci-R2 well has not cored the Etropole formation by February 18, 2012.

Second Quarter 2011 Operational Update

During the second quarter of 2011, we continued to develop our Selmo oil field and Thrace Basin gas fields. In addition, we continued the process of integrating the properties, equipment and personnel of Amity, Petrogas, Direct Bulgaria and TBNG into our operations. For the quarter ended June 30, 2011, we produced an average of approximately 2,400 net Bbls of oil per day and approximately 7.5 net Mmcf of natural gas per day, excluding production from TBNG. On June 30, 2011, we produced approximately 2,520 net Bbls of oil and 15.2 net Mmcf of natural gas.

Turkey-Thrace Basin. In the Thrace Basin, we completed four wells, drilled and completed two wells and began drilling five additional wells. Effective June 7, 2011, we were producing an additional approximately 7.0 net Mmcf of natural gas per day from our acquisition of TBNG. We began drilling two additional wells on our TBNG acreage in June 2011.

On June 14, 2011, we entered into a farmout agreement with a subsidiary of Valeura Energy, Ltd. (“Valeura”) under which Valeura will pay 100% of the costs to acquire 150 square kilometers of 3D seismic data and drill two exploration wells to a minimum depth of 1,500 meters (approximately 5,000 feet) to earn a 50% interest in our Malkara licenses 4094 and 4532. We will retain a 50% interest in the two licenses, and we expect the 3D seismic acquisition to commence by October 2011.

On July 21, 2011, Petrogas was awarded a wholesale natural gas license and began selling gas from our Edirne license 4037 at a rate of approximately 3.3 net Mmcf per day.

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Southeastern Turkey. At Selmo, we completed two wells and began drilling five additional wells. On our Arpatepe license, we and the operator of the license, Aladdin Middle East, Ltd., each mobilized one drilling rig to initiate operations for the drilling of a development well and an exploration well. We expect to have results from these two wells in August 2011 and, depending on drilling results, plan to maintain two drilling rigs at Arpatepe through the end of 2011.

In addition, we completed a 23-kilometer, 6-inch pipeline from the Bakuk-101 well to an existing pipeline to the south, commissioned the pipeline and began selling limited quantities of natural gas from the well in April 2011. We anticipate natural gas sales from the Bakuk-101 well to grow to approximately 2.0 net Mmcf per day in September 2011 after Turkiye Petrolleri Anonim Ortakligi (“TPAO”), the national oil company of Turkey, completes a tie-in from our existing pipeline to a nearby power plant.

Bulgaria. We continued evaluating potential locations in Bulgaria for a planned Deventci-R2 well on the A-Lovech permit (100% working interest) to appraise the Orzirovo formation on the northern portion of the license.

Romania. We continued evaluating a potential exploration well to test a Silurian-aged shale and a potential Jurassic-aged oil play and reprocessing seismic data previously shot over the Sud Craiova exploration license (50% working interest). We recently applied for a two-year extension on the Sud Craiova license along with the operator of the license, Sterling Resources, Ltd. (“Sterling”). As a condition to the extension, we committed to participate in a 200 kilometer 2D seismic survey and agreed to a 2,000 square kilometer reduction in the Sud Craiova license area, from 6,070 square kilometers to 4,070 square kilometers.

Morocco. The GRB-1 exploration well on the Asilah exploration permits in Morocco was non-commercial and will be plugged and abandoned. We drilled the TKN-1 exploration well on the Tselfat exploration permit, but the well failed to encounter the target formation and has been plugged and abandoned. We have determined to sell our existing interests in Morocco and transfer our drilling services equipment from Morocco to Turkey.

Drilling Services. We provide drilling and other oilfield services through our wholly owned subsidiary Viking International Limited (“Viking International”), and we provide seismic acquisition services through our wholly owned subsidiary Viking Geophysical Services, Ltd. (“Viking Geophysical”). As of June 30, 2011, we owned eleven drilling rigs and five workover and completion rigs in Turkey, and we owned two drilling rigs in Morocco, one of which is being transferred to Turkey. In addition, we managed one drilling rig in Turkey for Viking Drilling, LLC (“Viking Drilling”) and one drilling rig in Iraq for Maritas A.Ş. (“Maritas”) pursuant to management services agreements.

During the second quarter of 2011, Viking International and Viking Geophysical generated revenues of approximately $4.8 million and $0.1 million, respectively, from providing oilfield services and geophysical services to third parties in Turkey and Iraq.

On May 5, 2011, our board of directors formed a special committee, comprised of four independent directors, to evaluate strategic alternatives related to our drilling services business. The special committee is in the process of engaging independent experts to assist in its evaluation.

Planned 2011 Operations

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

• Increasing Production. We plan to increase our oil and natural gas production in Turkey through the development of our recently acquired TBNG, Amity and Petrogas acreage, as well as through the development of our Selmo and Arpatepe oil fields. We anticipate that our planned completions and extensions of pipelines will also bring shut-in natural gas production to market. We anticipate that these initiatives, combined with the application of modern well stimulation techniques such as gelled acidizing and fracture stimulation and the expanded application of directional drilling, should benefit production.

• Unlocking Unconventional Potential in the Thrace Basin. We currently have an inventory of 50 re-entry well fracture stimulation (“frac”) candidates on our TBNG licenses, three of which have been fracced. Our objective is to vary parameters around interval selection and frac design to achieve optimum results and then expand the program to provide new offset drilling locations.

• Expanding our Existing Inventory of Exploration Opportunities. In the Thrace Basin region of northwestern Turkey, we recently completed two additional 3D seismic surveys on an aggregate of 358 square kilometers on license 4861. Two additional 3D seismic surveys on an aggregate of 461 square kilometers are underway on the newly acquired Tekirdag and Hayrabolu licenses in the southern Thrace Basin. We anticipate that these surveys will significantly add to

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our conventional shallow acreage opportunities and will define deeper unconventional tight gas opportunities on large structures that have already been identified. We have commenced a 100 square kilometer 3D seismic survey on our joint Amity/TPAO licenses, which should be completed by mid-September 2011. We believe that this survey will identify a number of development and exploration locations on those licenses. In southeastern Turkey, we are interpreting data from a recently acquired 2D seismic survey on the Adana/Yuksekkoy license and anticipate that this survey will identify shallow structural plays similar to those found in the Thrace Basin.

• Securing Partners to Reduce Exploration Risk. We are seeking strategic partners for our exploration acreage in Bulgaria, Romania and our large portfolio of Tertiary-aged basins in central Turkey. Through farmouts, we expect to accelerate development and mitigate exploration risk. In Romania, along with Sterling, we are seeking a partner to drill and test the Silurian shale potential on the Sud Craiova license. We have taken a strategic decision to divest our remaining interests in Morocco in order to focus on our core geographic areas. We have engaged FirstEnergy Capital LLP (“FirstEnergy”) as our exclusive financial advisor for the sale of our interests in Morocco and to seek joint venture partners for the development of our exploration acreage in Bulgaria, Romania and central Turkey.

• Integrating Acquisitions. We completed the acquisition of TBNG on June 7, 2011, which brought additional acreage, production, personnel and equipment into our Turkey operations. We will continue the process of integrating TBNG, Amity, Petrogas and Direct Bulgaria into our operations.

For the remainder of 2011, we expect our capital expenditures for our exploration and production activities will be approximately $37.0 million. Our prior 2011 capital expenditure estimates did not take into account the benefit of using our own drilling services equipment. Approximately 50% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Approximately 50% of these anticipated expenditures will occur in southeastern Turkey, devoted to developing oil production at Selmo and Arpatepe and drilling exploratory wells on various licenses. If cash on hand, borrowings from our amended and restated credit facility and cash flow from operations are not sufficient to fund our capital expenditures, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2011 capital budget is subject to change and could be reduced if we do not raise additional funds. We currently plan to execute the following drilling and exploration activities in 2011:

Turkey. We plan to drill approximately 34 gross wells during the remainder of 2011, including wells to be drilled on the recently acquired TBNG acreage. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill. Following the acquisition of TBNG, we have accelerated plans for exploration and development of TBNG’s onshore acreage. We have identified 41 wells on the TBNG licenses with “behind pipe” production potential, and we are embarking on a recompletion program of these wells to increase production. We have commenced two 3D seismic surveys, one in the Tekirdag area and one in the Hayrabolu area. Our drilling program will continue to be based on our current drilling inventory of 2D seismic-based leads until an expanded drilling inventory is generated from the two 3D seismic surveys that are now being acquired on TBNG’s acreage.

To optimize the ability to frac both the Osmancik and Mezardere formations, we have started a series of fracs using different testing parameters. Since June 30, 2011, three fracs have been conducted from an inventory of 50 re-entry frac candidates. These standing wellbores offer the opportunity to vary techniques from well to well to optimize the gross interval selected. Our objective is to establish the optimum template for TBNG acreage as well as our other licenses in the Thrace Basin. Our three recent re-entry fracs include:

• Bati Kazanci-3 was a test of tight sands within a known producing horizon. Following the frac treatment, the commercial test for the well was positive and the well is currently on an extended flow test.

• Bati Kazanci-4 was a new well completion that was drilled to target shallow conventional targets. We identified a zone of interest for tight gas potential and pumped a frac stimulation. We have concluded that the test is non-commercial but are encouraged by the pressure regime and the formation’s response to fracture stimulation, and we are looking elsewhere on the structure for opportunities in the same formation.

• Yazir-2 is new concept for the region and is designed to test the Teslimkoy Mezardere formation, which is at the base on the conventional producing horizons of Thrace Basin. We are currently evaluating the results of the second stage of this frac.

We plan on fraccing one or more wellbores per week. Based upon results we may drill and frac offsetting locations to extend the play. To assess and optimize results of our unconventional work, we have engaged two firms with experience in unconventional natural gas plays in similar formations in the U.S. Our objective is to minimize the early learning curve that is typical of most unconventional plays.

At Selmo we are drilling S-78 well, which is the eighth well drilled in 2011. We have initiated completion activities on three wells on our first multi-well drilling pad. The use of multi-well pads and directionally drilled holes has been successful in expediting the rigline at Selmo by reducing landowner issues which previously limited access to some of our drilling locations. The next multi-well pad is adjacent to the successful S-71 well drilled earlier this year, which is still producing approximately 230 Bbls per day.

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Morocco. On our Tselfat exploration permit, the HR-33 bis well is on an extended production test. We are constructing wellsites to facilitate the drilling of two additional exploration wells to a depth of at least 1,500 meters on the Tselfat exploration permit by July 2012. We intend to sell our existing interests in Morocco and transfer our drilling services equipment from Morocco to Turkey.

Bulgaria. Direct Bulgaria is in the process of obtaining the Koynare production concession over the northern 647 square kilometers (approximately 160,000 acres) of the A-Lovech license, based upon a conventional discovery in the Jurassic-aged Orzirovo formation.

Romania. We are seeking a farmout partner to drill an exploration well to test the Silurian-aged shale formations present on the Sud Craiova license. We and Sterling have engaged FirstEnergy to assist us in this effort.

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

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. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in Notes 3 and 4 to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2010 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, 2010.

Recent Accounting Pronouncements

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

In December 2010, FASB issued ASU No. 2010-28Intangibles—Goodwill and Other (Topic 350): When to Perform Step 2 of the Goodwill Impairment Test for Reporting Units with Zero or Negative Carrying Amounts(“ASU 2010-28”). ASU 2010-28 modifies Step 1 of the goodwill impairment test for reporting units with zero or negative carrying amounts. For those reporting units, an entity is required to perform Step 2 of the goodwill impairment test if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, an entity should consider whether there are any adverse qualitative factors indicating that an impairment may exist. The update is effective for interim and annual reporting periods beginning after December 15, 2010. This update will be considered on an interim and annual basis when we review and perform our goodwill impairment test.

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In December 2010, FASB issued ASU No. 2010-29Business Combinations (Topic 805): Disclosure of Supplementary Pro Forma Information for Business Combinations(“ASU 2010-29”). ASU 2010-29 specifies that if a public entity presents comparative financial statements, the entity should disclose revenue and earnings of the combined entity as though the business combination(s) that occurred during the current year had occurred as of the beginning of the comparable prior annual reporting period only. The update also expands the supplemental pro forma disclosures under ASC Topic 805 to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The update is effective prospectively for business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2010. The adoption of ASU 2010-29 did not have a material impact on our financial statements.

In May 2011, FASB issued 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 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 will be effective for interim and annual periods beginning after December 15, 2011. The adoption of ASU 2011-04 is not expected to have a material effect on our condensed consolidated financial statements, but may require certain additional disclosures.

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. ASU 2011-05 will be effective fiscal years, and interim periods within those years, beginning after December 15, 2011. The adoption of ASU 2011-05 is not expected to have a material effect on our condensed consolidated financial statements, but may require a change in the presentation of our comprehensive income from the notes of the condensed consolidated financial statements, where it is currently disclosed, to the face of the condensed consolidated financial statements.

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

Results of Operations—Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

	Three Months Ended June 30,				Change
	2011		2010		2011-2010
	(in thousands of U.S. dollars, except per unit prices and production  volumes)
Production:
Oil (Mbbl)		219		170		49
Natural gas (Mmcf)		862		355		507
Total production (Mboe)		362		229		133
Average prices:
Oil (per Bbl)	$	109.28	$	72.85	$	36.43
Natural gas (per Mcf)	$	7.34	$	7.30	$	0.04
Oil equivalent (per Boe)	$	84.96	$	69.15	$	15.81
Revenues:
Oil and natural gas sales		30,755		15,836		14,919
Oilfield services		4,754		2,768		1,986
Total revenues		35,509		18,604		16,905
Costs and expenses:
Production		4,156		4,697		(541	)
Exploration, abandonment and impairment		4,463		4,149		314
Seismic and other exploration		939		2,273		(1,334	)
Oilfield services costs		5,725		1,701		4,024
Revaluation of contingent consideration		1,250		—		1,250
General and administrative		10,246		6,774		3,472
Depreciation, depletion and amortization		12,797		4,243		8,554
Interest and other expense		3,695		654		3,041

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	Three Months Ended June 30,					Change
	2011			2010		2011-2010
	(in thousands of U.S. dollars, except per unit prices and production  volumes)
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts		(1,890	)		—		(1,890	)
Non-cash change in fair value on commodity derivative contracts		2,044			3,034		(990	)
Total gain (loss) on commodity derivative contracts		154			3,034		(2,880	)

Revenue.Total oil and natural gas revenues increased $14.9 million to $30.8 million for the three months ended June 30, 2011 from $15.8 million realized in the same period in 2010. Of this increase, $5.7 million was attributable to the increase in our average prices received. For the three months ended June 30, 2011, our average price was $84.96 per Boe, compared to $69.15 per Boe for the same period in 2010. The remaining $9.2 million was due to an increase in our total production volumes of 133 Mboe for the three months ended June 30, 2011 compared to the same period in 2010. Production volumes increased primarily due to the acquisitions of Amity and Petrogas in August 2010, Direct Bulgaria in February 2011 and TBNG in June 2011, accounting for approximately 102 Mboe of the increase.

Oilfield Services Revenue.Oilfield services revenues increased approximately $2.0 million for the three months ended June 30, 2011 to $4.8 million, compared to $2.8 million during the same period in 2010. The increase was the result of an increase in oilfield drilling services provided to third parties for the three months ended June 30, 2011.

Production.Production expenses for the three months ended June 30, 2011 decreased to $4.2 million from $4.7 million for the same period in 2010. The decrease was primarily attributable to an increase in the utilization of our drilling services business to provide these services.

Exploration, Abandonment and Impairment.Exploration, abandonment and impairment costs for the three months ended June 30, 2011 remained consistent, at approximately $4.5 million, from $4.1 million for the same period in 2010.

Seismic and Other Exploration.Seismic and other exploration costs decreased to $0.9 million for the three months ended June 30, 2011 compared to $2.3 million for the same period in 2010. This decrease was due primarily to a decrease in the utilization of third parties to provide our seismic services. As we are increasingly using Viking Geophysical to provide these services, an increase in expenses has been eliminated upon consolidation.

Oilfield Services Costs. Oilfield services costs increased to $5.7 million for the three months ended June 30, 2011 compared to $1.7 million for the same period in 2010. This increase was due primarily to the overall increase in our oilfield services business.

Revaluation of Contingent Consideration.During the second quarter of 2011, we determined that there is an increase in the likelihood that we may not be able to complete one of our drilling obligations required as part of the Direct acquisition in February 2011. Therefore, we have increased our costs and expenses to record $1.3 million in the three months ended June 30, 2011 to reflect our potential future costs.

General and Administrative. General and administrative expense was $10.2 million for the three months ended June 30, 2011 compared to $6.8 million for the same period in 2010. The increase was due to an increase in consulting and professional service fees, primarily related to the late filings 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 quarter ended March 31, 2011, as well as the overall expansion of our business in 2011.

Depreciation, Depletion and Amortization.Depreciation, depletion and amortization increased approximately $8.6 million to $12.8 million for the three months ended June 30, 2011 compared to $4.2 million in the same period of 2010. The increase was primarily due to the increase in our production, as well as an increase in our depreciable asset base.

Interest and Other Expense. Interest and other expense increased to $3.7 million for the three months ended June 30, 2011, compared to $0.7 million for the same period in 2010. The increase was primarily due to an increase in our outstanding debt. At June 30, 2011, our total outstanding debt was approximately $161.3 million, compared to $80.1 million at June 30, 2010.

Gain (Loss) on Commodity Derivative Contracts. During the three months ended June 30, 2011, we recorded a gain on commodity derivative contracts of approximately $0.1 million compared to a gain of $3.0 million for the same period in 2010. We recorded a $2.0 million unrealized gain and a $1.9 million realized loss on our derivative contracts for the three months ended June 30, 2011, compared to a $3.0 million unrealized gain for the three months ended June 30, 2010. 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 with Standard Bank and BNP Paribas to hedge a portion of our oil production in the Selmo and Arpatepe oil fields in Turkey.

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Other Comprehensive Loss. 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, 2011 changed to a loss of $12.5 million from a loss of $5.5 million for the same period in 2010 due to the strengthening of the U.S. Dollar compared to the foreign currencies of the other countries in which we operate.

Discontinued Operations. In June 2011, we announced that we would sell our existing interests in Morocco and transfer our drilling services equipment from Morocco to Turkey. All revenues and expenses associated with the Moroccan operations for the three months ended June 30, 2011 and 2010 have been included in discontinued operations.

The results of operations for our Moroccan operations are as follows:

	Three Months Ended June 30,
	2011			2010
	(in thousands)
Revenues:
Oil and natural gas sales	$	139		$	—
Costs and expenses:
Production		1,249			—
Exploration, abandonment and impairment		9,100			9,167
Seismic and other exploration		—			55
Oilfield services costs		10			1,441
General and administrative		139			260
Depreciation, depletion and amortization		1,192			923
Accretion		1			—
Total costs and expenses		11,691			11,846
Operating loss		(11,552	)		(11,846	)
Other (expense) income:
Interest and other expense		(42	)		—
Interest and other income		—			21
Foreign exchange gain (loss)		(54	)		—
Total costs and expenses		(96	)		21
Loss from discontinued operations		(11,648	)		(11,825	)

Results of Operations—Six Months Ended June 30, 2011 Compared to Six Months Ended June 30, 2010

	Six Months Ended June 30,				Change
	2011		2010		2011-2010
	(in thousands of U.S. dollars, except per unit prices and production  volumes)
Production:
Oil (Mbbl)		438		317		121
Natural gas (Mmcf)		1,673		356		1,317
Total production (Mboe)		717		376		341

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	Six Months Ended June 30,					Change
	2011			2010		2011-2010
	(in thousands of U.S. dollars, except per unit prices and production  volumes)
Average prices:
Oil (per Bbl)	$	108.74		$	75.42	$	33.32
Natural gas (per Mcf)	$	7.31		$	7.30	$	0.01
Oil equivalent (per Boe)	$	82.89		$	72.22	$	10.67
Revenues:
Oil and natural gas sales		59,431			27,153		32,278
Oilfield services		8,274			3,843		4,431
Total revenues		67,705			30,996		36,709
Costs and expenses:
Production		8,258			8,886		(628	)
Exploration, abandonment and impairment		11,695			8,422		3,273
Seismic and other exploration		2,428			2,668		(240	)
Oilfield services costs		10,786			4,416		6,370
Revaluation of contingent consideration		1,250			—		1,250
General and administrative		20,502			12,553		7,949
Depreciation, depletion and amortization		21,088			7,232		13,856
Interest and other expense		7,471			1,180		6,291
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts		(2,612	)		—		(2,612	)
Non-cash change in fair value on commodity derivative contracts		(6,545	)		3,637		(10,182	)
Total gain (loss) on commodity derivative contracts		(9,157	)		3,637		(12,794	)

Revenue.Total oil and natural gas sales increased $32.3 million to $59.4 million for the six months ended June 30, 2011 from $27.2 million realized in the same period in 2010. Of this increase, $7.7 million was the result of an increase in the average prices received and $24.6 million was the result of an increase in our production volumes of 341 Mboe for the six months ended June 30, 2011, compared to the same period in 2010. Our average price for the six months ended June 30, 2011 was $82.89 per Boe, compared to $72.22 per Boe for the six months ended June 30, 2010. Production volumes increased primarily due to the acquisitions of Amity and Petrogas in August 2010, Direct Bulgaria in February 2011 and TBNG in June 2011, accounting for approximately 196 Mboe of the increase. The remaining increased production volumes were primarily attributable to increased production in the Selmo oil field and from an entire six months worth of production from our Edirne licenses. Edirne began production in April 2010.

Oilfield Services Revenues. Oilfield services revenues increased approximately $4.4 million for the six months ended June 30, 2011, to $8.2 million compared to $3.8 million during the same period in 2010. The increase was the result of an increase in oilfield drilling services provided to third parties for the six months ended June 30, 2011.

Production.Production expenses for the six months ended June 30, 2011 decreased approximately $0.6 million to $8.3 million from $8.9 million, for the same period in 2010. The decrease was primarily attributable to the increase in the utilization of our drilling services business to provide these services.

Exploration, Abandonment and Impairment.Exploration, abandonment and impairment costs for the six months ended June 30, 2011 increased to $11.7 million from $8.4 million for the same period in 2010. The increase was primarily due to dry hole expense in Turkey.

Seismic and Other Exploration.Seismic and other exploration costs decreased to $2.4 million for the six months ended June 30, 2011 compared to $2.7 million for the same period in 2010. This decrease was due primarily to a decrease in the utilization of third parties to provide our seismic services. As we are increasingly using Viking Geophysical to provide these services, an increase in expenses has been eliminated upon consolidation.

Oilfield Services Costs. Oilfield services costs increased approximately $6.4 million to $10.8 million for the six months ended June 30, 2011 compared to $4.4 million for the same period in 2010. This increase was due primarily to the overall increase in our oilfield services business.

Revaluation of Contingent Consideration. During the second quarter of 2011, we determined that there is an increase in the likelihood we may not be able to complete one of our drilling obligations required as part of the Direct acquisition in February 2011. Therefore, we have increased our costs and expenses to record $1.3 million in the six months ended June 30, 2011 to reflect our potential future costs.

General and Administrative. General and administrative expenses were $20.5 million for the six months ended June 30, 2011 compared to $12.6 million for the same period in 2010. The increase was due to an increase in consulting and professional service fees, primarily related to the late filings 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, as well as the overall expansion of our business in 2011.

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Depreciation, Depletion and Amortization.Depreciation, depletion and amortization increased to $21.1 million for the six months ended June 30, 2011 compared to $7.2 million in the same period of 2010. The increase was primarily due to the increase in our production, as well as an increase in our depreciable asset base.

Interest and Other Expense. Interest and other expense increased to $7.5 million for the six months ended June 30, 2011 compared to $1.2 million for the same period in 2010. The increase was primarily due to the increase in our outstanding debt. At June 30, 2011, our total outstanding debt was approximately $161.3 million, compared to $80.1 million at June 30, 2010.

Gain (Loss) on Commodity Derivative Contracts. During the six months ended June 30, 2011, we recorded a loss of $9.2 million compared to a gain of $3.6 million for the same period in 2010. We recorded a $6.5 million unrealized loss and a $2.7 million realized loss on our derivative contracts for the six months ended June 30, 2011, compared to a $3.6 million unrealized gain for the six months ended June 30, 2010. 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 with Standard Bank and BNP Paribas to hedge a portion of our oil production in the Selmo and Arpatepe oil fields in Turkey.

Other Comprehensive Loss. 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, 2011 changed to a loss of $10.2 million from a loss of $7.5 million for the same period in 2010 due to a strengthening of the U.S. Dollar compared to the foreign currencies of the other countries in which we operate.

Discontinued Operations. In June 2011, we announced that we would sell our existing interests in Morocco and transfer our drilling services equipment from Morocco to Turkey. All revenues and expenses associated with the Moroccan operations for the six months ended June 30, 2011 and 2010 have been included in discontinued operations.

The results of operations for our Morocco operations are as follows:

	Six Months Ended June 30,
	2011			2010
	(in thousands)
Revenues:
Oil and natural gas sales	$	187		$	—
Costs and expenses:
Production		1,254			9
Exploration, abandonment and impairment		11,666			9,377
Seismic and other exploration		27			79
Oilfield services costs		474			2,442
General and administrative		244			481
Depreciation, depletion and amortization		2,248			1,904
Accretion		1			—
Total costs and expenses		15,914			14,292
Operating loss		(15,727	)		(14,292	)
Other (expense) income:
Interest and other expense		(116	)		—
Interest and other income		—			5
Foreign exchange gain (loss)		(55	)		—
Total costs and expenses		(171	)		5
Loss from discontinued operations		(15,898	)		(14,287	)

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Capital Expenditures

For the six months ended June 30, 2011, we incurred $35.2 million in capital expenditures from continuing operations compared to capital expenditures of $53.0 million from continuing operations for the six months ended June 30, 2010. The decrease in capital expenditures was primarily due to 2010 being a capital intensive year, as we began purchasing fracture stimulation equipment.

For the remainder of 2011, we expect our capital expenditures for our exploration and production activities will be approximately $37.0 million. Our prior 2011 capital expenditure estimates did not take into account the benefit of using our own drilling services equipment. Approximately 50% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Approximately 50% of these anticipated expenditures will occur in southeastern Turkey, devoted to developing oil production at Selmo and Arpatepe and drilling exploratory wells on various licenses. If cash on hand, borrowings from our amended and restated credit facility and cash flow from operations are not sufficient to fund our capital expenditures, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2011 capital budget is subject to change and could be reduced if we do not raise additional funds.

Liquidity and Capital Resources

Our primary sources of liquidity for the second quarter of 2011 were cash and cash equivalents, cash flow from operations and borrowings under our various debt agreements. At June 30, 2011, we had cash and cash equivalents of $26.3 million, $93.0 million in short-term debt, $68.4 million in long-term debt and a working capital deficit of $50.4 million compared to cash and cash equivalents of $34.7 million, $106.7 million in short-term debt, $30.1 million in long-term debt and a working capital deficit of $60.2 million at December 31, 2010. Cash provided by operating activities from continuing operations for the six months ended June 30, 2011 increased to $24.7 million compared to cash used in operating activities from continuing operations of $23.1 million for the six months ended June 30, 2010, primarily as a result of an increase in revenues and better cash management.

As of June 30, 2011, the outstanding principal amount of our debt was $161.3 million. Of this amount, $73.0 million under the Dalea credit agreement is due December 31, 2011. We forecast that we will need to either extend the maturity date of the Dalea credit agreement or raise additional debt or equity financing to fund our repayment of the Dalea credit agreement and fund our operations, including our planned exploration and development activities. To obtain these funds, we are considering the issuance of common shares, public debt, private debt or the sale of assets. However, there is no assurance that our forecasts will prove to be accurate or that our efforts to raise additional debt or equity financing or consummate the sale of assets will prove to be successful. Should we be unable to raise additional financing, we may not have sufficient funds to continue operations beyond December 31, 2011. As a result, there is significant doubt regarding our ability to continue as a going concern. The continuing application of the going concern assumption is dependent upon our continuing ability to obtain the necessary financing to discharge our existing obligations, carry out our exploration and development programs, fund ongoing operations and ultimately achieve profitable operations. The inability to secure additional funding when and as needed could have a material adverse effect on our operations and financial condition.

In addition to cash, cash equivalents and cash flow from operations, at June 30, 2011, we had an amended and restated credit facility, a credit agreement with Dalea, a term note with Viking Drilling, an equipment loan with a Turkish bank and a credit agreement with a Turkish bank, each of which is discussed below.

Amended and Restated Senior Secured Credit Facility. On May 18, 2011, DMLP, TEMI, Talon Exploration, TAT and Petrogas entered into the amended and restated credit facility with Standard Bank and BNP Paribas. Each of the Borrowers are a wholly owned subsidiaries. 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 (collectively, the “Guarantors”).

On May 24, 2011, we used a portion of the amounts borrowed under the amended and restated credit facility to repay the $30.0 million short-term secured credit agreement, dated as of August 25, 2010, between TransAtlantic Worldwide and Standard Bank, which was scheduled to mature on May 25, 2011. We plan to use the remainder of the amounts borrowed under the amended and restated credit facility to finance a portion of the development of our oil and gas properties in Turkey and for working capital purposes in Turkey.

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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 August 5, 2011, the lenders had aggregate commitments of $120.0 million, with individual commitments of $60.0 million each. 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 amount under the amended and restated credit facility was increased to $95.0 million following the joinder of Amity as a borrower. 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. 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 field life coverage ratio means, for any calculation date, the ratio of (i) the net present value of cash flow available for debt service from the calculation date until the last abandonment date, to (ii) the aggregate outstanding principal amount of the loans, plus the aggregate undrawn maximum face amount of letters of credit, plus the aggregate unpaid drawings on such calculation date, minus the aggregate credit balance of the cash collateral account on such calculation date. The loan life coverage ratio means, for any calculation date, the ratio of (i) the net present value of the cash flow available for debt service from the calculation date until the maturity date, to (ii) the aggregate principal amount of the loans, plus the aggregate undrawn maximum face amount of letters of credit, plus the aggregate unpaid drawings on such calculation date, minus the aggregate credit balance of the cash collateral account on such calculation date. The debt service coverage ratio means, for any calculation date, the ratio of (i) the cash flow available for debt service for such calculation period, to (ii) the aggregate amount of all principal, interest and fees due and payable under the loan documents during such calculation period.

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 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, (iv) the hydrocarbon licenses owned by the Borrowers in Turkey and (v) substantially all of the present and future assets of the Borrowers.

The Borrowers are required to maintain certain ratios under the amended and restated credit facility’s financial covenants during the four most recently completed fiscal quarters occurring on or after March 31, 2011. These financial covenants require each of the Borrowers to maintain a:

• 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

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

The amended and restated credit facility defines EBITDAX as net income (excluding extraordinary items) plus, to the extent deducted in calculating such net income, (i) interest expense (excluding interest paid-in-kind, or non cash interest expense and interest incurred on certain subordinated intercompany debt or interest on equity recapitalized into subordinated debt), (ii) income tax expense, (iii) depreciation, depletion and amortization expense, (iv) amortization of intangibles and organization costs, (v) any extraordinary, unusual or non-recurring non-cash expenses or losses, (vi) expenses incurred in connection with oil and gas exploration activities entered into in the ordinary course of business (including related drilling, completion, geological and geophysical costs), (vii) transaction costs, expenses and fees incurred in connection with the negotiation, execution and delivery of the amended and restated credit facility and the related loan documents, and (vii) any other non-cash charges (including dry hole expenses and seismic expenses, to the extent such expenses would be capitalized), minus, to the extent included in calculating net income, (a) any extraordinary, unusual or non-recurring income or gains (including, gains on the sales of assets outside of the ordinary course of business) and (b) any other non-cash income or gains.

Pursuant to the terms of the amended and restated credit facility, until amounts under the amended and restated credit facility are repaid, each of the Borrowers shall not, and shall cause each of its subsidiaries not to, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to create any liens, (iii) enter into any merger, consolidation or amalgamation, liquidate or dissolve, (iv) dispose of any property or business, (v) pay any dividends, distributions or similar payments to shareholders, (vi) make certain types of investments, (vii) enter into any transactions with an affiliate, (viii) enter into a sale and leaseback arrangement, (ix) engage in any business or business activity, own any assets or assume any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and gas exploration and production company or operate or carry on business in any jurisdiction outside of Turkey or its jurisdiction of formation, (x) change its organizational documents, (xi) permit its fiscal year to end on a day other than December 31st or change its method of determining fiscal quarters, or alter the accounting principles it uses, (xii) modify certain hydrocarbon licenses and agreements or material contracts, (xiii) enter into any hedge agreement for speculative purposes or (xiv) open or maintain new deposit, securities or commodity accounts.

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 Guarantor or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or Guarantor; (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 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.

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 August 5, 2011, the Borrowers had borrowed $72.5 million under the amended and restated credit facility and had availability of $22.5 million under the amended and restated credit facility.

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

Borrowings under the short-term secured credit agreement accrued interest at a rate of LIBOR plus the applicable margin. The applicable margin equaled 3.75% for interest that accrued before November 23, 2010, 4.00% for interest that accrued on or after November 23, 2010 and before February 20, 2011, and 4.25% for interest that accrued on or after February 20, 2011 and before

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May 25, 2011. In addition, TransAtlantic Worldwide paid an arrangement fee of $750,000. The short-term secured credit agreement was scheduled to mature on May 25, 2011. TransAtlantic Worldwide repaid the loan in full on May 24, 2011, at which time the short-term secured credit agreement was terminated.

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 credit agreement with Dalea to extend the maturity date and increase the interest rate to match the interest rate payable under our amended and restated credit facility with Standard Bank and BNP Paribas.

Pursuant to the Dalea credit agreement, as amended, the aggregate unpaid principal balance, together with all accrued but unpaid interest and other costs, expenses or charges payable under the Dalea credit agreement are due and payable by us upon the earlier of (i) December 31, 2011, or (ii) the occurrence of an event of default and a demand for payment by Dalea. Events of default include, but are not limited to, payment defaults, defaults in the performance of any terms, covenants or conditions of the Dalea credit agreement or collateral documents, material misrepresentations by us or any subsidiary, we or any subsidiary ceases or threatens to cease to carry on business, the prohibition in trading in our shares or the suspension or delisting of our common shares from any stock exchange, any material adverse change occurs in us or any of our subsidiaries, Dalea believes in good faith that our ability to pay or perform any of the covenants contained in the Dalea credit agreement is materially impaired, our insolvency or the insolvency of any subsidiary, or a change in control of the Company. A change of control is defined as the change of ownership of, or control or direction over, directly or indirectly, 20% or more of our outstanding voting securities. If an event of default occurs and is continuing, Dalea may demand immediate payment of all monies owing under the Dalea credit agreement; provided, that with respect to certain specified events of default, all monies due under the Dalea credit agreement shall automatically become due and payable without any demand or any other action by Dalea or any other person.

Amounts due under the credit agreement accrue 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 credit agreement accrued interest at a rate of three-month LIBOR plus 2.50% per annum. In addition, we are required to pay all accrued interest in arrears on the last day of each month until the date of repayment and at any time that the principal balance is due and payable. We may prepay the amounts due under the credit agreement at any time before maturity without penalty.

The credit agreement contains certain covenants that limit our ability to, among other things, (i) make, give, create or permit or attempt to make, give or create any mortgage, charge, lien or encumbrance over any of our assets or any subsidiary’s assets (subject to certain specified exceptions), (ii) change our name or jurisdiction of organization, (iii) declare or provide for any dividends or other similar payments, (iv) redeem or repurchase any of our shares, (v) make or permit the sale of, or disposition of, any substantial or material part of our business, assets or undertaking or that of any subsidiary, (vi) borrow or cause any subsidiary to borrow money from any person (subject to certain specified exceptions) without obtaining and delivering a duly signed assignment and postponement of claim by such person in form and terms satisfactory to Dalea, (vii) pay out or permit the payment of any shareholder loans or other indebtedness to non-arm’s length parties by us or any subsidiary, or (viii) guarantee or permit the guarantee of the obligations of any other person by us or any subsidiary except in the ordinary course of business. In addition, any proceeds received by us or any subsidiary from any debt financings (subject to certain specified exceptions) must be used to repay amounts outstanding under the credit agreement, net of reasonable transaction and financing costs. We (or any subsidiary) are also required to repay amounts outstanding under the credit agreement from (i) any proceeds of any equity issuance received from Mr. Mitchell, his immediate family or any entities owned or controlled by Mr. Mitchell or his immediate family (collectively, the “Mitchell Family”), and (ii) all proceeds of any equity issuance in excess of $75.0 million (excluding any proceeds received from the Mitchell Family), net of reasonable transaction costs. Amounts repaid under the credit agreement cannot be reborrowed. We were required to pay for Dalea’s reasonable legal fees and other expenses incidental to the completion of the credit agreement.

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

At August 5, 2011, we had borrowed $73.0 million under the Dalea credit agreement. No further borrowings are permitted under the Dalea credit agreement.

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. Viking International paid $1.5 million in cash for the drilling rig and entered into a note payable with Viking Drilling in the amount of $5.9 million. The note was due and payable on August 1, 2010, bore interest at a fixed rate of 10% per annum and was secured by the drilling rig and associated equipment. We paid interest on the note on November 1, 2009 and February 1, 2010. On February 19, 2010, Viking International purchased the I-14 drilling rig and associated equipment from Viking Drilling and entered into an amended and restated note payable to Viking Drilling in the amount of $11.8 million, which was comprised of $5.9 million payable related to the I-14 drilling rig and $5.9 million payable related to the purchase

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of the I-13 drilling rig. Under the terms of the amended and restated note, interest is payable monthly at a floating rate of LIBOR plus 6.25%, and the amended and restated note is due and payable August 1, 2012. The amended and restated note is secured by the I-13 and I-14 drilling rigs and associated equipment. At June 30, 2011, the outstanding balance under this note was $5.4 million.

Viking International Equipment Loan.On July 21, 2010 and December 30, 2010, Viking International, our wholly owned subsidiary, entered into a secured credit agreement with a Turkish bank to fund the purchase of vehicles. The credit agreement has a term of 48 months and matures on July 20, 2014, bears interest at an annual rate of 3.84% and is secured by the vehicles purchased with the proceeds of the loan. There is no further availability under the credit agreement. At June 30, 2011, Viking International had borrowed $2.8 million under the credit agreement.

TBNG Credit Agreement.TBNG is a party to an unsecured credit agreement with a Turkish bank. At June 30, 2011, there were outstanding borrowings of approximately 19.4 million Turkish Lira (approximately $14.0 million) under the credit agreement. Borrowings under the credit agreement bear interest at a rate of 11.65% per annum, and interest is payable quarterly. The credit facility matures on September 13, 2011 and may be renewed for an additional period on the same terms.

Contractual Obligations

The following table presents our contractual obligations at June 30, 2011:

			Payments Due by Year
	Total		2011		2012		2013		2014		2015		Thereafter
	(in thousands)
Leases and other	$	15,319	$	2,015	$	3,558	$	2,051	$	1,362	$	1,330	$	5,003
Contracts		36,550		31,050		5,500		—		—		—		—
Permits		32,780		16,780		16,000		—		—		—		—
	$	84,649	$	49,845	$	25,058	$	2,051	$	1,362	$	1,330	$	5,003

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at June 30, 2011.

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.

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 including increases in taxes and receipt of required approvals, 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; 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.

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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.

Note Regarding Boe

We use the term barrels of oil equivalent, or Boe, in this Quarterly Report on Form 10-Q. We calculate Boe by converting natural gas to oil in the ratio of six Mcf of natural gas to one Bbl of oil. The conversion factor is the convention used by many oil and gas companies. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

During the second quarter of 2011, 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, 2010. The following tables set forth our outstanding derivatives contracts with respect to future oil production as of June 30, 2011:

Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
									(in thousands)
Collar		July 1, 2011 — December 31, 2011		1,060	$	64.39	$	101.32	$	(2,450	)
Collar		January 1, 2012 — December 31, 2012		960	$	64.69	$	106.98		(4,757	)
Collar		January 1, 2013 — December 31, 2013		400	$	75.00	$	125.50		(701	)
Collar		January 1, 2014 — December 31, 2014		380	$	75.00	$	124.25		(568	)
									$	(8,476	)

	Period		Quantity (Bbl/day)		Collar				Additional Call		Estimated Fair Value of Liability (in thousands)
Type					Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)
Three-way collar contract		July 1, 2011 — December 31, 2011		240	$	70.00	$	100.00	$	129.50	$	(558	)
Three-way collar contract		January 1, 2012 — December 31, 2012		240	$	70.00	$	100.00	$	129.50		(1,028	)
											$	(1,586	)

Item 4. Controls and Procedures

Recent Acquisitions

On August 25, 2010, we acquired Amity and Petrogas. For purposes of determining the effectiveness of our disclosure controls and procedures and any change in our internal control over financial reporting, management has excluded the internal control over financial reporting of Amity and Petrogas from its evaluation of these matters. The acquired businesses represent approximately 17.6% of our consolidated total assets at June 30, 2011 and approximately 11.0% of our total revenues for the six months ended June 30, 2011.

On February 18, 2011, we acquired Direct Morocco, Anschutz and Direct Bulgaria. For purposes of determining the effectiveness of our disclosure controls and procedures and any change in our internal control over financial reporting, management has excluded the internal control over financial reporting of Direct Morocco, Anschutz and Direct Bulgaria from its evaluation of these matters. The acquired businesses represent approximately less than 1% of our consolidated total assets and total revenues at June 30, 2011 and for the six months ended June 30, 2011, respectively.

On June 7, 2011, we acquired TBNG. For purposes of determining the effectiveness of our disclosure controls and procedures and any change in our internal control over financial reporting, management has excluded the internal control over financial reporting of TBNG from its evaluation of these matters. The acquired businesses represent approximately 15.3% of our consolidated total assets at June 30, 2011 and approximately 2.8% of our total revenues for the six months ended June 30, 2011.

Any material change to our internal control over financial reporting due to the acquisition of Amity, Petrogas, Direct Morocco, Anschutz, Direct Bulgaria and TBNG will be disclosed in our annual report for the year ending December 31, 2011, in which our assessment that encompasses these entities will be included.

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the 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.

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As of June 30, 2011, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures. Based upon the evaluation, which excluded the internal control over financial reporting of Amity, Petrogas, Direct Morocco, Anschutz, Direct Bulgaria and TBNG, 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, 2010, our chief executive officer and chief financial officer concluded that, as of June 30, 2011, 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

There were no changes in our internal control over financial reporting that occurred during the second quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting, except as follows:

Staffing. In May and June 2011, we hired the following accounting personnel who have specific experience in financial reporting for public companies, preparation of consolidated financial statements, and oil and gas property, oilfield services and multi-currency accounting:

• Corporate Controller, whose responsibilities include overseeing all aspects of our accounting function and the consolidation of our financial statements;

• Director of Financial Reporting, whose responsibilities include overseeing the timely filing of our Quarterly Reports on Form 10-Q and Annual Report on Form 10-K and playing a key role in the remediation of deficiencies in our internal control over financial reporting;

• Director of Internal Audit, whose responsibilities include establishing and monitoring the effectiveness of our internal control over financial reporting and monitoring the remediation of deficiencies in our internal control over financial reporting. The director of internal audit is also responsible for ensuring that we maintain an effective anti-fraud program;

• Director of Mergers and Acquisitions Accounting, whose responsibilities include leading the accounting and finance integration of acquisitions, including Direct Bulgaria and TBNG;

• Controller, Exploration and Production, whose responsibilities include managing the accounting for our exploration and production business segment and implementing the controls necessary to remediate deficiencies in our internal control over financial reporting; and

• Controller, Drilling Services, whose responsibilities include managing the accounting for our drilling services business segment and implementing the controls necessary to remediate deficiencies in our internal control over financial reporting.

Integration of Accounting Functions. In May 2011, we completed the integration of two separate and distinct accounting system databases located in Istanbul (used for our Turkish subsidiaries) and Dallas (used for consolidating and reporting and for accounting for our holding companies and our Moroccan, Bulgarian and Romanian subsidiaries) into one database in Istanbul, effective for all activity on or after January 1, 2011. The combined database has multi-currency functionality and is able to generate U.S. GAAP reports for individual subsidiaries. We believe this integration has improved accuracy and has reduced conflicts and redundancies. Because the underlying data largely resides in a single location, the number of adjusting entries has also been reduced.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

During the second quarter of 2011, there were no material developments to the Legal Proceedings disclosed in “Part I, Item 3. Legal Proceedings” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Item 1A. Risk Factors

During the second quarter of 2011, there were no material changes to the Risk Factors disclosed in “Part I, Item 1A. Risk Factors” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2010, as updated by the Risk Factors disclosed in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, except for the following:

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

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

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

• difficulty transitioning customers and other business relationships to our company;

• problems unifying management of a combined company;

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

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

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

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Reserved

Item 5. Other Information

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Item 6. Exhibits

2.1*	Share Purchase Agreement, dated April 23, 2011, by and between Mustafa Mehmet Corporation and TransAtlantic Worldwide, Ltd.
2.2*	First Amendment to Share Purchase Agreement, dated June 6, 2011, by and between Mustafa Mehmet Corporation and TransAtlantic Worldwide, Ltd.
2.3*	Multi-Party Agreement, dated June 6, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Valeura Energy, Inc., Valeura Energy (Netherlands) Coöperatief UA, Pinnacle Turkey Holding Company, LLC, Thrace Basin Natural Gas Turkiye Corporation, Pinnacle Turkey, Inc. and Corporate Resources B.V.
3.1	Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.2	Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated August 20, 2009 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.3	Bye-Laws of TransAtlantic Petroleum Ltd., dated July 14, 2009 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
4.1	Amended and Restated Registration Rights Agreement, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Riata Management, LLC (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009).
4.2	Registration Rights Agreement, dated February 18, 2011, by and between TransAtlantic Petroleum Ltd. and Direct Petroleum Exploration, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated February 18, 2011, filed with the SEC on February 24, 2011).
4.3	Common Share Purchase Warrant, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009).
4.4	Common Share Purchase Warrant, dated September 1, 2010, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP. (incorporated by reference to Exhibit 4.4 to the Company’s Annual Report on Form 10-K, filed with the SEC on April 21, 2011).
10.1	Amended and Restated Credit Agreement, dated as of May 18, 2011, by and between DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, the lenders party thereto from time to time, and Standard Bank Plc and BNP Paribas (Suisse) SA, as joint mandated lead arrangers and joint bookrunners, and Standard Bank Plc as administrative agent, collateral agent and technical agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 17, 2011, filed with the SEC on May 19, 2011).
10.2	First Amendment to Credit Agreement, dated May 18, 2011, by and between Dalea Partners, LP and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated May 17, 2011, filed with the SEC on May 19, 2011).
10.3	Amendment to Credit Agreement, dated as of April 1, 2011, by and among TransAtlantic Worldwide, Ltd., as borrower, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., Amity Oil International Pty Limited and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., as guarantors, the lenders as defined in the Credit Agreement, and Standard Bank Plc, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K dated April 1, 2011, filed with the SEC on April 6, 2011).
10.4	Amendment to Letter Agreement, dated April 2, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).
10.5	Amendment to Letter Agreement, dated April 15, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).

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10.6	Amendment to Letter Agreement, dated April 23, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).
10.7	Amendment to Letter Agreement, dated April 29, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).
10.8	Amendment to Letter Agreement, dated May 10, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).
10.9	Amendment to Letter Agreement, dated May 19, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).
10.10*	Escrow Agreement, dated June 6, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Pinnacle Turkey Holding Company, LLC, Valeura Energy (Netherlands) Coöperatief UA, Mustafa Mehmet Corporation and American Escrow Company.
10.11	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, dated July 13, 2011, filed with the SEC on July 19, 2011).
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.

† Management contract or compensatory plan arrangement.

* Filed herewith. Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

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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.

By:	/s/    N. MALONE MITCHELL, 3rd
	N. Malone Mitchell, 3rd Chief Executive Officer
By:	/S/    WIL F. SAQUETON
	Wil F. Saqueton Chief Financial Officer
Date: August 8, 2011

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INDEX TO EXHIBITS

2.1*	Share Purchase Agreement, dated April 23, 2011, by and between Mustafa Mehmet Corporation and TransAtlantic Worldwide, Ltd.
2.2*	First Amendment to Share Purchase Agreement, dated June 6, 2011, by and between Mustafa Mehmet Corporation and TransAtlantic Worldwide, Ltd.
2.3*	Multi-Party Agreement, dated June 6, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Valeura Energy, Inc., Valeura Energy (Netherlands) Coöperatief UA, Pinnacle Turkey Holding Company, LLC, Thrace Basin Natural Gas Turkiye Corporation, Pinnacle Turkey, Inc. and Corporate Resources B.V.
3.1	Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.2	Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated August 20, 2009 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.3	Bye-Laws of TransAtlantic Petroleum Ltd., dated July 14, 2009 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
4.1	Amended and Restated Registration Rights Agreement, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Riata Management, LLC (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009).
4.2	Registration Rights Agreement, dated February 18, 2011, by and between TransAtlantic Petroleum Ltd. and Direct Petroleum Exploration, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated February 18, 2011, filed with the SEC on February 24, 2011).
4.3	Common Share Purchase Warrant, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009).
4.4	Common Share Purchase Warrant, dated September 1, 2010, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP. (incorporated by reference to Exhibit 4.4 to the Company’s Annual Report on Form 10-K, filed with the SEC on April 21, 2011).
10.1	Amended and Restated Credit Agreement, dated as of May 18, 2011, by and between DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, the lenders party thereto from time to time, and Standard Bank Plc and BNP Paribas (Suisse) SA, as joint mandated lead arrangers and joint bookrunners, and Standard Bank Plc as administrative agent, collateral agent and technical agent (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 17, 2011, filed with the SEC on May 19, 2011).
10.2	First Amendment to Credit Agreement, dated May 18, 2011, by and between Dalea Partners, LP and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated May 17, 2011, filed with the SEC on May 19, 2011).
10.3	Amendment to Credit Agreement, dated as of April 1, 2011, by and among TransAtlantic Worldwide, Ltd., as borrower, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., Amity Oil International Pty Limited and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., as guarantors, the lenders as defined in the Credit Agreement, and Standard Bank Plc, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K dated April 1, 2011, filed with the SEC on April 6, 2011).
10.4	Amendment to Letter Agreement, dated April 2, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).
10.5	Amendment to Letter Agreement, dated April 15, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).

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10.6	Amendment to Letter Agreement, dated April 23, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.10 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).
10.7	Amendment to Letter Agreement, dated April 29, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.11 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).
10.8	Amendment to Letter Agreement, dated May 10, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).
10.9	Amendment to Letter Agreement, dated May 19, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd. and Valeura Energy Inc. (incorporated by reference to Exhibit 10.13 to the Company’s Quarterly Report on Form 10-Q, filed with the SEC on May 31, 2011).
10.10*	Escrow Agreement, dated June 6, 2011, by and between TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Pinnacle Turkey Holding Company, LLC, Valeura Energy (Netherlands) Coöperatief UA, Mustafa Mehmet Corporation and American Escrow Company.
10.11	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, dated July 13, 2011, filed with the SEC on July 19, 2011).
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.

† Management contract or compensatory plan arrangement.

* Filed herewith. Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

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