Edgar Filing: TRANSATLANTIC PETROLEUM LTD.

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

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: September 30, 2011

¨	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 Nispetiye Caddesi 34330 Etiler, Istanbul, Turkey		None
(Address of principal executive offices)		(Zip Code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant is required to submit and post such files). Yes x No ¨

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

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 November 7, 2011, the registrant had 365,730,492 common shares outstanding.

TABLE OF CONTENTS


Part I. Financial Information

Item 1.	Financial Statements

		Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010	1

		Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2011 and 2010	2

		Consolidated Statements of Equity for the Nine Months Ended September 30, 2011	3

		Consolidated Statements of Cash Flows for the Nine Months Ended September 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		22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		37

Item 4.	Controls and Procedures		38

Part II. Other Information

Item 1.	Legal Proceedings		39

Item 1A.	Risk Factors		39

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		39

Item 3.	Defaults Upon Senior Securities		39

Item 4.	Reserved		39

Item 5.	Other Information		39

Item 6.	Exhibits		40

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

(Unaudited)

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


	September 30, 2011			December 31, 2010
				(as adjusted)
ASSETS
Current assets:
Cash and cash equivalents	$	22,132		$	34,676
Accounts receivable
Oil and gas sales, net		28,518			23,077
Related party		1,338			3,783
Other		18,541			6,326
Prepaid and other current assets		15,996			6,376
Deferred income taxes		2,568			991
Assets held for sale		129,421			—

Total current assets		218,514			75,229

Property and equipment:
Oil and gas properties (successful efforts method)
Proved		178,303			150,407
Unproved		92,811			80,167
Equipment and other property		42,148			174,654

		313,262			405,228
Less accumulated depreciation, depletion and amortization		(34,264	)		(36,382	)

Property and equipment, net		278,998			368,846
Other long-term assets:
Restricted cash		1,471			7,956
Deposit on acquisition		—			10,000
Deferred charges		4,323			1,596
Goodwill		8,715			10,341

Total other assets		14,509			29,893

Total assets	$	512,021		$	473,968

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	23,693		$	15,842
Accounts payable — related party		883			969
Accrued and other liabilities		20,198			10,329
Loans payable		8,130			30,869
Loan payable — related party		73,000			75,804
Derivative liabilities		2,221			1,612
Liabilities held for sale		15,775			—
Liabilities held for sale — related party		4,154			—

Total current liabilities		148,054			135,425
Long-term liabilities:
Asset retirement obligations		13,069			6,943
Accrued liabilities		4,484			724
Deferred income taxes		20,477			22,835
Loan payable		78,000			27,147
Loans payable — related party		—			2,932
Derivative liabilities		59			1,905

Total long-term liabilities		116,089			62,486

Total liabilities		264,143			197,911
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.01 par value, 1,000,000,000 shares authorized; 365,672,523 issued and outstanding as of September 30, 2011 and 336,442,984 as of December 31, 2010		3,657			3,364
Additional paid in capital		533,726			465,973
Accumulated other comprehensive income (loss)		(53,094	)		1,833
Accumulated deficit		(236,411	)		(195,113	)

Total shareholders’ equity		247,878			276,057

Total liabilities and shareholders’ equity	$	512,021		$	473,968

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

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

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


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2011			2010			2011			2010
				(as adjusted)						(as adjusted)
Revenues:
Oil and natural gas sales	$	31,621		$	18,327		$	91,052		$	45,480
Other		417			369			1,664			388

Total revenues		32,038			18,696			92,716			45,868
Costs and expenses:
Production		3,269			5,347			11,527			14,242
Exploration, abandonment and impairment		3,851			—			15,525			7,459
Seismic and other exploration		2,818			3,735			6,816			9,304
Revaluation of contingent consideration		—			—			1,250			—
General and administrative		8,483			6,016			26,887			17,744
Depreciation, depletion and amortization		12,205			3,363			25,312			7,083
Accretion of asset retirement obligations		341			69			893			174

Total costs and expenses		30,967			18,530			88,210			56,006

Operating income (loss)		1,071			166			4,506			(10,138	)
Other income (expense):
Interest and other expense		(3,330	)		(2,741	)		(10,487	)		(3,571	)
Interest and other income		458			70			792			184
Gain (loss) on commodity derivative contracts		6,460			(3,032	)		(2,697	)		605
Foreign exchange gain		242			1,266			411			726

Total other income (expense)		3,830			(4,437	)		(11,981	)		(2,056	)

Income (loss) before income taxes		4,901			(4,271	)		(7,475	)		(12,194	)
Current income tax benefit (expense)		970			(812	)		(2,692	)		(3,397	)
Deferred income tax benefit (expense)		(2,214	)		619			121			1,319

Income (loss) from continuing operations		3,657			(4,464	)		(10,046	)		(14,272	)
Loss from discontinued operations, net of taxes		(3,985	)		(7,310	)		(31,252	)		(25,276	)

Net loss	$	(328	)	$	(11,774	)	$	(41,298	)	$	(39,548	)
Other comprehensive income (loss):
Foreign currency translation adjustment		(44,700	)		22,120			(54,927	)		14,659

Comprehensive income (loss)	$	(45,028	)	$	10,346		$	(96,225	)	$	(24,889	)

Net income (loss) per common share:
Basic and diluted net income (loss) per common share:
From continuing operations	$	0.01		$	(0.01	)	$	(0.03	)	$	(0.05	)
From discontinued operations	$	(0.01	)	$	(0.02	)	$	(0.09	)	$	(0.08	)
Basic and diluted weighted average shares outstanding		365,472			305,564			352,682			304,520

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

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 (as adjusted)		336,443	$	3,364	$	465,973		$	1,833		$	(195,113	)	$	276,057
Issuance of common shares		27,424		274		65,763			—			—			66,037
Exercise of warrants		80		1		95			—			—			96
Exercise of stock options		785		8		559			—			—			567
Issuance of restricted stock units		940		10		(10	)		—			—			—
Share-based compensation		—		—		1,346			—			—			1,346
Foreign currency translation adjustments		—		—		—			(54,927	)		—			(54,927	)
Net loss		—		—		—			—			(41,298	)		(41,298	)

Balance at September 30, 2011		365,672	$	3,657	$	533,726		$	(53,094	)	$	(236,411	)	$	247,878

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

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands of U.S. dollars)


	For the Nine Months Ended September 30,
	2011			2010
				(as adjusted)
Operating activities:
Net loss	$	(41,298	)	$	(39,548	)
Adjustment for loss from discontinued operations		31,252			25,276

Net loss from continuing operations		(10,046	)		(14,272	)
Adjustments to reconcile net loss to net cash used in operating activities:
Share-based compensation		1,346			1,444
Foreign currency loss (gain)		2,529			(25	)
Unrealized gain on commodity derivative contracts		(1,219	)		(605	)
Amortization of debt issuance costs		1,447			620
Deferred income tax expense		(121	)		(1,319	)
Amortization of warrants — related party		1,972			1,107
Exploration, abandonment and impairment		10,422			3,144
Depreciation, depletion and amortization		25,312			7,083
Accretion of asset retirement obligations		893			174
Loss on revaluation of contingent consideration		1,250			—
Changes in operating assets and liabilities, net of effect of acquisitions:
Accounts receivable		(4,542	)		(6,379	)
Prepaid expenses and other assets		(12,813	)		868
Accounts payable and accrued liabilities		18,960			(8,349	)

Net cash provided by (used in) operating activities from continuing operations		35,390			(16,509	)
Net cash used in operating activities from discontinued operations		(5,999	)		(21,249	)

Net cash provided by (used in) operating activities		29,391			(37,758	)
Investing activities:
Acquisitions net of cash		(747	)		(96,500	)
Additions to oil and gas properties		(47,780	)		(35,124	)
Additions to equipment and other		(7,636	)		(9,431	)
Restricted cash		3,445			(173	)

Net cash used in investing activities of continuing operations		(52,718	)		(141,228	)
Net cash used in investing activities of discontinued operations		(2,554	)		(41,977	)

Net cash used in investing activities		(55,272	)		(183,205	)
Financing activities:
Exercise of stock options and warrants		663			1,412
Issuance of shares		—			65,300
Issuance of shares – related party		—			5,000
Issuance costs		—			(3,690	)
Loan proceeds		31,696			46,930
Loan proceeds — related party		—			91,500
Loan repayment		(13,752	)		(2,315	)
Loan repayment — related party		—			(18,500	)

Net cash provided by financing activities of continuing operations		18,607			185,637
Net cash used in financing activities of discontinued operations		(3,509	)		(335	)

Net cash provided by financing activities		15,098			185,302
Effect of exchange rate changes on cash and cash equivalents		(1,761	)		1,795
Net decrease in cash and cash equivalents		(12,544	)		(33,866	)
Cash and cash equivalents, beginning of period		34,676			90,484

Cash and cash equivalents, end of period	$	22,132		$	56,618

Supplemental disclosures:
Cash paid for interest	$	6,052		$	1,306

Cash paid for income taxes	$	4,404		$	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.

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 an international oil and gas company engaged in acquisition, exploration, development and production. We hold interests in developed and undeveloped oil and gas properties in Turkey, Bulgaria and Romania. As of November 1, 2011, approximately 42% of our outstanding common shares were beneficially owned by N. Malone Mitchell, 3rd, our 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 exchange for (i) $2.4 million in cash and (ii) the issuance of 8.9 million of our common shares (at a deemed price of $3.15 per common share) to the seller, Direct Petroleum Exploration, Inc. (“Direct”), in a private placement, 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 AŞ. (“Petrogas”) as borrowers, and to increase the borrowing base. Following our semi-annual borrowing base redetermination on October 1, 2011, our borrowing base is currently $81.4 million. As of November 1, 2011, we had borrowed $78.0 million and had $3.4 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 November 7, 2011, we entered into a second amendment to the Dalea credit agreement to extend the maturity date to the earlier of (i) March 31, 2012 or (ii) the sale of our wholly owned subsidiaries, Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”);

•

on May 24, 2011, we used a portion of the amounts borrowed under the amended and restated credit facility to repay a $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 (at a deemed price of $2.05 per share), (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 of MMC, and (iii) the payment of $10.5 million in cash. Through the acquisition of TBNG, we acquired drilling rigs and oilfield service assets as well as interests ranging from 25% to 62.5% in 10 exploration licenses and four production leases;

•

on June 27, 2011, we decided to discontinue our operations in Morocco;

•

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

•

on September 30, 2011, we engaged a financial advisor to assist with the sale, transfer or other disposition of our oilfield services business. We intend to complete the bid process for the sale of this business in the fourth quarter of 2011 and expect to consummate the sale by the end of the first quarter of 2012.

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 generally accepted in the United States of America (“U.S. GAAP”) have been omitted pursuant to such rules and regulations. 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 $41.3 million during the nine months ended September 30, 2011, which includes a net loss from discontinued operations of $31.3 million. At September 30, 2011, the outstanding principal amount of our debt was $165.7 million, of which $6.6 million is held for sale. Excluding assets held for sale of $129.4 million and total liabilities held for sale of $19.9 million, we had a working capital deficit of $39.0 million. Of our outstanding debt, $73.0 million under the Dalea credit agreement is due the earlier of (i) March 31, 2012 or (ii) the sale of Viking International and Viking Geophysical. We forecast that we will need to extend the maturity date of the Dalea credit agreement, consummate the sale of assets or raise additional debt or equity financing 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 have engaged a financial advisor to assist with the sale, transfer or other disposition of our oilfield services business and are considering the issuance of common shares, public debt or private debt. 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 consummate the sale of assets or raise additional financing, we will not have sufficient funds to continue operations beyond March 31, 2012. 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. 2010-28 Intangibles—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 is considered on an interim and annual basis when we review and perform our goodwill impairment test. The adoption of ASU 2010-28 did not have a material impact on our financial statements.

In December 2010, FASB issued ASU No. 2010-29 Business 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 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 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, but may require a change in the presentation of our comprehensive income from the notes of the financial statements, where it is currently disclosed, to the face of the 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, TransAtlantic Worldwide acquired TBNG in exchange 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 that 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 and comprehensive income (loss) for the nine months ended September 30, 2011	$	1,013

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 accounts receivable that were acquired was $24.4 million, consisting of a gross amount of $27.9 million, of which $3.5 million is 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 revenues and loss of TBNG included in our consolidated statement of operations and comprehensive income (loss) for the nine months ended September 30, 2011 are shown below:


	Revenue		Loss
	(in thousands)
Actual from June 7, 2011 through September 30, 2011	$	6,103	$	(4,567	)

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) to Direct in a private placement, 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.

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. As part of the agreement, $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 we have not cored the Etropole formation by February 18, 2012. The fair value of this contingent liabilities represents our best estimate of the amounts to be paid for each of the milestones, based on the probability of commercial success. Subsequent changes in the fair value of the liability will be recorded in earnings. As of September 30, 2011, we had determined that the likelihood of payment for the failure to timely drill the Deventci-R2 well had 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 income (loss).

Acquisition-Related Costs:


Included in general and administrative expenses on our consolidated statement of operations and comprehensive income (loss) for the nine months ended September 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 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.

The amounts of revenue and loss of Direct Morocco, Anschutz and Direct Bulgaria included in our consolidated statement of operations and comprehensive income (loss) for the nine months ended September 30, 2011 are shown below:


	Revenue		Loss
	(in thousands)
Continuing operations	$	364	$	(1,200	)
Discontinued operations		—		(21	)

Total from February 18, 2011 through September 30, 2011	$	364	$	(1,221	)

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 final recognized amounts of assets acquired and liabilities assumed that 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		56,722
Proved properties		47,712
Drilling services and related equipment		4,256
Inventory		3,032

Total oil and gas properties, drilling services and other equipment		111,722
Liabilities:
Accounts payable, consisting of normal trade obligations		198
Accrued liabilities, consisting primarily of accrued compensated employee absences		677
Deferred income taxes		16,063
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		17,490

Total identifiable net assets	$	96,547

After receiving the final valuation report, we determined that certain proved properties were reclassified between fields and between reserve categories. These changes resulted in lower values of the properties that were acquired. Additionally, unproved properties increased due to higher valuations on certain licenses. These changes reduced proved properties by $7.1 million, increased unproved properties by $7.0 million and decreased deferred income taxes by $0.1 million. Under ASC 805, a change to the initial purchase price allocation is recast as if the final valuations had been recorded on the date of the acquisition. Due to the change in proved properties, our depletion expense decreased by $1.4 million, net of tax in 2010 and by $2.2 million, net of tax in 2011.

Pro forma results of operations

The following table presents the unaudited pro forma results of operations as though the acquisitions of Amity, Petrogas, Direct Morocco, Anschutz, Direct Bulgaria and TBNG had occurred as of January 1, 2010 (in thousands, except per share amounts):


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2011			2010			2011			2010
Total revenues	$	32,577		$	27,690		$	104,773		$	80,141
Income (loss) from continuing operations before income taxes		7,100			(1,880	)		(2,796	)		(13,904	)
Income (loss) from continuing operations		5,504			(3,081	)		(6,298	)		(17,348	)
Loss from discontinued operations		(4,516	)		(7,907	)		(32,954	)		(27,070	)
Net income (loss)		988			(10,988	)		(39,252	)		(44,418	)
Net income (loss) per common share from continuing operations
Basic	$	0.01		$	(0.01	)	$	(0.02	)	$	(0.05	)
Diluted	$	0.01		$	(0.01	)	$	(0.02	)	$	(0.05	)
Net loss per common share from discontinued operations
Basic	$	(0.01	)	$	(0.02	)	$	(0.09	)	$	(0.08	)
Diluted	$	(0.01	)	$	(0.02	)	$	(0.09	)	$	(0.08	)

5.	Discontinued operations

In June 2011, we decided to discontinue our operations in Morocco. We intend to sell our existing Moroccan interests and operations and transfer our oilfield services equipment from Morocco to Turkey. All revenues and expenses associated with the Moroccan operations for the three and nine months ended September 30, 2011 and 2010 have been included in discontinued operations.

In September 2011, we engaged a financial advisor to assist us with the sale of our oilfield services business. We anticipate completing the bid process for the sale of this business in the fourth quarter of 2011 and expect to consummate the sale by the end of the first quarter of 2012. Upon consummation of a sale, we will no longer have an oilfield services segment. As such, we classified our oilfield services segment as discontinued operations at September 30, 2011. All revenues and expenses associated with our oilfield services segment for the three and nine months ended September 30, 2011 and 2010 have been included in discontinued operations.

The summary operating results for our Moroccan and oilfield services operations are as follows:


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2011			2010			2011			2010
	(in thousands)
Total revenues	$	12,974		$	5,532		$	20,188		$	9,356
Costs and expenses		15,615			10,337			48,054			31,435

Operating loss		(2,641	)		(4,805	)		(27,866	)		(22,079	)
Other expense		(291	)		(1,613	)		(1,443	)		(1,873	)

Loss before income taxes		(2,932	)		(6,418	)		(29,309	)		(23,952	)
Total income tax expense		(1,053	)		(892	)		(1,943	)		(1,324	)

Loss from discontinued operations	$	(3,985	)	$	(7,310	)	$	(31,252	)	$	(25,276	)

The assets and liabilities of discontinued operations presented under the captions “Assets held for sale”, “Liabilities held for sale” and “Liabilities held for sale – related party” on the consolidated balance sheet at September 30, 2011 are valued at the lower of cost or fair value less the estimated cost of selling. At September 30, 2011, our assets and liabilities held for sale consisted of the following:


	(in thousands)
Assets held for sale
Drilling services and other equipment, net	$	114,711
Oil and gas properties, net		2,447
Other assets		12,263

Total assets held for sale	$	129,421


Liabilities held for sale
Accounts payable and accrued liabilities	$	13,308
Loans payable		2,467
Liabilities held for sale – related party		4,154

Total liabilities held for sale	$	19,929

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:


	September 30, 2011			December 31, 2010
	(in thousands)
Oil and gas properties, proved:
Turkey	$	173,192		$	150,407
Bulgaria		5,111			—

Total oil and gas properties, proved	$	178,303		$	150,407

Oil and gas properties, unproved:
Turkey	$	62,983		$	73,662
Bulgaria		29,828			—
Morocco		—			5,036
Other		—			1,469

Total oil and gas properties, unproved		92,811			80,167
Accumulated depletion		(30,689	)		(14,360	)

Net oil and gas properties	$	240,425		$	216,214

At September 30, 2011 and December 31, 2010, we excluded $5.7 million and $11.7 million, respectively, from the depletion calculation for proved development wells currently in progress.

At September 30, 2011, our oil and gas properties were comprised of $72.0 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $72.9 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 nine months ended September 30, 2011, we incurred approximately $9.4 million in exploratory drilling costs, of which $6.2 million was charged to earnings (included in exploration, abandonment and impairment expense) and $3.2 million remained capitalized at September 30, 2011. We reclassified $0.4 million of our exploratory well costs to proved properties during the nine months ended September 30, 2011. No amount of our exploratory well costs as of September 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.

(b)

Equipment and other property. The historical cost of equipment and other property is summarized as follows:


	September 30, 2011			December 31, 2010
	(in thousands)
Other equipment	$	5,826		$	83,916
Inventory		22,257			37,569
Gas gathering system and facilities		6,983			7,960
Fracture stimulation equipment		—			16,410
Seismic equipment		—			14,882
Vehicles		1,044			9,324
Office equipment and furniture		6,038			4,593

Gross equipment and other property		42,148			174,654
Accumulated depreciation		(3,575	)		(22,022	)

Net equipment and other property	$	38,573		$	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 September 30, 2011, we excluded $1.8 million of gas gathering system and facilities, $0.2 million of other equipment and $22.3 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 other 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 a portion 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, we record the contracts at fair value and recognize changes in fair value in earnings as they occur.

Our commodity derivative contracts are carried at their fair value on our consolidated balance sheet under either the caption “Derivative liabilities” or “Derivative assets.” All of our oil derivative contracts are settled based upon Brent oil pricing. We recognize unrealized and realized gains and losses related to these contracts on a fair value basis in our consolidated statements of operations and comprehensive income (loss) under the caption “Gain (loss) on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows.

For the three months ended September 30, 2011, we recorded a net gain on commodity derivative contracts of approximately $6.5 million, consisting of a $7.8 million unrealized gain related to changes in fair value and a $1.3 million realized loss for settled contracts. For the nine months ended September 30, 2011, we recorded a net loss on commodity derivative contracts of $2.7 million, consisting of a $1.2 million unrealized gain related to changes in fair value and a $3.9 million realized loss for settled contracts.

For the three and nine months ended September 30, 2010, we recorded a net unrealized loss and a net unrealized gain on commodity derivative contracts of $3.0 million and $0.6 million, respectively.

At September 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 September 30, 2011


Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Asset (Liability)
									(in thousands)
Collar		October 1, 2011—December 31, 2011		1,060	$	64.39	$	101.32	$	(451	)
Collar		January 1, 2012—December 31, 2012		960	$	64.69	$	106.98		(2,078	)
Collar		January 1, 2013—December 31, 2013		400	$	75.00	$	125.50		255
Collar		January 1, 2014—December 31, 2014		380	$	75.00	$	124.25		360

									$	(1,914	)


		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 Asset (Liability)
										(in thousands)
Three-way collar contract	October 1, 2011—December 31, 2011		640	$	79.38	$	114.38	$	137.16	$	(104	)
Three-way collar contract	January 1, 2012—December 31, 2012		240	$	70.00	$	100.00	$	129.50	$	(447	)
Three-way collar contract	January 1, 2012— March 31, 2012		350	$	85.00	$	118.88	$	138.13	$	73
Three-way collar contract	April 1, 2012 — June 30, 2012		350	$	85.00	$	116.25	$	137.38	$	112

										$	(366	)

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	)

8.	Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations at the dates indicated:


	September 30, 2011			December 31, 2010
	(in thousands)
Asset retirement obligations at beginning of period	$	6,943		$	3,125
Acquisitions		6,480			552
Change in estimates		14			2,220
Foreign exchange change effect		(2,213	)		(251	)
Additions		952			827
Accretion expense		893			470

Asset retirement obligations at end of period	$	13,069		$	6,943

9.	Third-party loans payable

Our third-party debt consisted of the following at the dates indicated:


	September 30, 2011		December 31, 2010
	(in thousands)
Third-Party Floating Rate Debt
Amended and restated credit facility	$	78,000	$	25,000
Short-term secured credit agreement		—		30,000
Unsecured lines of credit		—		126
Third-Party Fixed Rate Debt
TBNG credit agreement		8,130		—
Viking International equipment loan		—		2,890

Total third-party debt		86,130		58,016
Less: short-term third-party debt		8,130		30,869

Total long-term third-party debt	$	78,000	$	27,147

Amended and restated 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 our 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”).

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 September 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 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. Following our semi-annual borrowing base redetermination on October 1, 2011, our borrowing base is currently $81.4 million.

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, and (iv) substantially all of the present and future assets of the Borrowers.

The Borrowers are required to comply with certain financial and non-financial covenants under the amended and restated credit facility, including maintaining the following financial ratios during the four most recently completed fiscal quarters occurring on or after March 31, 2011:

•

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.

At September 30, 2011, the Borrowers had borrowed $78.0 million and were in compliance with all covenants under the amended and restated credit facility.

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.

TBNG credit agreements

TBNG is a party to unsecured credit agreements with a Turkish bank. During September 2011, we repaid the outstanding balance of approximately $4.1 million, on one of the agreements. At September 30, 2011, there were outstanding borrowings of approximately 15.0 million New Turkish Lira (approximately $8.1 million) under the remaining credit agreement. Borrowings under the credit agreement bear interest at a rate of 11.65% per annum, and interest is payable quarterly. The credit agreement matures on March 13, 2012 and may be renewed for an additional period on the same terms.

Viking International equipment loan

In 2010, Viking International entered into a secured credit agreement with a Turkish bank to fund the purchase of vehicles. The credit agreement 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 September 30, 2011, the outstanding balance under the secured credit agreement was $2.4 million and the secured credit agreement was included in “Liabilities held for sale” in our consolidated balance sheets.

10.

Related party loans payable

Related party debt consisted of the following:


Related Party Floating Rate Debt	September 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		—		7,708

Total related party debt		73,000		78,736
Less: short-term related party debt		73,000		75,804

Total long-term related party debt	$	—	$	2,932

Dalea credit agreement

On June 28, 2010, we entered into a credit agreement with Dalea. 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. On November 7, 2011, we entered into a second amendment to the Dalea credit agreement to extend the maturity date to the earlier of (i) March 31, 2012 or (ii) the sale of Viking International and Viking Geophysical.

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) March 31, 2012, (ii) the sale of Viking International and Viking Geophysical or (iii) 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.

As of September 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”). 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. 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 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. As of September 30, 2011, the outstanding balance under the note was $4.2 million and the note is included in “Liabilities held for sale – related party” in our consolidated balance sheets. Dalea owns 85% of Viking Drilling.

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 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 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 $1.3 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three and nine months ended September 30, 2011, respectively. We recorded share-based compensation expense of $0.6 million and $1.5 million for the three and nine months ended September 30, 2010, respectively.

As of September 30, 2011, we had approximately $2.5 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.5 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 nine months ended September 30, 2011. At September 30, 2011, all stock options have been fully amortized.

Earnings per share

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


	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2011		2010		2011		2010
Unvested RSUs		1,565,337		2,128,563		1,709,334		2,104,068
Stock options		1,457,479		2,571,803		1,826,273		2,846,663
Warrants		17,318,720		12,778,169		17,334,251		11,411,203

Additionally, we have a contingent liability at September 30, 2011 of approximately $5.3 million that is payable in our common shares. See Note 4 for further discussion. At the September 30, 2011 closing stock price, this liability represents 6,402,439 common shares that could be potentially dilutive to future earnings per share calculations.

12.

Segment information

We have one operating segment, exploration and production, within three geographic segments, Turkey, Bulgaria and Romania. Summarized financial information concerning our geographic segments is shown in the following table:


	Corporate			Bulgaria			Romania			Turkey			Total
	(in thousands)
For the three months ended September 30, 2011
Net revenues	$	18		$	109		$	—		$	32,400		$	32,527
Inter-segment revenues		—			—			—			(489	)		(489	)

Total revenues		18			109			—			31,911			32,038
Income (loss) from continuing operations	$	(4,625	)	$	112		$	(346	)	$	8,516		$	3,657
For the three months ended September 30, 2010
Total revenues	$	50		$	—		$	—		$	18,646		$	18,696
Income (loss) from continuing operations	$	(5,356	)	$	—		$	(257	)	$	1,149		$	(4,464	)
For the nine months ended September 30, 2011
Net revenues	$	110		$	364		$	—		$	93,872		$	94,346
Inter-segment revenues		—			—			—			(1,630	)		(1,630	)

Total revenues		110			364			—			92,242			92,716
Income (loss) from continuing operations	$	(18,459	)	$	(1,199	)	$	(959	)	$	10,571		$	(10,046	)
For the nine months ended September 30, 2010
Total revenues	$	151		$	—		$	—		$	45,717		$	45,868
Income (loss) from continuing operations	$	(13,163	)	$	—		$	(6,218	)	$	5,109		$	(14,272	)
Segment assets
September 30, 2011	$	5,352		$	35,224		$	1,372		$	340,652		$	382,600	*
December 31, 2010	$	44,038		$	—		$	3,465		$	342,444		$	389,947	*
Goodwill
September 30, 2011	$	—		$	—		$	—		$	8,715		$	8,715
December 31, 2010	$	—		$	—		$	—		$	10,341		$	10,341

Excludes assets from our discontinued Moroccan operations and oilfield services business of $129.4 million and $41.2 million at September 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 September 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 September 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 New Turkish Lira. We have not used foreign currency forward contracts to manage exchange rate fluctuations. The New Turkish Lira (“TYL”) devalued during 2011, causing fluctuations in our monetary assets and liabilities. The conversion rate to the U.S. dollar was approximately 1.85 TYL to $1.00 at September 30, 2011, compared to 1.56 TYL to $1.00 at December 31, 2010.

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 September 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 AŞ. (“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.

Fair value measurements

The following table summarizes the valuation of our financial assets and liabilities as of September 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:
Related party floating rate debt	$	—	$	(73,000	)	$	—	$	(73,000	)
Senior secured credit facility		—		(78,000	)		—		(78,000	)
TBNG credit agreements		—		(8,130	)		—		(8,130	)
Oil derivative contracts		—		(2,280	)		—		(2,280	)
Contingent consideration on acquisition		—		(5,250	)		—		(5,250	)

Total	$	—	$	(166,660	)	$	—	$	(166,660	)

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	)
Related party 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 September 30, 2011 and December 31, 2010:


	September 30, 2011		December 31, 2010
	(in thousands)
Related party accounts receivable:
Riata Management service agreement	$	—	$	4
Maritas services agreement		924		3,700
Viking Oilfield Services services agreement		414		79

Total related party accounts receivable	$	1,338	$	3,783

Related party accounts payable:
Riata Management service agreement	$	385	$	863
Viking Drilling services agreement		99		21
Maritas services agreement		—		85
Viking Oilfield Services services agreement		399		—

Total related party accounts payable	$	883	$	969

Other transactions

In July 2008, Longfellow Energy, LP 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.

15.

Subsequent events

On November 7, 2011, we entered into a second amendment to the Dalea credit agreement to extend the maturity date to the earlier of (i) March 31, 2012 or (ii) the sale of Viking International and Viking Geophysical. There were no other changes to the existing terms and conditions of the Dalea credit agreement.

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 an international oil and gas company engaged in acquisition, exploration, development and production. We hold interests in developed and undeveloped oil and gas properties in Turkey, Bulgaria and Romania. As of November 1, 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 third quarter of 2011 include:

•

During the quarter ended September 30, 2011, we derived approximately 75% of our revenues from the production of oil and approximately 25.0% of our revenues from the production of natural gas.

•

Total oil and natural gas sales increased 72.5% to $31.6 million for the quarter ended September 30, 2011 from $18.3 million realized in the same period in 2010. The increase was the result of an increase in production volumes and higher average prices.

•

Production increased to approximately 222 net thousand barrels (Mbbls) of oil and approximately 1,426 net million cubic feet (Mmcf) of natural gas for the quarter ended September 30, 2011, compared to approximately 178 net Mbbls of oil and 515 net Mmcf of natural gas for the same period in 2010.

•

For the quarter ended September 30, 2011, we produced an average of approximately 2,413 net barrels (Bbls) of oil per day and approximately 15.5 net Mmcf of natural gas per day. On September 30, 2011, we produced approximately 2,420 net Bbls of oil and 16.8 net Mmcf of natural gas.

•

For the quarter ended September 30, 2011, we incurred $24.1 million in capital expenditures compared to capital expenditures of $114.2 million for the same period in 2010. The decrease in capital expenditures was primarily due to significant purchases of oilfield services equipment and the acquisition of Amity Oil International Pty. Ltd. (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Insaat Sanayi ve Ticaret A.S. (“Petrogas”) in the 2010 period.

•

As of September 30, 2011, our short-term borrowings from continuing operations decreased to $81.1 million, compared to short-term borrowings of $106.7 million as of December 31, 2010.

Recent Developments

Divestiture of Oilfield Services Business. On September 30, 2011, we engaged a financial advisor to assist with the sale, transfer or other disposition of our oilfield services business. We intend to complete the bid process for the sale of this business in the fourth quarter of 2011 and expect to consummate the sale by the end of the first quarter of 2012. See “— Divestiture of Oilfield Services Business”.

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 previously served as our consultant from February 2011 until May 2011 and as our corporate controller from May 2011 until August 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 July 2006 to December 2010. From July 1995 until July 2006, he held a variety of positions at Intel Corporation, including strategic controller at the Chipset Group, operations controller at the Americas Sales and Marketing Organization Division, finance manager at the Intel Online Services, Inc. Division and senior financial analyst at the Chipset Group. Prior to 1995, Mr. Saqueton was a senior associate at Price Waterhouse, LP. Mr. Saqueton holds a Masters of Business Administration degree from the University of California, Davis.

Exit from Morocco Operations. On June 27, 2011, we decided to discontinue our Moroccan operations. We intend to sell our existing Moroccan interests and operations and transfer our oilfield services equipment from Morocco to Turkey. See “— Divestiture of Morocco Operations.”

Third Quarter 2011 Operational Update

During the third quarter of 2011, we continued to develop our Selmo and Arpatepe oil fields in southeastern Turkey and our Thrace Basin gas fields in northwestern Turkey, including the gas fields acquired in the acquisition of Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”). In addition, we continued to expand our inventory of exploration opportunities with new prospects identified on recently completed 3D seismic surveys. We achieved positive results on recent fracture stimulation (“frac”) jobs in the Thrace Basin and made an oil discovery in the Goksu-1 well at Molla (License 4174) in southeastern Turkey.

Production. For the quarter ended September 30, 2011, we produced an average of approximately 2,413 net Bbls of oil per day and approximately 15.5 net Mmcf of natural gas per day. The increase in gas production from the second quarter of 2011 was primarily due to the acquisition of TBNG in June 2011 and the initiation of gas sales from Edirne License 4037 at a rate of approximately 3.3 net Mmcf per day following the award of a wholesale natural gas license to Petrogas in July 2011. On September 30, 2011, we produced approximately 2,420 net Bbls of oil and 16.8 net Mmcf of natural gas. We expect our year-end 2011 production exit rate to increase to between 7,000 and 7,500 barrels of oil equivalent per day (“Boepd”) from the September 30, 2011 rate of approximately 5,200 Boepd. See “— Note Regarding Boe.” We anticipate increasing fourth quarter 2011 production through the expansion of our drilling inventory, planned completions and extensions of pipelines to bring shut-in natural gas production to market, the application of gelled acidizing and fracture stimulation in the Thrace Basin and at Selmo and the expansion of directional drilling at Selmo.

Turkey-Thrace Basin. Following the acquisition of TBNG in June 2011, we accelerated plans for exploration and development of TBNG’s acreage. Our immediate emphasis was on identifying low-cost, high-yield conventional potential in existing wellbores. In the third quarter of 2011, we completed 22 recompletions of existing wellbores on our TBNG acreage, adding production of approximately 3.5 Mmcf of natural gas per day. This program has been the primary contributor in offsetting normal field decline rates.

We have recently had encouraging results unlocking unconventional natural gas sand opportunities on our TBNG acreage in the Thrace Basin. We fracture stimulated the BTD-2 well, an existing low-rate producer, and achieved initial flow rates of 2.8 Mmcf per day following the fracture stimulation. Additionally, the Kayi-15 well, which was previously a non-producing well, is currently producing at approximately 550 Mcf per day after fracture stimulation. Our existing inventory of 44 re-entry wellbore frac candidates have been prioritized based upon these two successes and are scheduled to be completed following a round of fracture stimulations that are currently underway at the Selmo oil field. These successes will ultimately generate an inventory of new wells, expanding the unconventional resources indentified through these wellbore re-entries.

In July 2011, we began selling natural gas from our Edirne License 4037 at a rate of approximately 3.3 net Mmcf per day following the award of a wholesale natural gas license to one of our subsidiaries.

Southeastern Turkey.

•

Selmo. We completed five wells and began drilling four additional wells during the third quarter of 2011. We completed the first multi-well drilling pad and drilled three development wells from the pad. These wells encountered tight pay, and we expect to frac these wells upon the arrival of equipment from the Thrace Basin. The use of multi-well pads and directionally drilled holes has been successful in expediting our drilling schedule and reducing location construction at Selmo. It has also resulted in reduced landowner issues, which previously limited access to some of our drilling locations.

•

Arpatepe. We and the operator of the license, Aladdin Middle East, Ltd. (“AME”), each mobilized one drilling rig to initiate operations for the drilling of a development well and an exploration well. We successfully drilled the Arpatepe-4 development well, which we are currently completing. The Kocahuyuk-1 exploration well, which tested a down dip fault block, encountered the target Bedinan sands formation and was plugged and abandoned as non-commercial. Despite this dry hole, we are optimistic regarding other untested fault blocks on the license and plan to maintain two drilling rigs, one of which is operated by AME, at Arpatepe through the end of 2011.

•

Molla. We completed the Goksu-1 well as a new field discovery in the Mardin group at approximately 5,500 feet (1,650 meters), with an initial flow rate of approximately 340 Bbls of oil per day. Existing 2D seismic data indicates the Goksu structure may be 2,500 acres (10 square kilometers) in extent. This new discovery demonstrates Mardin potential extending south through our Molla license. In addition to the Mardin test, the Goksu-1 well also flared gas from the Dadas shale, consistent with core data which was rich in hydrocarbons.

Bulgaria. In September 2011, we entered into an agreement with LNG Energy, Ltd. (“LNG”) pursuant to which LNG agreed to fund $7.5 million to drill an exploration well to 10,500 feet (approximately 3,200 meters) on the southern portion of the A-Lovech exploration permit in Bulgaria. The objective of the well is to core and test the unconventional Etropole formation. If the well is successful and we obtain a production concession covering the Etropole formation on the southern portion of the A-Lovech exploration permit, LNG would fund up to an additional $12.5 million, of which $7.5 million would be used to drill a second well or for other exploration activities on the Etropole production concession. In return, LNG would earn a 50% working interest in the Etropole production concession. We commenced drilling this well, the Peshtene-R11, on September 27, 2011.

In addition, we have built the location for the Deventci-R2 well on the A-Lovech exploration permit. We commenced drilling the Deventci-R2 well on October 27, 2011 to appraise the Orzirovo formation on the northern portion of the permit.

Romania. We received a two-year extension on the Sud Craiova license. As a condition to the extension, we and the operator of the license, Sterling Resources, Ltd. (“Sterling”), 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. We intend to sell our existing Moroccan interests and operations and transfer our oilfield services equipment from Morocco to Turkey.

Planned 2011 Operations

We continue to actively explore and develop our existing oil and gas natural properties in Turkey, Bulgaria and Romania. Evaluating our large acreage positions efficiently by acquiring seismic data will continue to be a high priority. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. For the fourth quarter 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 TBNG, Amity and Petrogas acreage, as well as through the development of our Selmo and Arpatepe oil fields. We expect 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 increase production.

•

Unlocking Unconventional Potential in the Thrace Basin. We currently have an inventory of 44 re-entry well fracture stimulation candidates on our TBNG licenses, not including six wells that have already been fracced. We plan to frac an additional six wells in the fourth quarter of 2011, including our first fracture stimulation of a deep, unconventional natural gas target. 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. We recently completed the acquisition of approximately 870 square kilometers of 3D seismic data on various licenses in the Thrace Basin, which we expect to interpret during the fourth quarter of 2011. We anticipate that these surveys will significantly add to our conventional shallow acreage opportunities and will define deeper, unconventional natural gas opportunities on large structures that have already been identified. In southeastern Turkey, we have identified seven shallow natural gas prospects that are structurally similar to our Thrace Basin gas plays. We interpreted them using recently acquired 2D seismic data on the Adana/Yuksekkoy license. We also identified an additional five prospects from a recent seismic survey on the Idil (License 4642) license near the Syrian border.

•

Securing Partners to Reduce Exploration Risk. We have engaged FirstEnergy Capital LLP (“FirstEnergy”) as our exclusive financial advisor for the sale of our interests and operations in Morocco and to seek strategic partners for the development of our exploration acreage in Bulgaria, Romania and central Turkey. In October 2011, we entered into a binding term sheet with a major oil company to farmout a 60% working interest in our Sivas Basin licenses covering approximately 1.6 million acres in central Turkey. The agreement is subject to finalization of definitive agreements and approval from the government of Turkey regarding the planned exploration program, including the extension of the deadlines for our Sivas Basin drilling obligations to December 2013. Through farmouts, we expect to accelerate development and mitigate exploration risk.

For the fourth quarter of 2011, we expect our capital expenditures for our exploration and production activities to be approximately $18.0 million. Approximately 56% 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. The remaining 44% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Selmo, Arpatepe, Gaziantep and Molla. Our projected 2011 capital budget is subject to change, and 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. We currently plan to execute the following drilling and exploration activities in the fourth quarter of 2011:

Turkey-Thrace Basin. We plan to drill five wells and fracture stimulate six additional wells in the fourth quarter of 2011. In addition, we plan to recomplete 38 existing wellbores on TBNG acreage. We believe these recompletions, together with the new 3D seismic-based exploration inventory, should provide a steady growth in production through the end of 2011. We expect to commence the re-entry fracture stimulations beginning in November 2011. These projects will commence when our frac equipment returns to the Thrace Basin from Selmo.

On October 1, 2011, we commenced drilling a side-track of the existing Pancarkoy-1 well on License 4861, which previously tested gas in the Mezardere sands formation at a depth of approximately 10,170 feet (3,080 meters) and represents our first test of the deep unconventional natural gas potential in the Thrace Basin. We expect to fracture stimulate and test this well by the end of November 2011. If successful, this re-entry will support offset locations to fully develop the structure in 2012 and will confirm the the existence of deeper, unconventional natural gas opportunities that are found on a number of similar structures in the Thrace Basin. On License 3734, the Suleymaniye-1 well is scheduled to commence drilling in December 2011 to test a large structure with downdip gas tests. We anticipate the target sand formations will require fracture stimulation for commercial development. We plan to drill additional shallow and deep targets on License 4861 in the fourth quarter of 2011, including a test of the Avluobasi structure, which is already producing on an adjacent license that is operated by Turkey Petrolleri Anonim Ortakligi (“TPAO”), the national oil company of Turkey.

We expect to complete a 20 kilometer gas pipeline connecting the Alpullu gas field to the TBNG gathering system at Hayrabolu by the end of November 2011. In addition to adding sales capacity at the Alpullu field, this pipeline will ensure sales capacity in the event that our prospects on License 4861 are successful.

Southeastern Turkey.

•

Selmo. We expect to drill five wells and fracture stimulate five additional wells in the fourth quarter of 2011. We have revised our previous estimates as a result of diverting a drilling rig to Arpatepe, the addition of other priority targets at Gaziantep, and to drill a well to offset the Goksu-1 discovery at Molla. We will concentrate drilling at Selmo in locations off two existing drilling pads on the western side of the field where we have achieved better results. We also plan to frac five existing wells in which we have encountered tight dolomites formations. These wells have not been responsive to gelled acid treatments, which have otherwise generally been successful in the field.

In addition, we anticipate completing two projects at Selmo during the fourth quarter of 2011 that will reduce our current operating expenses. The largest operating expense at Selmo is the use of diesel fuel to generate power, primarily for the artificial lift facilities that are required to produce the oil. We anticipate converting these facilities to electric grid power, eliminating the need for diesel fuel and resulting in a substantial cost reduction. Additionally, we expect to complete the replacement of steel gathering lines with polypipe, eliminating leaks that are normally associated with steel gathering systems for additional cost reductions.

•

Arpatepe. Based upon tests in the Goksu-1 well immediately to the north of Arpatepe, we believe that Arpatepe now includes Dadas and Mardin potential, in addition to the existing Bedinan objectives. We expect that future exploration

wells on this license will target all three objectives where possible. We are currently drilling the Arpatepe-6 exploration well, and we expect that AME will commence drilling the Arpatepe-5 development well in November 2011. We plan to maintain two drilling rigs at Arpatepe, one of which is operated by AME, through the end of 2011.

•

Molla. In addition to ongoing facility construction for the Goksu-1 discovery well, we plan to drill a development well that will target the Mardin structure. We anticipate that regional mapping of the Hazro, Mardin and Dadas structures, along with a 3D seismic survey planned for early 2012, will identify other prospects at Molla and Arpatepe.

•

Gaziantep. We plan to commence drilling the Siratas-1 exploration well in November 2011. This well will target a large four-way structure defined on seismic with two downdip producing fields. We believe that a discovery would support up to 10 development locations.

•

Bakuk. We anticipate natural gas sales from the Bakuk-101 well to grow to approximately 1.0 net Mmcf per day by December 2011 after TPAO completes a tie-in from our existing pipeline to a nearby power plant. We expect to resume exploration drilling on this license in 2012 following the delays experienced in 2011 due to unrest in southeastern Turkey along the Syrian border.

Bulgaria. We are in the process of obtaining an environmental impact assessment as part of our application for the Koynare production concession over the northern approximately 160,000 acres (647 square kilometers) of the A-Lovech exploration permit. This application is based upon the conventional discovery in the Jurassic-aged Orzirovo formation in the Deventci-R1 well. We expect to complete and stimulate the Peshtene-R11 well in December 2011. If this well is successful, we expect the results to support an application for a separate production concession over the southern portion of the A-Lovech exploration permit for the Etropole shale formation. We commenced drilling the Deventci-R2 well on October 27, 2011 to appraise the Orzirovo formation on the northern portion of the A-Lovech exploration permit. We also are evaluating whether we will fracture stimulate the existing tight sand formations in the Deventci-R1 well in the first quarter of 2012.

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.

Morocco. We intend to sell our existing Moroccan interests and operations and transfer our oilfield services equipment from Morocco to Turkey. We anticipate a full reduction in our staff in Morocco by year-end 2011.

Divestiture of Oilfield Services Business

We provide drilling and other oilfield services through our wholly owned subsidiary Viking International Limited (“Viking International”) and seismic acquisition services through our wholly owned subsidiary Viking Geophysical Services, Ltd. (“Viking Geophysical”). On September 30, 2011, we engaged a financial advisor to assist with the sale, transfer or other disposition of our oilfield services business. We intend to complete the bid process for the sale of this business in the fourth quarter of 2011 and expect to consummate the sale by the end of the first quarter of 2012. We expect to use the net proceeds from the sale of this business to repay outstanding debt and to fund capital expenditures and working capital.

In connection with the sale, we intend to enter into a master services agreement with Viking International and Viking Geophysical that would provide us with drilling, seismic and oilfield services at competitive retail pricing and maintain the availability of these services in furtherance of our long-term exploration and development plans. After the consummation of the sale of these operations, we will no longer own drilling rigs and oilfield services equipment, which will increase our costs and expenses, but will reduce our depreciation and amortization expenses. We will also be subject to greater risks related to the availability and cost of drilling rigs and third party services. There is no assurance that we will complete the sale of our oilfield services business as contemplated or at all. Under applicable accounting rules, we have presented our oilfield services segment as discontinued operations for all periods presented, and they are not included in results from continuing operations under generally accepted accounting principles in the United States (“U.S. GAAP”).

Divestiture of Morocco Operations

On June 27, 2011, we decided to discontinue our Moroccan operations. We intend to sell our existing Moroccan interests and operations and transfer our oilfield services equipment from Morocco to Turkey. We have engaged a financial advisor for the sale of our Moroccan interests and operations and expect to use the net proceeds from the sale for general corporate purposes. There is no assurance that we will complete the sale of our Moroccan interests and operations as contemplated or at all. Under applicable accounting rules, we have presented the Moroccan segment operating results as discontinued operations for all periods presented, and they are not included in results from continuing operations under U.S. GAAP.

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 U.S. GAAP. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in 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

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 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.

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


	Three Months Ended September 30,				Change
	2011		2010		2011-2010
	(in thousands of U.S. dollars, except per unit prices and production volumes)
			(as adjusted)
Production:
Oil (Mbbl)		222		178		44
Natural gas (Mmcf)		1,426		515		911
Total production (Mboe)		460		264		196
Average prices:
Oil (per Bbl)	$	104.43	$	74.17	$	30.26
Natural gas (per Mcf)	$	6.53	$	7.58	$	(1.05	)
Oil equivalent (per Boe)	$	68.74	$	69.42	$	(0.68	)


	Three Months Ended September 30,						Change
	2011			2010			2011-2010
	(in thousands of U.S. dollars, except per unit prices and production volumes)
				(as adjusted)
Revenues:
Oil and natural gas sales		31,621			18,327			13,294
Other		417			369			48

Total revenues		32,038			18,696			13,342
Costs and expenses:
Production		3,269			5,347			(2,078	)
Exploration, abandonment and impairment		3,851			—			3,851
Seismic and other exploration		2,818			3,735			(917	)
General and administrative		8,483			6,016			2,467
Depreciation, depletion and amortization		12,205			3,363			8,842
Interest and other expense		3,330			2,741			589
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts		(1,304	)		—			(1,304	)
Non-cash change in fair value on commodity derivative contracts		7,764			(3,032	)		10,796

Total gain (loss) on commodity derivative contracts		6,460			(3,032	)		9,492

Oil and Natural Gas Sales. Total oil and natural gas revenues increased $13.3 million to $31.6 million for the three months ended September 30, 2011 from $18.3 million realized in the same period in 2010. Of this increase, $13.6 million was due to an increase in our total production volumes of 196 Mboe to 460 Mboe for the three months ended September 30, 2011 compared 264 Mboe to the same period in 2010. Production volumes increased primarily due to the acquisitions of Amity and Petrogas in August 2010, Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”) in February 2011 and TBNG in June 2011, which accounted for approximately 138 Mboe of the increase. A decrease in our average sales price offset the increase by approximately $0.3 million. For the three months ended September 30, 2011, our average price received was $68.74 per Boe, compared to $69.42 per Boe for the same period in 2010.

Production. Production expenses for the three months ended September 30, 2011 decreased to $3.3 million from $5.3 million for the same period in 2010. The decrease was primarily attributable to an increase in the utilization of our oilfield services business to provide these services.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended September 30, 2011 increased approximately $3.9 million, to $3.9 million. We did not record any exploration, abandonment and impairment costs during the same period in 2010. The increase was due to dry hole expense in Turkey.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $2.8 million for the three months ended September 30, 2011 compared to $3.7 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.

General and Administrative. General and administrative expense was $8.5 million for the three months ended September 30, 2011 compared to $6.0 million for the same period in 2010. The increase was due to the overall expansion of our business in 2011. Additionally, general and administrative expense increased due to an increase in personnel from our recent acquisitions, as well as in our accounting function. The accounting personnel were hired to help remediate our material weaknesses in internal control over financial reporting.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased approximately $8.8 million to $12.2 million for the three months ended September 30, 2011 compared to $3.4 million in the same period of 2010. The increase was primarily due to increased production, as well as an increase in our depreciable asset base, both of which were primarily the result of our recent acquisitions.

Interest and Other Expense. Interest and other expense increased to $3.3 million for the three months ended September 30, 2011, compared to $2.7 million for the same period in 2010. The increase was primarily due to an increase in our outstanding debt. At September 30, 2011, our total outstanding debt was approximately $165.7 million (of which $6.6 million was held for sale), compared to $128.4 million at September 30, 2010.

Gain (Loss) on Commodity Derivative Contracts. During the three months ended September 30, 2011, we recorded a gain on commodity derivative contracts of approximately $6.5 million compared to a loss of $3.0 million for the same period in 2010. We recorded a $7.8 million unrealized gain and a $1.3 million realized loss on our derivative contracts for the three months ended September 30, 2011, compared to a $3.0 million unrealized loss for the three months ended September 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 Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“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 three months ended September 30, 2011 changed to a loss of $44.7 million from a gain of $22.1 million for the same period in 2010 due to the devaluation of the New Turkish Lira (“TYL”) compared to the U.S. dollar in 2011. The conversion rate of the TYL to the U.S. dollar was approximately 1.85 TYL to $1.00 at September 30, 2011, compared to 1.46 TYL to $1.00 at September 30, 2010.

Discontinued Operations. In June 2011, we decided to discontinue our Moroccan operations and transfer our oilfield services equipment from Morocco to Turkey. All revenues and expenses associated with the Moroccan operations for the three and nine months ended September 30, 2011 and 2010 have been included in discontinued operations.

In September 2011, we engaged a financial advisor to assist us in the sale, transfer or other disposition of our oilfield services business. We anticipate completing the bid process for the sale of this business in the fourth quarter of 2011 and expect to consummate the sale by the end of the first quarter of 2012. Upon consummation of a sale, we will no longer have an oilfield services segment. As such, we classified our oilfield services segment as discontinued operations at September 30, 2011. All revenues and expenses associated with our oilfield services segment for the three and nine months ended September 30, 2011 and 2010 have been included in discontinued operations.

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


	Three Months Ended September 30,
	2011			2010
	(in thousands)
Revenues:
Oil and natural gas sales	$	27		$	—
Oilfield services		12,947			5,532

Total revenues		12,974			5,532
Costs and expenses:
Production		300			—
Exploration, abandonment and impairment		338			3,415
Seismic and other exploration		—			115
Oilfield services costs		9,294			2,484
General and administrative		2,797			537
Depreciation, depletion and amortization		2,886			3,786
Accretion of asset retirement obligations		—			—

Total costs and expenses		15,615			10,337
Operating loss		(2,641	)		(4,805	)

Other (expense) income:
Interest and other expense		(160	)		(744	)
Interest and other income		31			10
Foreign exchange loss		(162	)		(879	)

Total other expense		(291	)		(1,613	)


Loss before income taxes from discontinued operations		(2,932	)		(6,418	)
Current income tax expense		(1,173	)		(1,006	)
Deferred income tax benefit		120			114

Net loss from discontinued operations	$	(3,985	)	$	(7,310	)

Results of Operations—Nine Months Ended September 30, 2011 Compared to Nine Months Ended September 30, 2010


	Nine Months Ended September 30,					Change
	2011			2010		2011-2010
	(in thousands of U.S. dollars, except per unit prices and production volumes)
				(as adjusted)
Production:
Oil (Mbbl)		660			494		166
Natural gas (Mmcf)		3,099			871		2,228
Total production (Mboe)		1,176			639		537
Average prices:
Oil (per Bbl)	$	104.62		$	75.01	$	29.61
Natural gas (per Mcf)	$	6.85		$	7.47	$	(0.62	)
Oil equivalent (per Boe)	$	77.43		$	71.17	$	6.26
Revenues:
Oil and natural gas sales		91,052			45,480		45,572
Other		1,664			388		1,276

Total revenues		92,716			45,868		46,848
Costs and expenses:
Production		11,527			14,242		(2,715	)
Exploration, abandonment and impairment		15,525			7,459		8,066
Seismic and other exploration		6,816			9,304		(2,488	)
Revaluation of contingent consideration		1,250			—		1,250
General and administrative		26,887			17,744		9,143
Depreciation, depletion and amortization		25,312			7,083		18,229
Interest and other expense		10,487			3,571		6,916
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts		(3,916	)		—		(3,916	)
Non-cash change in fair value on commodity derivative contracts		1,219			605		614

Total gain (loss) on commodity derivative contracts		(2,697	)		605		(3,302	)

Oil and Natural Gas Sales. Total oil and natural gas sales increased $45.6 million to $91.1 million for the nine months ended September 30, 2011 from $45.5 million realized in the same period in 2010. Of this increase, $7.4 million was the result of an increase in the average prices received and $38.2 million was the result of an increase in our production volumes of 537 Mboe to 1,176 Mboe for the nine months ended September 30, 2011, compared to 639 Mboe for the same period in 2010. Our average price received for the nine months ended September 30, 2011 was $77.43 per Boe, compared to $71.17 per Boe for the nine months ended September 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, which accounted for approximately 367 Mboe of the increase. The remaining production volume increase was primarily attributable to increased production in the Selmo oil field and from an entire nine months worth of production from our Edirne licenses, which began began production in April 2010.

Production. Production expenses for the nine months ended September 30, 2011 decreased approximately $2.7 million to $11.5 million from $14.2 million for the same period in 2010. The decrease was primarily attributable to the increase in the utilization of our oilfield services business to provide these services.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the nine months ended September 30, 2011 increased to $15.5 million from $7.5 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 $6.8 million for the nine months ended September 30, 2011 compared to $9.3 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.

Revaluation of Contingent Consideration. During the nine months ended September 30, 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 acquisition of Direct Petroleum Morocco, Inc. (“Direct Morocco”), Anschutz Morocco Corporation (“Anschutz”) and Direct Bulgaria in February 2011. Therefore, we have increased our costs and expenses to record $1.3 million in the nine months ended September 30, 2011 to reflect our potential future costs.

General and Administrative. General and administrative expenses were $26.9 million for the nine months ended September 30, 2011 compared to $17.7 million for the same period in 2010. The increase was due to the overall expansion of our business in 2011, as well as 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.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $25.3 million for the nine months ended September 30, 2011 compared to $7.1 million in the same period of 2010. The increase was primarily due to increased production, as well as an increase in our depreciable asset base, both of which were primarily the result of our recent acquisitions.

Interest and Other Expense. Interest and other expense increased to $10.5 million for the nine months ended September 30, 2011 compared to $3.6 million for the same period in 2010. The increase was primarily due to the increase in our outstanding debt. At September 30, 2011, our total outstanding debt was approximately $165.7 million (of which $6.6 million was held for sale), compared to $128.4 million at September 30, 2010.

Gain (Loss) on Commodity Derivative Contracts. During the nine months ended September 30, 2011, we recorded a loss of $2.7 million compared to a gain of $0.6 million for the same period in 2010. We recorded a $1.2 million unrealized gain and a $3.9 million realized loss on our derivative contracts for the nine months ended September 30, 2011, compared to a $0.6 million unrealized gain for the nine months ended September 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 nine months ended September 30, 2011 changed to a loss of $54.9 million from a gain of $14.7 million for the same period in 2010 due to the devaluation of the TYL compared to the U.S. dollar in 2011.

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


	Nine Months Ended September 30,
	2011		2010
	(in thousands)
Revenues:
Oil and natural gas sales	$	214	$	—
Oilfield services		19,974		9,356

Total revenues		20,188		9,356


	Nine Months Ended September 30,
	2011			2010
	(in thousands)
Costs and expenses:
Production		1,554			—
Exploration, abandonment and impairment		12,025			13,755
Seismic and other exploration		6			200
Oilfield services costs		19,010			6,435
General and administrative		5,139			1,843
Depreciation, depletion and amortization		10,319			9,202
Accretion		1			—

Total costs and expenses		48,054			31,435
Operating loss		(27,866	)		(22,079	)

Other (expense) income:
Interest and other expense		(590	)		(1,094	)
Interest and other income		93			41
Foreign exchange loss		(946	)		(820	)

Total other expense		(1,443	)		(1,873	)

Loss before income taxes from discontinued operations		(29,309	)		(23,952	)
Current income tax expense		(2,490	)		(1,424	)
Deferred income tax benefit		547			100

Net loss from discontinued operations	$	(31,252	)	$	(25,276	)

Capital Expenditures

For the nine months ended September 30, 2011, we incurred $56.2 million in capital expenditures from continuing operations compared to capital expenditures of $141.8 million from continuing operations for the nine months ended September 30, 2010. The decrease in capital expenditures was primarily due to the 2010 period being capital intensive, as we made significant purchases of fracture stimulation equipment and acquired Amity and Petrogas.

Liquidity and Capital Resources

Our primary sources of liquidity for the third quarter of 2011 were cash and cash equivalents, cash flow from operations and borrowings under our various debt agreements. At September 30, 2011, we had cash and cash equivalents of $22.1 million, $81.1 million in short-term debt associated with our continuing operations, $6.6 million of short-term debt associated with our discontinued operations, $78.0 million in long-term debt associated with our continuing operations and, excluding assets held for sale of $129.4 million and total liabilities held for sale of $19.9 million associated with our discontinued operations, a working capital deficit of $39.0 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 nine months ended September 30, 2011 increased to $35.4 million compared to cash used in operating activities from continuing operations of $16.5 million for the nine months ended September 30, 2010, primarily as a result of an increase in revenues and better cash management.

At September 30, 2011, the outstanding principal amount of our debt was $165.7 million, of which $6.6 million was held for sale. Of our outstanding debt, $73.0 million under the credit agreement with Dalea Partners, LP (“Dalea”) is due upon the earlier of (i) March 31, 2012 or (ii) the sale of Viking International and Viking Geophysical. We forecast that we will need to extend the maturity date of the Dalea credit agreement, consummate the sale of assets or raise additional debt or equity financing 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 have engaged a financial advisor to assist with the sale, transfer or other disposition of our oilfield services business and are considering the issuance of common shares, public debt or private debt. However, there is no assurance that our forecasts will prove to be accurate or that our efforts to raise additional debt or equity financing or consummate the sale of assets will

prove to be successful. Should we be unable to consummate the sale of assets or raise additional financing, we will not have sufficient funds to continue operations beyond March 31, 2012. 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. 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 September 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 Credit Facility. DMLP, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Ltd. (“TAT”), Amity and Petrogas (collectively, the “Borrowers”) are parties to an amended and restated credit facility with Standard Bank and BNP Paribas. Each of the Borrowers are our wholly owned subsidiaries. The amended and restated credit facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) (collectively, the “Guarantors”).

The amount drawn under the amended and restated credit facility may not exceed the lesser of (i) $250.0 million, (ii) the borrowing base amount at such time, (iii) the aggregate commitments of all lenders at such time, and (iv) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment. At November 1, 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 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.

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 and is not available to be borrowed, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to Standard Bank or (b) 5.50% for all other letters of credit.

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

•

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

•

ratio of EBITDAX (less non-discretionary capital expenditures) to aggregate amounts payable under the amended and restated credit facility of not less than 1.50 to 1.00;

•

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

•

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

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

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

At November 1, 2011, the Borrowers had borrowed $78.0 million under the amended and restated credit facility, had availability of $3.4 million under the amended and restated credit facility and were in compliance with the covenants. For additional information concerning the ratios, financial and non-financial covenants, events of default and other material terms of our amended and restated credit facility, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in our Annual Report on Form 10-K for the year ended December 31, 2010.

Dalea Credit Agreement. We also have a credit agreement with Dalea. 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. On November 7, 2011, we entered into a second amendment to the credit agreement with Dalea to extend the maturity date to the earlier of (i) March 31, 2012 or (ii) the sale of Viking International and Viking Geophysical.

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) March 31, 2012, or (ii) the occurrence of an event of default and a demand for payment by Dalea. The Dalea credit agreement is subject to customary events of default, such as payment defaults, defaults in any terms, covenants or conditions of the agreement, the prohibition in trading in our common shares, suspension or delisting of our common shares from any stock exchange, the occurrence of a material adverse change and the occurrence of a change in control. 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 Dalea credit agreement is also subject to customary covenants, such as covenants that limit our ability to incur indebtedness or create any mortgage, charge, lien or encumbrance, declare or provide for any dividends, redeem or repurchase shares, make or permit the sale or disposition of any substantial or material part of our business, assets or undertakings and borrow or allow our subsidiaries to borrow money from any person.

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 November 1, 2011, we had borrowed $73.0 million under the Dalea credit agreement. No further borrowings are permitted under the Dalea credit agreement. For additional information concerning the covenants, events of default and other material terms of the Dalea Credit Agreement, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

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. On February 19, 2010, Viking International purchased the I-14 drilling rig and associated equipment from Viking Drilling and entered into an amended and restated note payable to Viking Drilling in the amount of $11.8 million, which was comprised of $5.9 million payable related to the I-14 drilling rig and $5.9 million payable related to the purchase of the I-13 drilling rig. Under the terms of the amended and restated note, interest 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 November 1, 2011, the outstanding balance under this note was $3.7 million.

Viking International Equipment Loan. In 2010, Viking International entered into a secured credit agreement with a Turkish bank to fund the purchase of vehicles. The credit agreement 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 November 1, 2011, Viking International had borrowed $2.9 million under the credit agreement.

TBNG Credit Agreement. TBNG is a party to an unsecured credit agreement with a Turkish bank. At November 1, 2011, there were outstanding borrowings of approximately 15.0 million TYL (approximately $8.6 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 agreement matures on March 13, 2012 and may be renewed for an additional period on the same terms.

Contractual Obligations

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


			Payments Due by Year
	Total		2011		2012		2013		2014		2015		Thereafter
	(in thousands)
Debt	$	165,752	$	1,534	$	84,867	$	843	$	508	$	—	$	78,000
Leases and other		12,709		924		3,294		1,798		1,115		1,083		4,495
Contracts		17,508		7,053		10,455		—		—		—		—
Permits		28,500		7,000		21,500		—		—		—		—

	$	224,469	$	16,511	$	120,116	$	2,641	$	1,623	$	1,083	$	82,495

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at September 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; the ability to consummate the sale of assets as contemplated or at all; the effect of the sale of assets to our costs and expenses; 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; the ability to consummate the sale of assets as contemplated or at all; the effect of the sale of assets to our costs and expenses; cash flows; uses of cash flows; collectability of receivables; availability of trade credit; expected operating costs; changes in any of the foregoing and other statements using forward-looking terminology are forward-looking statements.

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

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

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.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

During the third 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 September 30, 2011:


Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Asset (Liability)
									(in thousands)
Collar		October 1, 2011 — December 31, 2011		1,060	$	64.39	$	101.32	$	(451	)
Collar		January 1, 2012 — December 31, 2012		960	$	64.69	$	106.98		(2,078	)
Collar		January 1, 2013 — December 31, 2013		400	$	75.00	$	125.50		255
Collar		January 1, 2014 — December 31, 2014		380	$	75.00	$	124.25		360

									$	(1,914	)


			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 Asset (Liability)
											(in thousands)
Three-way collar contract		October 1, 2011 — December 31, 2011		640	$	79.38	$	114.38	$	137.16	$	(104	)
Three-way collar contract		January 1, 2012 — December 31, 2012		240	$	70.00	$	100.00	$	129.50	$	(447	)
Three-way collar contract		January 1, 2012 — March 31, 2012		350	$	85.00	$	118.88	$	138.13	$	73
Three-way collar contract		April 1, 2012 — June 30, 2012		350	$	85.00	$	116.25	$	137.38	$	112

											$	(366	)

Item 4.

Controls and Procedures

Acquisitions

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 6.8% of our consolidated total assets at September 30, 2011 and less than 1% of total revenues for the nine months ended September 30, 2011.

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 14.3% of our consolidated total assets at September 30, 2011 and approximately 6.6% of our total revenues for the nine months ended September 30, 2011.

Any material change to our internal control over financial reporting due to the acquisition of 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.

As of September 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 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 September 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

The following changes in our internal control over financial reporting occurred during the third quarter of 2011 and have affected, or are reasonably likely to materially affect, our internal control over financial reporting.

•

We conducted testing of our information technology general controls in the third quarter of 2011, which showed marked improvement from December 31, 2010.

•

We issued policies and procedures for account reconciliations and journal entry processing with enhanced controls and forms. We also performed training to ensure adequate knowledge of the process and requirements.

•

We addressed the material weaknesses in our anti-fraud program by enhancing our fraud alert line and placing awareness posters at every facility.

•

We hired a new in-country finance and accounting director in Istanbul that is responsible for overseeing all aspects of our accounting function in Turkey and implementing the controls that are necessary to remediate deficiencies in our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

During the third 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 third 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 Reports on Form 10-Q for the quarters ended June 30, 2011 and March 31, 2011, except for the following:

The sale of our oilfield services business could increase our costs and expenses and negatively impact our ability to conduct our business.

We rely upon our oilfield services business to provide services that are necessary to conduct our business. If the sale of the oilfield services business is successful, we will no longer own drilling rigs and oilfield services equipment, which will increase our costs and expenses. In addition, we will also be subject to greater risks related to the availability and cost of drilling rigs and third party oilfield services. Our reliance upon our oilfield services business as a service provider and our limited ability to control certain costs and expenses following the consummation of the sale could materially adversely affect our business, financial condition and results of operations.

We will require significant capital to continue our exploration and development activities beyond March 31, 2012.

We may not have sufficient funds to continue our operations beyond March 31, 2012, the maturity date of our credit agreement with Dalea, as amended. If we are unable to finance our operations or successfully consummate the sale of assets on acceptable terms or at all, our business, financial condition and results of operations may be materially and adversely affected.

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

•

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

•

success in finding and commercially producing reserves; and

•

prices of natural gas and oil.

Debt financing could lead to:

•

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

•

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

•

restrictions on our operations.

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

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

As of September 30, 2011, the outstanding principal amount of our debt was $165.7 million. Of this amount, $73.0 million is due upon the earlier of (i) March 31, 2012 or (ii) the sale of Viking International and Viking Geophysical under our credit agreement with Dalea. We must generate sufficient amounts of cash to service and repay our debt. Our ability to generate cash will be affected by general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control. Future borrowings may not be available to us under our amended and restated credit facility or from the capital markets in amounts sufficient to pay our obligations as they mature or to fund other liquidity needs. In addition, disruptions in the credit and financial markets can constrain our access to capital and increase its cost. The inability to service, repay or refinance our indebtedness could adversely affect our financial condition and results of operations.

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

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

Item 6.

Exhibits


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*		Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of August 4, 2011, by and between Amity Oil International Pty. Ltd., DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd. and TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, and Standard Bank Plc as administrative agent and as collateral agent.

10.2*		Amendment No. 2 to the Amended and Restated Credit Agreement, dated as of September 14, 2011, by and between Amity Oil International Pty. Ltd., DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd. and TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors and Standard Bank Plc as administrative agent and collateral agent.

10.3		Office Lease, dated August 23, 2011, by and between TransAtlantic Petroleum (USA) Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on August 25, 2011).



10.4		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.

101†		The following materials from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, formatted in XBRL (eXtensible Business Reporting Language), (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Loss, (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements.

*	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.

†

Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

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: November 9, 2011

INDEX TO EXHIBITS


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*		Amendment No. 1 to the Amended and Restated Credit Agreement, dated as of August 4, 2011, by and between Amity Oil International Pty. Ltd., 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, and Standard Bank Plc as administrative agent, and as collateral agent.

10.2*		Amendment No. 2 to the Amended and Restated Credit Agreement, dated as of September 14, 2011, by and between Amity Oil International Pty. Ltd., DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd. and TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors and Standard Bank Plc as administrative agent and collateral agent.

10.3		Office Lease, dated August 23, 2011, by and between TransAtlantic Petroleum (USA) Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on August 25, 2011).



10.4		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.

101†		The following materials from the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, formatted in XBRL (eXtensible Business Reporting Language), (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Loss, (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements.

*	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.

†