Edgar Filing: TRANSATLANTIC PETROLEUM LTD.

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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, 2012

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

For the transition period from to

Commission file number: 001-34574

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)


Bermuda		None
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

Akmerkez B Blok Kat 6 Nispetiye Caddesi 34330 Etiler, Istanbul, Turkey		None
(Address of Principal Executive Offices)		(Zip Code)

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

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

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

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

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 26, 2012, the registrant had 368,694,553 common shares outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

	Consolidated Balance Sheets as of September 30, 2012 (Unaudited) and December 31, 2011	1

	Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2012 and 2011 (Unaudited)	2

	Consolidated Statements of Equity for the Nine Months Ended September 30, 2012 (Unaudited)	3

	Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2012 and 2011 (Unaudited)	4

	Notes to Consolidated Financial Statements (Unaudited)	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	29

Item 4.	Controls and Procedures	30

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	31

Item 1A.	Risk Factors	31

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	31

Item 3.	Defaults Upon Senior Securities	31

Item 4.	Mine Safety Disclosures	31

Item 5.	Other Information	31

Item 6.	Exhibits	32

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

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


	September 30, 2012			December 31, 2011
	(Unaudited)			(See Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	26,169		$	15,116
Accounts receivable
Oil and natural gas sales, net		27,784			23,187
Joint interest and other		28,243			23,141
Related party		87			—
Prepaid and other current assets		6,689			8,338
Deferred income taxes		2,364			2,124
Assets held for sale		1,547			128,117

Total current assets		92,883			200,023

Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		215,958			174,222
Unproved		88,274			70,779
Equipment and other property		34,675			39,914

		338,907			284,915
Less accumulated depreciation, depletion and amortization		(78,431	)		(49,486	)

Property and equipment, net		260,476			235,429
Other long-term assets:
Other assets		3,135			4,673
Note receivable – related party		11,500			—
Goodwill		9,011			8,514

Total other assets		23,646			13,187

Total assets	$	377,005		$	448,639

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	14,774		$	25,855
Accounts payable — related party		20,542			323
Accrued liabilities		35,541			23,992
Loan payable		—			7,732
Loan payable — related party		—			73,000
Derivative liabilities		4,315			3,716
Asset retirement obligations		3,275			3,031
Liabilities held for sale — related party		—			3,677
Liabilities held for sale		9,472			23,136

Total current liabilities		87,919			164,462
Long-term liabilities:
Asset retirement obligations		10,973			10,503
Accrued liabilities		793			5,538
Deferred income taxes		19,216			15,508
Loan payable		32,766			78,000
Derivative liabilities		4,933			3,355

Total long-term liabilities		68,681			112,904

Total liabilities		156,600			277,366
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.01 par value, 1,000,000,000 shares authorized; 368,659,553 shares issued and outstanding as of September 30, 2012 and 365,790,492 shares issued and outstanding as of December 31, 2011		3,687			3,658
Additional paid-in capital		536,887			533,907
Accumulated other comprehensive loss		(32,586	)		(50,236	)
Accumulated deficit		(287,583	)		(316,056	)

Total shareholders’ equity		220,405			171,273

Total liabilities and shareholders’ equity	$	377,005		$	448,639

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,
	2012			2011			2012			2011
				(See Note 1)						(See Note 1)
Revenues:
Oil and natural gas sales	$	31,786		$	31,621		$	98,323		$	91,052
Other		1,167			417			2,093			1,586

Total revenues		32,953			32,038			100,416			92,638
Costs and expenses:
Production		4,542			3,329			12,470			12,036
Exploration, abandonment and impairment		2,104			3,944			11,783			15,787
Seismic and other exploration		1,725			3,174			2,401			7,799
Revaluation of contingent consideration		—			—			—			1,250
General and administrative		6,744			8,949			25,301			27,514
Depreciation, depletion and amortization		8,147			11,368			26,698			22,613
Accretion of asset retirement obligations		164			341			579			893

Total costs and expenses		23,426			31,105			79,232			87,892

Operating income		9,527			933			21,184			4,746
Other income (expense):
Interest and other expense		(1,086	)		(3,314	)		(6,363	)		(10,471	)
Interest and other income		1,019			466			1,501			938
Gain (loss) on commodity derivative contracts		(7,146	)		6,460			(5,277	)		(2,697	)
Foreign exchange (loss) gain		(133	)		(9,129	)		3,066			(9,206	)

Total other expense		(7,346	)		(5,517	)		(7,073	)		(21,436	)

Income (loss) from continuing operations before income taxes		2,181			(4,584	)		14,111			(16,690	)
Current income tax (expense) benefit		(1,440	)		970			(3,882	)		(2,692	)
Deferred income tax (expense) benefit		(272	)		(1,190	)		(2,660	)		773

Net income (loss) from continuing operations		469			(4,804	)		7,569			(18,609	)
Income (loss) from discontinued operations before income taxes		122			(428	)		(4,540	)		(28,897	)
Gain on disposal of discontinued operations		6,437			—			33,651			—
Income tax provision		(34	)		(1,180	)		(8,207	)		(1,698	)

Net income (loss) from discontinued operations		6,525			(1,608	)		20,904			(30,595	)
Net income (loss)	$	6,994		$	(6,412	)	$	28,473		$	(49,204	)
Other comprehensive income (loss):
Foreign currency translation adjustment		3,146			(38,271	)		17,650			(48,673	)

Comprehensive income (loss)	$	10,140		$	(44,683	)	$	46,123		$	(97,877	)

Net income (loss) per common share:
Basic net income (loss) per common share:
Continuing operations	$	0.00		$	(0.01	)	$	0.02		$	(0.05	)
Discontinued operations	$	0.02		$	0.00		$	0.06		$	(0.09	)
Weighted average common shares outstanding		367,960			365,472			366,981			352,682
Diluted net income (loss) per common share:
Continuing operations	$	0.00		$	(0.01	)	$	0.02		$	(0.05	)
Discontinued operations	$	0.02		$	0.00		$	0.06		$	(0.09	)
Weighted average common and common equivalent shares outstanding		370,020			365,472			368,869			352,682

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 Loss			Accumulated Deficit			Total Shareholders’ Equity
Balance at December 31, 2011 (See Note 1)		365,790	$	3,658	$	533,907		$	(50,236	)	$	(316,056	)	$	171,273
Exercise of stock options		735		7		635			—			—			642
Issuance of restricted stock units		2,135		22		(22	)		—			—			—
Tax withholding on restricted stock units		—		—		(147	)		—			—			(147	)
Share-based compensation		—		—		2,514			—			—			2,514
Foreign currency translation adjustments		—		—		—			17,650			—			17,650
Net income attributable to common shareholders		—		—		—			—			28,473			28,473

Balance at September 30, 2012		368,660	$	3,687	$	536,887		$	(32,586	)	$	(287,583	)	$	220,405

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,
	2012			2011
				(See Note 1)
Operating activities:
Net income (loss)	$	28,473		$	(49,204	)
Adjustment for net (income) loss from discontinued operations		(20,904	)		30,595

Net income (loss) from continuing operations		7,569			(18,609	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-based compensation		1,506			1,346
Foreign currency loss (gain)		1,997			8,657
Unrealized (gain) loss on commodity derivative contracts		2,177			(1,219	)
Amortization of loan financing costs		846			1,447
Deferred income tax expense (benefit)		2,660			(773	)
Amortization of warrants — related party		—			1,972
Exploration, abandonment and impairment		7,869			10,422
Depreciation, depletion and amortization		26,698			22,613
Accretion of asset retirement obligations		579			893
Loss on revaluation of contingent consideration		—			1,250
Changes in operating assets and liabilities, net of effect of acquisitions:
Accounts receivable		(24,928	)		(4,269	)
Prepaid expenses and other assets		4,684			(12,333	)
Accounts payable and accrued liabilities		18,998			21,294

Net cash provided by operating activities from continuing operations		50,655			32,691
Net cash used in operating activities from discontinued operations		(24,138	)		(3,300	)

Net cash provided by operating activities		26,517			29,391
Investing activities:
Acquisitions, net of cash		—			(747	)
Additions to oil and natural gas properties		(42,068	)		(47,780	)
Additions to equipment and other properties		(451	)		(7,636	)
Restricted cash		1,059			3,445

Net cash used in investing activities from continuing operations		(41,460	)		(52,718	)
Net cash provided by (used in) investing activities from discontinued operations		156,150			(2,554	)

Net cash provided by (used in) investing activities		114,690			(55,272	)
Financing activities:
Exercise of stock options and warrants		642			663
Tax withholding on restricted stock units		(147	)		—
Loan proceeds		16,976			31,696
Loan proceeds — related party		11,000			—
Loan repayment		(69,940	)		(13,752	)
Loan financing costs		(250	)		—
Loan repayment — related party		(84,000	)		—

Net cash (used in) provided by financing activities from continuing operations		(125,719	)		18,607
Net cash used in financing activities from discontinued operations		(5,049	)		(3,509	)

Net cash (used in) provided by financing activities		(130,768	)		15,098
Effect of exchange rate changes on cash		614			(1,761	)
Net increase (decrease) in cash and cash equivalents		11,053			(12,544	)
Cash and cash equivalents, beginning of year		15,116			34,676

Cash and cash equivalents, end of period	$	26,169		$	22,132

Supplemental disclosures:
Cash paid for interest	$	5,603		$	6,052

Cash paid for income taxes	$	3,513		$	4,404

Supplemental non-cash investing and financing activities:
Note receivable — related party from sale of oilfield services business	$	11,500		$	—
Issuance of common shares for acquisitions		—			66,037
Repayment of short-term credit facility from refinancing		—			30,000

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

TRANSATLANTIC PETROLEUM LTD.

Notes to Consolidated Financial Statements

1. General

Nature of operations

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

Basis of presentation

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

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

Reclassification

During the six months ended June 30, 2012, we reclassified certain balance sheet amounts previously reported on our consolidated balance sheet at December 31, 2011 to conform to current year presentation. Specifically, we reclassified $12.2 million of joint interest receivables out of accounts receivable, oil and natural gas to accounts receivable, joint interest.

Revision of prior period financial statements and out-of-period adjustments

During the three months ended June 30, 2012 and September 30, 2012, we identified and corrected errors that originated in prior periods. We assessed the materiality of the errors in accordance with the SEC guidance on considering the effects of prior period misstatements based on an analysis of quantitative and qualitative factors. Based on this analysis, we determined that the errors were immaterial to each of the prior reporting periods affected and, therefore, amendments of reports previously filed with the SEC were not required. However, we have concluded that correcting the errors in our 2012 financial statements would materially understate results for the year ending December 31, 2012. Accordingly, we have reflected the correction of these prior period errors in the periods in which they originated and revised our consolidated balance sheet and consolidated statement of equity for the year ended December 31, 2011, our consolidated statement of cash flows for the nine months ended September 30, 2011 and our consolidated statement of operations and comprehensive income (loss) for the three and nine months ended September 30, 2011 in this Quarterly Report on Form 10-Q. In addition, a reduction to retained earnings will be reflected as an adjustment to the beginning balance for the earliest year presented in the financial statements included in our Annual Report on Form 10-K for the year ending December 31, 2012.

These errors consisted mainly of accrued liabilities that should have been recorded in prior periods, errors in foreign currency gain/loss remeasurement, inappropriate recognition of receivable balances, and other minor corrections with immaterial impact to other miscellaneous accounts. We also reclassified a receivable balance which had been netted with a payable balance of approximately $5.2 million.

Additionally, we revised our gain on the sale of our oilfield services business during the three months ended September 30, 2012 by $5.1 million. This revision was primarily due to an intercompany balance that was not contemplated as part of the gain at June 30, 2012.

The reclassification made as of June 30, 2012, as discussed under the sub-heading “reclassification”, was reflected in the December 31, 2011 consolidated balance sheet filed with our June 30, 2012 Form 10-Q. The condensed version of that consolidated balance sheet is presented below under the column titled “As Reported”, prior to any immaterial corrections discussed above. The effect of the immaterial corrections on the consolidated balance sheet as of December 31, 2011 are as follows (in thousands):


	As Reported			Correction			As Revised
Accounts receivable	$	42,694		$	3,634		$	46,328
Other assets		403,078			(767	)		402,311

Total assets	$	445,772		$	2,867		$	448,639


Accrued liabilities, current	$	16,450		$	7,542		$	23,992
Other liabilities		253,118			256			253,374

Total liabilities		269,568			7,798			277,366

Accumulated other comprehensive loss		(50,615	)		379			(50,236	)
Other shareholders’ equity		226,819			(5,310	)		221,509

Total shareholders’ equity		176,204			(4,931	)		171,273

Total liabilities and shareholders’ equity	$	445,772		$	2,867		$	448,639

The effect of the corrections on the Company’s consolidated statements of operations and comprehensive loss for the three and nine months ended September 30, 2011 are as follows:


	As Reported			Correction			As Revised
For the three months ended September 30, 2011
Total revenues	$	32,038		$	—		$	32,038
Total costs and expenses		(30,967	)		(138	)		(31,105	)
Total other (expense) income		(5,571	)		54			(5,517	)

Loss from continuing operations before income taxes		(4,500	)		(84	)		(4,584	)
Net loss from continuing operations		(4,551	)		(253	)		(4,804	)
Net loss from discontinued operations		(926	)		(682	)		(1,608	)

Net loss		(5,477	)		(935	)		(6,412	)
Foreign currency translation adjustment		(38,653	)		382			(38,271	)

Comprehensive loss	$	(44,130	)	$	(553	)	$	(44,683	)


	As Reported			Correction			As Revised
For the nine months ended September 30, 2011
Total revenues	$	92,716		$	(78	)	$	92,638
Total costs and expenses		(88,210	)		318			(87,892	)
Total other (expense) income		(21,382	)		(54	)		(21,436	)

(Loss) income from continuing operations before income taxes		(16,876	)		186			(16,690	)
Net loss from continuing operations		(18,254	)		(355	)		(18,609	)
Net loss from discontinued operations		(28,193	)		(2,402	)		(30,595	)

Net loss		(46,447	)		(2,757	)		(49,204	)
Foreign currency translation adjustment		(48,880	)		207			(48,673	)

Comprehensive (loss) income	$	(95,327	)	$	(2,550	)	$	(97,877	)

2. Change to going concern assumption

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

On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”), to a joint venture owned by Dalea and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $168.5 million, consisting of approximately $157.0 million in cash and a $11.5 million promissory note from Dalea. We used a portion of the net proceeds from the sale to pay off our $73.0 million credit agreement with Dalea, our $11.0 million credit facility with Dalea, our $0.9 million promissory note with Viking Drilling, LLC (“Viking Drilling”), and our $1.8 million credit agreement with a Turkish bank. In addition, we used a portion of the net proceeds from the sale to pay down approximately $45.2 million in outstanding indebtedness under our amended and restated senior secured credit facility with Standard Bank Plc and BNP Paribas (Suisse) SA (the “Amended and Restated Credit Facility”).

As of September 30, 2012, we had no short-term debt and availability of $44.7 million under our Amended and Restated Credit Facility. In addition, at September 30, 2012, we had net working capital of $12.9 million, excluding assets and liabilities held for sale. As a result, management believes that the conditions that led to the substantial doubt about our ability to continue as a going concern at March 31, 2012 no longer existed at September 30, 2012.

3. Recent accounting policies

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

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

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

In December 2011, FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of ASU 2011-11 is required for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We are currently evaluating the effects of adopting ASU 2011-11.

In July 2012, FASB issued ASU 2012-02, Intangibles—Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-02”). The update provides an entity with the option first to assess qualitative factors in determining whether it is more likely than not that the indefinite-lived intangible asset is impaired. After assessing the qualitative factors, if an entity determines that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. If an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. Early adoption was permitted. We did not early adopt the provisions of this ASU. We do not expect the impact of adopting this ASU to be material to the Company’s financial position, results of operations or cash flows.

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

4. Pro forma results of operations

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


	For the Nine Months Ended September 30, 2011
	(in thousands, except per share data)
Total revenues	$	110,799
Loss from continuing operations before income taxes		(17,428	)
Loss from continuing operations		(19,199	)
Loss from discontinued operations		(32,297	)
Net loss		(51,496	)
Net loss per common share from continuing operations:
Basic	$	(0.05	)
Diluted	$	(0.05	)
Net loss per common share from discontinued operations:
Basic	$	(0.09	)
Diluted	$	(0.09	)

5. Discontinued operations

Discontinued operations in Morocco

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

Discontinued operations of oilfield services business

On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International and Viking Geophysical, to a joint venture owned by Dalea and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $168.5 million, consisting of approximately $157.0 million in cash and a $11.5 million promissory note from Dalea. The transaction was approved by a special committee of our board of directors after the receipt of a fairness opinion solely for the benefit of the special committee, which was subject to certain assumptions and limitations as provided in such opinion. The promissory note is payable five years from the date of issuance or earlier upon the occurrence of certain specified events, including an initial public offering by the joint venture. Upon the consummation of an initial public offering by the joint venture and the prior approval of Dalea, we can elect to convert the outstanding balance of the promissory note, including accrued interest, into the number of shares offered in the initial public offering equal to such outstanding balance divided by the per share purchase price paid by the public in the initial public offering. The promissory note bears interest at a rate of 3.0% per annum and is guaranteed by Mr. Mitchell. We used a portion of the net proceeds from the sale to pay off our $73.0 million credit agreement with Dalea, our $11.0 million credit facility with Dalea, our $0.9 million promissory note with Viking Drilling and our $1.8 million

credit agreement with a Turkish bank. In addition, we used a portion of the net proceeds from the sale of our oilfield services business to pay down approximately $45.2 million in outstanding indebtedness under our Amended and Restated Credit Facility. We have presented the oilfield services segment operating results as discontinued operations for the nine months ended September 30, 2012 and the three and nine months ended September 30, 2011.

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


	September 30, 2012		December 31, 2011
			(See Note 1)
	(in thousands)
Cash	$	21	$	1,185
Receivables, net		—		8,098
Property and equipment, net		—		114,523
Other assets		1,526		4,311

Total assets held for sale	$	1,547	$	128,117

Accrued expenses and other liabilities	$	9,472	$	23,136
Liabilities held for sale — related party		—		3,677

Total liabilities held for sale	$	9,472	$	26,813

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


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2012			2011			2012			2011
				(See Note 1)						(See Note 1)
	(in thousands)
Total revenues	$	—		$	12,975		$	20,956		$	20,110
Total costs and expenses		(223	)		(16,455	)		(25,074	)		(50,907	)
Total other income (expense)		345			3,052			(422	)		1,900

Income (loss) from discontinued operations before income taxes		122			(428	)		(4,540	)		(28,897	)
Gain on disposal of discontinued operations		6,437			—			33,651			—
Income tax provision		(34	)		(1,180	)		(8,207	)		(1,698	)

Net income (loss) from discontinued operations	$	6,525		$	(1,608	)	$	20,904		$	(30,595	)

6. Goodwill

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


	September 30, 2012		December 31, 2011
	(in thousands)
Goodwill at beginning of period	$	8,514	$	10,341
Foreign exchange change effect		497		(1,827	)

Goodwill at end of period	$	9,011	$	8,514

7. Property and equipment

Oil and natural gas properties

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


	September 30, 2012			December 31, 2011
				(See Note 1)
	(in thousands)
Oil and natural gas properties, proved:
Turkey	$	213,600		$	172,531
Bulgaria		2,358			1,691

Total oil and natural gas properties, proved		215,958			174,222
Oil and natural gas properties, unproved:
Turkey		88,274			70,779

Gross oil and natural gas properties		304,232			245,001
Accumulated depletion		(73,091	)		(45,327	)

Net oil and natural gas properties	$	231,141		$	199,674

At September 30, 2012 and December 31, 2011, we excluded $13.2 million and $7.1 million, respectively, from the depletion calculation for proved development wells currently in progress and for fields currently not in production.

At September 30, 2012, our oil and natural gas properties were comprised of $50.5 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $79.1 million relating to exploratory well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.

At December 31, 2011, our oil and natural gas properties were comprised of $61.8 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $60.0 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, 2012, we incurred approximately $22.3 million in exploratory drilling costs, of which $3.9 million was charged to earnings (included in exploration, abandonment and impairment expense), $2.7 million was reclassified from unproved to proved properties and $15.7 million remained capitalized at September 30, 2012. No exploratory well costs were reclassified to proved properties in the third quarter of 2011. Uncertainties affect the recoverability of costs of our oil and natural gas properties, as the recovery of the costs are dependent upon us maintaining licenses in good standing and achieving commercial production or sale.

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

As of September 30, 2012, we had $5.6 million of exploratory well costs capitalized for the Pancarkoy-1 well, which we began drilling in the fourth quarter of 2010. After the second fracture stimulation of the Pancarkoy-1 well, commercial natural gas production could not be sustained due to the high amount of water production. A third fracture stimulation of the Pancarkoy-1 well was performed in April 2012, but commercial production could not be sustained due to high water production. We expect to further test the up-hole interval in the fourth quarter of 2012. Further fracture stimulation of this well will depend on the outcome of the conventional test results. In June 2012, we wrote off a portion of the exploratory well costs related to this well, with only the sidetrack wellbore costs remaining capitalized. The following table summarizes the costs related to this well:


	Year Ended December 31,				Nine Months Ended September 30, 2012		Partial Write-Off			Total at September 30, 2012
	2010		2011		Nine Months Ended September 30, 2012		Partial Write-Off			Total at September 30, 2012
			(in thousands)
Pancarkoy-1 well initial re-entry and fracture stimulation (Ceylan and Mezardere formations)	$	798	$	4,925	$	1,983	$	(2,097	)	$	5,609

Total Pancarkoy-1 capitalized costs	$	798	$	4,925	$	1,983	$	(2,097	)	$	5,609

As of September 30, 2012, we had three exploratory wells that have costs capitalized for more than one year for which we have plans to complete in the fourth quarter of 2012 or the first quarter of 2013. The combined costs of the three wells are less than $1 million. We plan to test behind pipe in the Osmancik section on the Kilavzlu-1 well and plan to complete the Akcahalil-1 and Guney Karanfiltepe-1 wells due to the recent success in utilizing larger-sized fracs in the Tekirdag area.

Equipment and other property

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


	September 30, 2012			December 31, 2011
				(See Note 1)
	(in thousands)
Other equipment	$	2,135		$	6,351
Inventory		19,484			19,879
Gas gathering system and facilities		5,364			6,822
Vehicles		135			1,001
Office equipment and furniture		7,557			5,861

Gross equipment and other property		34,675			39,914
Accumulated depreciation		(5,340	)		(4,159	)

Net equipment and other property	$	29,335		$	35,755

We classify our materials and supply inventory, including steel tubing and casing, as long-term assets because such materials will ultimately be classified as long-term assets when the material is used in the drilling of a well.

At September 30, 2012, we excluded $0.4 million of other equipment and $19.5 million of inventory from depreciation, as the equipment and inventory had not been placed into service.

At December 31, 2011, we excluded $0.5 million of other equipment, $19.9 million of inventory and $1.8 million of gas gathering system and facilities from depreciation as the equipment, inventory and system had not been placed into service.

8. Commodity derivative instruments

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

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

For the three months ended September 30, 2012, we recorded a net loss on commodity derivative contracts of approximately $7.1 million, consisting of a $6.3 million unrealized loss related to changes in fair value and a $0.8 million realized loss for settled contracts. For the nine months ended September 30, 2012, we recorded a net loss on commodity derivative contracts of $5.3 million, consisting of a $2.2 million unrealized loss related to changes in fair value and a $3.1 million realized loss for settled contracts.

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.

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

Fair Value of Derivative Instruments as of September 30, 2012


Type	Period	Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Asset (Liability)
								(in thousands)
Collar	October 1, 2012—December 31, 2012		960	$	64.69	$	106.98	$	(553	)
Collar	January 1, 2013—December 31, 2013		400	$	75.00	$	125.50		(276	)
Collar	January 1, 2014—December 31, 2014		380	$	75.00	$	124.25		(142	)

								$	(971	)


		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	October 1, 2012—December 31, 2012		240	$	70.00	$	100.00	$	129.50	$	(231	)
Three-way collar contract	October 1, 2012—December 31, 2012		170	$	85.00	$	97.13	$	162.13		(262	)
Three-way collar contract	January 1, 2013—December 31, 2013		831	$	85.00	$	97.13	$	162.13		(3,801	)
Three-way collar contract	January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13		(1,982	)
Three-way collar contract	January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(2,001	)

										$	(8,277	)

Fair Value of Derivative Instruments as of December 31, 2011


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

								$	(2,633	)


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

										$	(4,438	)

9. Asset retirement obligations

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


	September 30, 2012			December 31, 2011
	(in thousands)
Asset retirement obligations at beginning of period	$	13,534		$	6,943
Acquisitions		—			6,480
Change in estimates		(1,241	)		512
Liabilities settled		(93	)		(195	)
Foreign exchange change effect		764			(2,524	)
Additions		705			1,176
Accretion expense		579			1,142

Asset retirement obligations at end of period		14,248			13,534
Less: current portion		3,275			3,031

Long-term portion	$	10,973		$	10,503

10. Third party loans payable

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


	September 30, 2012		December 31, 2011
	(in thousands)
Third-Party Floating Rate Debt
Amended and Restated Credit Facility	$	32,766	$	78,000
Third-Party Fixed Rate Debt
TBNG credit agreement		—		7,732
Viking International equipment loan		—		—	⁽¹⁾

Total third-party debt		32,766		85,732
Less: short-term third-party debt		—		7,732

Long-term third-party debt	$	32,766	$	78,000

(1)

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

Amended and restated senior secured credit facility

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

In November 2012, we entered into an amendment to the Amended and Restated Credit Facility. The amendment, among other things, reduces the commitment fee rate and extends the first commitment reduction date from September 30, 2012 to December 31, 2013. In addition, the amendment provides for a scheduled quarterly reduction of the commitment amount beginning on December 31, 2013, when the commitment amount will be reduced to $67.0 million, and ending on March 31, 2016, when the commitment amount will reach zero.

Availability under the Amended and Restated Credit Facility is subject to a borrowing base. The borrowing base is re-determined semi-annually on April 1st and October 1st of each year prior to September 30, 2012, and quarterly on January 1st, April 1st, July 1st and October 1st of each year after September 30, 2012. The borrowing base is currently $77.5 million. We have not finalized the September 30, 2012 borrowing base redetermination, but we expect that the redetermination will reduce the borrowing base to approximately $60.0 million. In June 2012, we used a portion of the net proceeds from the sale of our oilfield services business to pay down approximately $45.2 million in outstanding indebtedness under the Amended and Restated Credit Facility.

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

TBNG credit agreement

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

Viking International equipment loan

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

11. Related party loans payable

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


	September 30, 2012		December 31, 2011
	(in thousands)
Related Party Floating Rate Debt
Dalea credit agreement	$	—	$	73,000
Dalea credit facility		—		—
Viking Drilling note		—		—	⁽¹⁾

Total related party debt		—		73,000
Less: short-term related party debt		—		73,000

Long-term related party debt	$	—	$	—

(1)

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

Dalea credit agreement

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

Dalea credit facility

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

Viking Drilling note

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

12. Contingencies relating to exploration permits

our performance of the Tselfat exploration permit work program. Although we plan to pursue a settlement with the Moroccan government for a lesser amount, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during the second quarter of 2012 for this contractual obligation.

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

13. Shareholders’ equity

June 2011 share issuance

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

February 2011 share issuance

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

Restricted stock units

Share-based compensation expense of approximately $0.4 million and $1.5 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three and nine months ended September 30, 2012, respectively. We recorded share-based compensation expense of $0.4 million and $1.3 million for the three and nine months ended September 30, 2011, respectively.

As of September 30, 2012, we had approximately $2.1 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.7 years.

Stock option plan

Our Amended and Restated Stock Option Plan (2006) (the “Option Plan”) terminated on June 16, 2009. All outstanding awards issued under the Option Plan remained in full force and effect. All options that are presently outstanding under the Option Plan have a five-year term. We did not grant any stock options during the nine months ended September 30, 2012 or 2011. At September 30, 2012, all stock options have been fully amortized.

Earnings per share

We account for earnings per share in accordance with ASC Subtopic 260-10, Earnings Per Share (“ASC 260-10”). ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted. Basic earnings per common share for the three and nine months ended September 30, 2012 and 2011 equals net income divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding RSUs. Diluted earnings per common share for the three and nine months ended September 30, 2012 and 2011 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes stock options, RSUs and warrants, whether exercisable or not. The computation of diluted earnings per common share excluded 7,455,000 and 20,543,909 antidilutive common share equivalents from the three months ended September 30, 2012 and 2011, respectively, and 7,461,240 and 21,092,158 antidilutive common share equivalents from the nine months ended September 30, 2012 and 2011, respectively.

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


	Three Months Ended September 30,					Nine Months Ended September 30,
	2012		2011			2012		2011
(in thousands, except per share amounts)			(See Note 1)					(See Note 1)

Net income (loss) from continuing operations	$	469	$	(4,804	)	$	7,569	$	(18,609	)
Net income (loss) from discontinued operations	$	6,525	$	(1,608	)	$	20,904	$	(30,595	)
Basic net income (loss) per common share:
Shares:
Weighted average common shares outstanding		367,960		365,472			366,981		352,682

Basic net income (loss) per common share:
Continuing operations	$	0.00	$	(0.01	)	$	0.02	$	(0.05	)

Discontinued operations	$	0.02	$	0.00		$	0.06	$	(0.09	)

Diluted net income (loss) per common share:
Shares:
Weighted average common shares outstanding		367,960		365,472			366,981		352,682
Dilutive effect of:
Restricted stock units		1,941		—			1,745		—
Stock options		119		—			143		—

Weighted average common and common equivalent shares outstanding		370,020		365,472			368,869		352,682

Diluted net income (loss) per common share:
Continuing operations	$	0.00	$	(0.01	)	$	0.02	$	(0.05	)

Discontinued operations	$	0.02	$	0.00		$	0.06	$	(0.09	)

Additionally, we had a contingent liability at September 30, 2012 of approximately $10.0 million that is payable in our common shares. At the September 28, 2012 closing price of our common shares, this liability represented 9,523,810 common shares that could be potentially dilutive to future earnings per share calculations.

14. Segment information

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


	Corporate			Romania			Turkey		Bulgaria			Total
	(in thousands)
For the three months ended September 30, 2012
Total revenues	$	—		$	—		$	32,905	$	48		$	32,953
Income (loss) from continuing operations before income taxes		(2,534	)		(149	)		5,042		(178	)		2,181
Capital expenditures	$	—		$	—		$	24,498	$	—		$	24,498
For the three months ended September 30, 2011 (See Note 1)
Total revenues	$	18		$	—		$	31,911	$	109		$	32,038
Income (loss) from continuing operations before income taxes		(4,625	)		(346	)		275		112			(4,584	)
Capital expenditures	$	57		$	—		$	23,163	$	906		$	24,126
For the nine months ended September 30, 2012
Total revenues	$	—		$	—		$	100,219	$	197		$	100,416
Income (loss) from continuing operations before income taxes		(9,808	)		(804	)		27,301		(2,578	)		14,111
Capital expenditures	$	—		$	—		$	71,777	$	168		$	71,945
For the nine months ended September 30, 2011 (See Note 1)
Total revenues	$	110		$	—		$	92,164	$	364		$	92,638
Income (loss) from continuing operations before income taxes		(18,502	)		(959	)		3,970		(1,199	)		(16,690	)
Capital expenditures	$	100		$	—		$	53,009	$	3,054		$	56,163
Segment assets
September 30, 2012	$	17,193		$	97		$	355,689	$	2,479		$	375,458	⁽¹⁾
December 31, 2011 (See Note 1)	$	2,835		$	881		$	312,642	$	4,164		$	320,522	⁽¹⁾
Goodwill
September 30, 2012	$	—		$	—		$	9,011	$	—		$	9,011
December 31, 2011	$	—		$	—		$	8,514	$	—		$	8,514

(1) Excludes assets from our discontinued Moroccan operations and oilfield services business of $1.5 million and $128.1 million at September 30, 2012 and December 31, 2011, respectively.

15. Financial instruments

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

Interest rate risk

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

Foreign currency risk

We have underlying foreign currency exchange rate exposure. Our currency exposures relate to transactions denominated in the Canadian Dollar, Bulgarian Lev, European Union Euro, Romanian New Leu, Moroccan Dirham and New Turkish Lira. We are also subject to foreign currency exposures resulting from translating the functional currency of our foreign subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At September 30, 2012, we had 29.8 million New Turkish Lira (approximately $16.7 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the New Turkish Lira.

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, 2012 and December 31, 2011, we were a party to commodity derivative contracts.

Concentration of credit risk

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

Fair value measurements

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


	Fair Value Measurement Classification
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Liabilities:
Amended and Restated Credit Facility	$	—	$	(32,766	)	$	—	$	(32,766	)
Derivative financial instruments (commodity)		—		(9,248	)		—		(9,248	)

Total	$	—	$	(42,014	)	$	—	$	(42,014	)

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


	Fair Value Measurement Classification
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Liabilities:
Related party floating rate debt	$	—	$	(73,000	)	$	—	$	(73,000	)
Amended and Restated Credit Facility		—		(78,000	)		—		(78,000	)
TBNG credit agreement		—		(7,732	)		—		(7,732	)
Derivative financial instruments (commodity)		—		(7,071	)		—		(7,071	)

Total	$	—	$	(165,803	)	$	—	$	(165,803	)

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

16. Related party transactions

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


	September 30, 2012		December 31, 2011
	(in thousands)
Related party accounts receivable:
Viking International	$	87	$	—

Total related party accounts receivable	$	87	$	—


Related party accounts payable:
Viking International master services agreement	$	18,064	$	—
Viking Geophysical master services agreement		2,438		—
Riata Management service agreement		40		323

Total related party accounts payable	$	20,542	$	323

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


	September 30, 2012		December 31, 2011
	(in thousands)
Related party accounts receivable:
Maritas services agreement	$	—	$	251
Viking Oilfield Services services agreement		—		116

Total related party accounts receivable held for sale	$	—	$	367

Related party accounts payable:
Viking Drilling services agreement	$	—	$	92
Viking Oilfield Services services agreement		—		617
Gundem lease agreements		—		36

Total related party accounts payable held for sale	$	—	$	745

On June 13, 2012, we entered into separate master services agreements with each of Viking International, Viking Petrol Sahasi Hizmetleri A.S. (“VOS”) and Viking Geophysical in connection with the sale of our oilfield services business. Pursuant to the master services agreements with Viking International and VOS, we are entitled to receive certain oilfield services and materials, including, but not limited to, drilling rigs and fracture stimulation that are needed for our operations in Bulgaria, Romania and Turkey. Pursuant to the master services agreement with Viking Geophysical, we are also entitled to receive geophysical services and materials that are needed for our operations in those countries. Each master services agreement is for a five-year term. Currently, we can contract for services and materials on a firm basis and, to the extent that we do not contract for all of their services or materials, Viking International, VOS and Viking Geophysical are allowed to contract with third parties for any remaining capacity.

On June 13, 2012, we entered into a transition services agreement with Viking Services Management, Ltd. (“Viking Management”) in connection with the sale of our oilfield services business. Pursuant to the transition services agreement, we agreed to provide certain administrative services, including, but not limited to, continued use of certain of our employees and independent contractors, a guarantee of a lease for flats in Turkey, Turkish tax or legal advice and services, office space in Istanbul, Turkey, information technology support and certain software or licenses to Viking Management. In addition, Viking Management agreed to cause its subsidiaries to provide us with the continued use of certain office space in Tekirdag, Turkey. In the third quarter of 2012, we entered into an addendum to the transition services agreement whereby Viking Management agreed to cause its subsidiaries to provide us with the continued use of certain equipment yards in the Thrace Basin and in southwestern Turkey. The transition services agreement has a two-year term. Viking Management agreed to use commercially reasonable efforts to eliminate its need for such services as soon as practicable following the entry into the agreement.

For the three and nine months ended September 30, 2012 and 2011, we incurred expenses of $26.1 million, $43.9 million, $5.3 million and $11.7 million, respectively, related to our various related party agreements.

Item 2.

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

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

Executive Overview

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

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

•

For the three months ended September 30, 2012, we reported $0.5 million of net income from continuing operations. This includes a $6.3 million non-cash loss on the change in fair value of our commodity derivative contracts.

•

During the quarter ended September 30, 2012, we derived 73.2% of our revenues from the production of oil and 22.8% of our revenues from the production of natural gas.

•

Total oil and natural gas revenues increased 0.5% to $31.8 million for the quarter ended September 30, 2012 from $31.6 million realized in the same period in 2011. The increase was primarily the result of an increase in our average realized price received, which increased revenues by $5.4 million. This increase was offset by lower production volumes, which decreased revenues by $5.2 million.

•

Total production was approximately 229 net thousand barrels (“Mbbls”) of oil and approximately 928 net million cubic feet (“Mmcf”) of natural gas for the third quarter of 2012, as compared to approximately 222 net Mbbls of oil and approximately 1,426 net Mmcf of natural gas for the same period in 2011.

•

As of September 30, 2012, we produced an aggregate of approximately 2,441 net barrels (“Bbls”) of oil per day and approximately 10.1 net Mmcf of natural gas per day.

•

For the quarter ended September 30, 2012, we incurred $24.5 million in capital expenditures, as compared to capital expenditures of $24.1 million for the quarter ended September 30, 2011.

•

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

Recent Developments

Amendment to Amended and Restated Credit Facility. In November 2012, we entered into an amendment to our amended and restated senior secured credit facility (the “Amended and Restated Credit Facility”) with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”). The amendment, among other things, reduces the commitment fee rate, extends the first commitment reduction date from September 30, 2012 to December 31, 2013 and provides for a scheduled quarterly reduction of the commitment amount beginning on December 31, 2013, when the commitment amount, which is currently $78.0 million, will be reduced to $67.0 million, and ending on March 31, 2016, when the commitment amount will reach zero.

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

Closing of Sale of Oilfield Services Business. On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”), to a joint venture owned by Dalea Partners, LP, an affiliate of Mr. Mitchell (“Dalea”), and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $168.5 million, consisting of approximately $157.0 million in cash and a $11.5 million promissory note from Dalea. The transaction was approved by a special committee of our board of directors after the receipt of a fairness opinion solely for the benefit of the special committee, which was subject to certain assumptions and limitations as provided in such opinion. The promissory note is payable five years from the date of issuance or earlier upon the occurrence of certain specified events, including an initial public offering by the joint venture. Upon the consummation of an initial public offering by the joint venture and the prior approval of Dalea, we can elect to convert the outstanding balance of the promissory note, including accrued interest, into the number of shares offered in the initial public offering equal to such outstanding balance divided by the per share purchase price paid by the public in the initial public offering. The promissory note bears interest at a rate of 3.0% per annum and is guaranteed by Mr. Mitchell. We used a portion of the net proceeds from the sale to pay off our $73.0 million credit agreement with Dalea, our $11.0 million credit facility with Dalea, our $0.9 million promissory note with Viking Drilling, LLC (“Viking Drilling”) and our $1.8 million credit agreement with a Turkish bank. In addition, we used a portion of the net proceeds from the sale to pay down approximately $45.2 million in outstanding indebtedness under our Amended and Restated Credit Facility.

Entry into Master Services Agreements. On June 13, 2012, we also entered into separate master services agreements with each of Viking International, Viking Petrol Sahasi Hizmetleri A.S. (“VOS”) and Viking Geophysical in connection with the sale of our oilfield services business. Pursuant to the master services agreements with Viking International and VOS, we are entitled to receive certain oilfield services and materials, including, but not limited to, drilling rigs and fracture stimulation, that are needed for our operations in Bulgaria, Romania and Turkey. Pursuant to the master services agreement with Viking Geophysical, we are also entitled to receive geophysical services and materials that are needed for our operations in those countries. Each master services agreement is for a five-year term. Currently, we can contract for services and materials on a firm basis and, to the extent that we do not contract for all of their services or materials, Viking International, VOS and Viking Geophysical are allowed to contract with third parties for any remaining capacity.

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

Amendment to Ban on Fracture Stimulation in Bulgaria. In January 2012, the Bulgarian Parliament enacted legislation that was intended to ban fracture stimulation in the Republic of Bulgaria. The legislation also prevented conventional drilling and completion activities. The Bulgarian Parliament has since amended the legislation to allow conventional drilling and completion activities. In November 2012, we were awarded a production concession over the Koynare concession area, which covers approximately 160,000 acres. As a result we expect our conventional natural gas exploration, development and production activity in the country to resume. As long as the current legislation remains in effect, our unconventional natural gas exploration, development and production activities in Bulgaria will be significantly constrained.

Third Quarter 2012 Operational Update

During the third quarter of 2012, we continued to develop our oil fields in southeastern Turkey and our Thrace Basin natural gas fields in northwestern Turkey. In addition, we continued to expand our inventory of exploration opportunities with new prospects identified on recently completed 3D seismic surveys.

Production. For the quarter ended September 30, 2012, we produced an average of approximately 2,492 net Bbls of oil per day and approximately 10.1 net Mmcf of natural gas per day.

Turkey-Southeast.

•

Selmo. We completed four wells and began drilling one additional well during the third quarter of 2012. In September 2012, we completed five of 14 planned fracture stimulations of existing wells at Selmo.

•

Arpatepe. In the third quarter of 2012, we began completion activity for the Arpatepe-6 well. The well started producing during the fourth quarter of 2012 at an initial gross rate of approximately 200 Bbls of oil per day. The Bati Arpatepe-1 well, which was drilled and funded by Aladdin Middle East, Ltd., the operator of the Arpatepe license, did not find commercial quantities of hydrocarbons and has been plugged and abandoned.

•

Molla. We conducted completion operations on the Bahar-1 well, which encountered oil and natural gas shows in the Bedinan sands formation as well as in the Mardin, Hazro and Dadas formations. In addition, we completed drilling the Goksu-3H well, which we expect to complete during the fourth quarter of 2012 as our first producing horizontal well in Turkey.

Turkey-Thrace Basin. In the third quarter of 2012, we spud six wells, completed 10 new wells and fracture stimulated five wells. As of September 30, 2012, we had $5.6 million of exploratory well costs capitalized for the Pancarkoy-1 well, which we began drilling in the fourth quarter of 2010. We have identified at least two more sands within the Mezardere formation that we expect the Pancarkoy-1 well to initially test by conventional means.

Turkey-Central Basins. We completed the initial planned acquisition of the Sivas Basin data, which Shell Upstream Turkey B.V. co-funded. We have extended the seismic data acquisition program in the Sivas Basin and expect to complete this additional data acquisition in the fourth quarter of 2012. We drilled the Alibey-1H well, which is our first horizontal well in Turkey. We are currently evaluating completion techniques for this well, which is located on our Gaziantep exploration licenses. In addition, we resumed drilling the Konak-1 exploration well on our Gurun exploration license.

Planned Operations

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

•

Commence Tekirdag Field Area Development. We expect to begin drilling our infield tight-gas development program in the Tekirdag field area in the Thrace Basin based upon our projected 50-acre drainage wells. Based on the results of fracture stimulations of new and existing wells, we have designed an initial 88-well development program, which we expect to begin during the fourth quarter of 2012. The development program is expected to proceed as a two-rig campaign with continuous drilling and completion activity continuing into 2015.

•

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

•

Expand Fracture Stimulation Program. We expect to complete the 14-well fracture stimulation program at Selmo during the fourth quarter of 2012. We also plan to fracture stimulate the Bedinan sand formation in the Bahar-1 well during the fourth quarter of 2012. We plan to resume fracture stimulation activity in the Thrace Basin after the Selmo frac program and the Bahar-1 fracture stimulations are completed.

•

Develop Southeastern Turkey Licenses. We plan to complete and test the Alibey-1H well and the Goksu-3H well in the fourth quarter of 2012. In addition, we expect to begin the acquisition of approximately 200 kilometers of 2D seismic data over our recently acquired West Molla exploration license. We plan to spud the Durukoy-1 exploration well on our Idil exploration license.

•

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

Capital expenditures for the remainder of 2012 are expected to range between $20 million and $35 million. Approximately 40% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Most of the remaining 60% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling, completing and stimulating developmental and exploratory oil wells at Selmo, Arpatepe, Molla, Idil and Gurun.

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

Turkey. We plan to drill approximately 10 gross wells, five of which we expect to fracture stimulate. In addition, we plan to perform up-hole recompletions in 14 wells in the Thrace Basin and fracture stimulate nine existing wells at our Selmo oilfield. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill.

Bulgaria. In November 2012, we received a production concession on our Koynare concession area, and we expect to resume conventional operating activity on the concession in the first quarter of 2013.

Romania. We plan to seek approval from the Romanian government to suspend our exploration activities as a result of recent legislation prohibiting unconventional drilling and completion operations. In the alternative, we have made preparations to participate in a 200-kilometer 2D seismic survey on the Sud Craiova license.

Discontinued Operations in Morocco

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

Discontinued Operations of Oilfield Services Business

On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International and Viking Geophysical. We have presented the oilfield services segment operating results as discontinued operations for the nine months ended September 30, 2012 and the three and nine months ended September 30, 2011.

Significant Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3. Significant accounting policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2011 and are of particular importance to the portrayal of our financial position and results of operations and require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. There have been no changes to the significant accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011.

Recent Accounting Pronouncements

In December 2011, FASB issued ASU 2011-11, Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of ASU 2011-11 is required for annual reporting periods beginning on or after January 1, 2013, and interim periods within those annual periods. We are currently evaluating the effects of adopting ASU 2011-11.

In July 2012, FASB issued ASU 2012-02, Intangibles—Goodwill and Other (Topic 350): Testing Indefinite-Lived Intangible Assets for Impairment (“ASU 2012-12”). The update provides an entity with the option first to assess qualitative factors in determining whether it is more likely than not that the indefinite-lived intangible asset is impaired. After assessing the qualitative factors, if an entity determines that it is not more likely than not that the indefinite-lived intangible asset is impaired, then the entity is not required to take further action. If an entity concludes otherwise, then it is required to determine the fair value of the indefinite-lived intangible asset and perform the quantitative impairment test. ASU 2012-02 is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. Early adoption was permitted. We did not early adopt the provisions of this ASU. We do not expect the impact of adopting this ASU to be material to the Company’s financial position, results of operations or cash flows.

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

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


	Three Months Ended September 30,						Change
	2012			2011			2012-2011
	(See Note 1)
	(in thousands of U.S. dollars, except per unit prices and costs and production volumes)
Production:
Oil (Mbbl)		229			222			7
Natural gas (Mmcf)		928			1,426			(498	)
Total production (Mboe)		384			460			(76	)
Average prices:
Oil (per Bbl)	$	105.81		$	104.43		$	1.38
Natural gas (per Mcf)	$	8.14		$	6.53		$	1.61
Oil equivalent (per Boe)	$	82.78		$	68.74		$	14.04
Revenues:
Oil and natural gas sales	$	31,786		$	31,621		$	165
Costs and expenses:
Production		4,542			3,329			1,213
Exploration, abandonment and impairment		2,104			3,944			(1,840	)
Seismic and other exploration		1,725			3,174			(1,449	)
General and administrative		6,744			8,949			(2,205	)
Depletion		7,794			10,347			(2,553	)
Depreciation and amortization		353			1,021			(668	)
Interest and other expense		1,086			3,314			(2,228	)
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts		(853	)		(1,304	)		451
Non-cash change in fair value on commodity derivative contracts		(6,293	)		7,764			(14,057	)

Total gain (loss) on commodity derivative contracts		(7,146	)		6,460			(13,606	)
Oil and gas costs per Boe:
Production	$	11.83		$	7.24		$	4.59
Depletion	$	20.30		$	22.49		$	(2.19	)

Oil and Natural Gas Sales. Total oil and natural gas revenues increased $0.2 million to $31.8 million for the three months ended September 30, 2012, from $31.6 million realized in the same period in 2011. Of the increase, $5.4 million resulted from an increase in our average price received for production, offset by a decrease of $5.2 million due to lower production volumes. Our average price received for production increased $14.04 per Boe to $82.78 per Boe for the three months ended September 30, 2012, from $68.74 per Boe for the same period in 2011. Production volumes decreased primarily on our Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) wells due to less drilling activity in the three months ended September 30, 2012, compared to the same period in 2011.

Production. Production expenses for the three months ended September 30, 2012 increased to $4.5 million from $3.3 million for the same period in 2011. The increase was primarily attributable to the sale of our oilfield services business in June 2012. Prior to the sale, these expenses were eliminated upon consolidation as they were classified as intercompany and are now classified as third party.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended September 30, 2012 decreased approximately $1.8 million to $2.1 million, from $3.9 million for the same period in 2011. During the three months ended September 30, 2012, four wells were written off for an average of $0.5 million per well, as compared to the three months ended September 30, 2011 for which there were primarily two wells written off in the amounts of $2.8 million and $0.6 million.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $1.7 million for the three months ended September 30, 2012, as compared to $3.2 million for the same period in 2011. This decrease was due primarily to a decrease in seismic activity in 2012.

General and Administrative. General and administrative expense was $6.7 million for the three months ended September 30, 2012, as compared to $8.9 million for the same period in 2011. The decrease was primarily due to a decrease in employee-related costs of approximately $1.4 million, a $0.6 million decrease in acquisition costs and a $0.4 million decrease in rents on offices and corporate apartments. Employee-related costs decreased due to reductions in headcount. In addition, for the three months ended September 30, 2011, we had costs associated with our acquisition of TBNG. We had no acquisitions in the current period. These decreases were offset by increases in accounting expenses of $0.6 million. Accounting expense increased due to an increase in our audit fees and consultants hired to help us with our Sarbanes-Oxley compliance efforts. The remaining decrease of $0.4 million was attributable to our overall cost reduction efforts.

Depletion. Depletion decreased to $7.8 million for the three months ended September 30, 2012, as compared to $10.3 million in the same period of 2011. The decrease was primarily due to a lower depletable base, resulting from impairment taken at December 31, 2011 and at June 30, 2012.

Depreciation and Amortization. Depreciation and amortization decreased to $0.4 million for the three months ended September 30, 2012, as compared to $1.0 million in the same period of 2011.

Interest and Other Expense. Interest and other expense decreased to $1.1 million for the three months ended September 30, 2012, as compared to $3.3 million for the same period in 2011. The decrease was due to a lower outstanding balance on our debt. At September 30, 2012, we had approximately $32.8 million outstanding in total debt, compared to $159.1 million at September 30, 2011.

Gain (Loss) on Commodity Derivative Contracts. During the three months ended September 30, 2012, we recorded a loss on commodity derivative contracts of approximately $7.1 million, as compared to a gain of $6.5 million for the same period in 2011. We recorded a $6.3 million unrealized loss and a $0.8 million realized loss on our derivative contracts for the three months ended September 30, 2012, as compared to a $7.8 million unrealized gain and a $1.3 million realized loss for the three months ended September 30, 2011. Unrealized gains and losses are attributable to changes in oil and natural gas prices and volumes hedged from one period end to another. We are required under our Amended and Restated Credit Facility to hedge a portion of our anticipated oil production in the Selmo and Arpatepe oil fields in Turkey.

Other Comprehensive Income (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, 2012 increased to a gain of $3.1 million from a loss of $38.3 million for the same period in 2011 due to the strengthening of the New Turkish Lira against the U.S. Dollar at September 30, 2012.

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

The results of these discontinued operations were as follows:


	Three Months Ended September 30,
	2012			2011
				(See Note 1)
	(in thousands)
Revenues:
Oil and natural gas sales	$	—		$	27
Oilfield services		—			12,948

Total revenues	$	—		$	12,975
Costs and expenses:
Production		89			300
Exploration, abandonment and impairment		—			338
Oilfield services costs		287			9,294
General and administrative		(153	)		2,800
Depreciation, depletion and amortization		—			3,723
Accretion of asset retirement obligations		—			—

Total costs and expenses		223			16,455

Operating loss		(223	)		(3,480	)
Other income (expense):
Interest and other expense		38			(175	)
Interest and other income		307			37
Foreign exchange gain		—			3,190

Total other income (expense)		345			3,052

Income (loss) from discontinued operations before income taxes		122			(428	)
Gain on disposal of discontinued operations		6,437			—
Income tax provision		(34	)		(1,180	)

Net income (loss) from discontinued operations	$	6,525		$	(1,608	)

Results of Operations—Nine Months Ended September 30, 2012 Compared to Nine Months Ended September 30, 2011

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


	Nine Months Ended September 30,				Change
	2012		2011		2012-2011
			(See Note 1)
	(in thousands of U.S. dollars, except per unit prices and costs and production volumes)
Production:
Oil (Mbbl)		686		660		26
Natural gas (Mmcf)		3,376		3,099		277
Total production (Mboe)		1,249		1,176		73
Average prices:
Oil (per Bbl)	$	103.42	$	104.62	$	(1.20	)
Natural gas (per Mcf)	$	8.15	$	6.85	$	1.30
Oil equivalent (per Boe)	$	78.72	$	77.43	$	1.29
Revenues:
Oil and natural gas sales	$	98,323	$	91,052	$	7,271
Costs and expenses:
Production		12,470		12,036		434
Exploration, abandonment and impairment		11,783		15,787		(4,004	)
Seismic and other exploration		2,401		7,799		(5,398	)
Revaluation of contingent consideration		—		1,250		(1,250	)
General and administrative		25,301		27,514		(2,213	)
Depletion		25,073		20,484		4,589
Depreciation and amortization		1,625		2,129		(504	)
Interest and other expense		6,363		10,471		(4,108	)


	Nine Months Ended September 30,						Change
	2012			2011			2012-2011
				(See Note 1)
	(in thousands of U.S. dollars, except per unit prices and costs and production volumes)
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts		(3,100	)		(3,916	)		816
Non-cash change in fair value on commodity derivative contracts		(2,177	)		1,219			(3,396	)

Total gain (loss) on commodity derivative contracts		(5,277	)		(2,697	)		(2,580	)
Oil and gas costs per Boe:
Production	$	9.98		$	10.23		$	(0.25	)
Depletion	$	20.07		$	17.42		$	2.65

Oil and Natural Gas Sales. Total oil and natural gas revenues increased $7.3 million to $98.3 million for the nine months ended September 30, 2012 from $91.1 million realized in the same period in 2011. Of this increase, $5.7 million was due to an increase in production volumes, while $1.6 million was attributable to an increase in our average price received for production. For the nine months ended September 30, 2012, production volumes increased 73 Mboe to 1,249 Mboe, from 1,176 Mboe for the same period in 2011. Production volumes increased primarily due to the acquisition of TBNG in June 2011, which accounted for 147 Mboe of the increase. This increase was offset by a decrease in production in our Edirne and Amity fields. Our average price received for production increased $1.29 per Boe to $78.72 per Boe for the nine months ended September 30, 2012, from $77.43 per Boe for the same period in 2011.

Production. Production expenses for the nine months ended September 30, 2012 increased to $12.5 million from $12.0 million for the same period in 2011.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the nine months ended September 30, 2012 decreased approximately $4.0 million to $11.8 million, from $15.8 million for the same period in 2011. During the nine months ended September 30, 2012, there were nine exploratory dry holes drilled with an average cost of $0.9 million each. Additionally, there was a partial write-off of $2.0 million for the Pankarcoy-1 well. During the same period in 2011, there were five wells written off, with costs ranging from $0.6 million to $6.4 million per well. Additionally, during the nine months ended September 30, 2012, we recorded $1.5 million of impairment charges on our proved properties, primarily due to a reduction in the reserves value of the Alpullu field, as compared to no impairment in the nine months ended September 30, 2011.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $2.4 million for the nine months ended September 30, 2012, as compared to $7.8 million for the same period in 2011. This decrease was due primarily to fewer seismic projects for the nine months ended September 30, 2012, compared to the same period in 2011.

Revaluation of Contingent Consideration. During the nine months ended September 30, 2011, we determined that there was an increase in the likelihood that we would not be able to complete one of our drilling obligations required as part of a February 2011 acquisition. Therefore, we recorded an expense of $1.3 million to reflect our potential future costs. There were no contingent consideration costs required during the nine months ended September 30, 2012.

General and Administrative. General and administrative expense was $25.3 million for the nine months ended September 30, 2012, as compared to $27.5 million for the same period in 2011. The decrease was primarily due to reductions in employee-related costs of approximately $2.8 million, legal and accounting expenses of approximately $1.2 million, acquisition costs of approximately $1.2 million and travel costs of approximately $0.4 million. Employee-related costs decreased due to reductions in headcount. Legal and accounting expenses were higher in the comparable period in 2011 due to the late filing of our Annual Report on Form 10-K for the year ended December 31, 2010 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2011. We had no acquisitions during the nine months ended September 30, 2012, as compared to two acquisitions during the same period in 2011. This decrease was partially offset by increases of $2.0 million for a contingency related to our Aglen exploration permit in Bulgaria and $1.9 million as a result of TBNG being included for the full nine months of 2012. The remaining decrease of $0.5 million was attributable to our overall cost reduction efforts.

Depletion. Depletion increased to $25.1 million for the nine months ended September 30, 2012, as compared to $20.5 million in the same period of 2011. The increase was primarily due to an increase in our production over the same period in 2011, primarily due to the TBNG acquisition in June 2011.

Depreciation and Amortization. Depreciation and amortization decreased to $1.6 million for the nine months ended September 30, 2012, as compared to $2.1 million in the same period of 2011.

Interest and Other Expense. Interest and other expense decreased to $6.4 million for the nine months ended September 30, 2012, as compared to $10.5 million for the same period in 2011. The decrease was primarily due to amortization of warrants of $1.9 million for the nine months ended September 30, 2011 and a lower outstanding balance on our debt. At September 30, 2012, we had approximately $32.8 million of total debt, as compared to $159.1 million at September 30, 2011.

Gain (Loss) on Commodity Derivative Contracts. During the nine months ended September 30, 2012, we recorded a loss on commodity derivative contracts of approximately $5.3 million, as compared to a loss of $2.7 million for the same period in 2011. We recorded a $2.2 million unrealized loss and a $3.1 million realized loss on our derivative contracts for the nine months ended September 30, 2012, as compared to a $1.2 million unrealized gain and a $3.9 million realized loss for the nine months ended September 30, 2011. Unrealized gains and losses are attributable to changes in oil and natural gas prices and volumes hedged from one period end to another. We are required under our Amended and Restated Credit Facility to hedge a portion of our anticipated oil production in the Selmo and Arpatepe oil fields in Turkey.

Other Comprehensive Income (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, 2012 increased to a gain of $17.7 million from a loss of $48.7 million for the same period in 2011 due to the strengthening of the New Turkish Lira against the U.S. Dollar at September 30, 2012.

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

The results of these discontinued operations were as follows:


	Nine Months Ended September 30,
	2012			2011
				(See Note 1)
	(in thousands)
Revenues:
Oil and natural gas sales	$	—		$	214
Oilfield services		20,956			19,896

Total revenues	$	20,956		$	20,110
Costs and expenses:
Production		738			1,554
Exploration, abandonment and impairment		—			12,045
Seismic and other exploration		—			—
Oilfield services costs		14,023			19,037
General and administrative		10,313			5,252
Depreciation, depletion and amortization		—			13,018
Accretion of asset retirement obligations		—			1

Total costs and expenses		25,074			50,907

Operating loss		(4,118	)		(30,797	)
Other income (expense):
Interest and other expense		(138	)		(605	)
Interest and other income		479			99
Foreign exchange gain (loss)		(763	)		2,406

Total other income (expense)		(422	)		1,900

Loss from discontinued operations before income taxes		(4,540	)		(28,897	)
Gain on disposal of discontinued operation		33,651			—
Income tax provision		(8,207	)		(1,698	)

Net income (loss) from discontinued operations	$	20,904		$	(30,595	)

Capital Expenditures

For the quarter ended September 30, 2012, we incurred $24.5 million in capital expenditures compared to capital expenditures from continuing operations of $24.1 million for the quarter ended September 30, 2011.

For the remainder of 2012, we expect our capital expenditures to range between approximately $20 million and $35 million. Approximately 40% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Most of the remaining 60% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling, completing and stimulating developmental and exploratory oil wells at Selmo, Arpatepe, Molla, Idil and Gurun.

Liquidity and Capital Resources

Our primary sources of liquidity for the third quarter of 2012 were our cash and cash equivalents and cash flow from operations. At September 30, 2012, we had cash and cash equivalents of $26.2 million, no short-term debt associated with our continuing operations, no short-term debt associated with our discontinued operations, $32.8 million in long-term debt associated with our continuing operations, no long-term debt associated with our discontinued operations, and working capital of $12.9 million (excluding assets and liabilities held for sale), compared to cash and cash equivalents of $15.1 million, $80.7 million in short-term debt associated with our continuing operations, $5.0 million in short-term debt associated with our discontinued operations, $78.0 million in long-term debt associated with our continuing operations, and excluding assets held for sale of $128.1 million and liabilities held for sale of $26.7 million, a working capital deficit of $65.7 million at December 31, 2011. Net cash provided by operating activities for the nine months ended September 30, 2012 decreased to $26.5 million, as compared to net cash provided by operating activities of $29.4 million for the nine months ended September 30, 2011, primarily as a result of lower oil prices.

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

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

In November 2012, we entered into an amendment to the Amended and Restated Credit Facility. The amendment, among other things, reduces the commitment fee rate, extends the first commitment reduction date from September 30, 2012 to December 31, 2013 and provides for a scheduled quarterly reduction of the commitment amount beginning on December 31, 2013 according to the following schedule:


End of Period	Commitment Amount
December 2013	$	67,500,000
March 2014	$	60,000,000
June 2014	$	52,000,000
September 2014	$	45,000,000
December 2014	$	37,500,000
March 2015	$	30,000,000
June 2015	$	22,500,000
September 2015	$	15,000,000
December 2015	$	7,500,000
March 2016	$	0

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, 2012, the lenders had aggregate commitments of $78.0 million, with individual commitments of $39.0 million each.

The borrowing base is re-determined semi-annually on April 1st and October 1st of each year prior to September 30, 2012, and quarterly on January 1st, April 1st, July 1st and October 1st of each year after September 30, 2012. The borrowing base is currently $77.5 million. We have not finalized the September 30, 2012 borrowing base redetermination, but we expect that the redetermination will reduce the borrowing base to approximately $60.0 million.

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

•

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

•

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

•

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

The Amended and Restated Credit Facility matures on the earlier of (i) May 18, 2016 or (ii) the last date of the borrowing base calculation period that immediately precedes the date that the semi-annual report of Standard Bank and the Borrowers determines that the aggregate amount of hydrocarbons to be produced from the borrowing base assets in Turkey are less than 25% of the amount of hydrocarbons to be produced from the borrowing base assets shown in the initial report prepared by Standard Bank and the Borrowers. The Amended and Restated Credit Facility bears various letter of credit sub-limits, including, among other things, sub-limits of up to (i) $10.0 million, (ii) the aggregate available unused and uncancelled portion of the lenders’ commitments or (iii) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment.

Loans under the Amended and Restated Credit Facility accrue interest at a rate of three-month LIBOR plus 5.50% per annum. The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.20% 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) 1.10% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available amount under the Amended and Restated Credit Facility, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to Standard Bank or (b) 5.50% for all other letters of credit.

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

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

•

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

•

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

•

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

•

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

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

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

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

Contingencies Relating to Exploration Permits

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

Contractual Obligations

There were no material changes to our contractual obligations set forth in our Quarterly Report on Form 10-Q for the period ended June 30, 2012.

Off-Balance Sheet Arrangements

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

Forward-Looking Statements

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

The following factors, among others, could cause actual results to differ from those set forth in the forward-looking statements: market prices for natural gas, natural gas liquids and oil products; estimates of reserves and economic assumptions; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which we carry on business, especially economic slowdowns; actions by governmental authorities, receipt of required approvals, increases in taxes, legislative and regulatory initiatives relating to fracture stimulation activities, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; the negotiation and closing of material contracts; shortages of drilling rigs, equipment or oilfield services; and the other factors discussed in other documents that we file with or furnish to the Securities and Exchange Commission (“SEC”). The impact of any one factor on a particular forward-looking statement is not determinable with certainty, as such factors are interdependent upon other factors. In that regard, any statements as to future natural gas or oil production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital program; drilling of new wells; demand for natural gas and oil products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves; dates by which transactions are expected to close; cash flows; uses of cash flows; collectability of receivables; availability of trade credit; expected operating costs; changes in any of the foregoing and other statements using forward-looking terminology are forward-looking statements.

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

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

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


Type	Period	Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Asset (Liability)
								(in thousands)
Collar	October 1, 2012—December 31, 2012		960	$	64.69	$	106.98	$	(553	)
Collar	January 1, 2013—December 31, 2013		400	$	75.00	$	125.50		(276	)
Collar	January 1, 2014—December 31, 2014		380	$	75.00	$	124.25		(142	)

								$	(971	)


		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	October 1, 2012—December 31, 2012		240	$	70.00	$	100.00	$	129.50	$	(231	)
Three-way collar contract	October 1, 2012—December 31, 2012		170	$	85.00	$	97.13	$	162.13		(262	)
Three-way collar contract	January 1, 2013—December 31, 2013		831	$	85.00	$	97.13	$	162.13		(3,801	)
Three-way collar contract	January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13		(1,982	)
Three-way collar contract	January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(2,001	)

										$	(8,277	)

Item 4.

Controls and Procedures

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

During the preparation and review of our financial statements for the third quarter of 2012, we identified that our processes and procedures over significant non-routine transactions, specifically the computation of the gain on the sale of our oilfield services business, including our review controls, failed to identify that the computation did not include certain intercompany balances at June 30, 2012. This error was not identified in the proper period, in part, due to the complex nature of the divestiture and lack of dedicated technical accounting staff. This control deficiency resulted in an error in our consolidated financial statements for the three and six months ended June 30, 2012 that increased our gain on the sale of our oilfield services business for the three months ended September 30, 2012. Accordingly, management has concluded that this deficiency in internal control over financial reporting constituted a material weakness.

As a result of the error and our material weaknesses described in our Annual Report on Form 10-K for the year ended December 31, 2011, if sufficient dedicated technical accounting staff do not reside within the permanent accounting staff, we will hire consultants on complex transactions.

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

Changes in Internal Control over Financial Reporting

There were no changes during the third quarter of 2012 that have affected, or are reasonably likely to materially affect, our internal control over financial reporting, except as follows:

Staffing. Management made the following staffing changes:

•

Recently hired an additional U.S. GAAP-trained resource residing in Turkey as general ledger supervisor;

•

Redefined the role of an ex-U.S. Big 4 accountant residing in Turkey to lead the account reconciliation process;

•

Recently hired a dedicated inventory/warehouse manager to oversee all the warehouses throughout Turkey and ensure the proper recording and tracking of purchases and consumption;

•

Recently hired a new warehouse supervisor for the Selmo warehouse, where we have had a history of unreconciled inventory;

•

Engaged external advisors and consultants to assist management with updating and improving the documentation of the design of financial reporting process flows and related internal controls. Specific focus has been placed on improvements in the design of internal control over financial reporting related to areas previously identified as containing material weaknesses; and

•

Hired a property accountant with public company, international oil and gas exploration accounting experience to begin in January 2013.

Processes. Management made the following process changes:

•

Implemented cycle counts at all warehouses with full quarterly counts in our Selmo warehouse. As a result, we had no book-to-physical adjustments in the third quarter of 2012;

•

Implemented an accrual process resulting in quarterly financial statements completed sooner than in prior quarters. This has allowed more time for management and the audit committee to review the Form 10-Q;

•

Established a process whereby the statutory tax accounts, prepared in accordance with Turkish tax laws, are compared quarterly to the U.S. GAAP accounts;

•

Automated the calculation of asset retirement obligations using a third-party software package, which mitigates the risk of manual errors; and

•

Commenced a project to reduce our chart of accounts.

As a result of the items noted above coupled with other actions taken earlier, management identified the majority of the prior period errors disclosed in Note 1 to our consolidated financial statements and will continue remediation efforts in the fourth quarter of 2012.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

On June 27, 2012, the Kozluk Civil Court of First Instance dismissed the underlying litigation regarding persons who claimed ownership of a portion of the surface at our Selmo oil field in southeastern Turkey. The court issued its formal decision on August 8, 2012, and the plaintiffs have filed an appeal with the Court of Appeal. We will continue to vigorously defend our interests.

Item 1A.

Risk Factors

During the third quarter of 2012, there were no material changes to the Risk Factors disclosed in “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2011, as updated by the Risk Factors disclosed in our Quarterly Reports on Form 10-Q for the quarters ended June 30, 2012 and March 31, 2012.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

None.

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).

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.INS†		XBRL Instance Document.

101.SCH†		XBRL Taxonomy Extension Schema Document.

101.CAL†		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF†		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB†		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE†		XBRL Taxonomy Extension Presentation Linkbase Document.

*	Filed herewith.

†

Furnished herewith. 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 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 30, 2012

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).

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.INS†		XBRL Instance Document.

101.SCH†		XBRL Taxonomy Extension Schema Document.

101.CAL†		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF†		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB†		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE†		XBRL Taxonomy Extension Presentation Linkbase Document.

*	Filed herewith.

†

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