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: March 31, 2013

¨	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.)

16803 Dallas Parkway Addison, Texas		75001
(Address of Principal Executive Offices)		(Zip Code)

Registrant’s Telephone Number, Including Area Code: (214) 220-4323

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 May 15, 2013, the registrant had 368,906,996 common shares outstanding.

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012			1

Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2013 and 2012			2

Consolidated Statements of Equity for the Three Months Ended March 31, 2013			3

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2013 and 2012			4

Notes to Consolidated Financial Statements			5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			15

Item 3. Quantitative and Qualitative Disclosures About Market Risk			23

Item 4. Controls and Procedures			23

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			25

Item 1A. Risk Factors			25

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			25

Item 3. Defaults Upon Senior Securities			25

Item 4. Mine Safety Disclosures			25

Item 5. Other Information			25

Item 6. Exhibits			26

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

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


	March 31, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	19,428		$	14,768
Accounts receivable
Oil and natural gas sales, net		29,446			34,158
Joint interest and other		12,888			18,192
Related party		644			419
Prepaid and other current assets		1,736			2,339
Restricted cash		7,000			—
Deferred income taxes		1,966			1,895
Assets held for sale		534			1,619

Total current assets		73,642			73,390

Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		237,270			231,498
Unproved		73,208			68,938
Equipment and other property		35,780			35,747

		346,258			336,183
Less accumulated depreciation, depletion and amortization		(87,817	)		(80,031	)

Property and equipment, net		258,441			256,152
Other long-term assets:
Other assets		8,068			8,195
Note receivable – related party		11,500			11,500
Goodwill		8,891			9,021

Total other assets		28,459			28,716

Total assets	$	360,542		$	358,258

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	14,712		$	12,864
Accounts payable — related party		14,272			15,634
Accrued liabilities		25,662			29,972
Derivative liabilities		3,618			3,908
Asset retirement obligations		813			818
Liabilities held for sale		7,077			8,416

Total current liabilities		66,154			71,612
Long-term liabilities:
Asset retirement obligations		11,052			11,140
Accrued liabilities		7,311			7,548
Deferred income taxes		17,251			16,483
Loan payable		39,766			32,766
Derivative liabilities		4,696			4,882

Total long-term liabilities		80,076			72,819

Total liabilities		146,230			144,431
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.01 par value, 1,000,000,000 shares authorized; 368,906,996 shares issued and outstanding as of March 31, 2013 and 368,748,592 shares issued and outstanding as of December 31, 2012		3,689			3,687
Additional paid-in capital		538,342			537,962
Accumulated other comprehensive loss		(30,848	)		(28,012	)
Accumulated deficit		(296,871	)		(299,810	)

Total shareholders’ equity		214,312			213,827

Total liabilities and shareholders’ equity	$	360,542		$	358,258

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

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)

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


	For the Three Months Ended March 31,
	2013			2012
				(See Note 1)
Revenues:
Oil and natural gas sales	$	32,725		$	34,667
Sales of purchased natural gas		2,274			1,662
Other		513			1,177

Total revenues		35,512			37,506
Costs and expenses:
Production		5,527			3,635
Exploration, abandonment and impairment		3,864			2,796
Cost of purchased natural gas		2,180			1,736
Seismic and other exploration		243			663
General and administrative		7,523			9,277
Depreciation, depletion and amortization		8,976			9,169
Accretion of asset retirement obligations		129			251

Total costs and expenses		28,442			27,527

Operating income		7,070			9,979
Other income (expense):
Interest and other expense		(890	)		(3,259	)
Interest and other income		375			134
Loss on commodity derivative contracts		(776	)		(12,435	)
Foreign exchange (loss) gain		(487	)		4,272

Total other expense		(1,778	)		(11,288	)

Income (loss) from continuing operations before income taxes		5,292			(1,309	)
Current income tax (expense) benefit		(1,339	)		(2,020	)
Deferred income tax (expense) benefit		(921	)		1,859

Net income (loss) from continuing operations		3,032			(1,470	)
Net loss from discontinued operations, net of taxes		(93	)		(2,157	)

Net income (loss)	$	2,939		$	(3,627	)
Other comprehensive income (loss):
Foreign currency translation adjustment		(2,836	)		13,363

Comprehensive income	$	103		$	9,736

Net income (loss) per common share:
Basic net income (loss) per common share:
Continuing operations	$	0.01		$	0.00
Discontinued operations	$	0.00		$	(0.01	)
Weighted average common shares outstanding		368,886			366,436
Diluted net income (loss) per common share:
Continuing operations	$	0.01		$	0.00
Discontinued operations	$	0.00		$	(0.01	)
Weighted average common and common equivalent shares outstanding		368,886			366,436

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, 2012		368,749	$	3,687	$	537,962		$	(28,012	)	$	(299,810	)	$	213,827
Issuance of restricted stock units		158		2		(2	)		—			—			—
Share-based compensation		—		—		382			—			—			382
Foreign currency translation adjustments		—		—		—			(2,836	)		—			(2,836	)
Net income		—		—		—			—			2,939			2,939

Balance at March 31, 2013		368,907	$	3,689	$	538,342		$	(30,848	)	$	(296,871	)	$	214,312

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 Three Months Ended March 31,
	2013			2012
				(See Note 1)
Operating activities:
Net income (loss)	$	2,939		$	(3,627	)
Adjustment for net loss from discontinued operations		93			2,157

Net income (loss) from continuing operations		3,032			(1,470	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-based compensation		382			493
Foreign currency gain (loss)		490			(7,664	)
Unrealized (gain) loss on commodity derivative contracts		(476	)		10,960
Amortization of loan financing costs		128			225
Deferred income tax expense (benefit)		921			(1,859	)
Exploration, abandonment and impairment		3,864			2,796
Depreciation, depletion and amortization		8,976			9,169
Accretion of asset retirement obligations		129			252
Changes in operating assets and liabilities
Accounts receivable		9,166			(2,454	)
Prepaid expenses and other assets		219			838
Accounts payable and accrued liabilities		(7,182	)		2,349

Net cash provided by operating activities from continuing operations		19,649			13,635
Net cash used in operating activities from discontinued operations		(1,072	)		(4,322	)

Net cash provided by operating activities		18,577			9,313
Investing activities:
Additions to oil and natural gas properties		(13,423	)		(15,904	)
Additions to equipment and other properties		(1,133	)		(824	)
Restricted cash		(7,110	)		1,062

Net cash used in investing activities from continuing operations		(21,666	)		(15,666	)
Net cash provided by (used in) investing activities from discontinued operations		1,016			(1,208	)

Net cash used in investing activities		(20,650	)		(16,874	)
Financing activities:
Tax withholding on restricted stock units		—			210
Exercise of stock options and warrants		—			600
Loan proceeds		13,589			4,284
Loan proceeds — related party		—			11,000
Loan repayment		(6,589	)		(7,497	)
Loan financing costs		—			(250	)

Net cash provided by financing activities from continuing operations		7,000			8,347
Net cash used in financing activities from discontinued operations		—			(1,519	)

Net cash provided by financing activities		7,000			6,828
Effect of exchange rate changes on cash		(267	)		704
Net increase (decrease) in cash and cash equivalents		4,660			(29	)
Cash and cash equivalents, beginning of year		14,768			15,116

Cash and cash equivalents, end of period	$	19,428		$	15,087

Supplemental disclosures:
Cash paid for interest	$	702		$	2,747

Cash paid for income taxes	$	396		$	2,007

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 have established, yet underexplored petroleum systems, have stable governments, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of May 15, 2013, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell, 3rd, our chief executive officer and chairman of our board of directors.

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 consolidated financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and in the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fairly the consolidated financial position of TransAtlantic at March 31, 2013 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual consolidated 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 consolidated 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, 2012. Certain prior period amounts have been reclassified to conform to the current period presentation.

In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated 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 three months ended March 31, 2012, we reclassified certain amounts previously reported on our consolidated statements of comprehensive income (loss) to conform to current year presentation. Specifically, we reclassified the revenue and cost related to natural gas purchased from third parties. For the three months ended March 31, 2012, these reclassifications increased total revenues and expenses by approximately $1.7 million and $1.7 million, respectively.

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

During the three months ended 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 consolidated financial statements would materially understate results for the year ended 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 statements of comprehensive income (loss) and our consolidated statements of cash flows for the three months ended March 31, 2012 in this Quarterly Report on Form 10-Q.

These errors consisted mainly of accrued liabilities that should have been recorded in prior periods, inappropriate recognition of receivable balances, and other minor corrections with immaterial impact to other miscellaneous accounts.

Additionally, during the three months ended March 31, 2013, we identified and corrected errors previously reported on our consolidated statements of cash flows. As a result, we increased the “Exploration, abandonment and impairment” sub-caption, which is an adjustment to reconcile net income (loss) to net cash provided by operating activities, and increased the cash used in investing activities related to “Additions to oil and natural gas properties” by $1.3 million for the three months ended March 31, 2012, as we previously did not include the cash portion of additions to oil and natural gas properties in investing activities for dry hole expenses that were recognized in the same period as the related cash disbursed. These amounts had also been excluded from the adjustment to reconcile net income (loss) to net cash provided by operating activities.

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. Accordingly, we have reflected the correction of these prior period errors in the periods in which they originated and revised our consolidated statements of cash flows for the three months ended March 31, 2012 in this Quarterly Report on Form 10-Q.

The effect of the out-of-period adjustments on the Company’s consolidated statements of comprehensive income (loss) for the three months ended March 31, 2012 are as follows (in thousands):


	As Reported			Correction			As Revised
For the three months ended March 31, 2012
Total revenues	$	34,935		$	2,571		$	37,506
Total costs and expenses		(26,264	)		(1,263	)		(27,527	)
Total other (expense) income		(11,149	)		(139	)		(11,288	)

Loss from continuing operations before income taxes		(2,478	)		1,169			(1,309	)
Net loss from continuing operations		(2,639	)		1,169			(1,470	)
Net loss from discontinued operations		(2,157	)		—			(2,157	)

Net loss		(4,796	)		1,169			(3,627	)
Foreign currency translation adjustment		14,374			(1,011	)		13,363

Comprehensive income	$	9,578		$	158		$	9,736

The effect of the out-of-period adjustments and reclassifications on our consolidated statements of cash flows for the three months ended March 31, 2012 are as follows (in thousands):


	As Reported			Correction			As Revised
For the three months ended March 31, 2012
Operating activities:
Exploration, abandonment and impairment	$	1,493		$	1,303		$	2,796
Other		9,803			1,036			10,839
Net cash provided by operating activities from continuing operations		11,296			2,339			13,635
Net cash provided by operating activities		6,974			2,339			9,313
Investing activities:
Additions to oil and natural gas properties		(13,355	)		(2,549	)		(15,904	)
Net cash used in investing activities from continuing operations		(13,117	)		(2,549	)		(15,666	)
Net cash used in investing activities		(14,325	)		(2,549	)		(16,874	)
Financing activities:
Tax withholding on restricted stock units		—			210			210
Net cash provided by financing activities from continuing operations		8,137			210			8,347
Net cash provided by financing activities	$	6,618		$	210		$	6,828

2. Recent accounting policies

In July 2012, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 was effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012. The adoption of ASU 2012-02 did not have a material impact on our consolidated financial statements.

In February 2013, FASB issued ASU 2013-02, New Disclosures for Items Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 requires reclassification adjustments for items that are reclassified out of accumulated other comprehensive income to net income to be presented in the statements where the components of net income and the components of other comprehensive income are presented or in the footnotes to the financial statements. Additionally, the amendment requires cross-referencing to other disclosures currently required for other reclassification items. The amendments were effective for interim and annual reporting periods beginning after December 15, 2012. The adoption of ASU 2013-02 did not have a material impact on our consolidated financial statements.

We have reviewed 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.

3. 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.

The assets and liabilities held for sale at March 31, 2013 and December 31, 2012 were as follows:


	March 31, 2013		December 31, 2012
	(in thousands)
Cash	$	24	$	93
Other assets (1)		510		1,526

Total assets held for sale	$	534	$	1,619

Accrued expenses and other liabilities	$	7,077	$	8,416

Total liabilities held for sale	$	7,077	$	8,416

(1)	Other assets consists primarily of $0.5 million of restricted cash

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 Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”), to a joint venture owned by Dalea Partners, LP (“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 promissory note bears interest at a rate of 3.0% per annum and is guaranteed by Mr. Mitchell. We have presented the oilfield services segment operating results as discontinued operations for the three months ended March 31, 2012.

Our operating results from discontinued operations for the three months ended March 31, 2013 and 2012 are summarized as follows:


	For the Three Months Ended March 31,
	2013			2012
	(in thousands)
Total revenues	$	—		$	10,284
Total costs and expenses		(86	)		(9,526	)
Total other expense		(7	)		(935	)

Loss from discontinued operations before income taxes		(93	)		(177	)
Income tax provision		—			(1,980	)

Loss from discontinued operations, net of taxes	$	(93	)	$	(2,157	)

4. 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 have goodwill from acquisitions where we anticipated access to potential exploration and production opportunities. All of our goodwill is attributable to our Turkey operating segment. Our goodwill at March 31, 2013 and December 31, 2012 was as follows:


	March 31, 2013			December 31, 2012
	(in thousands)
Goodwill at beginning of period	$	9,021		$	8,514
Foreign exchange change effect		(130	)		507

Goodwill at end of period	$	8,891		$	9,021

5. 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 as of:


	March 31, 2013			December 31, 2012
	(in thousands)
Oil and natural gas properties, proved:
Turkey	$	235,288		$	229,462
Bulgaria		1,982			2,036

Total oil and natural gas properties, proved		237,270			231,498
Oil and natural gas properties, unproved:
Turkey		73,208			68,938

Gross oil and natural gas properties		310,478			300,436
Accumulated depletion		(81,279	)		(74,099	)

Net oil and natural gas properties	$	229,199		$	226,337

At March 31, 2013 and December 31, 2012, we excluded $2.6 million and $1.8 million, respectively, from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At March 31, 2013, the capitalized costs of our net oil and natural gas properties included $46.6 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $106.8 million relating to well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.

At December 31, 2012, the capitalized costs of our oil and natural gas properties were comprised of $49.5 million relating to acquisition costs of proved properties before the fourth quarter impairment, which are being amortized by the unit-of-production method using total proved reserves, and $105.3 million relating to well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.

During the three months ended March 31, 2013, we incurred approximately $13.8 million in exploratory drilling costs, of which $3.8 million was included in exploration, abandonment and impairment expense, $0.3 million was reclassified from unproved to proved properties and $9.7 million remained capitalized at March 31, 2013. No exploratory well costs were reclassified to proved properties in the first quarter of 2012. Uncertainties affect the recoverability of costs of our oil and natural gas properties, as the recovery of the costs are dependent upon us maintaining licenses in good standing and achieving commercial production or sale.

As of March 31, 2013, we had $4.2 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. In the fourth quarter of 2012, we tested the up-hole interval of the well. Based on the test results, further fracture stimulation of this well is planned in 2013. In June 2012, based on the test results, we wrote off a portion of the exploratory well costs related to this well, with only the sidetrack wellbore costs remaining capitalized.

The Meneske-1 well was spud in November 2011, and we have capitalized $2.0 million of exploratory well costs as of March 31, 2013. Due to expected high tie-in costs of the Meneske-1 well, we are waiting on the test results of other nearby wells to decide whether to invest capital in a pipeline tie-in.

The Suleymaniye-2 well was spud in December 2011 and is being evaluated for artificial lift. As of March 31, 2013, we had capitalized $0.8 million of drilling and completion costs for this well.

The following table summarizes the costs related to these wells:


	Year Ended December 31,						Three Months Ended			Partial Write-Off and Other			Total at March 31, 2013
	2010		2011		2012		March 31, 2013			Partial Write-Off and Other			Total at March 31, 2013
	(in thousands)
Pancarkoy-1 well initial re-entry and fracture stimulation (Ceylan and Mezardere formations)	$	787	$	4,860	$	1,303	$	—		$	(2,702	)	$	4,248
Meneske-1 well		—		2,197		142		(1	)		(342	)		1,996
Suleymaniye-2 well		—		—		785		(12	)		—			773

Total capitalized costs	$	787	$	7,057	$	2,230	$	(13	)	$	(3,044	)	$	7,017

Equipment and other property

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


	March 31, 2013			December 31, 2012
	(in thousands)
Other equipment	$	2,384		$	2,013
Inventory		20,380			20,517
Gas gathering system and facilities		5,292			5,369
Vehicles		235			131
Office equipment and furniture		7,489			7,717

Gross equipment and other property		35,780			35,747
Accumulated depreciation		(6,538	)		(5,932	)

Net equipment and other property	$	29,242		$	29,815

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 March 31, 2013 and December 31, 2012, we excluded $20.4 million and $20.5 million, respectively, of inventory from depreciation, as the inventory had not been placed into service.

6. Commodity derivative instruments

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

To the extent that a legal right of offset exists, we net the value of our derivative instruments with the same counterparty in our consolidated balance sheets. All of our oil derivative contracts are settled based upon Brent 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 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 senior secured credit facility (as amended, the “Amended and Restated Credit Facility”) with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”) 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 March 31, 2013, we recorded a net loss on commodity derivative contracts of approximately $0.8 million, consisting of a $0.5 million unrealized gain related to changes in fair value and a $1.3 million realized loss for settled contracts. For the three months ended March 31, 2012, we recorded a net loss on commodity derivative contracts of $12.4 million, consisting of a $11.0 million unrealized loss related to changes in fair value and a $1.4 million realized loss for settled contracts.

At March 31, 2013 and December 31, 2012, 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 March 31, 2013


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		April 1, 2013—December 31, 2013		775	$	82.26	$	121.36	$	(132	)
Collar		January 1, 2014—December 31, 2014		662	$	80.83	$	118.07		(293	)

									$	(425	)


			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		April 1, 2013—December 31, 2013		831	$	85.00	$	97.13	$	162.13	$	(2,677	)
Three-way collar contract		January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13		(2,416	)
Three-way collar contract		January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(2,796	)

											$	(7,889	)

Fair Value of Derivative Instruments as of December 31, 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		January 1, 2013—December 31, 2013		775	$	82.26	$	121.36	$	(253	)
Collar		January 1, 2014—December 31, 2014		662	$	80.83	$	118.07		(292	)

									$	(545	)


			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, 2013—December 31, 2013		831	$	85.00	$	97.13	$	162.13	$	(3,655	)
Three-way collar contract		January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13		(2,150	)
Three-way collar contract		January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(2,440	)

											$	(8,245	)

7. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations for the three months ended March 31, 2013 and for the year ended December 31, 2012:


	March 31, 2013			December 31, 2012
	(in thousands)
Asset retirement obligations at beginning of period	$	11,958		$	13,534
Change in estimates		(8	)		(3,868	)
Liabilities settled		(50	)		(110	)
Foreign exchange change effect		(183	)		793
Additions		19			899
Accretion expense		129			710

Asset retirement obligations at end of period		11,865			11,958
Less: current portion		813			818

Long-term portion	$	11,052		$	11,140

8. Loan payable

As of the indicated dates, our debt consisted of the following:


	March 31, 2013		December 31, 2012
	(in thousands)
Floating Rate Debt
Amended and Restated Credit Facility	$	39,766	$	32,766

Loan Payable	$	39,766	$	32,766

Amended and Restated Senior Secured Credit Facility

On May 18, 2011, DMLP, Ltd., TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd., TransAtlantic Turkey, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayive Ticaret A.Ş. and Amity Oil International Pty Ltd (collectively, the “Borrowers”) entered into 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.

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. As of April 1, 2013 our borrowing base is $56.9 million.

At March 31, 2013, we had borrowed $39.8 million under the Amended and Restated Credit Facility.

9. Contingencies relating to exploration permits

We are involved in litigation with persons who claim ownership of a portion of the surface at the Selmo oil field in Turkey. These cases are being vigorously defended by TEMI and Turkish governmental authorities. We do not have enough information to estimate the potential additional operating costs we would incur in the event the purported surface owners’ claims are ultimately successful. Any adjustment arising out of the claims will be recorded when it becomes probable and measurable.

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. In February 2013, the Moroccan government drew down our $1.0 million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we plan to pursue a settlement with the Moroccan government for a lesser amount, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during the second quarter of 2012 for this contractual obligation.

In the second quarter of 2012, we were notified that the Bulgarian government may seek to recover approximately $2.0 million in contractual obligations under our Aglen exploration permit work program. Due to the Bulgarian government’s January 2012 ban on fracture stimulation and related activities, a force majeure event under the terms of the exploration permit was recognized by the government. Although we invoked force majeure, we 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.

Pursuant to the purchase agreement with Direct Petroleum Exploration, Inc., $10.0 million worth of our common shares would be due if we have not completed certain obligations regarding the drilling the Deventci-R2 well and the coring of the Etropole shale formation. A $10.0 million provision for this contingency was accrued at December 31, 2011.

10. Shareholders’ equity

Restricted stock units

Share-based compensation expense of approximately $0.4 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three months ended March 31, 2013. We recorded share-based compensation expense of $0.5 million for the three months ended March 31, 2012.

As of March 31, 2013, we had approximately $2.0 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 three months ended March 31, 2013 or 2012. At March 31, 2013, all stock options have been fully amortized.

Earnings per share

We account for earnings per share in accordance with Accounting Standards Codification (“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 months ended March 31, 2013 equals net income divided by the weighted average shares outstanding during the period. 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 months ended March 31, 2013 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 20,543,909 antidilutive common share equivalents from the three months ended March 31, 2012.

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


	Three Months Ended March 31,
	2013			2012
(in thousands, except per share amounts)				(See Note 1)
Net income (loss) from continuing operations	$	3,032		$	(1,470	)
Net loss from discontinued operations	$	(93	)	$	(2,157	)
Basic net income (loss) per common share:
Shares:
Weighted average common shares outstanding		368,886			366,436

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

Discontinued operations	$	0.00		$	(0.01	)

Diluted net income (loss) per common share:
Shares:
Weighted average common shares outstanding		368,886			366,436

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

Discontinued operations	$	0.00		$	(0.01	)

Additionally, we had a contingent liability at March 31, 2013 of approximately $10.0 million that is payable in our common shares. At the March 31, 2013 closing price of our common shares, this liability represented 10,752,688 common shares that could be potentially dilutive to future earnings per share calculations.

11. 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 March 31, 2013
Total revenues	$	—		$	—		$	35,444	$	68		$	35,512
Income (loss) from continuing operations before income taxes		(2,957	)		(23	)		8,372		(100	)		5,292
Capital expenditures	$	—		$	—		$	18,699	$	—		$	18,699
For the three months ended March 31, 2012 (See Note 1)
Total revenues	$	—		$	—		$	37,441	$	65		$	37,506
Income (loss) from continuing operations before income taxes		(5,439	)		(298	)		4,628		(200	)		(1,309	)
Capital expenditures	$	—		$	—		$	14,011	$	168		$	14,179


	Corporate		Romania		Turkey		Bulgaria		Total
	(in thousands)
Segment assets
March 31, 2013	$	13,781	$	69	$	344,232	$	1,926	$	360,008	⁽¹⁾
December 31, 2012	$	14,825	$	105	$	339,752	$	1,957	$	356,639	⁽¹⁾
Goodwill
March 31, 2013	$	—	$	—	$	8,891	$	—	$	8,891
December 31, 2012	$	—	$	—	$	9,021	$	—	$	9,021

(1)	Excludes assets held for sale from our discontinued Moroccan operations of $0.5 million and $1.6 million at March 31, 2013 and December 31, 2012, respectively.

12. 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 March 31, 2013 and December 31, 2012, 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 March 31, 2013, we had 29.2 million New Turkish Lira (approximately $16.2 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 March 31, 2013 and December 31, 2012, 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, and Turkiye Petrol Rafinerileri A.Ş., a privately owned oil refinery in Turkey, which purchase the majority of our oil production. The receivables are not collateralized. To date, we have experienced minimal bad debts. 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 March 31, 2013:


	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:
Derivative financial instruments (commodity)	$	—	$	(8,314	)	$	—	$	(8,314	)

Total	$	—	$	(8,314	)	$	—	$	(8,314	)

The following table summarizes the valuation of our financial assets and liabilities as of December 31, 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:
Derivative financial instruments (commodity)	$	—	$	(8,790	)	$	—	$	(8,790	)

Total	$	—	$	(8,790	)	$	—	$	(8,790	)

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.

13. Related party transactions

The following table summarizes related party accounts receivable and accounts payable as of March 31, 2013 and December 31, 2012:


	March 31, 2013		December 31, 2012
	(in thousands)
Related party accounts receivable:
Viking International master services agreement	$	618	$	313
Riata Management service agreement		26		—
Dalea promissory note		—		106

Total related party accounts receivable	$	644	$	419

Related party accounts payable:
Viking International master services agreement	$	14,147	$	15,467
Riata Management service agreement		125		167

Total related party accounts payable	$	14,272	$	15,634

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 Turkey and Bulgaria. 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.

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 months ended March 31, 2013 and 2012, we incurred expenses of $20.2 million and $2.7 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 have established, yet underexplored petroleum systems, have stable governments, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of May 15, 2013, we held interests in approximately 3.9 million net onshore acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of May 15, 2013, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell, 3rd, our chief executive officer and chairman of our board of directors.

Financial and Operational Performance Highlights. Highlights of our financial and operational performance for the first quarter of 2013 include:

•

We reported $3.0 million of net income from continuing operations. This includes a $0.5 million non-cash gain on the change in fair value of our commodity derivative contracts.

•

We derived 69.3% 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 sales revenues decreased 5.6% to $32.7 million for the quarter ended March 31, 2013 from $34.7 million in the same period in 2012. The decrease was primarily the result of lower production of 79 Mboe, which decreased revenues by $6.1 million. This decrease was partially offset by an increase in our average realized price received, which increased revenues by $4.1 million.

•

Total net production was 239 thousand barrels (“Mbbls”) of oil and 801 million cubic feet (“Mmcf”) of natural gas, as compared to 224 Mbbls of oil and 1,367 Mmcf of natural gas for the same period in 2012.

•

As of March 31, 2013, we produced an average of 2,656 net barrels (“Bbls”) of oil per day and 8.9 net Mmcf of natural gas per day.

•

For the quarter ended March 31, 2013, we incurred $18.7 million in capital expenditures, as compared to capital expenditures of $14.2 million for the quarter ended March 31, 2012.

•

As of March 31, 2013, we had $39.8 million in outstanding debt and no short-term borrowings, as compared to $32.8 million in outstanding debt and no short-term borrowings as of December 31, 2012.

Recent Developments

Acquisition of Additional Exploration Acreage in Southeastern Turkey. On May 20, 2013, we completed the acquisition of three exploration licenses from ARAR Petrol ve Gaz Arama Uretim Pazarlama A.S. The exploration licenses, which cover an aggregate of 150,000 acres, are located adjacent to our Molla exploration licenses in southeastern Turkey. We are the 100% owner and operator of the licenses.

Relinquishment of Sud Craiova Exploration License. In 2012, the Romanian government temporarily suspended unconventional exploration of hydrocarbons, including fracture stimulation, pending a government review of unconventional drilling and completion techniques. As a result, on May 10, 2013, we notified the Romanian government that we were relinquishing our Sud Craiova exploration license, covering approximately 500,000 net onshore acres in Romania.

Changes in Executive Management. On January 1, 2013, we appointed Ian J. Delahunty, our former vice president, business development, as our president. On January 31, 2013, Mustafa Yavuz resigned as our chief operating officer.

Technical Leadership Team Based in Dallas. As a result of successful initial results in several new plays on our Molla and Gaziantep exploration licenses in southeastern Turkey, and continued activity in the Thrace Basin, most of our 2013 exploration wells will be drilled horizontally or directionally, and many of our planned completions will require fracture stimulation. Accordingly, we determined to increase internal exposure to resource development practices among our technical management and evaluation personnel. As part of this strategy, we recently hired a vice president, drilling, a vice president, completions, a senior reservoir engineer and several other drilling and completions engineers with strong experience in horizontal drilling and fracture stimulation completion methods. This new technical leadership team is based in Addison, Texas, in order to take advantage of the latest North American horizontal drilling and unconventional completions techniques and knowledge.

First Quarter 2013 Operational Update

During the first quarter of 2013, we continued to develop our oil fields in southeastern Turkey and our Thrace Basin natural gas fields in northwestern Turkey.

Turkey-Southeast.

Molla. We spud the Goksu-4H horizontal well, which is our fourth well targeting the Cretaceous Mardin limestone formation on our Molla licenses. It is our second horizontal well in the area, and sales from the Goksu-4H commenced in April 2013 at an initial rate of 314 Bbls per day. We spud the Bahar-2 well, an appraisal of our successful Bahar-1 well in the northern area of the Molla licenses, which has produced 44,000 gross Bbls of oil as of May 1, 2013 following a one-stage frac. The Bahar-2 well will be our first horizontal to test the Paleozoic Bedinan formation and is designed to evaluate the economics associated with horizontal, multi-stage completion techniques. We expect to finish drilling this well in the second quarter of 2013 and anticipate fracture stimulating the well thereafter, depending on equipment availability.

Selmo. We conducted routine maintenance activities during the first quarter of 2013 and expect to begin drilling our first horizontal well and additional wells at Selmo in the second half of 2013.

Arpatepe. We conducted routine maintenance activities during the first quarter of 2013 and expect to begin drilling an exploration well on our Arpatepe exploration license in the second quarter of 2013.

Gaziantep. Our Alibey-1H horizontal exploration well, which made an oil discovery in the Mardin formation on our Gaziantep licenses, remained suspended during the first quarter of 2013 due to adverse weather conditions. We expect to complete the well and put it into production in the second quarter of 2013.

Idil. We completed drilling the Durukoy-1 exploration well on our Idil license along the Syrian border with Turkey. Upon reaching planned total depth and encountering minor oil shows, we deemed a completion of the well uneconomic and plugged the well.

Turkey-Thrace Basin.

In the first quarter of 2013, we spud five wells, completed six new wells and fracture stimulated five wells. Our operations focused on exploring and appraising multiple tight gas targets in the Thrace Basin. We spud a deep appraisal well in the Hayrabolu trend to appraise the over-pressured gas zones identified in the recently drilled Kazanci-5 well. We are continuing completion operations on the Kazanci-5 well, but early test results indicate that many of the over-pressured zones encountered by the well may, in fact, be non-productive.

In the Tekirdag area, we successfully stimulated the Baglik-1 well in the Teslimkoy and Kesan intervals. Following the initial cleanup, the well had an initial production rate of 3 Mmcf per day. The well is currently choked back and continuing to produce approximately 2 Mmcf per day. We completed two other wells in the area targeting the same formations, but with less net pay, and those wells had initial production rates of approximately 600 Mcf per day. We expect to drill horizontal wells to test several structures in the Tekirdag area in the second half of 2013. If successful, these wells would reduce the number of wells required to develop the Tekirdag tight gas area and lead to greater productivity per well.

In addition, we continued our workover and recompletion efforts in the Thrace Basin. We recompleted multiple wells on licenses that we hold with Turkiye Petrolleri Anonim Ortakligi, the national oil company of Turkey, resulting in an average production increase of 650 Mcf per day per well recompleted. We have continued our de-watering efforts through the installation of plunger lifts, rod pumps and progressive cavity pumps, resulting in an average 30% production increase in the wells in which we installed de-watering equipment.

Turkey-Central Basins.

After review of technical data gathered in 2011 and 2012, our farm-out partner, Shell Upstream Turkey B.V., elected not to exercise its option to acquire a 60% working interest in our Sivas Basin exploration licenses. We are currently evaluating the Sivas Basin technical data to determine whether or not we will drill an exploration well on the licenses in 2013.

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. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. For the remainder of 2013, we are focused on accomplishing the following objectives:

•

Increase Production. We plan to increase our oil and natural gas production in Turkey through exploration and development on our Molla, Thrace Basin, Selmo and Arpatepe licenses and production leases, including the application of fracture stimulation techniques and horizontal drilling.

•

Continue to Expand Fracture Stimulation Program. In 2012, our Thrace Basin fracture simulation program tested and defined deeper intervals and provided important lessons regarding frac design. In 2013, we plan to expand our application of fracture stimulation techniques in several of our exploration licenses in southeastern Turkey. We anticipate that employing fracture stimulation techniques will result in the commercial development of production and reserves that would have otherwise not been commercial.

•

Expand the Use of Horizontal Drilling. In 2012, we had initial success with horizontal drilling with our Goksu-3H well on our Molla licenses and the Alibey-1 well on our Gaziantep licenses. During 2013, we anticipate our drilling in southeastern Turkey will include extensive use of horizontal drilling techniques, including nine wells on our Molla licenses, five wells at Selmo, and one well on our Gaziantep licenses.

•

Accelerate 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 and Turkey and plan to continue this effort during the remainder of 2013.

Capital expenditures, including seismic expenditures, for the second, third and fourth quarters of 2013 are expected to range between $90.0 million and $110.0 million. Approximately 30% of these anticipated expenditures will occur in the Thrace Basin, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Most of the remaining 70% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Molla, Selmo, Arpatepe and Gaziantep. The remainder of our projected 2013 capital budget is subject to change, and if cash on hand, borrowings from our amended and restated senior secured credit facility (as amended, the “Amended and Restated Credit Facility”) with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”) and cash flow from operations are not sufficient to fund our capital expenditures, we will either curtail our discretionary capital expenditures or seek other funding sources. We currently plan to execute the following drilling and exploration activities during the second, third and fourth quarters of 2013:

Turkey. We plan to drill approximately 30 gross wells, 15 of which are expected to be drilled horizontally and approximately 50% of which will be fracture stimulated. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill.

Bulgaria. We plan to resume drilling the Deventci-R2 well on our Koynare Concession Area in the second half of 2013.

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 the three months ended March 31, 2013 and March 31, 2012, and they are not included in results from continuing operations.

Discontinued Operations of Oilfield Services Business

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, 2012 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, 2012.

Recent Accounting Pronouncements

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

Results of Operations—Three Months Ended March 31, 2013 Compared to Three Months Ended March 31, 2012

Our results of operations for the three months ended March 31, 2013 and 2012 were as follows:


	Three Months Ended March 31,						Change
	2013			2012			2013-2012
				(See Note 1)
	(in thousands of U.S. Dollars, except per unit prices and costs and production volumes)
Production:
Oil (Mbbl)		239			224			15
Natural gas (Mmcf)		801			1,367			(566	)
Total production (Mboe)		373			452			(79	)
Average prices:
Oil (per Bbl)	$	103.00		$	108.14		$	(5.14	)
Natural gas (per Mcf)		10.12			7.64			2.48
Oil equivalent (per Boe)		87.73			76.70			11.03
Revenues:
Oil and natural gas sales	$	32,725		$	34,667		$	(1,942	)
Sales of purchased natural gas		2,274			1,662			612
Other		513			1,177			(664	)
Costs and expenses:
Production	$	5,527		$	3,635		$	1,892
Exploration, abandonment and impairment		3,864			2,796			1,068
Cost of purchased natural gas		2,180			1,736			444
Seismic and other exploration		243			663			(420	)
General and administrative		7,523			9,277			(1,754	)
Depletion		8,386			8,491			(105	)
Depreciation and amortization		590			678			(88	)
Interest and other expense		890			3,259			(2,369	)
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	(1,252	)	$	(1,474	)	$	(222	)


	Three Months Ended March 31,						Change
	2013			2012			2013-2012
				(See Note 1)
	(in thousands of U.S. Dollars, except per unit prices and costs and production volumes)
Non-cash change in fair value on commodity derivative contracts		476			(10,961	)	$	11,437

Total gain (loss) on commodity derivative contracts	$	(776	)	$	(12,435	)	$	(11,659	)
Oil and gas costs per Boe:
Production	$	14.82		$	8.04		$	6.78
Depletion	$	22.48		$	18.79		$	3.69

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $1.9 million to $32.7 million for the three months ended March 31, 2013, from $34.7 million realized in the same period in 2012. Of the decrease, $6.1 million resulted from lower production volumes of 79 Mboe. This was partially offset by an increase of $4.1 million due to higher average realized prices per Boe due to producing a higher percentage of oil. Our average price received for production increased $11.03 per Boe to $87.73 per Boe for the three months ended March 31, 2013, from $76.70 per Boe for the same period in 2012. Production volumes decreased primarily on our Thrace Basin wells due to depletion of wells recompleted in the second half of 2011.

Production. Production expenses for the three months ended March 31, 2013 increased to $5.5 million from $3.6 million for the same period in 2012. 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 expenses.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended March 31, 2013 increased $1.1 million to $3.9 million, from $2.8 million for the same period in 2012. During the three months ended March 31, 2013, two wells were written off for an average of $0.5 million per well, as compared to the three months ended March 31, 2012, when there were two wells written off for an average of $1.4 million per well. Additionally, one additional well was written off during the three months ended March 31, 2013 for $2.9 million.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $0.2 million for the three months ended March 31, 2013, as compared to $0.7 million for the same period in 2012.

General and Administrative. General and administrative expense was $7.5 million for the three months ended March 31, 2013, as compared to $9.3 million for the same period in 2012. The decrease was primarily due to a decrease in employee-related costs of approximately $0.3 million, a $0.4 million decrease in rents on offices and corporate apartments and a $0.9 million decrease in legal and consulting expenses. Employee-related costs decreased due to reductions in headcount. Legal and consulting expenses were higher during the three months ended March 31, 2012 due to increased legal and consulting fees associated with the sale of our oilfield services business. The remaining decrease of $0.2 million was attributable to our overall cost reduction efforts.

Depletion. Depletion decreased to $8.4 million for the three months ended March 31, 2013, as compared to $8.5 million for the same period of 2012.

Depreciation and Amortization. Depreciation and amortization decreased to $0.6 million for the three months ended March 31, 2013, as compared to $0.7 million for the same period of 2012.

Interest and Other Expense. Interest and other expense decreased to $0.9 million for the three months ended March 31, 2013, as compared to $3.3 million for the same period in 2012. The decrease was due to a lower outstanding balance on our total debt during the three months ended March 31, 2013. At March 31, 2013, we had approximately $39.8 million of total debt outstanding, as compared to $166.5 million at March 31, 2012.

Loss on Commodity Derivative Contracts. During the three months ended March 31, 2013, we recorded a loss on commodity derivative contracts of approximately $0.8 million, as compared to a loss of $12.4 million for the same period in 2012. We recorded a $0.5 million unrealized gain and a $1.3 million realized loss on our derivative contracts for the three months ended March 31, 2013, as compared to a $11.0 million unrealized loss and a $1.4 million realized loss for the three months ended March 31, 2012. 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 March 31, 2013 decreased to a loss of $2.9 million from a gain of $13.4 million for the same period in 2012 due to the devaluation of the New Turkish Lira.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations for the three months ended March 31, 2013 and 2012 and the oilfield services business for the three months ended March 31, 2012 have been included in discontinued operations.

The results of these discontinued operations were as follows:


	Three Months Ended March 31,
	2013			2012
	(in thousands)
Revenues:
Oil and natural gas sales	$	—		$	—
Oilfield services		—			10,284

Total revenues	$	—		$	10,284
Costs and expenses:
Production		69			288
Oilfield services costs		—			7,072
General and administrative		17			2,166

Total costs and expenses		86			9,526

Operating (loss) income		(86	)		758
Other income (expense):
Interest and other expense		(7	)		(65	)
Interest and other income		—			18
Foreign exchange loss		—			(888	)

Total other expense		(7	)		(935	)

Loss from discontinued operations before income taxes		(93	)		(177	)
Income tax provision		—			(1,980	)

Net loss from discontinued operations, net of taxes	$	(93	)	$	(2,157	)

Capital Expenditures

For the quarter ended March 31, 2013, we incurred $18.7 million in capital expenditures from continuing operations, as compared to $14.2 million for the quarter ended March 31, 2012.

For the second, third and fourth quarters of 2013, we expect our capital expenditures, including seismic expenditures, to range between approximately $90.0 million and $110.0 million. Approximately 30% 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 70% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling, completing and stimulating developmental and exploratory oil wells at Molla, Selmo, Arpatepe and Gaziantep. The remainder of our projected 2013 capital budget is subject to change, and if cash on hand, borrowings from our Amended and Restated Credit Facility and cash flow from operations are not sufficient to fund our capital expenditures, we will either curtail our discretionary capital expenditures or seek other funding sources.

Liquidity and Capital Resources

Our primary sources of liquidity for the first quarter of 2013 were our cash and cash equivalents, cash flow from operations and net borrowings under our Amended and Restated Credit Facility. At March 31, 2013, we had cash and cash equivalents of $19.4 million, no short-term debt, $39.8 million in long-term debt, and working capital of $14.0 million (excluding assets and liabilities held for sale), compared to cash and cash equivalents of $14.8 million, no short-term debt, $32.8 million in long-term debt, and working capital of $8.6 million (excluding assets and liabilities held for sale) at December 31, 2012. Net cash provided by operating activities from continuing operations for the three months ended March 31, 2013 increased to $19.6 million, as compared to net cash provided by operating activities from continuing operations of $13.6 million for the three months ended March 31, 2012, primarily as a result of the timing of collection on our accounts receivable and payments on our accounts payable.

As of March 31, 2013, the outstanding principal amount of our debt was $39.8 million. In addition to cash, cash equivalents and cash flow from operations, at March 31, 2013, 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, Amity Oil International Pty Ltd, Talon Exploration, Ltd., TransAtlantic Turkey, Ltd. and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (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”).

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 March 31, 2013, the lenders had aggregate commitments of $78.0 million, with individual commitments of $39.0 million each.

The borrowing base is re-determined quarterly on January 1st, April 1st, July 1st and October 1st of each year. As of April 1, 2013, our borrowing base is $56.9 million.

Under the terms of the Amended and Restated Credit Facility, we are required to provide our unaudited consolidated financial statements for the quarter ended March 31, 2013 to the lenders by May 15, 2013. We have obtained waivers from Standard Bank and BNP Paribas that extend this deadline to May 25, 2013.

At March 31, 2013, we had outstanding borrowings of $39.8 million under the Amended and Restated Credit Facility and had availability of $17.1 million 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, 2012.

Contingencies Relating to Exploration Permits

Contractual Obligations

There were no material changes to our contractual obligations set forth in our Annual Report on Form 10-K for the year ended December 31, 2012.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at March 31, 2013.

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 first quarter of 2013, 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, 2012. 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 March 31, 2013:


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		April 1, 2013—December 31, 2013		775	$	82.26	$	121.36	$	(132	)
Collar		January 1, 2014—December 31, 2014		662	$	80.83	$	118.07		(293	)

									$	(425	)


			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		April 1, 2013—December 31, 2013		831	$	85.00	$	97.13	$	162.13	$	(2,677	)
Three-way collar contract		January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13		(2,416	)
Three-way collar contract		January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(2,796	)

											$	(7,889	)

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 March 31, 2013, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon the evaluation, and as a result of the material weaknesses in internal control over financial reporting described in our Annual Report on Form 10-K for the year ended December 31, 2012, our chief executive officer and chief financial officer concluded that, as of March 31, 2013, our disclosure controls and procedures were not effective at the reasonable assurance level.

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

Changes in Internal Control over Financial Reporting

There were no changes during the first quarter of 2013 that have affected, or are reasonably likely to materially affect, our internal control over financial reporting, except as follows:

In March 2013, we hired a consulting firm to review our 2012 accounting of oil and natural gas properties, deferred income taxes and share-based compensation, assist management with its reviews of the first quarter financial statements and disclosures, assist management in developing and implementing adequate review procedures and checklists and implement accounting process improvements.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

During the first quarter of 2013, there were no material developments to the Legal Proceedings disclosed in “Part I, Item 3. Legal Proceedings” in our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 1A.

Risk Factors

During the first quarter of 2013, 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, 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: May 23, 2013

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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