TransAtlantic Petroleum (TAT) 10-Q 2014 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: June 30, 2014

OR

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

For the transition period from            to            

Commission file number: 001-34574

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

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

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

As of August 1, 2014, the registrant had 37,479,956 common shares outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	1
Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June  30, 2014 and 2013	2
Consolidated Statements of Equity for the Six Months Ended June 30, 2014	3
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	4
Notes to Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	17
Item 3. Quantitative and Qualitative Disclosures About Market Risk	28
Item 4. Controls and Procedures	28
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	29
Item 1A. Risk Factors	29
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)

	June 30, 2014			December 31, 2013
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	5,161		$	12,881
Accounts receivable
Oil and natural gas sales, net		38,796			30,619
Joint interest and other		5,974			15,348
Related party		192			1,004
Prepaid and other current assets		3,242			5,072
Deferred income taxes		2,666			2,239
Assets held for sale		29			536
Total current assets		56,060			67,699
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		298,369			260,857
Unproved		61,957			54,392
Equipment and other property		41,285			39,916
		401,611			355,165
Less accumulated depreciation, depletion and amortization		(127,761	)		(104,193	)
Property and equipment, net		273,850			250,972
Other long-term assets:
Other assets		9,973			8,880
Note receivable – related party		11,500			11,500
Goodwill		7,574			7,535
Total other assets		29,047			27,915
Total assets	$	358,957		$	346,586
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	13,002		$	16,712
Accounts payable - related party		7,697			23,090
Accrued liabilities		16,477			20,658
Derivative liabilities		8,279			3,737
Asset retirement obligations		397			610
Loan payable		28,288			43,284
Liabilities held for sale		7,533			7,559
Total current liabilities		81,673			115,650
Long-term liabilities:
Asset retirement obligations		10,830			10,286
Accrued liabilities		6,785			6,487
Deferred income taxes		19,018			16,134
Loan payable		59,766			26,482
Derivative liabilities		5,716			4,230
Total long-term liabilities		102,115			63,619
Total liabilities		183,788			179,269
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.10 par value, 100,000,000 shares authorized; 37,447,909 shares issued and outstanding as of June 30, 2014 and 37,340,206 shares issued and outstanding as of December 31, 2013		3,745			3,734
Additional paid-in capital		542,725			542,091
Accumulated other comprehensive loss		(63,188	)		(64,985	)
Accumulated deficit		(308,113	)		(313,523	)
Total shareholders’ equity		175,169			167,317
Total liabilities and shareholders’ equity	$	358,957		$	346,586

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

1

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 June 30,						For the Six Months Ended June 30,
	2014			2013			2014			2013
Revenues:
Oil and natural gas sales	$	40,441		$	29,455		$	73,425		$	62,180
Sales of purchased natural gas		491			719			1,036			1,525
Other		129			342			246			855
Total revenues		41,061			30,516			74,707			64,560
Costs and expenses:
Production		4,666			3,328			8,797			8,855
Exploration, abandonment and impairment		3,775			11,885			7,916			15,749
Cost of purchased natural gas		440			619			925			1,331
Seismic and other exploration		892			1,090			4,186			1,333
Revaluation of contingent consideration		—			(5,000	)		(2,500	)		(5,000	)
General and administrative		7,460			6,893			14,012			14,416
Depreciation, depletion and amortization		12,588			9,581			22,678			18,557
Accretion of asset retirement obligations		106			124			204			253
Total costs and expenses		29,927			28,520			56,218			55,494
Operating income		11,134			1,996			18,489			9,066
Other (expense) income:
Interest and other expense		(1,769	)		(955	)		(2,972	)		(1,845	)
Interest and other income		327			307			600			682
(Loss) gain on commodity derivative contracts		(9,522	)		4,278			(8,560	)		3,502
Foreign exchange gain (loss)		2,494			(2,543	)		1,150			(3,030	)
Total other (expense) income		(8,470	)		1,087			(9,782	)		(691	)
Income from continuing operations before income taxes		2,664			3,083			8,707			8,375
Current income tax expense		(838	)		(528	)		(907	)		(1,867	)
Deferred income tax (expense) benefit		(389	)		348			(2,370	)		(573	)
Net income from continuing operations		1,437			2,903			5,430			5,935
Net loss from discontinued operations		—			—			(20	)		(93	)
Net income	$	1,437		$	2,903		$	5,410		$	5,842
Other comprehensive income (loss):
Foreign currency translation adjustment		5,092			(13,543	)		1,797			(16,379	)
Comprehensive income (loss)	$	6,529		$	(10,640	)	$	7,207		$	(10,537	)
Net income per common share:
Basic net income per common share:
Continuing operations	$	0.04		$	0.08		$	0.15		$	0.16
Discontinued operations	$	0.00		$	0.00		$	0.00		$	0.00
Weighted average common shares outstanding		37,411			36,893			37,402			36,891
Diluted net income per common share:
Continuing operations	$	0.04		$	0.08		$	0.15		$	0.16
Discontinued operations	$	0.00		$	0.00		$	0.00		$	0.00
Weighted average common and common equivalent shares outstanding		37,411			36,893			37,402			36,891

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

2

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, 2013		37,340	$	3,734	$	542,091		$	(64,985	)	$	(313,523	)	$	167,317
Issuance of restricted stock units		108		11		(11	)		—			—			—
Share-based compensation		—		—		713			—			—			713
Tax withholding on restricted stock units		—		—		(68	)		—			—			(68	)
Foreign currency translation adjustments		—		—		—			1,797			—			1,797
Net income		—		—		—			—			5,410			5,410
Balance at June 30, 2014		37,448	$	3,745	$	542,725		$	(63,188	)	$	(308,113	)	$	175,169

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

3

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands of U.S. dollars)

	For the Six Months Ended June 30,
	2014			2013
Operating activities:
Net income	$	5,410		$	5,842
Adjustment for net loss from discontinued operations		20			93
Net income from continuing operations		5,430			5,935
Adjustments to reconcile net income to net cash provided by operating activities:
Share-based compensation		713			881
Foreign currency loss		74			2,138
Loss (gain) on commodity derivative contracts		8,560			(3,502	)
Cash settlement on commodity derivative contracts		(2,533	)		(1,736	)
Amortization of loan financing costs		764			256
Deferred income tax expense		2,370			573
Exploration, abandonment and impairment		7,916			15,749
Depreciation, depletion and amortization		22,678			18,557
Accretion of asset retirement obligations		204			253
Revaluation of contingent consideration		(2,500	)		(5,000	)
Changes in operating assets and liabilities:
Accounts receivable		2,215			10,432
Prepaid expenses and other assets		2,056			141
Accounts payable and accrued liabilities		(6,487	)		11,045
Net cash provided by operating activities from continuing operations		41,460			55,722
Net cash used in operating activities from discontinued operations		(64	)		(1,071	)
Net cash provided by operating activities		41,396			54,651
Investing activities:
Additions to oil and natural gas properties		(62,993	)		(52,320	)
Additions to equipment and other properties		(2,589	)		(7,925	)
Restricted cash		—			(206	)
Net cash used in investing activities from continuing operations		(65,582	)		(60,451	)
Net cash provided by investing activities from discontinued operations		500			1,016
Net cash used in investing activities		(65,082	)		(59,435	)
Financing activities:
Tax withholding on restricted stock units		(68	)		—
Loan proceeds		26,092			22,885
Loan repayment		(7,804	)		(15,885	)
Loan financing costs		(2,176	)		—
Net cash provided by financing activities from continuing operations		16,044			7,000
Effect of exchange rate changes on cash		(78	)		(1,064	)
Net (decrease) increase in cash and cash equivalents		(7,720	)		1,152
Cash and cash equivalents, beginning of period		12,881			14,768
Cash and cash equivalents, end of period	$	5,161		$	15,920
Supplemental disclosures:
Cash paid for interest	$	1,212		$	1,539
Cash paid for taxes	$	—		$	1,448
Supplemental non-cash financing activities:
Repayment of amended and restated credit facility from refinancing	$	49,766		$	—

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

4

TRANSATLANTIC PETROLEUM LTD.

Notes to Consolidated Financial Statements

(Unaudited)

1. General

Nature of operations

TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the “Company” or “TransAtlantic”) is an international oil and 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 August 1, 2014, 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. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews estimates, including those related to fair value measurements associated with acquisitions and financial derivatives, the recoverability and impairment of long-lived assets and goodwill, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with U.S. GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2013.

2. Recent accounting pronouncements

In April 2014, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08,Reporting Discontinued Operations and Disclosures of Components of an Entity(“ASU 2014-08”). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. Currently, we do not expect the adoption of ASU 2014-08 to have a material impact on our consolidated financial statements or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers(“ASU 2014-09”). ASU 2014-09 amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods or services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The update is effective for periods beginning after December 15, 2016. We are currently assessing the potential impact of ASU 2014-09 on our consolidated financial statements and results of operations.

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

5

3. 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:

	June 30, 2014			December 31, 2013
	(in thousands)
Oil and natural gas properties, proved:
Turkey	$	297,748		$	260,232
Bulgaria		621			625
Total oil and natural gas properties, proved		298,369			260,857
Oil and natural gas properties, unproved:
Turkey		57,502			51,273
Bulgaria		4,455			3,119
Total oil and natural gas properties, unproved		61,957			54,392
Gross oil and natural gas properties		360,326			315,249
Accumulated depletion		(119,373	)		(96,958	)
Net oil and natural gas properties	$	240,953		$	218,291

At June 30, 2014 and December 31, 2013, we excluded $0.7 million and $1.5 million, respectively, from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At June 30, 2014, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $32.6 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $146.2 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

At December 31, 2013, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $35.5 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $126.9 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

Impairment and dry hole costs

During the three and six months ended June 30, 2014, we recorded $3.8 million and $7.9 million of impairment and exploratory dry hole costs, respectively. Of the $7.9 million of costs incurred during the six months ended June 30, 2014, $3.5 million related to impairment on one well in the first quarter of 2014 and $2.8 million related to impairment of the Kazanci-5 well in the second quarter of 2014. Of the $7.9 million of costs incurred during the six months ended June 30, 2014, $1.4 million was cash spent during the period.

Capitalized cost greater than one year

As of June 30, 2014, we had $1.7 million of exploratory well costs capitalized for the Hayrabolu-10 well, which we spud in February 2013. The Hayrabolu-10 well continues to be evaluated for completion pending more analysis and comparable well results.

Equipment and other property

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

	June 30, 2014			December 31, 2013
	(in thousands)
Other equipment	$	3,944		$	2,678
Inventory		24,811			24,318
Gas gathering system and facilities		4,508			4,485
Vehicles		347			321
Leasehold improvements, office equipment and software		7,675			8,114
Gross equipment and other property		41,285			39,916
Accumulated depreciation		(8,388	)		(7,235	)
Net equipment and other property	$	32,897		$	32,681

6

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 June 30, 2014, we excluded $24.8 million of inventory and $1.2 million of software from depreciation as the inventory and software had not been placed into service. At December 31, 2013, we excluded $24.3 million of inventory and $0.7 million of software from depreciation as the inventory and software had not been placed into service.

4. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations (“ARO”) for the six months ended June 30, 2014 and for the year ended December 31, 2013:

	June 30, 2014			December 31, 2013
	(in thousands)
Asset retirement obligations at beginning of period	$	10,896		$	11,958
Change in estimates		—			(7	)
Liabilities settled		(212	)		(296	)
Foreign exchange change effect		53			(2,258	)
Additions		286			991
Accretion expense		204			508
Asset retirement obligations at end of period		11,227			10,896
Less: current portion		397			610
Long-term portion	$	10,830		$	10,286

Our ARO is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging costs, remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.

5. Commodity derivative instruments

We use collar derivative contracts to economically hedge against the variability in cash flows associated with the forecasted sale of a portion of our future oil production. We have not designated the derivative contracts as hedges for accounting purposes, and accordingly, we record the derivative 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 contracts 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 gains and losses related to these contracts on a fair value basis in our consolidated statements of comprehensive income (loss) under the caption “(Loss) gain on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on commodity derivative contracts.” We are required under our senior secured credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP Paribas”) and the International Finance Corporation (“IFC”) to hedge at least 30% of our anticipated oil production volumes in Turkey.

In May 2014, we novated our existing commodity derivative contracts with Standard Bank Plc (“Standard Bank”) and BNP Paribas and entered into new commodity derivative contracts with BNP Paribas. During the three months ended June 30, 2014, we recognized a $0.7 million realized loss on the unwinding of these commodity derivative contracts, which is included in our consolidated statement of comprehensive income (loss) under the caption “(Loss) gain on commodity derivative contracts”.

7

During the three months ended June 30, 2014 and 2013, we recorded a net loss on commodity derivative contracts of $9.5 million and a net gain of $4.3 million, respectively. During the six months ended June 30, 2014 and 2013, we recorded a net loss on commodity derivative contracts of $8.6 million and a net gain of $3.5 million, respectively.

At June 30, 2014 and December 31, 2013, we had outstanding contracts with respect to our future crude oil production as set forth in the tables below:

Fair Value of Derivative Instruments as of June 30, 2014

Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
									(in thousands)
Collar		July 1, 2014—December 31, 2014		1,770	$	85.00	$	97.25	$	(4,758	)
Collar		January1, 2015—December 31, 2015		1,410	$	85.00	$	97.25		(6,027	)
									$	(10,785	)

			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, 2016—December 31, 2016		1,066	$	85.00	$	97.25	$	114.25	$	(2,057	)
Three-way collar contract		January 1, 2017—December 31, 2017		888	$	85.00	$	97.25	$	114.25		(851	)
Three-way collar contract		January 1, 2018—December 31, 2018		726	$	85.00	$	97.25	$	114.25		(282	)
Three-way collar contract		January 1, 2019—March 31, 2019		663	$	85.00	$	97.25	$	114.25		(20	)
											$	(3,210	)

Fair Value of Derivative Instruments as of December 31, 2013

Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
									(in thousands)
Collar		January 1, 2014—December 31, 2014		622	$	80.83	$	118.07	$	(387	)
									$	(387	)

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			Collars						Additional Call
Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
											(in thousands)
Three-way collar contract		January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13	$	(3,350	)
Three-way collar contract		January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(4,230	)
											$	(7,580	)

Balance sheet presentation

The following table summarizes both: (i) the gross fair value of our commodity derivative instruments by the appropriate balance sheet classification even when the commodity derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at June 30, 2014 and December 31, 2013, and (ii) the net recorded fair value as reflected on our consolidated balance sheets at June 30, 2014 and December 31, 2013.

			As of June 30, 2014
Underlying commodity	Location on Balance Sheet		Gross Amount of Recognized Liabilities		Gross Amount Offset in the Consolidated Balance Sheet		Net Amount of Liabilities Presented in the Consolidated Balance Sheet
			(in thousands)
Crude oil		Current liabilities	$	8,279	$	—	$	8,279
Crude oil		Long-term liabilities	$	5,716	$	—	$	5,716
			As of December 31, 2013
Underlying commodity	Location on Balance Sheet		Gross Amount of Recognized Liabilities		Gross Amount Offset in the Consolidated Balance Sheet		Net Amount of Liabilities Presented in the Consolidated Balance Sheet
			(in thousands)
Crude oil		Current liabilities	$	3,737	$	—	$	3,737
Crude oil		Long-term liabilities	$	4,230	$	—	$	4,230

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6. Loan payable

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

	June 30, 2014		December 31, 2013
Floating Rate Debt	(in thousands)
Amended and Restated Credit Facility	$	—	$	49,766
Senior Credit Facility		59,766		—
TBNG credit facility		26,700		20,000
Unsecured lines of credit		1,588		—
Loan payable		88,054		69,766
Less: current portion		28,288		43,284
Long-term portion	$	59,766	$	26,482

Amended and Restated Credit Facility

On May 18, 2011, DMLP, Ltd. (“DMLP”), TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”) (collectively, and together with Amity Oil International Pty Ltd (“Amity”), the “Borrowers”) entered into an amended and restated credit facility (the “Amended and Restated Credit Facility”) with Standard Bank and BNP Paribas. 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 was guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”). On May 6, 2014, we entered into the new Senior Credit Facility and, on May 15, 2014, we repaid the Amended and Restated Credit Facility in full and it was terminated.

Senior Credit Facility

On May 6, 2014, the Borrowers entered into the Senior Credit Facility with BNP Paribas and IFC. Each of the Borrowers is our wholly owned subsidiary. The Senior Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide (each, a “Guarantor”).

The amount drawn under the Senior Credit Facility may not exceed the lesser of (i) $150.0 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. The lenders have an initial aggregate commitment of $80.0 million, with individual commitments of $40.0 million each. The Company has the ability to increase the commitments up to an aggregate of $150.0 million by March 31, 2016. On the first day of each fiscal quarter commencing April 1, 2016, the lenders’ commitments are subject to reduction in an amount equal to 7.69% of the aggregate commitments in effect on April 1, 2016.

The borrowing base amount is re-determined semi-annually on April 1st and October 1st of each year, beginning April 1, 2015. The current borrowing base is $74.6 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; and

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

The Senior Credit Facility matures on the earlier of (i) March 31, 2019, or (ii) the last date of the borrowing base calculation period that immediately precedes the date that the semi-annual banking case of BNP Paribas 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 banking case prepared by BNP Paribas and the Borrowers. The Senior 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.

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Loans under the Senior Credit Facility accrue interest at a rate of three-month LIBOR plus 5.00% per annum (5.23% at June 30, 2014). The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.00% 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 Senior Credit Facility, and (b) 1.00% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available amount under the Senior Credit Facility and is not available to be borrowed, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to BNP Paribas or (b) 5.00% for all other letters of credit.

The Senior 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 Senior Credit Facility, including maintaining the following financial ratios during the four most recently completed fiscal quarters occurring on or after March 31, 2014:

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

Pursuant to the terms of the Senior Credit Facility, until amounts under the Senior Credit Facility are repaid, each of the Borrowers shall not, and shall cause each of its subsidiaries not to, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to create any liens, (iii) enter into any merger, consolidation or amalgamation, liquidate or dissolve, (iv) dispose of any property or business, (v) pay any dividends, distributions or similar payments to shareholders, (vi) make certain types of investments, (vii) enter into any transactions with an affiliate, (viii) enter into a sale and leaseback arrangement, (ix) engage in any business or business activity, own any assets or assume any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and natural gas exploration and production company or operate or carry on business in any jurisdiction outside of Turkey or its jurisdiction of formation, (x) change its organizational documents, (xi) permit its fiscal year to end on a day other than December 31st or change its method of determining fiscal quarters, or alter the accounting principles it uses, (xii) modify certain hydrocarbon licenses and agreements or material contracts, (xiii) enter into any hedge agreement for speculative purposes, (xiv) open or maintain new deposit, securities or commodity accounts, (xv) use the proceeds from any loan in the territories of any country that is not a member of the World Bank, (xvi) incur any expenditure that is not covered by the projections in the most recent corporate cashflow projection, (xvii) modify its social and environmental action plans as determined in conjunction with IFC, (xviii) enter into any transaction or engage in any activity prohibited by the United Nations Security Council, or (xix) engage in any corrupt, fraudulent, coercive, collusive or obstructive practice.

An event of default under the Senior Credit Facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and beneficially, all of the equity of the Borrowers or any Guarantor or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or Guarantor; (ii) the failure by the Borrowers to own or hold, directly or indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated in the Senior Credit Facility; or (iii) (a) Mr. Mitchell ceases

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for any reason to be the executive chairman of our board of directors at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner, directly or indirectly, of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis; provided, that, if Mr. Mitchell ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute an event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event.

As of July 1, 2014, we had outstanding borrowings of $59.8 million under the Senior Credit Facility and availability of $14.8 million.

TBNG credit facility

On June 18, 2013, our wholly owned subsidiary, Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”), entered into a 78.8 million New Turkish Lira (“TRY”) (approximately $37.1 million at June 30, 2014) unsecured line of credit with a Turkish bank, of which 60 million TRY is available in cash for TBNG and 18.8 million TRY is available in the form of non-cash bank guarantees and letters of credit for TBNG and several other of our wholly owned subsidiaries operating in Turkey. The interest rate is established at the time of each borrowing. We have made three borrowings under this credit facility, on October 9, 2013, November 5, 2013 and January 22, 2014, each of which has a one-year term at a fixed interest rate of 4.6% per annum. At maturity, we expect to renew the borrowings for one additional year at then current market interest rates. As of June 30, 2014, we had borrowed $26.7 million under this credit facility.

Unsecured lines of credit

Our wholly owned subsidiaries operating in Turkey are party to unsecured, non-interest bearing lines of credit with a Turkish bank. At June 30, 2014, we had outstanding borrowings of $1.6 million under these lines of credit.

7. Contingencies relating to production leases and exploration permits

Selmo

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.

Morocco

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 believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during 2012 for this contingency.

Aglen

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 2012 for this contractual obligation.

Direct Petroleum

In July 2013, we entered into a second amendment (the “Amendment”) to the purchase agreement (the “Purchase Agreement”) with Direct Petroleum Exploration, LLC (“Direct”). The Amendment set forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. We completed the drilling and testing requirements pursuant to the Amendment during April 2014, which resulted in the reversal of the $2.5 million contingent liability recorded in 2011. The reversal is recognized in our consolidated statements of comprehensive income (loss) under the caption “Revaluation of contingent consideration” during the six months ended June 30, 2014.

In addition, the Amendment provides that we will issue $7.5 million in common shares if the Deventci-R2 well is a commercial success (as defined in the Purchase Agreement) on or prior to May 1, 2016. We will record any provision for this contingent consideration when it is estimable and probable. As of June 30, 2014, we had not recorded a contingent liability for this contingent consideration. Any adjustment will be recorded when it becomes probable and estimable.

Additionally, the Amendment provides that if the Bulgarian government issues a production concession over the stefenetz concession area (the “Stefenetz Concession Area”), Direct will be entitled to a payment of $10.0 million in common shares, or a pro rata amount if the production concession is less than 200,000 acres. We do not have enough information to estimate the potential contingent liability we would incur in the event the Bulgarian government issues a production concession over the Stefenetz Concession Area. Any adjustment will be recorded when it becomes probable and estimable.

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8. Shareholders’ equity

Reverse stock split

On March 4, 2014, our shareholders approved a 1-for-10 reverse stock split, which became effective March 6, 2014. Pursuant to the reverse stock split, all shareholders of record received one common share for each ten common shares owned (subject to minor adjustments as a result of fractional shares). The reverse stock split reduced the issued and outstanding common shares as of March 4, 2014 from 374,026,984 to 37,402,698. U.S. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all common share amounts and transactions herein have been adjusted to reflect the 1-for-10 reverse stock split.

Restricted stock units

Share-based compensation expense of approximately $0.3 million and $0.7 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three and six months ended June 30, 2014, respectively. We recorded share-based compensation expense of $0.5 million and $0.9 million for the three and six months ended June 30, 2013, respectively.

As of June 30, 2014, we had approximately $1.4 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.7 years.

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 and six months ended June 30, 2014 and 2013 equals net income divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding RSUs. Diluted earnings per common share for the three and six months ended June 30, 2014 and 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 RSUs. For the three and six months ended June 30, 2014 and 2013, there were no dilutive securities included in the calculation of diluted earnings per share.

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

	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands, except per share amounts)	2014		2013		2014			2013
Net income from continuing operations	$	1,437	$	2,903	$	5,430		$	5,935
Net loss from discontinued operations	$	—	$	—	$	(20	)	$	(93	)
Basic net income per common share:
Shares:
Weighted average shares outstanding		37,411		36,893		37,402			36,891
Basic net income per common share:
Continuing operations	$	0.04	$	0.08	$	0.15		$	0.16
Discontinued operations	$	0.00	$	0.00	$	0.00		$	0.00
Diluted net income per common share:
Shares:
Weighted average common and common equivalent shares outstanding		37,411		36,893		37,402			36,891
Diluted net income per common share:
Continuing operations	$	0.04	$	0.08	$	0.15		$	0.16
Discontinued operations	$	0.00	$	0.00	$	0.00		$	0.00

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9. Segment information

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

	Corporate			Turkey		Bulgaria			Total
	(in thousands)
For the three months ended June 30, 2014
Total revenues	$	—		$	41,051	$	10		$	41,061
Income (loss) from continuing operations before income taxes		(3,082	)		5,819		(73	)		2,664
Capital expenditures	$	64		$	27,540	$	334		$	27,938
For the three months ended June 30, 2013
Total revenues	$	2		$	30,486	$	28		$	30,516
Income (loss) from continuing operations before income taxes		(3,154	)		1,525		4,712			3,083
Capital expenditures	$	—		$	27,147	$	—		$	27,147
For the six months ended June 30, 2014
Total revenues	$	—		$	74,690	$	17		$	74,707
Income (loss) from continuing operations before income taxes		(6,902	)		13,319		2,290			8,707
Capital expenditures	$	233		$	49,321	$	1,375		$	50,929
For the six months ended June 30, 2013
Total revenues	$	2		$	64,462	$	96		$	64,560
Income (loss) from continuing operations before income taxes		(6,134	)		9,897		4,612			8,375
Capital expenditures	$	—		$	45,846	$	—		$	45,846
Segment assets
June 30, 2014	$	13,464		$	338,754	$	6,710		$	358,928	(1)
December 31, 2013	$	14,070		$	321,749	$	10,231		$	346,050	(1)
Goodwill
June 30, 2014	$	—		$	7,574	$	—		$	7,574
December 31, 2013	$	—		$	7,535	$	—		$	7,535

(1) Excludes assets held for sale from our discontinued Moroccan operations of $29,000 and $536,000 at June 30, 2014 and December 31, 2013, respectively.

10. Financial instruments

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities and our loan payable were each estimated to have a fair value approximating the carrying amount at June 30, 2014 and December 31, 2013, 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 Senior 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 TRY. We are also subject to foreign currency exposures resulting from translating the functional currency of our foreign subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At June 30, 2014, we had 8.2 million TRY (approximately $3.9 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY.

Commodity price risk

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including, but not limited to, supply and demand. At June 30, 2014 and December 31, 2013, 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.

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Fair value measurements

The following table summarizes the valuation of our financial assets and liabilities as of June 30, 2014:

	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)	$	—	$	(13,995	)	$	—	$	(13,995	)
Total	$	—	$	(13,995	)	$	—	$	(13,995	)

The following table summarizes the valuation of our financial assets and liabilities as of December 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)	$	—	$	(7,967	)	$	—	$	(7,967	)
Total	$	—	$	(7,967	)	$	—	$	(7,967	)

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.

11. Related party transactions

The following table summarizes related party accounts receivable and accounts payable as of the dates indicated:

	June 30, 2014		December 31, 2013
	(in thousands)
Related party accounts receivable:
Viking International master services agreement	$	171	$	939
Riata Management service agreement		21		65
Total related party accounts receivable	$	192	$	1,004
Related party accounts payable:
Viking International master services agreement	$	7,258	$	15,956
Viking Geophysical master services agreement		18		6,800
Riata Management service agreement		421		334
Total related party accounts payable	$	7,697	$	23,090

For the three and six months ended June 30, 2014 and 2013, we incurred expenditures of $31.6 million and $50.6 million, and $17.5 million and $37.7 million, respectively, related to our various related party agreements.

12. 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.

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The assets and liabilities held for sale are summarized as follows:

	June 30, 2014		December 31, 2013
	(in thousands)
Cash	$	16	$	23
Other assets		13		513
Total assets held for sale	$	29	$	536
Accrued expenses and other liabilities	$	7,533	$	7,559
Total liabilities held for sale	$	7,533	$	7,559

Our operating results from discontinued operations for the three and six months ended June 30, 2014 and 2013 are summarized as follows:

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
	2014		2013			2014			2013
	(in thousands)
Total revenues	$	—	$	—		$	—		$	—
Total costs and expenses		—		(52	)		(20	)		(138	)
Total other income (expense)		—		52			—			45
Loss from discontinued operations before income taxes		—		—			(20	)		(93	)
Income tax provision		—		—			—			—
Net loss from discontinued operations	$	—	$	—		$	(20	)	$	(93	)

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

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

Executive Overview

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored petroleum systems, are net importers of petroleum, have existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of June 30, 2014, we held interests in approximately 1.8 million net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of August 1, 2014, 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 second quarter of 2014 include:

• We reported $1.4 million of net income from continuing operations for the three months ended June 30, 2014, as compared to $2.9 million for the same period in 2013.

• We derived 81.0% of our revenues from the production of oil, 17.5% of our revenues from the production of natural gas and 1.5% of our revenues from other sources during the three months ended June 30, 2014.

• Total oil and natural gas sales revenues increased 37% to $40.4 million for the quarter ended June 30, 2014, from $29.5 million in the same period in 2013. The increase was primarily the result of an increase in sales volumes of 89 thousand barrels of oil equivalent (“Mboe”) and an increase in the average sales price of $8.40 per barrel of oil equivalent (“Boe”).

• Wellhead production was 319 thousand barrels (“Mbbls”) of oil and 890 million cubic feet (“Mmcf”) of natural gas for the quarter ended June 30, 2014, as compared to 231 Mbbls of oil and 926 Mmcf of natural gas for the same period in 2013.

• For the quarter ended June 30, 2014, we incurred $28.7 million in capital expenditures, including license acquisition and seismic expenditures from continuing operations, as compared to $28.1 million for the quarter ended June 30, 2013.

• As of June 30, 2014, we had $59.8 million in long-term debt and $28.3 million in short-term debt, as compared to $26.5 million in long-term debt and $43.3 million in short-term debt as of December 31, 2013.

Recent Developments

Senior Credit Facility. On May 6, 2014, DMLP, Ltd. (“DMLP”), TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey Ltd., Amity Oil International Pty Ltd (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”)(collectively, the “Borrowers”) entered into a senior secured credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP Paribas”) and the International Finance Corporation (“IFC”). Each of the Borrowers is our wholly owned subsidiary. The Senior Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) (each, a “Guarantor”). We used the proceeds from the Senior Credit Facility to pay off in full our prior senior secured credit facility on May 15, 2014, and to fund our oil and natural gas development and exploration activities in Turkey.

Changes in Management. On May 27, 2014, our board of directors appointed Todd C. Dutton as president and James R. Huling as chief operating officer of the Company. On June 16, 2014, we announced that our board of directors appointed Harold “Lee” Muncy as vice president of geosciences. In addition, our board of directors accepted the resignation of vice president, legal and corporate secretary Jeffrey S. Mecom and appointed Matthew W. McCann as general counsel and corporate secretary effective as of August 6, 2014. Mr. Mecom plans to remain at the Company in an advisory capacity through September 8, 2014.

Second Quarter 2014 Operational Update

During the second quarter of 2014, we continued to develop our oil fields in southeastern Turkey and our Thrace Basin natural gas fields in northwestern Turkey, and tested the Deventci-R2 well in Bulgaria.

Turkey-Southeast

Molla. We completed shooting our Molla 3D seismic program of approximately 800 km² in April 2014. The final phase of processed data is projected to be delivered in the third quarter of 2014. We recently drilled the Bahar-2ST and Bahar-3 wells, both of which are being completed. We also commenced drilling the Bahar-4 and Bahar-6, vertical wells, which we expect will yield additional confirmation of the Bahar structure. For the remainder of 2014, we expect to spud at least two additional vertical Bahar wells. We also plan to drill one Mardin horizontal well based on our new Molla 3D seismic data.

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Selmo. We drilled three MSD horizontal wells, the Selmo-84H, Selmo-54H and Selmo-85H in the second quarter of 2014, and completed two of these wells. We are currently drilling the Selmo-68H3 well. During the first half of 2014, we spudded a total of five MSD horizontal wells, and we expect to spud four additional horizontal wells in the Selmo field during the remainder of 2014.

We initiated a waterflood pilot test program in the Selmo field in which two Selmo wells were converted to injector wells. To date, we have injected more than 250,000 barrels of water into the Selmo field. We believe secondary recovery will increase production from the field, and we intend to convert at least two additional Selmo wells to injector wells in 2014.

Based on the successful results of our five-well polymer injection program in the first quarter of 2014, which added approximately 250 barrels of oil per day (“bbl/d”), we plan to commence a second phase of polymer injections in the third quarter of 2014.

Arpatepe. We completed the Arpatepe-7, a Bedinan appraisal well in the second quarter of 2014. We plan to drill one additional appraisal well and initiate a waterflood pilot test in the Arpatepe field during the remainder of 2014.

Idil. We expect to drill a vertical exploration well on our Idil license in the second half of 2014. Our joint venture partner, Onshore Petroleum Company AS (“Onshore”), will be assigned a 50% interest in the Idil license and will fund 100% of TransAtlantic’s expected share of the cost of this well.

Turkey-Thrace Basin, Northwest

During the second quarter of 2014, we processed the remaining 25% of our Osmanli 3D seismic program. We recently spudded the TDR-5H well. During the remainder of 2014, we expect to drill five conventional shallow wells and one additional horizontal well targeting the Teslimkoy formation in the Thrace Basin.

Bulgaria

In the second quarter of 2014, we conducted a long-term pressure build-up test on the Deventci-R2 well to evaluate its connectivity to the reservoir following an initial production test of approximately 2.0 million cubic feet per day (“Mmcf/d”) of natural gas with condensates. On June 26, 2014, we submitted a request to the Bulgarian government to acidize the well. Upon receipt of approval, we plan to stimulate the well to enhance its productivity.

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 bringing these discoveries into production. For the remainder of 2014, we are focused on accomplishing the following objectives:

• Increase Reserves and Production. In the second quarter of 2014, we increased our average net sales volumes per day by 8% from the first quarter of 2014, and by 24% from the second quarter of 2013. We plan to continue to grow our oil and natural gas reserves and production in Turkey through exploration and development on our Selmo, Molla and Thrace Basin exploration licenses and production leases, including the application of 3D seismic, horizontal drilling and fracture stimulation techniques. During the remainder of 2014, we plan to drill, or participate in the drilling of, approximately nine new gross wells in southeastern Turkey and approximately six new gross wells in northwestern Turkey.

• Utilize New 3D Seismic Data to Improve Well Targeting. During the year ended December 31, 2013, we spent $12.8 million shooting 3D seismic over areas of Turkey where 3D seismic data did not previously exist. We expect this new data will improve our ability to target well locations, drill wells and ultimately delineate hydrocarbon reservoirs.

• Expand the Use of Horizontal Drilling. During 2013, we expanded our use of horizontal drilling, employing it on 13 of 35 wells drilled, with successful results in the Selmo, Molla and Thrace Basin areas. During the remainder of 2014, we anticipate that extensive use of horizontal drilling techniques on our wells in southeastern and northwestern Turkey will more effectively extract hydrocarbons and increase our returns on invested capital.

• Further Expand Fracture Stimulation Program. In 2013, we expanded our use of hydraulic fracturing technology to complete otherwise low productive formations in Turkey. The evolution of fracturing fluid and stimulation design has yielded positive results in both northwestern and southeastern Turkey. For the remainder of 2014, we plan to continue optimizing our hydraulic fracturing techniques to improve well performance and economics.

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• Pursue Other Growth Opportunities. In addition to growing our reserves and production through the exploration and development of our substantial acreage in Turkey and Bulgaria, we continually evaluate acquisition, joint venture and farm-in/out opportunities. We are focused on both strengthening our positions in Turkey and Bulgaria and identifying opportunities in new countries.

We expect net field capital expenditures for the remainder of 2014 to range between $45.0 million and $55.0 million for the drilling and completion of approximately 15 gross wells, the recompletion of approximately 15 existing gross wells, the processing of remaining seismic data, infrastructure improvements and other capital investments. Of these expenditures, we expect to spend approximately 75% in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Selmo, Arpatepe and Molla and processing seismic data. We expect to spend most of the remaining anticipated expenditures in northwestern Turkey, devoted to developing conventional and unconventional natural gas production and building infrastructure. We expect cash on hand, borrowings from our credit facilities and cash flow from operations will be sufficient to fund the remainder of our 2014 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2014 capital expenditure budget is subject to change. We currently plan to execute the following drilling and exploration activities during the third and fourth quarters of 2014:

Turkey. We plan to drill approximately 15 gross wells, six of which are expected to be drilled horizontally and approximately 75% of which will be fracture stimulated. We also plan to continue our waterflood pilot test and polymer injection programs.

Bulgaria. We plan to perform additional completion activities on the Deventci-R2 well pending approval from the Bulgarian government to acidize the well.

Discontinued Operations in Morocco

In June 2011, we discontinued 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 and six months ended June 30, 2014 and June 30, 2013.

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 2. Significant accounting policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2013 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, 2013.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08,Reporting Discontinued Operations and Disclosures of Components of an Entity(“ASU 2014-08”). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. Currently, we do not expect the adoption of ASU 2014-08 to have a material impact on our consolidated financial statements or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers(“ASU 2014-09”). ASU 2014-09 amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods or services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The update is effective for periods beginning after December 15, 2016. We are currently assessing the potential impact of ASU 2014-09 on our consolidated financial statements and results of operations.

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

Results of Operations—Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

Our results of operations for the three months ended June 30, 2014 and 2013 were as follows:

	Three Months Ended June 30,						Change
	2014			2013			2014-2013
	(in thousands of U.S. dollars, except per unit amounts and volumes)
Welhead Production:
Oil (Mbbl)		319			231			88
Natural gas (Mmcf)		890			926			(36	)
Total production (Mboe)		467			385			82
Average daily wellhead production (Boepd)		5,132			4,231			901
Sales volumes:
Oil (Mbbl)		318			230			88
Natural gas (Mmcf)		821			816			5
Total production (Mboe)		455			366			89
Average daily sales volumes (Boepd)		5,000			4,022			978
Average prices:
Oil (per Bbl)	$	104.53		$	94.13		$	10.40
Natural gas (per Mcf)	$	8.77		$	9.57		$	(0.80	)
Oil equivalent (per Boe)	$	88.88		$	80.48		$	8.40
Revenues:
Oil and natural gas sales	$	40,441		$	29,455		$	10,986
Sales of purchased natural gas		491			719			(228	)
Other		129			342			(213	)
Costs and expenses:
Production	$	4,666		$	3,328		$	1,338
Exploration, abandonment and impairment		3,775			11,885			(8,110	)
Cost of purchased natural gas		440			619			(179	)
Seismic and other exploration		892			1,090			(198	)
Revaluation of contingent consideration		—			(5,000	)		5,000
General and administrative		7,460			6,893			567
Depletion		12,022			8,976			3,046
Depreciation and amortization		566			605			(39	)
Interest and other expense		1,769			955			814
Foreign exchange (gain) loss		(2,494	)		2,543			(5,037	)
(Loss) gain on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	(1,781	)	$	(484	)	$	(1,297	)
Change in fair value on commodity derivative contracts		(7,741	)		4,762			(12,503	)
Total (loss) gain on commodity derivative contracts	$	(9,522	)	$	4,278		$	(13,800	)
Oil and natural gas costs per Boe:
Production	$	8.98		$	7.96		$	1.02
Depletion	$	23.14		$	21.46		$	1.68

Oil and Natural Gas Sales. Total oil and natural gas sales revenues increased $10.9 million to $40.4 million for the three months ended June 30, 2014, from $29.5 million realized in the same period in 2013. Of this increase, $7.2 million was due to an

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increase in sales volumes of 89 Mboe. Additionally, we realized a higher average price per Boe, which resulted in higher revenues of $3.8 million. Our average price received increased $8.40 per Boe to $88.88 per Boe for the three months ended June 30, 2014, from $80.48 per Boe for the same period in 2013.

Production.Production expenses for the three months ended June 30, 2014 increased to $4.7 million or $8.98 per Boe, from $3.3 million or $7.96 per Boe for the same period in 2013. The increase was primarily attributable to $1.1 million of operating expenses, which we billed back to our Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) joint venture partners during the three months ended June 30, 2013, following a redetermination of operating costs.

Exploration, Abandonment and Impairment.Exploration, abandonment and impairment costs for the three months ended June 30, 2014 decreased approximately $8.1 million to $3.8 million, from $11.9 million for the same period in 2013. During the three months ended June 30, 2014, we recorded impairment charges of $2.8 million primarily related to the Kazanci-5 well, compared to the three months ended June 30, 2013, when we incurred license impairment charges of $4.6 million. Additionally, three wells were written off for $6.1 million during three months ended June 30, 2013.

General and Administrative. General and administrative expense was $7.5 million for the three months ended June 30, 2014, as compared to $6.9 million for the same period in 2013. The increase was primarily due to an increase in employee-related costs of $0.9 million and an increase in travel expenses of $0.1 million, which was partially offset by a decrease in accounting and consulting expenses of $0.4 million. Employee-related costs increased primarily due to severance payments made to former employees. Accounting and consulting expenses were higher during the three months ended June 30, 2013 primarily due to the late filing of our Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2013.

Depletion.Depletion increased to $12.0 million or $23.14 per Boe for the three months ended June 30, 2014, compared to $9.0 million or $21.46 per Boe for the same period of 2013. The increase was primarily due to additions to proved properties during the three months ended June 30, 2014.

Interest and Other Expense. Interest and other expense increased to $1.8 million for the three months ended June 30, 2014, as compared to $1.0 million for the same period in 2013. The increase was primarily due to a $0.5 million write-off of loan financing costs related to the amended and restated credit facility, which was repaid in May 2014. Also contributing to the increase was an increase in our average level of debt outstanding during the three months ended June 30, 2014 compared to the same period in 2013. At June 30, 2014, we had $88.1 million of total debt outstanding, compared to $39.8 million at June 30, 2013.

Foreign Exchange (Gain) Loss.We recorded a foreign exchange gain of $2.5 million during the three months ended June 30, 2014, compared to a loss of $2.5 million for the same period of 2013. The change in foreign exchange was primarily unrealized (non-cash) in nature and resulted from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the New Turkish Lira (“TRY”) amount if it has not been settled previously. The increase in foreign exchange gain during the three months ended June 30, 2014 was due to an increase in the value of the TRY compared to the U.S. Dollar, versus the decrease in the value of the TRY compared to the U.S. Dollar for the three months ended June 30, 2013.

(Loss) Gain on Commodity Derivative Contracts. During the three months ended June 30, 2014, we recorded a net loss on commodity derivative contracts of approximately $9.5 million, as compared to a net gain of $4.3 million for the same period in 2013. During the three months ended June 30, 2014, we recorded a $7.7 million loss to mark our commodity derivatives to their fair value and a $1.8 million loss on settled contracts. During the same period in 2013, we recorded a $4.8 million gain to mark our commodity derivatives to their fair value and a $0.5 million loss on settled contracts. We are required under our Senior Credit Facility to hedge no less than 30% of our anticipated oil sales volumes in our oil fields in Turkey.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations for the three months ended June 30, 2014 and 2013 have been included in discontinued operations.

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

	Three Months Ended June 30,
	2014		2013
	(in thousands)
Costs and expenses:
Production	$	—	$	41
General and administrative		—		11
Total costs and expenses		—		52
Operating loss		—		(52	)
Other income (expense):
Interest and other expense		—		(6	)
Interest and other income		—		58
Total other income		—		52
Net income from discontinued operations	$	—	$	—

Results of Operations—Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Our results of operations for the six months ended June 30, 2014 and 2013 were as follows:

	Six Months Ended June 30,						Change
	2014			2013			2014-2013
	(in thousands of U.S. dollars, except per unit amounts and volumes)
Wellhead production:
Oil (Mbbl)		580			476			104
Natural gas (Mmcf)		1,950			1,782			168
Total production (Mboe)		905			773			132
Average daily wellhead production (Boepd)		5,000			4,271			729
Sales volumes:
Oil (Mbbl)		578			470			108
Natural gas (Mmcf)		1,755			1,616			139
Total production (Mboe)		871			739			132
Average daily sales volumes (Boepd)		4,812			4,083			729
Average prices:
Oil (per Bbl)	$	101.06		$	98.44		$	2.62
Natural gas (per Mcf)	$	8.52		$	9.85		$	(1.33	)
Oil equivalent (per Boe)	$	84.30		$	84.14		$	0.16
Revenues:
Oil and natural gas sales	$	73,425		$	62,180		$	11,245
Sales of purchased natural gas		1,036			1,525			(489	)
Other		246			855			(609	)
Costs and expenses:
Production	$	8,797		$	8,855		$	(58	)
Exploration, abandonment and impairment		7,916			15,749			(7,833	)
Cost of purchased natural gas		925			1,331			(406	)
Seismic and other exploration		4,186			1,333			2,853
Revaluation of contingent consideration		(2,500	)		(5,000	)		2,500
General and administrative		14,012			14,416			(404	)
Depletion		21,581			17,362			4,219
Depreciation and amortization		1,097			1,195			(98	)
Interest and other expense		2,972			1,845			1,127
Foreign exchange (gain) loss		(1,150	)		3,030			(4,180	)
(Loss) gain on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	(2,533	)	$	(1,736	)	$	(797	)
Change in fair value on commodity derivative contracts		(6,027	)		5,238			(11,265	)
Total (loss) gain on commodity derivative contracts	$	(8,560	)	$	3,502		$	(12,062	)
Oil and natural gas costs per Boe:
Production	$	8.85		$	10.49		$	(1.64	)
Depletion	$	21.71		$	20.56		$	1.15

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Oil and Natural Gas Sales. Total oil and natural gas sales revenues increased $11.2 million to $73.4 million for the six months ended June 30, 2014, from $62.2 million realized in the same period in 2013. Of this increase, $11.1 million was due to an increase in sales volumes of 132 Mboe. Additionally, we realized a slightly higher average price per Boe, which resulted in an additional $0.1 million of revenue. Our average price received increased $0.16 per Boe to $84.30 per Boe for the six months ended June 30, 2014, from $84.14 per Boe for the same period in 2013.

Production.Production expenses for the six months ended June 30, 2014 decreased to $8.8 million or $8.85 per Boe, from $8.9 million or $10.49 per Boe for the same period in 2013. The decrease of $1.64 per Boe was primarily attributable to an increase in our working interest production volumes during the six months ended June 30, 2014 compared to the same period in 2013.

Exploration, Abandonment and Impairment.Exploration, abandonment and impairment costs for the six months ended June 30, 2014 decreased approximately $7.8 million to $7.9 million, from $15.7 million for the same period in 2013. During the six months ended June 30, 2014, we impaired two wells for $6.3 million. During the six months ended June 30, 2013, we wrote off four wells for $10.0 million and incurred license impairment charges of $4.6 million.

Seismic and Other Exploration.Seismic and other exploration costs increased to $4.2 million for the six months ended June 30, 2014, as compared to $1.3 million for the same period in 2013. The increase was primarily due to seismic acquisition activity conducted on our West Molla and Osmanli licenses during the six months ended June 30, 2014.

General and Administrative. General and administrative expense was $14.0 million for the six months ended June 30, 2014, compared to $14.4 million for the same period in 2013. The decrease was primarily due to a decrease of $0.6 million in accounting and consulting expenses and a $0.2 million decrease in office expenses and rent, which was partially offset by a $0.4 million increase in employee-related costs. Accounting and consulting expenses were higher during the six months ended June 30, 2013 primarily due to the late filing of our Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2013. Employee-related costs increased during the six months ended June 30, 2014 primarily due to severance payments made to former employees.

Depletion.Depletion increased to $21.6 million or $21.71 per Boe for the six months ended June 30, 2014, compared to $17.4 million or $20.56 per Boe for the six months ended June 30, 2013. The increase was primarily due to additions to proved properties during the six months ended June 30, 2014.

Interest and Other Expense. Interest and other expense increased to $3.0 million for the six months ended June 30, 2014, compared to $1.8 million for the same period in 2013. The increase was primarily due to an increase in our average level of debt outstanding during the six months ended June 30, 2014 compared to the same period in 2013. At June 30, 2014, we had $88.1 million of total debt outstanding, compared to $39.8 million at June 30, 2013. Also contributing to the increase was a $0.5 million write-off of loan financing costs related to the amended and restated credit facility, which was repaid in May 2014.

Foreign Exchange (Gain) Loss.We recorded a foreign exchange gain of $1.2 million during the six months ended June 30, 2014, compared to a loss of $3.0 million in the same period of 2013. The change in foreign exchange was primarily unrealized (non-cash) in nature and resulted from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the TRY amount if it has not been settled previously. The increase in foreign exchange gain during the six months ended June 30, 2014 was due to an increase in the value of the TRY compared to the U.S. Dollar, versus the decrease in the value of the TRY compared to the U.S. Dollar for the six months ended June 30, 2013.

(Loss) Gain on Commodity Derivative Contracts. During the six months ended June 30, 2014, we recorded a net loss on commodity derivative contracts of approximately $8.6 million, compared to a net gain of $3.5 million for the same period in 2013. During the six months ended June 30, 2014, we recorded a $6.0 million loss to mark our commodity derivatives to their fair value and

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a $2.5 million loss on settled contracts. During the same period in 2013, we recorded a $5.2 million gain to mark our commodity derivatives to their fair value and a $1.7 million loss on settled contracts. We are required under our Senior Credit Facility to hedge no less than 30% of our anticipated oil sales volumes in our oil fields in Turkey.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations for the six months ended June 30, 2014 and 2013 have been included in discontinued operations.

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

	Six Months Ended June 30,
	2014			2013
	(in thousands)
Costs and expenses:
Production	$	—		$	110
General and administrative		20			28
Total costs and expenses		20			138
Operating loss		(20	)		(138	)
Other income (expense):
Interest and other expense		—			(8	)
Interest and other income		—			53
Total other income		—			45
Net loss from discontinued operations	$	(20	)	$	(93	)

Capital Expenditures

For the quarter ended June 30, 2014, we incurred $28.7 million in capital expenditures, including license acquisition and seismic expenditures from continuing operations, as compared to $28.1 million for the quarter ended June 30, 2013.

Capital expenditures, including seismic expenditures, for the third and fourth quarters of 2014 are expected to range between $45.0 million and $55.0 million. We expect to spend approximately 75% of these anticipated expenditures in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Selmo, Arpatepe and Molla and processing seismic data. We expect to spend most of the remaining anticipated expenditures in northwestern Turkey, devoted to developing conventional and unconventional natural gas production and building infrastructure. Our projected 2014 capital budget is subject to change, and if cash on hand, borrowings from our credit facilities, 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 second quarter of 2014 were our cash and cash equivalents, cash flow from operations and net borrowings under our Senior Credit Facility. At June 30, 2014, we had cash and cash equivalents of $5.2 million, $28.3 million in short-term debt, $59.8 million in long-term debt, and a working capital deficit of $12.5 million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities), compared to cash and cash equivalents of $12.9 million, $43.3 million in short-term debt, $26.5 million in long-term debt, and a working capital deficit of $39.4 million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities) at December 31, 2013. Net cash provided by operating activities from continuing operations for the six months ended June 30, 2014 decreased to $41.5 million, as compared to net cash provided by operating activities from continuing operations of $55.7 million for the six months ended June 30, 2013. This decrease was primarily a result of a decrease in our accounts payable during the six months ended June 30, 2014, compared to an increase in our accounts payable during the same period in 2013.

As of June 30, 2014, the outstanding principal amount of our debt was $88.1 million. In addition to cash, cash equivalents and cash flow from operations, at June 30, 2014, we had a Senior Credit Facility and a credit facility with a Turkish bank, which are discussed below.

Senior Credit Facility. On May 6, 2014, the Borrowers entered into the Senior Credit Facility with BNP Paribas and IFC. The Senior Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide.

The amount drawn under the Senior Credit Facility may not exceed the lesser of (i) $150.0 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. The lenders have an initial aggregate

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commitment of $80.0 million, with individual commitments of $40.0 million each. The Company has the ability to increase the commitments up to an aggregate of $150.0 million by March 31, 2016. On the first day of each fiscal quarter commencing April 1, 2016, the lenders’ commitments are subject to reduction in an amount equal to 7.69% of the aggregate commitments in effect on April 1, 2016.

The borrowing base amount is re-determined semi-annually on April 1st and October 1st of each year, beginning April 1, 2015. The current borrowing base is $74.6 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; and

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

The Senior Credit Facility matures on the earlier of (i) March 31, 2019, or (ii) the last date of the borrowing base calculation period that immediately precedes the date that the semi-annual banking case of BNP Paribas 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 banking case prepared by BNP Paribas and the Borrowers. The Senior 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 Senior Credit Facility accrue interest at a rate of three-month LIBOR plus 5.00% per annum (5.23% at June 30, 2014). The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.00% 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 Senior Credit Facility, and (b) 1.00% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available amount under the Senior Credit Facility and is not available to be borrowed, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to BNP Paribas or (b) 5.00% for all other letters of credit.

The Senior 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 Senior Credit Facility, including maintaining the following financial ratios during the four most recently completed fiscal quarters occurring on or after March 31, 2014:

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

Pursuant to the terms of the Senior Credit Facility, until amounts under the Senior Credit Facility are repaid, each of the Borrowers shall not, and shall cause each of its subsidiaries not to, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to create any liens, (iii) enter into any merger, consolidation or amalgamation, liquidate or dissolve, (iv) dispose of any property or business, (v) pay any dividends, distributions or similar payments to shareholders, (vi) make certain types of investments, (vii) enter into any transactions with an affiliate, (viii) enter into a sale and leaseback arrangement, (ix) engage in any business or business activity, own any assets or assume

25

any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and natural gas exploration and production company or operate or carry on business in any jurisdiction outside of Turkey or its jurisdiction of formation, (x) change its organizational documents, (xi) permit its fiscal year to end on a day other than December 31st or change its method of determining fiscal quarters, or alter the accounting principles it uses, (xii) modify certain hydrocarbon licenses and agreements or material contracts, (xiii) enter into any hedge agreement for speculative purposes, (xiv) open or maintain new deposit, securities or commodity accounts, (xv) use the proceeds from any loan in the territories of any country that is not a member of the World Bank, (xvi) incur any expenditure that is not covered by the projections in the most recent corporate cashflow projection, (xvii) modify its social and environmental action plans as determined in conjunction with IFC, (xviii) enter into any transaction or engage in any activity prohibited by the United Nations Security Council, or (xix) engage in any corrupt, fraudulent, coercive, collusive or obstructive practice.

An event of default under the Senior Credit Facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and beneficially, all of the equity of the Borrowers or any Guarantor or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or Guarantor; (ii) the failure by the Borrowers to own or hold, directly or indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated in the Senior Credit Facility; or (iii) (a) Mr. Mitchell ceases for any reason to be the executive chairman of our board of directors at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner, directly or indirectly, of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis; provided, that, if Mr. Mitchell ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute an event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event.

At July 1, 2014, we had borrowings of $59.8 million under the Senior Credit Facility and availability of $14.8 million.

TBNG Credit Facility. On June 18, 2013, TBNG entered into a 78.8 million TRY (approximately $37.1 million at June 30, 2014) unsecured line of credit with a Turkish bank, of which 60 million TRY is available in cash for TBNG and 18.8 million TRY is available in the form of non-cash bank guarantees and letters of credit for TBNG and several other of our wholly owned subsidiaries operating in Turkey. The interest rate will be established at the time of each borrowing. We have made three borrowings under this credit facility, each of which has a one-year term at a fixed interest rate of 4.6% per annum. At maturity, we expect to renew the borrowings for one additional year at then current market interest rates. As of June 30, 2014, we had borrowed $26.7 million under this credit facility with no remaining availability.

Contingencies Relating to Production Leases and Exploration Permits

Selmo

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.

Morocco

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 believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during 2012 for this contingency.

Aglen

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 2012 for this contractual obligation.

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Direct Petroleum

In July 2013, we entered into a second amendment (the “Amendment”) to the purchase agreement (the “Purchase Agreement”) with Direct Petroleum Exploration, LLC (“Direct”). The Amendment set forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. We completed the drilling and testing requirements pursuant to the Amendment during April 2014, which resulted in the reversal of the $2.5 million contingent liability recorded in 2011. The reversal is recognized in our consolidated statements of comprehensive income (loss) under the caption “Revaluation of contingent consideration” during the six months ended June 30, 2014.

In addition, the Amendment provides that we will issue $7.5 million in common shares if the Deventci-R2 well is a commercial success (as defined in the Purchase Agreement) on or prior to May 1, 2016. We will record any provision for this contingent consideration when it is estimable and probable. As of June 30, 2014, we had not recorded a contingent liability for this contingent consideration.

Additionally, the Amendment provides that if the Bulgarian government issues a production concession over the stefenetz concession area (the “Stefenetz Concession Area”), Direct will be entitled to a payment of $10.0 million in common shares, or a pro rata amount if the production concession is less than 200,000 acres. We do not have enough information to estimate the potential contingent liability we would incur in the event the Bulgarian government issues a production concession over the Stefenetz Concession Area. Any adjustment will be recorded when it becomes probable and estimable.

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, 2013.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at June 30, 2014.

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.

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Item  3. Quantitative and Qualitative Disclosures About Market Risk

During the second quarter of 2014, 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, 2013. Our oil derivatives contracts are settled based on Brent crude oil pricing. The following tables set forth our outstanding derivatives contracts with respect to future crude oil production as of June 30, 2014:

Fair Value of Derivative Instruments as of June 30, 2014

Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
									(in thousands)
Collar		July 1, 2014—December 31, 2014		1,770	$	85.00	$	97.25	$	(4,758	)
Collar		January 1, 2015—December 31, 2015		1,410	$	85.00	$	97.25		(6,027	)
									$	(10,785	)

			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, 2016—December 31, 2016		1,066	$	85.00	$	97.25	$	114.25	$	(2,057	)
Three-way collar contract		January 1, 2017—December 31, 2017		888	$	85.00	$	97.25	$	114.25		(851	)
Three-way collar contract		January 1, 2018—December 31, 2018		726	$	85.00	$	97.25	$	114.25		(282	)
Three-way collar contract		January 1, 2019—March 31, 2019		663	$	85.00	$	97.25	$	114.25		(20	)
											$	(3,210	)

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 June 30, 2014, 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, 2013, our chief executive officer and chief financial officer concluded that, as of June 30, 2014, 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.

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Changes in Internal Control over Financial Reporting

There were no changes during the second quarter of 2014 that have affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item  1. Legal Proceedings

During the second quarter of 2014, 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, 2013.

Item  1A. Risk Factors

During the second quarter of 2014, 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, 2013, except as disclosed below:

The majority of our oil is sold to two customers, and the loss of either customer could have a material adverse impact on our results of operations.

Turkiye Petrolleri Anonim Ortakligi (“TPAO”), the national oil company of Turkey, and Türkiye Petrol Rafinerileri A.Ş. (“TUPRAS”), a privately owned oil refinery in Turkey, purchase all of our oil production from the Selmo field. TUPRAS purchases the majority of our oil production from Selmo, representing 66.7% of our total revenues in 2013. If either of these companies reduces their oil purchases or fails to purchase our oil production, or there is a material non-payment, our results of operations could be materially and adversely affected. TPAO or TUPRAS may be subject to their own operating risks that could increase the risk that they could default on their obligations to us.

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

During 2013, we derived 71.3% of our oil production from the Selmo oil field in southeastern Turkey. Historically, the southeastern area of Turkey and nearby countries such as Iran, Iraq and Syria have experienced political, social, security and economic problems, terrorist attacks, insurgencies, war and civil unrest. Since December 2010, political instability has increased markedly in a number of countries in the Middle East and North Africa. As a result of the civil war in Syria, hundreds of thousands of Syrian refugees have fled to Turkey and more can be expected to cross the border as the conflict continues. Moreover, tensions between Turkey and Syria have escalated and hostilities between Turkey and Syria have broken out over a series of incidents, including mortar fire by Syrian forces into Turkey that killed a number of Turkish civilians. On May 10, 2013, a terrorist attack occurred in the Turkish town of Reyhanlı, Hatay in southern Turkey. On March 23, 2014, Turkey shot down a Syrian combat jet on the Turkish-Syrian border.

The instability surrounding the situation in Iraq, as well as tension in and involving the Kurdish regions of northern Iraq, which are contiguous to the region where the Selmo oil field is located, may have political, social or security implications in Turkey or otherwise have a negative impact on the Turkish economy. Stability and security in Iraq have deteriorated significantly in recent months.

Turkey has also experienced problems with domestic terrorist and ethnic separatist groups. For example, Turkey has been in conflict for many years with the People’s Congress of Kurdistan (formerly known as the PKK), an organization that is listed as a terrorist organization by states and organizations, including Turkey, the European Union and the United States. The issue of civil rights for Kurdish citizens remains a potential source of political instability, which may be exacerbated by continuing instability in the Middle East.

The potential impact on our business from such events, conditions and conflicts in these countries is uncertain. We may be unable to access the locations where we conduct operations or transport oil to our offtakers in a reliable manner. In those locations where we have employees or operations, we may incur substantial costs to maintain the safety of our personnel and our operations. Despite these precautions, the safety of our personnel and operations in these locations may continue to be at risk, and we may in the future suffer the loss of employees and contractors or our operations could be disrupted, any of which could have a material adverse effect on our business and results of operations.

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We have concentrated current production of oil in the Selmo oil field.

During 2013, we derived 71.3% of our oil production from the Selmo oil field in southeastern Turkey. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages, litigation or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, we are currently in litigation with a group of villagers who live around the Selmo oil field and who claim ownership of a portion of the surface rights at Selmo. Disruptions in our production of oil in the Selmo oil field from any of these factors could have a material adverse effect on our business and results of operations.

Restrictive covenants in our Senior Credit Facility may restrict our ability to pursue our business strategies and can lead to an event of default that may adversely affect our business, financial condition and results of operations.

The operating and financial restrictions and covenants in our Senior Credit Facility with BNP Paribas and IFC may adversely affect our ability to finance future operations or capital needs or to engage in other business activities. Our Senior Credit Facility contains various covenants that restrict the Borrowers’ ability to, among other things:

• incur additional debt;

• create liens;

• enter into any hedge agreement for speculative purposes;

• engage in business, own any assets or assume any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and natural gas exploration and production company, or operate or carry on the business in any jurisdiction outside of Turkey or its jurisdiction of formation;

• enter into sale and leaseback transactions;

• enter into any merger, consolidation or amalgamation;

• pay any dividends, distributions or other payments to shareholders; or

• enter into any transactions with an affiliate.

In addition, the Senior Credit Facility requires us to maintain specified financial ratios and tests. Various risks, uncertainties and events beyond our control could affect our ability to comply with the covenants and financial tests and ratios required by the Senior Credit Facility and could result in an event of default under the Senior Credit Facility.

An event of default under the Senior Credit Facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios, and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and beneficially, all of the equity of TEMI, Talon Exploration, TransAtlantic Turkey, Ltd., Amity, Petrogas, and DMLP or either of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide; or (ii) the failure by the Borrowers to own or hold, directly or indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated in the Senior Credit Facility. In addition, a change of control under the Senior Credit Facility would result if (a) Mr. Mitchell ceases for any reason to be the executive chairman of our board of directors at any time; (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner, directly or indirectly, of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis; provided that, if Mr. Mitchell ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute an event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event.

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

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Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our results of operations.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

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

None.

Item  3. Defaults Upon Senior Securities

None.

Item  4. Mine Safety Disclosures

Not applicable.

Item  5. Other Information

None.

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Item  6. Exhibits

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	Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
3.3	Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
10.1	Credit Agreement, dated as of May 6, 2014, by and between Amity Oil International Pty Ltd, DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, the lenders party thereto from time to time, and BNP Paribas (Suisse) SA as coordinating mandated lead arranger, sole bookrunner, letter of credit issuer, administrative agent, collateral agent and technical agent and International Finance Corporation, as mandated lead arranger (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014, filed with the SEC on May 8, 2014).
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.

32

Signatures

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

By:	/s/ N. MALONE MITCHELL 3rd
	N. Malone Mitchell 3rd Chief Executive Officer
By:	/s/ WIL F. SAQUETON
	Wil F. Saqueton Chief Financial Officer
Date: August 7, 2014

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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	Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
3.3	Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
10.1	Credit Agreement, dated as of May 6, 2014, by and between Amity Oil International Pty Ltd, DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, the lenders party thereto from time to time, and BNP Paribas (Suisse) SA as coordinating mandated lead arranger, sole bookrunner, letter of credit issuer, administrative agent, collateral agent and technical agent and International Finance Corporation, as mandated lead arranger (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014, filed with the SEC on May 8, 2014).
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.

34