Edgar Filing: TRANSATLANTIC PETROLEUM LTD.

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: September 30, 2013

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

For the transition period from to

Commission file number: 001-34574

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)


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

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

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

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

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

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

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

As of November 1, 2013, the registrant had 373,382,280 common shares outstanding.

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012			1

Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2013 and 2012			2

Consolidated Statements of Equity for the Nine Months Ended September 30, 2013			3

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2013 and 2012			4

Notes to Consolidated Financial Statements			5

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk			26

Item 4. Controls and Procedures			26

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			27

Item 1A. Risk Factors			27

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			27

Item 3. Defaults Upon Senior Securities			27

Item 4. Mine Safety Disclosures			27

Item 5. Other Information			27

Item 6. Exhibits			28

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

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


	September 30, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	12,271		$	14,768
Accounts receivable
Oil and natural gas sales, net		28,949			34,158
Joint interest and other		11,280			18,192
Related party		618			419
Prepaid and other current assets		3,875			2,339
Deferred income taxes		2,469			1,895
Assets held for sale		601			1,619

Total current assets		60,063			73,390

Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		254,070			231,498
Unproved		62,832			68,938
Equipment and other property		42,229			35,747

		359,131			336,183
Less accumulated depreciation, depletion and amortization		(98,025	)		(80,031	)

Property and equipment, net		261,106			256,152
Other long-term assets:
Other assets		7,162			8,195
Note receivable – related party		11,500			11,500
Goodwill		7,906			9,021

Total other assets		26,568			28,716

Total assets	$	347,737		$	358,258

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	14,406		$	12,864
Accounts payable – related party		23,859			15,634
Accrued liabilities		20,385			29,972
Derivative liabilities		2,721			3,908
Asset retirement obligations		916			818
Liabilities held for sale		7,355			8,416

Total current liabilities		69,642			71,612

Long-term liabilities:
Asset retirement obligations		10,362			11,140
Accrued liabilities		6,323			7,548
Deferred income taxes		17,116			16,483
Loan payable		49,766			32,766
Derivative liabilities		3,048			4,882

Total long-term liabilities		86,615			72,819

Total liabilities		156,257			144,431
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.01 par value, 1,000,000,000 shares authorized; 373,382,280 shares issued and outstanding as of September 30, 2013 and 368,748,592 shares issued and outstanding as of December 31, 2012		3,734			3,687
Additional paid-in capital		541,704			537,962
Accumulated other comprehensive loss		(55,017	)		(28,012	)
Accumulated deficit		(298,941	)		(299,810	)

Total shareholders’ equity		191,480			213,827

Total liabilities and shareholders’ equity	$	347,737		$	358,258

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

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)

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


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
				(See Note 1)						(See Note 1)
Revenues:
Oil and natural gas sales	$	31,648		$	32,603		$	93,828		$	99,160
Sales of purchased natural gas		1,511			1,883			5,751			5,546
Other		144			329			999			2,043

Total revenues		33,303			34,815			100,578			106,749
Costs and expenses:
Production		4,591			4,542			13,446			12,470
Exploration, abandonment and impairment		2,243			2,104			17,992			11,783
Cost of purchased natural gas		1,437			1,862			5,483			5,498
Seismic and other exploration		5,052			1,725			6,385			3,236
Revaluation of contingent consideration		—			—			(5,000	)		—
General and administrative		6,367			6,744			20,783			25,301
Depreciation, depletion and amortization		11,487			8,147			30,044			26,698
Accretion of asset retirement obligations		114			164			367			579

Total costs and expenses		31,291			25,288			89,500			85,565

Operating income		2,012			9,527			11,078			21,184
Other income (expense):
Interest and other expense		(919	)		(1,086	)		(2,764	)		(6,363	)
Interest and other income		282			1,019			964			1,501
(Loss) gain on commodity derivative contracts		(3,137	)		(7,146	)		365			(5,277	)
Foreign exchange (loss) gain		(2,923	)		(133	)		(5,953	)		3,066

Total other expense		(6,697	)		(7,346	)		(7,388	)		(7,073	)

(Loss) income from continuing operations before income taxes		(4,685	)		2,181			3,690			14,111
Current income tax benefit (expense)		1,284			(1,440	)		(583	)		(3,882	)
Deferred income tax expense		(1,417	)		(272	)		(1,990	)		(2,660	)

Net (loss) income from continuing operations		(4,818	)		469			1,117			7,569
(Loss) income from discontinued operations before income taxes		(155	)		122			(248	)		(4,540	)
Gain on disposal of discontinued operations		—			6,437			—			33,651
Income tax provision		—			(34	)		—			(8,207	)

Net (loss) income from discontinued operations		(155	)		6,525			(248	)		20,904
Net (loss) income	$	(4,973	)	$	6,994		$	869		$	28,473
Other comprehensive (loss) income:
Foreign currency translation adjustment		(10,626	)		3,146			(27,005	)		17,650

Comprehensive (loss) income	$	(15,599	)	$	10,140		$	(26,136	)	$	46,123

Net (loss) income per common share:
Basic net (loss) income per common share:
Continuing operations	$	(0.01	)	$	0.00		$	0.00		$	0.02
Discontinued operations	$	0.00		$	0.02		$	0.00		$	0.06
Weighted average common shares outstanding		371,503			367,960			369,785			366,981
Diluted net (loss) income per common share:
Continuing operations	$	(0.01	)	$	0.00		$	0.00		$	0.02
Discontinued operations	$	0.00		$	0.02		$	0.00		$	0.06
Weighted average common and common equivalent shares outstanding		371,503			370,020			369,785			368,869

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

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Equity

(Unaudited)

(U.S. dollars and shares in thousands)


	Common Shares		Common Shares ($)		Additional Paid-in Capital			Accumulated Other Comprehensive Loss			Accumulated Deficit			Total Shareholders’ Equity
Balance at December 31, 2012		368,749	$	3,687	$	537,962		$	(28,012	)	$	(299,810	)	$	213,827
Issuance of common shares		3,511		35		2,465			—			—			2,500
Issuance of restricted stock units		1,122		12		(12	)		—			—			—
Tax withholding on restricted stock units		—		—		(40	)		—			—			(40	)
Share-based compensation		—		—		1,329			—			—			1,329
Foreign currency translation adjustments		—		—		—			(27,005	)		—			(27,005	)
Net income		—		—		—			—			869			869

Balance at September 30, 2013		373,382	$	3,734	$	541,704		$	(55,017	)	$	(298,941	)	$	191,480

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

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands of U.S. dollars)


	For the Nine Months Ended September 30,
	2013			2012
				(See Note 1)
Operating activities:
Net income	$	869		$	28,473
Adjustment for net loss (income) from discontinued operations		248			(20,904	)

Net income from continuing operations		1,117			7,569
Adjustments to reconcile net income to net cash provided by operating activities:
Share-based compensation		1,329			1,506
Foreign currency loss		5,053			1,997
Unrealized (gain) loss on commodity derivative contracts		(3,020	)		2,177
Amortization of loan financing costs		383			846
Deferred income tax expense		1,990			2,660
Exploration, abandonment and impairment		17,992			11,783
Depreciation, depletion and amortization		30,044			26,698
Accretion of asset retirement obligations		367			579
Revaluation of contingent consideration		(5,000	)		—
Changes in operating assets and liabilities, net of effect of acquisitions:
Accounts receivable		5,657			(24,928	)
Prepaid expenses and other assets		(1,547	)		4,684
Accounts payable and accrued liabilities		15,431			18,998

Net cash provided by operating activities from continuing operations		69,796			54,569
Net cash used in operating activities from discontinued operations		(1,224	)		(24,138	)

Net cash provided by operating activities		68,572			30,431
Investing activities:
Additions to oil and natural gas properties		(76,435	)		(45,982	)
Additions to equipment and other properties		(11,538	)		(451	)
Restricted cash		(194	)		1,059

Net cash used in investing activities from continuing operations		(88,167	)		(45,374	)
Net cash provided by investing activities from discontinued operations		1,016			156,150

Net cash (used in) provided by investing activities		(87,151	)		110,776
Financing activities:
Exercise of stock options and warrants		—			642
Tax withholding on restricted stock units		(40	)		(147	)
Loan proceeds		40,856			16,976
Loan proceeds—related party		—			11,000
Loan repayment		(23,642	)		(69,940	)
Loan financing costs		—			(250	)
Loan repayment—related party		—			(84,000	)

Net cash provided by (used in) financing activities from continuing operations		17,174			(125,719	)
Net cash used in financing activities from discontinued operations		—			(5,049	)

Net cash provided by (used in) financing activities		17,174			(130,768	)
Effect of exchange rate changes on cash		(1,092	)		614
Net (decrease) increase in cash and cash equivalents		(2,497	)		11,053
Cash and cash equivalents, beginning of year		14,768			15,116

Cash and cash equivalents, end of period	$	12,271		$	26,169

Supplemental disclosures:
Cash paid for interest	$	2,263		$	5,603

Cash paid for taxes	$	2,387		$	3,513

Supplemental non-cash investing and financing activities:
Issuance of common shares—amendment to purchase agreement	$	2,500		$	—
Note receivable—related party from sale of oilfield services business	$	—		$	11,500

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

TRANSATLANTIC PETROLEUM LTD.

Notes to Consolidated Financial Statements

1. General

Nature of operations

TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the “Company” or “TransAtlantic”) is an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established yet underexplored petroleum systems, have stable governments, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of September 30, 2013, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

Basis of presentation

Our consolidated financial statements are expressed in U.S. Dollars and have been prepared by management in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). All amounts in these notes to the consolidated financial statements are in U.S. Dollars unless otherwise indicated. We have prepared the accompanying unaudited interim consolidated financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and in the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fairly the consolidated financial position of TransAtlantic at September 30, 2013 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual consolidated financial statements prepared in accordance with U.S. GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim consolidated financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2012. Certain prior period amounts have been reclassified to conform to the current period presentation.

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

Reclassification

As reported in our Annual Report on Form 10-K for the year ended December 31, 2012, during the three and nine months ended September 30, 2012, we reclassified certain amounts previously reported on our consolidated statements of comprehensive income (loss) to conform to current year presentation. Specifically, we reclassified the revenue and cost related to natural gas purchased from third parties. For the three and nine months ended September 30, 2012, these reclassifications increased total revenues and costs and expenses by approximately $1.9 million and $5.5 million, respectively.

Revision of prior period financial statements

During the three months ended March 31, 2013, we identified and corrected errors previously reported on our consolidated statements of cash flows. As a result, we increased the “Exploration, abandonment and impairment” sub-caption, which is an adjustment to reconcile net income (loss) to net cash provided by operating activities, and increased the cash used in investing activities related to “Additions to oil and natural gas properties” by $3.9 million for the nine months ended September 30, 2012, as we previously did not include the cash portion of additions to oil and natural gas properties in investing activities for dry-hole expenses that were recognized in the same period as the related cash disbursed. These amounts had also been excluded from the adjustment to reconcile net income (loss) to net cash provided by operating activities.

We assessed the materiality of the errors in accordance with the SEC guidance on considering the effects of prior period misstatements based on an analysis of quantitative and qualitative factors. Based on this analysis, we determined that the errors were immaterial to each of the prior reporting periods affected and, therefore, amendments of reports previously filed with the SEC were not required. Accordingly, we have reflected the correction of these prior period errors in the periods in which they originated and revised our consolidated statement of cash flows for the nine months ended September 30, 2012 in this Quarterly Report on Form 10-Q.

The following shows the effect of the out-of-period errors on our consolidated statement of cash flows for the nine months ended September 30, 2012 (in thousands):


	As Reported			Correction			As Revised
For the nine months ended September 30, 2012
Operating activities:
Exploration, abandonment and impairment	$	7,869		$	3,914		$	11,783
Net cash provided by operating activities from continuing operations		50,655			3,914			54,569
Net cash provided by operating activities		26,517			3,914			30,431
Investing activities:
Additions to oil and natural gas properties		(42,068	)		(3,914	)		(45,982	)
Net cash used in investing activities from continuing operations		(41,460	)		(3,914	)		(45,374	)
Net cash provided by (used in) investing activities	$	114,690		$	(3,914	)	$	110,776

2. Recent accounting policies

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

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

3. Discontinued operations

Discontinued operations in Morocco

In June 2011, we decided to discontinue our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for all periods presented.

The following shows our assets and liabilities held for sale at September 30, 2013 and December 31, 2012:


	September 30, 2013		December 31, 2012
	(in thousands)
Cash	$	91	$	93
Other assets (1)		510		1,526

Total assets held for sale	$	601	$	1,619

Accrued expenses and other liabilities	$	7,355	$	8,416

Total liabilities held for sale	$	7,355	$	8,416

(1)	Other assets consist primarily of $0.5 million and $1.5 million of restricted cash at September 30, 2013 and December 31, 2012, respectively.

Discontinued operations of oilfield services business

In June 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”), to a joint venture owned by Dalea Partners, LP (“Dalea”) and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $168.5 million, consisting of approximately $157.0 million in cash and a $11.5 million promissory note from Dalea. The promissory note bears interest at a rate of 3.0% per annum and is guaranteed by Mr. Mitchell. We have presented the oilfield services segment operating results as discontinued operations for the three and nine months ended September 30, 2013 and September 30, 2012.

Our operating results from discontinued operations for the three and nine months ended September 30, 2013 and 2012 are summarized as follows:


	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2013			2012			2013			2012
	(in thousands)
Total revenues	$	—		$	—		$	—		$	20,956
Total costs and expenses		(173	)		(223	)		(311	)		(25,074	)
Total other income (expense)		18			345			63			(422	)

(Loss) income from discontinued operations before income taxes		(155	)		122			(248	)		(4,540	)
Gain on disposal of discontinued operations		—			6,437			—			33,651
Income tax provision		—			(34	)		—			(8,207	)

Net (loss) income from discontinued operations	$	(155	)	$	6,525		$	(248	)	$	20,904

4. 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:


	September 30, 2013			December 31, 2012
	(in thousands)
Oil and natural gas properties, proved:
Turkey	$	252,866		$	229,462
Bulgaria		1,204			2,036

Total oil and natural gas properties, proved		254,070			231,498
Oil and natural gas properties, unproved:
Turkey		62,564			68,938
Bulgaria		268			—

Total oil and natural gas properties, unproved		62,832			68,938

Gross oil and natural gas properties		316,902			300,436
Accumulated depletion		(91,038	)		(74,099	)

Net oil and natural gas properties	$	225,864		$	226,337

At September 30, 2013 and December 31, 2012, we excluded $2.7 million and $1.8 million, respectively, from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At September 30, 2013, the capitalized costs of our net oil and natural gas properties included $38.7 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $121.6 million relating to well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.

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

During the nine months ended September 30, 2013, we incurred approximately $37.0 million in exploratory drilling costs, of which $6.1 million was included in exploration, abandonment and impairment expense, $16.1 million was reclassified from unproved properties to proved properties and $14.8 million remained capitalized at September 30, 2013. No exploratory well costs were reclassified to proved properties in the three months ended September 30, 2013. Uncertainties affect the recoverability of costs of our oil and natural gas properties, as the recovery of the costs are dependent upon us maintaining licenses in good standing and achieving commercial production or sale.

Capitalized cost greater than one year

As of September 30, 2013, we had $2.7 million of exploratory well costs capitalized for the Kazanci-5 well, which we spud in September 2012. We recently finished a long-term pressure build up on the current completion. We have identified potential pay up-hole. We are evaluating, with our partners, whether to test another unconventional zone or move up to the conventional pay and establish production.

Dry-hole costs

As of June 30, 2013, we had $4.3 million of exploratory well costs capitalized for the Pancarkoy-1 well, which we began drilling in the fourth quarter of 2010. After the second fracture stimulation of the Pancarkoy-1 well, commercial natural gas production could not be sustained due to the high amount of water production. A third fracture stimulation of the Pancarkoy-1 well was performed in April 2012, but commercial production could not be sustained due to high water production. In the fourth quarter of 2012, we tested the up-hole interval of the well. A further fracture stimulation of this well was performed in the second quarter of 2013, but commercial production could not be sustained. As a result, we have classified this well as a dry hole during the three months ended June 30, 2013.

The Meneske-1 well was spud in November 2011, and we had capitalized $1.9 million of exploratory well costs for this well as of June 30, 2013. After further review, based on the results of other nearby wells and the expected high tie-in costs of the Meneske-1 well, we have classified this well as a dry hole during the three months ended June 30, 2013.

The Suleymaniye-2 well was spud in December 2011, and we had capitalized $0.9 million of exploratory well costs for this well as of June 30, 2013. After being evaluated for artificial lift and based on the results of other nearby wells, we have classified this well as a dry hole during the three months ended June 30, 2013.

During the three months ended September 30, 2013, we recorded $0.7 million of dry-hole costs primarily relating to two wells drilled in the third quarter.

Of the $11.8 million of dry-hole costs expensed during the nine months ended September 30, 2013, approximately $4.7 million was related to cash spent during 2013.

Impairment and abandonment

During the three and nine months ended September 30, 2013, we recorded $1.5 million and $6.2 million, respectively, in impairment and abandonment charges on our proved and unproved properties, primarily related to our Malkara license. We recorded $1.5 million in impairment charges on our proved properties during the nine months ended September 30, 2012, primarily due to downward revisions in natural gas reserves in our Alpullu field.

Equipment and other property

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


	September 30, 2013			December 31, 2012
	(in thousands)
Other equipment	$	2,506		$	2,013
Inventory		26,842			20,517
Gas gathering system and facilities		4,706			5,369
Vehicles		232			131
Leasehold improvements, office equipment and software		7,943			7,717

Gross equipment and other property		42,229			35,747
Accumulated depreciation		(6,987	)		(5,932	)

Net equipment and other property	$	35,242		$	29,815

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

At September 30, 2013, we excluded $26.8 million of inventory and $0.6 million of software from depreciation, as the inventory and software had not been placed into service. At December 31, 2012, we excluded $20.5 million of inventory from depreciation, as the inventory had not been placed into service.

5. Commodity derivative instruments

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

To the extent that a legal right of offset exists, we net the value of our derivative instruments with the same counterparty in our consolidated balance sheets. All of our oil derivative contracts are settled based upon Brent crude oil pricing. We recognize unrealized and realized gains and losses related to these contracts on a fair value basis in our consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows. We are required under our amended and restated senior secured credit facility (as amended, the “Amended and Restated Credit Facility”) with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”) to hedge between 30% and 75% of our anticipated production volumes in Turkey.

For the three months ended September 30, 2013, we recorded a net loss on commodity derivative contracts of approximately $3.1 million, consisting of a $2.2 million unrealized loss related to changes in fair value and a $0.9 million realized loss for settled contracts. For the nine months ended September 30, 2013, we recorded a net gain on commodity derivative contracts of $0.4 million, consisting of a $3.0 million unrealized gain related to changes in fair value and a $2.6 million realized loss for settled contracts.

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

At September 30, 2013 and December 31, 2012, we had outstanding contracts with respect to our future crude oil production as set forth in the tables below:

Fair Value of Derivative Instruments as of September 30, 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		October 1, 2013—December 31, 2013		717	$	81.63	$	119.80	$	(15	)
Collar		January 1, 2014—December 31, 2014		622	$	80.83	$	118.07		(157	)

									$	(172	)


			Collars						Additional Call
Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
											(in thousands)
Three-way collar contract		October 1, 2013—December 31, 2013		770	$	85.00	$	97.13	$	162.13	$	(790	)
Three-way collar contract		January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13		(2,200	)
Three-way collar contract		January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(2,607	)

											$	(5,597	)

Fair Value of Derivative Instruments as of December 31, 2012


Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
									(in thousands)
Collar		January 1, 2013—December 31, 2013		775	$	82.26	$	121.36	$	(253	)
Collar		January 1, 2014—December 31, 2014		662	$	80.83	$	118.07		(292	)

									$	(545	)


			Collars						Additional Call
Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
											(in thousands)
Three-way collar contract		January 1, 2013—December 31, 2013		831	$	85.00	$	97.13	$	162.13	$	(3,655	)
Three-way collar contract		January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13		(2,150	)
Three-way collar contract		January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(2,440	)

											$	(8,245	)

6. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations (“ARO”) for the nine months ended September 30, 2013 and for the year ended December 31, 2012:


	September 30, 2013			December 31, 2012
	(in thousands)
Asset retirement obligations at beginning of period	$	11,958		$	13,534
Change in estimates		(8	)		(3,868	)
Liabilities settled		(132	)		(110	)
Foreign exchange change effect		(1,438	)		793
Additions		531			899
Accretion expense		367			710

Asset retirement obligations at end of period		11,278			11,958
Less: current portion		916			818

Long-term portion	$	10,362		$	11,140

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.

7. Loan payable

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


	September 30, 2013		December 31, 2012
	(in thousands)
Floating Rate Debt
Amended and Restated Credit Facility	$	49,766	$	32,766

Loan payable	$	49,766	$	32,766

Amended and Restated Senior Secured Credit Facility

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

Availability under the Amended and Restated Credit Facility is subject to a borrowing base. The borrowing base is re-determined quarterly on January 1st, April 1st, July 1st and October 1st of each year. As of October 1, 2013 our borrowing base was $56.5 million. Loans under the Amended and Restated Credit Facility accrue interest at a rate of three-month LIBOR plus 5.50% per annum.

At September 30, 2013, we had borrowed $49.8 million under the Amended and Restated Credit Facility.

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 (approximately $38.7 million at September 30, 2013) unsecured line of credit with a Turkish bank, of which 60 million New Turkish Lira is available in cash for TBNG and 18.8 million New Turkish Lira 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, and each borrowing is expected to have a two-year term. As of September 30, 2013, there were no borrowings under this credit facility.

8. 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 or contingent liability 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 estimable.

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

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 the second quarter of 2012 for this contractual obligation.

Direct Petroleum

In July 2013, we entered into a second amendment (the “Amendment”) to our Purchase Agreement (the “Purchase Agreement”) with Direct Petroleum Exploration, LLC, formerly Direct Petroleum Exploration, Inc. (“Direct”). Pursuant to the Amendment, we issued 3,510,743 common shares to Direct as partial payment of certain liquidated damages due under the Purchase Agreement. The number of shares was calculated by dividing $2.5 million by the volume weighted average price per share of our common shares on the NYSE MKT for the ten trading days prior to July 2, 2013.

The parties also agreed that Direct is not eligible for any liquidated damages relating to the coring of the Etropole shale formation, which resulted in the reversal of the $5.0 million contingent liability recorded in 2011, which we recognized in our consolidated statement of comprehensive income (loss) under the caption “Revaluation of contingent consideration” during the nine months ended September 30, 2013.

The Amendment sets forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. In the event that we do not meet the drilling and testing obligations by May 1, 2014, the Amendment requires us to issue an additional $2.5 million in common shares to Direct. As such, the $2.5 million contingent liability, recorded in 2011, remained as of September 30, 2013.

Additionally, the Amendment provides that if the Bulgarian government issues a production concession over 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. Any adjustment will be recorded when it becomes probable and estimable.

9. Shareholders’ equity

Restricted stock units

Share-based compensation expense of approximately $0.5 million and $1.3 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three and nine months ended September 30, 2013, respectively. We recorded share-based compensation expense of $0.4 million and $1.5 million for the three and nine months ended September 30, 2012, respectively.

As of September 30, 2013, we had approximately $2.1 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.6 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 nine months ended September 30, 2013 and 2012 equals net income divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding RSUs. Diluted earnings per common share for the three and nine months ended September 30, 2013 and 2012 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes stock options, RSUs and warrants, whether exercisable or not. For the three and nine months ended September 30, 2013, there were no common shares excluded from the computation of diluted earnings per share due to the September 1, 2013 expiration of warrants to acquire 7,300,000 common shares. The computation of diluted earnings per common share excluded 7,455,000 and 7,461,240 antidilutive common share equivalents from the three and nine months ended September 30, 2012, respectively, primarily related to our common share purchase warrants.

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


	Three Months Ended September 30,					Nine Months Ended September 30,
(in thousands, except per share amounts)	2013			2012		2013			2012
Net (loss) income from continuing operations	$	(4,818	)	$	469	$	1,117		$	7,569
Net (loss) income from discontinued operations	$	(155	)	$	6,525	$	(248	)	$	20,904
Basic net (loss) income per common share:
Shares:
Weighted average common shares outstanding		371,503			367,960		369,785			366,981

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

Discontinued operations	$	0.00		$	0.02	$	0.00		$	0.06

Diluted net (loss) income per common share:
Shares:
Weighted average common shares outstanding		371,503			367,960		369,785			366,981
Dilutive effect of:
Restricted stock units		—			1,941		—			1,745
Stock options		—			119		—			143

Weighted average common and common equivalent shares outstanding		371,503			370,020		369,785			368,869

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

Discontinued operations	$	0.00		$	0.02	$	0.00		$	0.06

Additionally, we had a contingent liability at September 30, 2013 of approximately $2.5 million that is payable in our common shares. At the September 30, 2013 closing price of our common shares, this liability represented 2,976,190 common shares that could be potentially dilutive to future earnings per share calculations (see Note 8).

10. Segment information

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


	Corporate			Romania			Turkey			Bulgaria			Total
	(in thousands)
For the three months ended September 30, 2013
Total revenues	$	(2	)	$	—		$	33,277		$	28		$	33,303
Loss from continuing operations before income taxes		(2,943	)		(46	)		(1,517	)		(179	)		(4,685	)
Capital expenditures	$	—		$	—		$	33,706		$	268		$	33,974
For the three months ended September 30, 2012
Total revenues	$	—		$	—		$	34,767		$	48		$	34,815


	Corporate			Romania			Turkey		Bulgaria			Total
	(in thousands)
(Loss) income from continuing operations before income taxes		(2,534	)		(149	)		5,042		(178	)		2,181
Capital expenditures	$	—		$	—		$	24,498	$	—		$	24,498
For the nine months ended September 30, 2013
Total revenues	$	—		$	—		$	100,454	$	124		$	100,578
(Loss) income from continuing operations before income taxes		(9,019	)		(104	)		8,380		4,433			3,690
Capital expenditures	$	—		$	—		$	81,282	$	268		$	81,550
For the nine months ended September 30, 2012
Total revenues	$	—		$	—		$	106,552	$	197		$	106,749
(Loss) income from continuing operations before income taxes		(9,808	)		(804	)		27,301		(2,578	)		14,111
Capital expenditures	$	—		$	—		$	71,777	$	168		$	71,945
Segment assets
September 30, 2013	$	13,849		$	46		$	327,069	$	6,172		$	347,136	⁽¹⁾
December 31, 2012	$	14,825		$	105		$	339,752	$	1,957		$	356,639	⁽¹⁾
Goodwill
September 30, 2013	$	—		$	—		$	7,906	$	—		$	7,906
December 31, 2012	$	—		$	—		$	9,021	$	—		$	9,021

(1)	Excludes assets held for sale from our discontinued Moroccan operations of $0.6 million and $1.6 million at September 30, 2013 and December 31, 2012, respectively.

11. 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 September 30, 2013 and December 31, 2012 due to the short maturity of those instruments.

Interest rate risk

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

Foreign currency risk

We have underlying foreign currency exchange rate exposure. Our currency exposures relate to transactions denominated in the Canadian Dollar, Bulgarian Lev, European Union Euro, Romanian New Leu, Moroccan Dirham and New Turkish Lira. We are also subject to foreign currency exposures resulting from translating the functional currency of our foreign subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At September 30, 2013, we had 14.5 million New Turkish Lira (approximately $7.1 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the New Turkish Lira.

Commodity price risk

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including, but not limited to, supply and demand. At September 30, 2013 and December 31, 2012, we were a party to commodity derivative contracts.

Concentration of credit risk

The majority of our receivables are within the oil and natural gas industry, primarily from our industry partners and from government agencies. Included in receivables are amounts due from Turkiye Petrolleri Anonim Ortakligi, the national oil company of Turkey, and Turkiye Petrol Rafinerileri A.Ş., a privately owned oil refinery in Turkey, which purchase the majority of our oil production. The receivables are not collateralized. To date, we have experienced minimal bad debts. The majority of our cash and cash equivalents are held by three financial institutions in the United States and Turkey.

Fair value measurements

The following table summarizes the valuation of our financial assets and liabilities as of September 30, 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)	$	—	$	(5,769	)	$	—	$	(5,769	)

Total	$	—	$	(5,769	)	$	—	$	(5,769	)

The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2012:


	Fair Value Measurement Classification
	Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)		Total
	(in thousands)
Liabilities:
Derivative financial instruments (commodity)	$	—	$	(8,790	)	$	—	$	(8,790	)

Total	$	—	$	(8,790	)	$	—	$	(8,790	)

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

12. Related party transactions

The following table summarizes related party accounts receivable and accounts payable as of September 30, 2013 and December 31, 2012:


	September 30, 2013		December 31, 2012
	(in thousands)
Related party accounts receivable:
Viking International master services agreement	$	577	$	313
Riata Management service agreement		41		—
Dalea promissory note		—		106

Total related party accounts receivable	$	618	$	419

Related party accounts payable:
Viking International master services agreement	$	20,592	$	15,467
Viking Geophysical master services agreement		3,103		—
Riata Management service agreement		164		167

Total related party accounts payable	$	23,859	$	15,634

For the three and nine months ended September 30, 2013 and 2012, we incurred expenditures of $27.8 million and $65.5 million and $26.1 million and $43.9 million, respectively, related to our various related party agreements.

Item 2.

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

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

Executive Overview

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established yet underexplored petroleum systems, have stable governments, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of September 30, 2013, we held interests in approximately 3.9 million net onshore acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of September 30, 2013, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

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

•

We reported a $4.8 million net loss from continuing operations for the three months ended September 30, 2013, which included a $2.2 million non-cash loss on our commodity derivatives and a $2.9 million foreign currency exchange loss, compared to net income from continuing operations of $0.5 million for the same period in 2012.

•

We derived 71.2% of our revenues from the production of oil and 23.9% of our revenues from the production of natural gas during the three months ended September 30, 2013.

•

Total oil and natural gas sales revenues decreased 2.9% to $31.6 million for the quarter ended September 30, 2013, from $32.6 million in the same period in 2012. The decrease was primarily the result of lower production of nine thousand barrels of oil equivalent (“Mboe”), which decreased revenues by $0.8 million, and a decrease in the average realized price per barrels of oil equivalent (“Boe”), which decreased revenues by $0.2 million.

•

Total net production was 230 thousand barrels (“Mbbls”) of oil and 868 million cubic feet (“Mmcf”) of natural gas, as compared to 229 Mbbls of oil and 928 Mmcf of natural gas for the same period in 2012.

•

For the quarter ended September 30, 2013, we produced an average of 4,076 net Boe per day, as compared to 4,174 net Boe per day for the same period in 2012.

•

For the quarter ended September 30, 2013, we incurred $34.0 million in capital expenditures, including license acquisition and seismic expenditures from continuing operations, as compared to $24.5 million for the quarter ended September 30, 2012.

•

As of September 30, 2013, we had $49.8 million in outstanding debt and no short-term borrowings, as compared to $32.8 million in outstanding debt and no short-term borrowings as of September 30, 2012.

Recent Developments

Bulgaria Farm-Out. In August 2013, our wholly owned subsidiary, TransAtlantic Worldwide, Ltd. (TransAtlantic Worldwide”), entered into a farm-out agreement with Koynare Development Ltd. (“KDL”), a private oil and natural gas investment company. Pursuant to the agreement, KDL will fund 75% of our initial $40 million work program in Bulgaria, and our wholly owned subsidiary, Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”), will assign KDL a 50% interest in the Koynare Concession Area. Direct Bulgaria will also assign KDL 50% of its interest in the Stefanetz Concession Area in the event that the pending concession application is approved by the Bulgarian government.

Amendment of Purchase Agreement. In July 2013, TransAtlantic Worldwide entered into a second amendment (the “Amendment”) to our purchase agreement (the “Purchase Agreement”) with Direct Petroleum Exploration, LLC (formerly Direct Petroleum Exploration, Inc.) (“Direct”). Pursuant to the Amendment, we issued 3,510,743 common shares to Direct as partial payment of certain liquidated damages due under the Purchase Agreement. The parties also agreed that Direct is not eligible for any liquidated damages relating to the coring of the Etropole shale formation, which resulted in the reversal of a $5.0 million contingent liability recorded in 2011 during the three months ended June 30, 2013. The Amendment sets forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. In the event that we do not meet the drilling and testing obligations by May 1, 2014, the Amendment requires us to issue an additional $2.5 million in common shares (the “Additional Liquidated Damages”) to Direct. In addition, the Amendment provides that we shall issue common shares to Direct in the amount of $7.5 million less the Additional Liquidated Damages, if any, if the Deventci-R2 well is a commercial success (as defined in the Purchase Agreement) on or prior to May 1, 2016.

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 (approximately $38.7 million at September 30, 2013) unsecured line of credit with a Turkish bank, of which 60 million New Turkish Lira is available in cash for TBNG and 18.8 million New Turkish Lira 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, and each borrowing is expected to have a two-year term. As of September 30, 2013, there were no borrowings under this credit facility.

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

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

Third Quarter 2013 Operational Update

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

Turkey-Southeast

Molla. We drilled the Goksu-5H horizontal well to the Mardin zone at a vertical depth of 5,200 feet and a total measured depth of 7,200 feet. Upon completion of the Goksu-5H, the ensuing production was nearly all water and production was discontinued in October 2013. We plan to convert the Goksu-5H into a disposal well.

We completed the Oba-1H well and successfully isolated the toe of the well. We are preparing to put the Oba-1H on a long-term production test. We also drilled the Alibey-1 well, and are currently executing a remediation plan to isolate the water zones on the well.

We drilled the Tepe-1 well, but did not encounter hydrocarbons in the Bedinan zone. The Tepe-1 has been plugged back to the Mardin zone for testing. We are currently drilling the Ambarcik-2 well, a second vertical Bedinan exploration well, and expect to complete the well during the fourth quarter of 2013. We also expect to drill at least one vertical well in the Arpatepe field in the fourth quarter of 2013.

We expect to complete the remaining 314 square km of an 800 square km 3D seismic program over Molla and the surrounding areas by the end of 2013 and interpret the seismic data in the first half of 2014.

Selmo. We drilled a horizontal well targeting the MSD zone at a vertical depth of approximately 5,200 feet and are currently drilling a second horizontal MSD well. After encountering instability in the wellbore, we re-drilled the lower section of the second well. We expect to complete both wells in the fourth quarter of 2013.

Turkey-Northwest

In the third quarter of 2013, we completed seven new wells, including the BTD-4H, fracture stimulated four wells and recompleted 10 wells. The BTD-4H is our second horizontal well in the southern Thrace Basin and began producing in the third quarter of 2013 at a ten-day average rate of 3.2 Mmcf per day (“Mmcf/d”). We are preparing to spud the BTD-5H, our third horizontal well in southern Thrace Basin and an offset of the BTD-4H well.

We drilled six shallow, vertical natural gas wells in the Edirne field after negotiating a low cost, group rate drilling and completion package. One well was a dry hole, and we completed the remaining five wells in October 2013. Four of these wells are producing an average of 750 Mmcf/d each.

We drilled the Karanfiltepe-5 well and are currently running logs to identify completion targets to test for the presence of hydrocarbons. We also spud the Yildirim-3 well targeting the Osmancik formation in September 2013.

We began a 234 square km 3D seismic program in the Osmanli area of southern Thrace Basin and expect to complete this seismic program in the fourth quarter of 2013.

Planned Operations

We continue to actively explore and develop our existing oil and natural gas properties in Turkey and Bulgaria. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and bringing these discoveries into production. For the remainder of 2013, we are focused on accomplishing the following objectives:

•

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

•

Continue to Expand Fracture Stimulation Program. In 2013, we have continued to expand our use of hydraulic fracturing technology to complete otherwise low productive formations in Turkey. The evolution of fracturing fluids and stimulation designs has yielded very positive results in both northwestern and southeastern Turkey. For the remainder of 2013, we plan to continue optimizing our hydraulic fracturing techniques to improve well performance and economics.

•

Expand the Use of Horizontal Drilling. During 2013, we have expanded our use of horizontal drilling, which achieved successful results in the Selmo, Molla and Thrace Basin areas. During the fourth quarter of 2013, we anticipate our drilling in southeastern Turkey will include extensive use of horizontal drilling techniques, including one well on our Molla licenses and five wells at Selmo. We also plan to drill two horizontal wells on our Thrace Basin licenses.

•

Accelerate Through Partnerships. In an effort to increase the pace of exploration activity, share exploration risk, and reduce our share of the capital commitments necessary to carry forward the exploration of our extensive acreage positions, we are currently seeking joint venture partners for our exploration acreage in Turkey and plan to continue this effort during the remainder of 2013. We recently entered into a farm-out agreement with KDL in which KDL will fund 75% of our initial $40 million work program in Bulgaria in exchange for 50% of our interest in the Koynare Concession Area and 50% of our interest in the Stefanetz Concession Area in the event that the pending concession application is approved by the Bulgarian government.

Capital expenditures, including seismic expenditures, for the fourth quarter of 2013 are expected to range between $35.0 million and $50.0 million. Approximately 75% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling developmental and exploratory oil wells and acquiring seismic data at Molla, Selmo, Arpatepe and Gaziantep. Most of the remaining 25% of these anticipated expenditures will occur in the Thrace Basin, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Our projected 2013 capital budget is subject to change, and if cash on hand, borrowings from our amended and restated senior secured credit facility (as amended, the “Amended and Restated Credit Facility”) with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”) and TBNG credit facility, and cash flow from operations are not sufficient to fund our capital expenditures, we will either curtail our discretionary capital expenditures or seek other funding sources.

We currently plan to execute the following drilling and exploration activities during the fourth quarter of 2013:

Turkey. We plan to continue our three-part strategy in Turkey: (i) the Molla program, (ii) the Selmo field redevelopment program, and (iii) the Thrace Basin development program. We plan to drill approximately 11 gross wells, eight of which are expected to be drilled horizontally and five of which are expected to be fracture stimulated. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill.

Bulgaria. We spud the Deventci-R2 well on our Koynare Concession Area on October 5, 2013, and plan to drill and complete the well in the fourth quarter of 2013.

Discontinued Operations in Morocco

In June 2011, we decided to discontinue our Moroccan operations. We have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for the three and nine months ended September 30, 2013 and September 30, 2012, and they are not included in results from continuing operations.

Discontinued Operations of Oilfield Services Business

Significant Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3. Significant accounting policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2012 and are of particular importance to the portrayal of our financial position and results of operations and require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. There have been no changes to the significant accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012.

Recent Accounting Pronouncements

Results of Operations—Three Months Ended September 30, 2013 Compared to Three Months Ended September 30, 2012

Our results of operations for the three months ended September 30, 2013 and 2012 were as follows:


	Three Months Ended September 30,				Change
	2013		2012		2013-2012
	(in thousands of U.S. dollars, except per unit prices and production volumes) (as adjusted)
Production:
Oil (Mbbl)		230		229		1
Natural gas (Mmcf)		868		928		(60	)
Total production (Mboe)		375		384		(9	)
Average daily production (Boe/day)		4,076		4,174		(98	)
Average prices:
Oil (per Bbl)	$	103.04	$	105.81	$	(2.77	)
Natural gas (per Mcf)	$	9.16	$	8.14	$	1.02
Oil equivalent (per Boe)	$	84.39	$	84.90	$	(0.51	)
Revenues:
Oil and natural gas sales	$	31,648	$	32,603	$	(955	)
Sales of purchased natural gas		1,511		1,883		(372	)
Other		144		329		(185	)
Costs and expenses:
Production		4,591		4,542		49
Exploration, abandonment and impairment		2,243		2,104		139
Cost of purchased natural gas		1,437		1,862		(425	)
Seismic and other exploration		5,052		1,725		3,327
General and administrative		6,367		6,744		(377	)
Depletion		10,925		7,794		3,131
Depreciation and amortization		562		353		209
Interest and other expense		919		1,086		(167	)
Foreign exchange loss		2,923		133		2,790


	Three Months Ended September 30,						Change
	2013			2012			2013-2012
	(in thousands of U.S. dollars, except per unit prices and production volumes) (as adjusted)
Loss on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	(919	)	$	(853	)	$	(66	)
Non-cash change in fair value on commodity derivative contracts		(2,218	)		(6,293	)		4,075

Total loss on commodity derivative contracts	$	(3,137	)	$	(7,146	)	$	4,009
Oil and natural gas costs per Boe(1):
Production	$	10.72		$	10.37		$	0.35
Depletion	$	25.53		$	20.32		$	5.21

(1)	We have recalculated the oil and natural gas costs per Boe for the three months ended September 30, 2012 based on working interest volumes before royalty deductions to conform to current year presentation.

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $1.0 million to $31.6 million for the three months ended September 30, 2013, from $32.6 million realized in the same period in 2012. Of this decrease, $0.8 million resulted from a decrease in production volumes of nine Mboe. Additionally, we realized a lower average realized price per Boe, which resulted in lower revenues of $0.2 million. For the three months ended September 30, 2013, our average realized price was $84.39 per Boe, as compared to $84.90 per Boe for the same period in 2012.

Production. Production expenses for the three months ended September 30, 2013 increased to $4.6 million, from $4.5 million for the same period in 2012.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended September 30, 2013 increased $0.1 million to $2.2 million, from $2.1 million for the same period in 2012. Of the $2.2 million of exploration, abandonment and impairment costs, approximately $1.8 million was cash spent during the third quarter. During the three months ended September 30, 2013, there were write-offs of two wells for an average of $0.4 million per well. During the three months ended September 30, 2012, there were write-offs of four wells for an average of $0.5 million per well. Additionally, during the three months ended September 30, 2013, we recorded $1.2 million of impairment charges on our unproved properties.

Seismic and Other Exploration. Seismic and other exploration costs increased to $5.1 million for the three months ended September 30, 2013, as compared to $1.7 million for the same period in 2012. The increase was primarily due to seismic acquisition activities conducted on our West Molla license during the three months ended September 30, 2013.

General and Administrative. General and administrative expense was $6.4 million for the three months ended September 30, 2013, as compared to $6.7 million for the same period in 2012. The decrease was primarily due to a $0.1 million decrease in employee-related costs resulting from a reduction in head count and a $0.2 million decrease in accounting and consulting expenses.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $11.5 million for the three months ended September 30, 2013, as compared to $8.1 million in the same period of 2012. The increase was primarily due to additions to proved properties during the three months ended September 30, 2013.

Interest and Other Expense. Interest and other expense decreased to $0.9 million for the three months ended September 30, 2013, as compared to $1.1 million for the same period in 2012.

Foreign Exchange Loss. Foreign currency exchange loss increased to $2.9 million for the three months ended September 30, 2013, as compared to $0.1 million for the same period in 2012. This increase was primarily due to the devaluation of the New Turkish Lira as compared to the U.S. Dollar.

Loss on Commodity Derivative Contracts. During the three months ended September 30, 2013, we recorded a loss on commodity derivative contracts of $3.1 million, as compared to a loss of $7.1 million for the same period in 2012. We recorded a $2.2 million unrealized loss and a $0.9 million realized loss on our derivative contracts for the three months ended September 30, 2013, as compared to a $6.3 million unrealized loss and a $0.8 million realized loss for the three months ended September 30, 2012. Unrealized gains and losses are attributable to changes in oil and natural gas prices and volumes hedged from one period end to another. We are required under our Amended and Restated Credit Facility to hedge a portion of our oil production in Turkey.

Other Comprehensive Loss (Income). We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. Dollar reporting currency. Foreign currency translation adjustment for the three months ended September 30, 2013 decreased to a loss of $10.6 million from a gain of $3.1 million for the same period in 2012 due to the devaluation of the New Turkish Lira as compared to the U.S. Dollar.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations and our oilfield services business for the three months ended September 30, 2013 and 2012 have been included in discontinued operations.

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


	Three Months Ended September 30,
	2013			2012
	(in thousands)
Revenues:
Total revenues	$	—		$	—

Costs and expenses:
Production		33			89
Oilfield services costs		11			287
General and administrative		129			(153	)

Total costs and expenses		173			223

Operating loss		(173	)		(223	)
Other income:
Interest and other expense		—			—
Interest and other income		18			345
Foreign exchange gain		—			—

Total other income		18			345

(Loss) income from discontinued operations before income taxes		(155	)		122
Gain on disposal of discontinued operations		—			6,437
Income tax provision		—			(34	)

Net (loss) income from discontinued operations	$	(155	)	$	6,525

Results of Operations—Nine Months Ended September 30, 2013 Compared to Nine Months Ended September 30, 2012

Our results of operations for the nine months ended September 30, 2013 and 2012 were as follows:


	Nine Months Ended September 30,						Change
	2013			2012			2013-2012
	(in thousands of U.S. dollars, except per unit prices and production volumes) (as adjusted)
Production:
Oil (Mbbl)		700			686			14
Natural gas (Mmcf)		2,484			3,376			(892	)
Total production (Mboe)		1,114			1,249			(135	)
Average daily production (Boe/day)		4,081			4,575			(494	)
Average prices:
Oil (per Bbl)	$	99.95		$	103.42		$	(3.47	)
Natural gas (per Mcf)	$	9.61		$	8.15		$	1.46
Oil equivalent (per Boe)	$	84.39		$	79.39		$	5.00
Revenues:
Oil and natural gas sales	$	93,828		$	99,160		$	(5,332	)
Sales of purchased natural gas		5,751			5,546			205
Other		999			2,043			(1,044	)
Costs and expenses:
Production	$	13,446		$	12,470		$	976
Exploration, abandonment and impairment		17,992			11,783			6,209
Cost of purchased natural gas		5,483			5,498			(15	)
Seismic and other exploration		6,385			3,236			3,149
Revaluation of contingent consideration		(5,000	)		—			(5,000	)
General and administrative		20,783			25,301			(4,518	)
Depletion		28,288			25,073			3,215
Depreciation and amortization		1,756			1,625			131
Interest and other expense		2,764			6,363			(3,599	)
Foreign exchange loss (gain)		5,953			(3,066	)		9,019


	Nine Months Ended September 30,						Change
	2013			2012			2013-2012
	(in thousands of U.S. dollars, except per unit prices and production volumes) (as adjusted)
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	(2,655	)	$	(3,100	)	$	445
Non-cash change in fair value on commodity derivative contracts		3,020			(2,177	)		5,197

Total gain (loss) on commodity derivative contracts	$	365		$	(5,277	)	$	5,642
Oil and natural gas costs per Boe(1):
Production	$	10.56		$	8.75		$	1.81
Depletion	$	22.22		$	17.60		$	4.62

(1)	We have recalculated the oil and natural gas costs per Boe for the nine months ended September 30, 2012 based on working interest volumes before royalty deductions to conform to current year presentation.

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $5.3 million to $93.8 million for the nine months ended September 30, 2013, from $99.1 million realized in the same period in 2012. Of this decrease, $10.7 million was due to a decrease in production volumes of 135 Mboe. Production volumes decreased on our Thrace Basin wells due to the depletion of wells recompleted in the second half of 2011. This was partially offset by an increase of $5.4 million, primarily due to higher average realized prices per Boe resulting from the production of a higher percentage of oil and the realization of higher natural gas prices. Our average price received increased $5.00 to $84.39 per Boe for the nine months ended September 30, 2013, from $79.39 per Boe for the same period in 2012.

Production. Production expenses for the nine months ended September 30, 2013 increased to $13.4 million, from $12.5 million for the same period in 2012. The increase was primarily attributable to the sale of our oilfield services business in June 2012. Prior to the sale, certain expenses were eliminated upon consolidation as they were classified as inter-company whereas they are now classified as third-party.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the nine months ended September 30, 2013 increased approximately $6.2 million to $18.0 million, from $11.8 million for the same period in 2012. During the nine months ended September 30, 2013, there were write-offs of four wells for $4.3 million, $2.9 million, $1.9 million and $0.9 million and two wells at an average of $0.4 million per well. During the same period in 2012, there were nine exploratory dry holes drilled with an average cost of $0.9 million each as well as a partial write-off of $2.0 million for the Pankarcoy-1 well. Additionally, during the nine months ended September 30, 2013, we recorded $5.7 million of impairment charges which primarily related to our Malkara license, as compared to $1.5 million of impairment charges for the same period in 2012.

Seismic and Other Exploration. Seismic and other exploration costs increased to $6.4 million for the nine months ended September 30, 2013, as compared to $3.2 million for the same period in 2012. The increase was primarily due to seismic acquisition activities conducted on our West Molla license during the nine months ended September 30, 2013.

Revaluation of Contingent Consideration. As a result of the Amendment to the Purchase Agreement with Direct, during the nine months ended September 30, 2013, we recognized the reversal of a $5.0 million contingent liability that was originally recorded in 2011.

General and Administrative. General and administrative expense was $20.8 million for the nine months ended September 30, 2013, as compared to $25.3 million for the same period in 2012. The decrease was primarily due to a decrease in employee-related costs of $1.4 million, a $0.4 million decrease in rent and a decrease of $0.6 million in consulting expenses, which was partially offset by an increase of $0.2 million in accounting and legal expenses. Employee-related costs decreased due to a reduction in head count. Accounting and legal expenses were higher during the nine months ended September 30, 2013 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. Also contributing to the decrease was a $2.0 million accrual for a contingency related to our Aglen exploration permit in Bulgaria, which was recognized during the nine months ended September 30, 2012. The remaining decrease of $0.3 million was attributable to our overall cost reduction efforts.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $30.0 million for the nine months ended September 30, 2013, as compared to $26.7 million for the same period in 2012. The increase was primarily due to additions to proved properties during the nine months ended September 30, 2013.

Interest and Other Expense. Interest and other expense decreased to $2.8 million for the nine months ended September 30, 2013, as compared to $6.4 million for the same period in 2012. The decrease was primarily due to decreased debt levels for the nine months ended September 30, 2013, as compared to the same period in 2012. In June 2012, we repaid $129.2 million of debt with the proceeds from the sale of our oilfield services business.

Foreign Exchange Loss (Gain). Foreign currency exchange loss was $6.0 million for the nine months ended September 30, 2013, as compared to a gain of $3.1 million for the same period in 2012. This increase is primarily due to the devaluation of the New Turkish Lira as compared to the U.S. Dollar for the nine months ended September 30, 2013 compared to the strengthening of the New Turkish Lira during the same period in 2012.

Gain (Loss) on Commodity Derivative Contracts. During the nine months ended September 30, 2013, we recorded a gain on commodity derivative contracts of $0.4 million, as compared to a loss of $5.3 million for the same period in 2012. We recorded a $3.0 million unrealized gain and a $2.6 million realized loss on our derivative contracts for the nine months ended September 30, 2013, as compared to a $2.2 million unrealized loss and a $3.1 million realized loss on our derivative contracts for the nine months ended September 30, 2012. Unrealized gains and losses are attributable to changes in oil and natural gas prices and volumes hedged from one period end to another. We are required under our Amended and Restated Credit Facility to hedge a portion of our oil production in Turkey.

Other Comprehensive Loss (Income). We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. Dollar reporting currency. Foreign currency translation adjustment for the nine months ended September 30, 2013 decreased to a loss of $27.0 million from a gain of $17.7 million for the same period in 2012 due to devaluation of the New Turkish Lira compared to the U.S. Dollar.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations and our oilfield services business for the nine months ended September 30, 2013 and 2012 have been included in discontinued operations.

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


	Nine Months Ended September 30,
	2013			2012
	(in thousands)
Revenues:
Oilfield services	$	—		$	20,956

Total revenues		—			20,956
Costs and expenses:
Production		143			738
Oilfield services costs		11			14,023
General and administrative		157			10,313

Total costs and expenses		311			25,074

Operating loss		(311	)		(4,118	)
Other income (expense):
Interest and other expense		(8	)		(138	)
Interest and other income		71			479
Foreign exchange loss		—			(763	)

Total other income (expense)		63			(422	)

Loss from discontinued operations before income taxes		(248	)		(4,540	)
Gain on disposal of discontinued operations		—			33,651
Income tax provision		—			(8,207	)

Net (loss) income from discontinued operations	$	(248	)	$	20,904

Capital Expenditures

Capital expenditures, including seismic expenditures, for the fourth quarter of 2013 are expected to range between $35.0 million and $50.0 million. Approximately 75% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling developmental and exploratory oil wells and acquiring seismic data at Molla, Selmo, Arpatepe and Gaziantep. Most of the remaining 25% of these anticipated expenditures will occur in the Thrace Basin, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Our projected 2013 capital budget is subject to change, and if cash on hand, borrowings from our Amended and Restated Credit Facility and TBNG credit facility, and cash flow from operations are not sufficient to fund our capital expenditures, we will either curtail our discretionary capital expenditures or seek other funding sources.

Liquidity and Capital Resources

Our primary sources of liquidity for the third quarter of 2013 were our cash and cash equivalents, cash flow from operations and net borrowings under our Amended and Restated Credit Facility. At September 30, 2013, we had cash and cash equivalents of $12.3 million, no short-term debt, $49.8 million in long-term debt, and a working capital deficit of $2.6 million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities), compared to cash and cash equivalents of $14.8 million, no short-term debt, $32.8 million in long-term debt, and working capital of $10.6 million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities) at December 31, 2012. Net cash provided by operating activities from continuing operations for the nine months ended September 30, 2013 increased to $69.8 million, as compared to net cash provided by operating activities from continuing operations of $54.6 million for the nine months ended September 30, 2012, primarily as a result of a decrease in general and administrative expenses, a decrease in interest expense and improved cash management.

As of September 30, 2013, the outstanding principal amount of our debt was $49.8 million. In addition to cash, cash equivalents and cash flow from operations, at September 30, 2013, we had an Amended and Restated Credit Facility and a credit facility with a Turkish bank, which are discussed below.

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

The amount drawn under the Amended and Restated Credit Facility may not exceed the lesser of (i) $250.0 million, (ii) the borrowing base amount at such time, (iii) the aggregate commitments of all lenders at such time and (iv) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment. At September 30, 2013, the lenders had aggregate commitments of $78.0 million, with individual commitments of $39.0 million each. Loans under the Amended and Restated Credit Facility accrue interest at a rate of three-month LIBOR plus 5.50% per annum.

The borrowing base is re-determined quarterly on January 1st, April 1st, July 1st and October 1st of each year. As of October 1, 2013, our borrowing base was $56.5 million.

At October 1, 2013, we had outstanding borrowings of $49.8 million and availability of $6.7 million under the Amended and Restated Credit Facility. For additional information concerning the ratios, financial and non-financial covenants, events of default and other material terms of our Amended and Restated Credit Facility, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in our Annual Report on Form 10-K for the year ended December 31, 2012.

TBNG Credit Facility. On June 18, 2013, our wholly owned subsidiary, TBNG, entered into a 78.8 million New Turkish Lira (approximately $38.7 million at September 30, 2013) unsecured line of credit with a Turkish bank, of which 60 million New Turkish Lira is available in cash for TBNG and 18.8 million New Turkish Lira 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, and each borrowing is expected to have a two-year term. As of September 30, 2013, there were no borrowings under this credit facility.

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

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 the second quarter of 2012 for this contractual obligation.

Direct Petroleum. In July 2013, we entered into the Amendment to our Purchase Agreement with Direct. Pursuant to the Amendment, we issued 3,510,743 common shares to Direct as partial payment of certain liquidated damages due under the Purchase Agreement. The number of shares was calculated by dividing $2.5 million by the volume weighted average price per share of our common shares on the NYSE MKT for the ten trading days prior to July 2, 2013.

Contractual Obligations

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

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at September 30, 2013.

Forward-Looking Statements

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

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

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

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

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

During the third quarter of 2013, there were no material changes in market risk exposures or their management that would affect the Quantitative and Qualitative Disclosures About Market Risk disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012. Our oil derivatives contracts are settled based upon Brent crude oil pricing. The following tables set forth our outstanding derivatives contracts with respect to future crude oil production as of September 30, 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		October 1, 2013—December 31, 2013		717	$	81.63	$	119.80	$	(15	)
Collar		January 1, 2014—December 31, 2014		622	$	80.83	$	118.07		(157	)

									$	(172	)


			Collars						Additional Call
Type	Period		Quantity (Bbl/ day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Liability
											(in thousands)
Three-way collar contract		October 1, 2013—December 31, 2013		770	$	85.00	$	97.13	$	162.13	$	(790	)
Three-way collar contract		January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13		(2,200	)
Three-way collar contract		January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(2,607	)

											$	(5,597	)

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

As of September 30, 2013, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon the evaluation, and as a result of the material weaknesses in internal control over financial reporting described in our Annual Report on Form 10-K for the year ended December 31, 2012, our chief executive officer and chief financial officer concluded that, as of September 30, 2013, our disclosure controls and procedures were not effective at the reasonable assurance level.

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

Changes in Internal Control over Financial Reporting

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

Item 1A.

Risk Factors

During the third quarter of 2013, there were no material changes to the Risk Factors disclosed in “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

In July 2013, we issued 3,510,743 common shares to Direct pursuant to the Amendment to the Purchase Agreement as partial payment of certain liquidated damages due under the Purchase Agreement. The number of shares was calculated by dividing $2.5 million by the volume weighted average price per share of our common shares on the NYSE MKT for the ten trading days prior to July 2, 2013.

The issuance of our common shares to Direct was made in reliance on the private placement exemption from the registration requirements of the Securities Act of 1933, as amended, provided by Section 4(2) thereof and Rule 506 of Regulation D promulgated thereunder. The issuance of the common shares was conducted without general solicitation or general advertising, Direct represented that it was an “accredited investor” as defined in Rule 501 of Regulation D and that the common shares were acquired for its own account and not with a view to resale or distribution.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

None.

Item 6. Exhibits



3.1		Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).

3.2		Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated August 20, 2009 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).

3.3		Bye-Laws of TransAtlantic Petroleum Ltd., dated July 14, 2009 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).

10.1		Second Amendment to Purchase Agreement dated effective July 2, 2013 by and among Direct Petroleum Exploration, LLC, TransAtlantic Worldwide, Ltd. and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated July 3, 2013, filed with the SEC on July 10, 2013).

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.

Signatures

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


By:		/s/ N. MALONE MITCHELL, 3rd
		N. Malone Mitchell, 3rd Chief Executive Officer

By:		/s/ WIL F. SAQUETON
		Wil F. Saqueton Chief Financial Officer

Date: November 7, 2013

INDEX TO EXHIBITS



3.1		Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).

3.2		Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated August 20, 2009 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).

3.3		Bye-Laws of TransAtlantic Petroleum Ltd., dated July 14, 2009 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).

10.1		Second Amendment to Purchase Agreement dated effective July 2, 2013 by and among Direct Petroleum Exploration, LLC, TransAtlantic Worldwide, Ltd. and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated July 3, 2013, filed with the SEC on July 10, 2013).

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.

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