Edgar Filing: TRANSATLANTIC PETROLEUM LTD.

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

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

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

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

As of August 5, 2013, the registrant had 369,838,025 common shares outstanding.

TABLE OF CONTENTS


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

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

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

Consolidated Statements of Equity for the Six Months Ended June 30, 2013		3

Consolidated Statements of Cash Flows for the Six Months Ended June 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		16

Item 3. Quantitative and Qualitative Disclosures About Market Risk		26

Item 4. Controls and Procedures		26

PART II. OTHER INFORMATION

Item 1. Legal Proceedings		26

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)


	June 30, 2013			December 31, 2012
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	15,920		$	14,768
Accounts receivable
Oil and natural gas sales, net		27,742			34,158
Joint interest and other		10,951			18,192
Related party		662			419
Prepaid and other current assets		2,009			2,339
Deferred income taxes		3,680			1,895
Assets held for sale		534			1,619

Total current assets		61,498			73,390

Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		250,491			231,498
Unproved		56,169			68,938
Equipment and other property		39,943			35,747

		346,603			336,183
Less accumulated depreciation, depletion and amortization		(91,754	)		(80,031	)

Property and equipment, net		254,849			256,152
Other long-term assets:
Other assets		7,825			8,195
Note receivable – related party		11,500			11,500
Goodwill		8,355			9,021

Total other assets		27,680			28,716

Total assets	$	344,027		$	358,258

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	11,948		$	12,864
Accounts payable — related party		18,922			15,634
Accrued liabilities		22,235			29,972
Derivative liabilities		1,516			3,908
Asset retirement obligations		968			818
Liabilities held for sale		7,169			8,416

Total current liabilities		62,758			71,612

Long-term liabilities:
Asset retirement obligations		10,750			11,140
Accrued liabilities		6,822			7,548
Deferred income taxes		17,722			16,483
Loan payable		39,766			32,766
Derivative liabilities		2,038			4,882

Total long-term liabilities		77,098			72,819

Total liabilities		139,856			144,431
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.01 par value, 1,000,000,000 shares authorized; 369,304,453 shares issued and outstanding as of June 30, 2013 and 368,748,592 shares issued and outstanding as of December 31, 2012		3,693			3,687
Additional paid-in capital		538,837			537,962
Accumulated other comprehensive loss		(44,391	)		(28,012	)
Accumulated deficit		(293,968	)		(299,810	)

Total shareholders’ equity		204,171			213,827

Total liabilities and shareholders’ equity	$	344,027		$	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 June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
				(See Note 1)						(See Note 1)
Revenues:
Oil and natural gas sales	$	29,455		$	31,890		$	62,180		$	66,557
Sales of purchased natural gas		1,966			2,001			4,240			3,663
Other		342			537			855			1,714

Total revenues		31,763			34,428			67,275			71,934
Costs and expenses:
Production		3,328			4,293			8,855			7,928
Exploration, abandonment and impairment		11,885			6,883			15,749			9,679
Cost of purchased natural gas		1,866			1,900			4,046			3,636
Seismic and other exploration		1,090			848			1,333			1,511
Revaluation of contingent consideration		(5,000	)		—			(5,000	)		—
General and administrative		6,893			9,280			14,416			18,557
Depreciation, depletion and amortization		9,581			9,382			18,557			18,551
Accretion of asset retirement obligations		124			164			253			415

Total costs and expenses		29,767			32,750			58,209			60,277

Operating income		1,996			1,678			9,066			11,657
Other income (expense):
Interest and other expense		(955	)		(2,018	)		(1,845	)		(5,277	)
Interest and other income		307			348			682			482
Gain on commodity derivative contracts		4,278			14,304			3,502			1,869
Foreign exchange (loss) gain		(2,543	)		(1,073	)		(3,030	)		3,199

Total other income (expense)		1,087			11,561			(691	)		273

Income from continuing operations before income taxes		3,083			13,239			8,375			11,930
Current income tax expense		(528	)		(422	)		(1,867	)		(2,442	)
Deferred income tax benefit (expense)		348			(4,247	)		(573	)		(2,388	)

Net income from continuing operations		2,903			8,570			5,935			7,100
Loss from discontinued operations before income taxes		—			(4,485	)		(93	)		(4,662	)
Gain on disposal of discontinued operations		—			27,214			—			27,214
Income tax provision		—			(6,193	)		—			(8,173	)

Net income (loss) from discontinued operations		—			16,536			(93	)		14,379
Net income	$	2,903		$	25,106		$	5,842		$	21,479
Other comprehensive income (loss):
Foreign currency translation adjustment		(13,543	)		1,141			(16,379	)		14,504

Comprehensive income (loss)	$	(10,640	)	$	26,247		$	(10,537	)	$	35,983

Net income per common share:
Basic net income per common share:
Continuing operations	$	0.01		$	0.02		$	0.02		$	0.02
Discontinued operations	$	0.00		$	0.05		$	0.00		$	0.04
Weighted average common shares outstanding		368,936			366,536			368,911			366,486
Diluted net income per common share:
Continuing operations	$	0.01		$	0.02		$	0.02		$	0.02
Discontinued operations	$	0.00		$	0.05		$	0.00		$	0.04
Weighted average common and common equivalent shares outstanding		368,936			368,855			368,911			368,288

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

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Equity

(Unaudited)

(U.S. dollars and shares in thousands)


	Common Shares		Common Shares ($)		Additional Paid-in Capital			Accumulated Other Comprehensive Loss			Accumulated Deficit			Total Shareholders’ Equity
Balance at December 31, 2012		368,749	$	3,687	$	537,962		$	(28,012	)	$	(299,810	)	$	213,827
Issuance of restricted stock units		555		6		(6	)		—			—			—
Share-based compensation		—		—		881			—			—			881
Foreign currency translation adjustments		—		—		—			(16,379	)		—			(16,379	)
Net income		—		—		—			—			5,842			5,842

Balance at June 30, 2013		369,304	$	3,693	$	538,837		$	(44,391	)	$	(293,968	)	$	204,171

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 Six Months Ended June 30,
	2013			2012
				(See Note 1)
Operating activities:
Net income	$	5,842		$	21,479
Adjustment for net loss (income) from discontinued operations		93			(14,379	)

Net income from continuing operations		5,935			7,100
Adjustments to reconcile net income to net cash provided by operating activities:
Share-based compensation		881			1,103
Foreign currency loss		2,138			1,972
Unrealized gain on commodity derivative contracts		(5,238	)		(4,116	)
Amortization of loan financing costs		256			645
Deferred income tax expense		573			2,388
Exploration, abandonment and impairment		15,749			9,679
Depreciation, depletion and amortization		18,557			18,551
Accretion of asset retirement obligations		253			415
Revaluation of contingent consideration		(5,000	)		—
Changes in operating assets and liabilities, net of effect of acquisitions:
Accounts receivable		10,432			(12,332	)
Prepaid expenses and other assets		141			1,584
Accounts payable and accrued liabilities		11,045			21,024

Net cash provided by operating activities from continuing operations		55,722			48,013
Net cash used in operating activities from discontinued operations		(1,071	)		(33,154	)

Net cash provided by operating activities		54,651			14,859
Investing activities:
Additions to oil and natural gas properties		(52,320	)		(30,685	)
Additions to equipment and other properties		(7,925	)		(2	)
Restricted cash		(206	)		1,059

Net cash used in investing activities from continuing operations		(60,451	)		(29,628	)
Net cash provided by investing activities from discontinued operations		1,016			154,871

Net cash (used in) provided by investing activities		(59,435	)		125,243
Financing activities:
Exercise of stock options and warrants		—			600
Tax withholding on restricted stock units		—			52
Loan proceeds		22,885			9,974
Loan proceeds—related party		—			11,000
Loan repayment		(15,885	)		(62,923	)
Loan financing costs		—			(250	)
Loan repayment—related party		—			(84,000	)

Net cash provided by (used in) financing activities from continuing operations		7,000			(125,547	)
Net cash used in financing activities from discontinued operations		—			(2,180	)

Net cash provided by (used in) financing activities		7,000			(127,727	)
Effect of exchange rate changes on cash		(1,064	)		388
Net increase in cash and cash equivalents		1,152			12,763
Cash and cash equivalents, beginning of year		14,768			15,116

Cash and cash equivalents, end of period	$	15,920		$	27,879

Supplemental disclosures:
Cash paid for interest	$	1,539		$	4,459

Cash paid for taxes	$	1,448		$	2,485

Supplemental non-cash investing and financing activities:
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 June 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 June 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 six months ended June 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 six months ended June 30, 2012, these reclassifications increased total revenues and costs and expenses by approximately $1.9 million and $3.6 million, respectively.

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

During the three months ended September 30, 2012, we identified and corrected errors that originated in prior periods. We assessed the materiality of the errors in accordance with the SEC guidance on considering the effects of prior period misstatements based on an analysis of quantitative and qualitative factors. Based on this analysis, we determined that the errors were immaterial to each of the prior reporting periods affected and, therefore, amendments of reports previously filed with the SEC were not required. However, we also concluded that not correcting the errors in our 2012 year-end consolidated financial statements would have materially understated results for the year ended December 31, 2012. Accordingly, we have reflected the correction of these prior period errors in the periods in which they originated and revised our consolidated statements of comprehensive income (loss) for the three and six months ended June 30, 2012 and our consolidated statements of cash flows for the six months ended June 30, 2012 in this Quarterly Report on Form 10-Q.

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

Additionally, during the three months ended March 31, 2013, we identified and corrected errors previously reported on our consolidated statements of cash flows. As a result, we increased the “Exploration, abandonment and impairment” sub-caption, which is an adjustment to reconcile net income (loss) to net cash provided by operating activities, and increased the cash used in investing activities related to “Additions to oil and natural gas properties” by $2.2 million for the six months ended June 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 six months ended June 30, 2012 in this Quarterly Report on Form 10-Q.

The following shows the effect of the out-of-period adjustments and reclassifications on the Company’s consolidated statement of comprehensive income (loss) for the three months ended June 30, 2012 (in thousands):


	As Reported			Correction			As Revised
For the three months ended June 30, 2012
Total revenues	$	32,528		$	1,900		$	34,428
Total costs and expenses		(31,894	)		(856	)		(32,750	)
Total other income		11,290			271			11,561

Income from continuing operations before income taxes		11,924			1,315			13,239
Net income from continuing operations		7,860			710			8,570
Net income from discontinued operations		15,052			1,484			16,536

Net income		22,912			2,194			25,106
Foreign currency translation adjustment		345			796			1,141

Comprehensive income	$	23,257		$	2,990		$	26,247

The following shows the effect of the out-of-period adjustments and reclassifications on the Company’s consolidated statement of comprehensive income (loss) for the six months ended June 30, 2012 (in thousands):


	As Reported			Correction			As Revised
For the six months ended June 30, 2012
Total revenues	$	67,463		$	4,471		$	71,934
Total costs and expenses		(58,158	)		(2,119	)		(60,277	)
Total other income		141			132			273

Income from continuing operations before income taxes		9,446			2,484			11,930
Net income from continuing operations		5,221			1,879			7,100
Net income from discontinued operations		12,895			1,484			14,379

Net income		18,116			3,363			21,479
Foreign currency translation adjustment		14,719			(215	)		14,504

Comprehensive income	$	32,835		$	3,148		$	35,983

The following shows the effect of the out-of-period adjustments and reclassifications on our consolidated statement of cash flows for the six months ended June 30, 2012 (in thousands):


	As Reported			Correction			As Revised
For the six months ended June 30, 2012
Operating activities:
Exploration, abandonment and impairment	$	7,464		$	2,215		$	9,679
Other		39,495			(1,161	)		38,334
Net cash provided by operating activities from continuing operations		46,959			1,054			48,013
Net cash provided by operating activities		12,321			2,538			14,859
Investing activities:
Additions to oil and natural gas properties		(27,937	)		(2,748	)		(30,685	)
Net cash used in investing activities from continuing operations		(26,880	)		(2,748	)		(29,628	)
Net cash provided by (used in) investing activities		127,991			(2,748	)		125,243
Financing activities:
Tax withholding on restricted stock units		(158	)		210			52
Net cash (used in) provided by financing activities from continuing operations		(125,757	)		210			(125,547	)
Net cash (used in) provided by financing activities	$	(127,937	)	$	210		$	(127,727	)

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

On June 27, 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 June 30, 2013 and December 31, 2012:


	June 30, 2013		December 31, 2012
	(in thousands)
Cash	$	24	$	93
Other assets (1)		510		1,526

Total assets held for sale	$	534	$	1,619

Accrued expenses and other liabilities	$	7,169	$	8,416

Total liabilities held for sale	$	7,169	$	8,416

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

Discontinued operations of oilfield services business

On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”), to a joint venture owned by Dalea Partners, LP (“Dalea”) and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $168.5 million, consisting of approximately $157.0 million in cash and a $11.5 million promissory note from Dalea. The promissory note bears interest at a rate of 3.0% per annum and is guaranteed by Mr. Mitchell. We have presented the oilfield services segment operating results as discontinued operations for the three and six months ended June 30, 2012.

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


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2013			2012			2013			2012
	(in thousands)
Total revenues	$	—		$	10,672		$	—		$	20,956
Total costs and expenses		(52	)		(15,325	)		(138	)		(24,851	)
Total other income (expense)		52			168			45			(767	)

Loss from discontinued operations before income taxes		—			(4,485	)		(93	)		(4,662	)
Gain on disposal of discontinued operations		—			27,214			—			27,214
Income tax provision		—			(6,193	)		—			(8,173	)

Net income (loss) from discontinued operations	$	—		$	16,536		$	(93	)	$	14,379

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:


	June 30, 2013			December 31, 2012
	(in thousands)
Oil and natural gas properties, proved:
Turkey	$	248,638		$	229,462
Bulgaria		1,853			2,036

Total oil and natural gas properties, proved		250,491			231,498
Oil and natural gas properties, unproved:
Turkey		56,169			68,938

Gross oil and natural gas properties		306,660			300,436
Accumulated depletion		(84,986	)		(74,099	)

Net oil and natural gas properties	$	221,674		$	226,337

At June 30, 2013 and December 31, 2012, we excluded $0.8 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 June 30, 2013, the capitalized costs of our net oil and natural gas properties included $42.0 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $122.7 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 six months ended June 30, 2013, we incurred approximately $26.3 million in exploratory drilling costs, of which $4.3 million was included in exploration, abandonment and impairment expense, $17.0 million was reclassified from unproved properties to proved properties and $5.0 million remained capitalized at June 30, 2013. No exploratory well costs were reclassified to proved properties in the second quarter of 2012. Uncertainties affect the recoverability of costs of our oil and natural gas properties, as the recovery of the costs are dependent upon us maintaining licenses in good standing and achieving commercial production or sale.

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 for 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.

Of the $7.3 million of dry hole costs expensed during the three months ended June 30, 2013, approximately $0.5 million was related to cash spent during the second quarter of 2013.

Impairment and abandonment

We recorded $4.6 million in impairment and abandonment charges on our proved and unproved properties during the six months ended June 30, 2013, primarily related to our Malkara license. We recorded $1.5 million in impairment charges on our proved properties during the six months ended June 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:


	June 30, 2013			December 31, 2012
	(in thousands)
Other equipment	$	2,583		$	2,013
Inventory		24,361			20,517
Gas gathering system and facilities		4,973			5,369
Vehicles		234			131
Office equipment and furniture		7,792			7,717

Gross equipment and other property		39,943			35,747
Accumulated depreciation		(6,768	)		(5,932	)

Net equipment and other property	$	33,175		$	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 June 30, 2013, we excluded $24.4 million of inventory and $0.4 million of office equipment and furniture from depreciation, as the inventory and office equipment and furniture 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 June 30, 2013, we recorded a net gain on commodity derivative contracts of approximately $4.3 million, consisting of a $4.8 million unrealized gain related to changes in fair value and a $0.5 million realized loss for settled contracts. For the six months ended June 30, 2013, we recorded a net gain on commodity derivative contracts of $3.5 million, consisting of a $5.2 million unrealized gain related to changes in fair value and a $1.7 million realized loss for settled contracts.

For the three months ended June 30, 2012, we recorded a net gain on commodity derivative contracts of approximately $14.3 million consisting of a $15.1 million unrealized gain related to changes in fair value and a $0.8 million realized loss for settled contracts. For the six months ended June 30, 2012, we recorded a net gain on commodity derivative contracts of $1.9 million, consisting of a $4.1 million unrealized gain related to changes in fair value and a $2.2 million realized loss for settled contracts.

At June 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 June 30, 2013


Type	Period		Quantity (Bbl/day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Asset
									(in thousands)
Collar		July 1, 2013—December 31, 2013		775	$	82.26	$	121.36	$	13
Collar		January 1, 2014—December 31, 2014		662	$	80.83	$	118.07		134

									$	147


			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		July 1, 2013—December 31, 2013		831	$	85.00	$	97.13	$	162.13	$	(837	)
Three-way collar contract		January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13		(1,292	)
Three-way collar contract		January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(1,572	)

											$	(3,701	)

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 six months ended June 30, 2013 and for the year ended December 31, 2012:


	June 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		(107	)		(110	)
Foreign exchange change effect		(870	)		793
Additions		492			899
Accretion expense		253			710

Asset retirement obligations at end of period		11,718			11,958
Less: current portion		968			818

Long-term portion	$	10,750		$	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:


	June 30, 2013		December 31, 2012
	(in thousands)
Floating Rate Debt
Amended and Restated Credit Facility	$	39,766	$	32,766

Loan payable	$	39,766	$	32,766

Amended and Restated Senior Secured Credit Facility

On May 18, 2011, DMLP, Ltd., TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd., TransAtlantic Turkey, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayive Ticaret A.Ş. and Amity Oil International Pty Ltd (collectively, the “Borrowers”) entered into the Amended and Restated Credit Facility. Each of the Borrowers is our wholly owned subsidiary. The Amended and Restated Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd (“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 July 4, 2013 our borrowing base was $58.2 million. Loans under the Amended and Restated Credit Facility accrue interest at a rate of three-month LIBOR plus 5.50% per annum.

At June 30, 2013, we had borrowed $39.8 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 $40.9 million at June 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 June 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 agreed to issue 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. This share issuance will be recorded in the three months ended September 30, 2013 in accordance with Accounting Standard Codification (“ASC”) 855, Subsequent Events (“ASC 855”) and is expected to have a dilutive effect on future earnings per share calculations.

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 three and six 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 to Direct. As such, the $2.5 million contingent liability, recorded in 2011, will remain as of June 30, 2013.

Additionally, the Amendment provides that if the Bulgarian government issues a production concession over the Stefenetz Concession Area of at least 200,000 acres, 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.

9. Shareholders’ equity

Restricted stock units

Share-based compensation expense of approximately $0.5 million and $0.9 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three and six months ended June 30, 2013, respectively. We recorded share-based compensation expense of $0.6 million and $1.1 million for the three and six months ended June 30, 2012, respectively.

As of June 30, 2013, we had approximately $2.6 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.8 years.

Earnings per share

We account for earnings per share in accordance with ASC Subtopic 260-10, Earnings Per Share (“ASC 260-10”). ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted. Basic earnings per common share for the three and six months ended June 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 six months ended June 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. The computation of diluted earnings per common share excluded 7,300,000 and 7,455,206 antidilutive common share equivalents from the three months ended June 30, 2013 and 2012, respectively, and 7,300,000 and 7,464,463 antidilutive common share equivalents from the six months ended June 30, 2013 and 2012, respectively.

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


	Three Months Ended June 30,				Six Months Ended June 30,
(in thousands, except per share amounts)	2013		2012		2013			2012
Net income from continuing operations	$	2,903	$	8,570	$	5,935		$	7,100
Net income (loss) from discontinued operations	$	—	$	16,536	$	(93	)	$	14,379
Basic net income per common share:
Shares:
Weighted average shares outstanding		368,936		366,536		368,911			366,486

Basic net income per common share:
Continuing operations	$	0.01	$	0.02	$	0.02		$	0.02

Discontinued operations	$	0.00	$	0.05	$	0.00		$	0.04

Diluted net income per common share:
Shares:
Weighted average number of common shares outstanding		368,936		366,536		368,911			366,486
Dilutive effect of:
Restricted stock units		—		2,169		—			1,645
Stock options		—		150		—			157

Weighted average common and common equivalent shares outstanding		368,936		368,855		368,911			368,288

Diluted net income per common share:
Continuing operations	$	0.01	$	0.02	$	0.02		$	0.02

Discontinued operations	$	0.00	$	0.05	$	0.00		$	0.04

Additionally, we had a contingent liability at June 30, 2013 of approximately $2.5 million that is payable in our common shares. At the June 28, 2012 closing price of our common shares, this liability represented 3,623,188 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 June 30, 2013
Total revenues	$	2		$	—		$	31,733	$	28		$	31,763
Income (loss) from continuing operations before income taxes		(3,119	)		(35	)		1,525		4,712			3,083
Capital expenditures	$	—		$	—		$	27,147	$	—		$	27,147
For the three months ended June 30, 2012
Total revenues	$	—		$	—		$	34,344	$	84		$	34,428
Income (loss) from continuing operations before income taxes		(1,835	)		(357	)		17,631		(2,200	)		13,239
Capital expenditures	$	—		$	—		$	13,760	$	—		$	13,760
For the six months ended June 30, 2013
Total revenues	$	2		$	—		$	67,177	$	96		$	67,275
Income (loss) from continuing operations before income taxes		(6,076	)		(58	)		9,897		4,612			8,375
Capital expenditures	$	—		$	—		$	45,846	$	—		$	45,846
For the six months ended June 30, 2012
Total revenues	$	—		$	—		$	71,785	$	149		$	71,934
Income (loss) from continuing operations before income taxes		(7,274	)		(655	)		22,259		(2,400	)		11,930
Capital expenditures	$	—		$	—		$	27,771	$	168		$	27,939
Segment assets
June 30, 2013	$	14,675		$	38		$	327,042	$	1,738		$	343,493	⁽¹⁾
December 31, 2012	$	14,825		$	105		$	339,752	$	1,957		$	356,639	⁽¹⁾
Goodwill
June 30, 2013	$	—		$	—		$	8,355	$	—		$	8,355
December 31, 2012	$	—		$	—		$	9,021	$	—		$	9,021

(1)	Excludes assets held for sale from our discontinued Moroccan operations of $0.5 million and $1.6 million at June 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 June 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 June 30, 2013, we had 25.7 million New Turkish Lira (approximately $13.4 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 June 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 June 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)	$	—	$	(3,554	)	$	—	$	(3,554	)

Total	$	—	$	(3,554	)	$	—	$	(3,554	)

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 June 30, 2013 and December 31, 2012:


	June 30, 2013		December 31, 2012
	(in thousands)
Related party accounts receivable:
Viking International master services agreement	$	629	$	313
Riata Management service agreement		33		—
Dalea promissory note		—		106

Total related party accounts receivable	$	662	$	419

Related party accounts payable:
Viking International master services agreement	$	18,803	$	15,467
Riata Management service agreement		119		167

Total related party accounts payable	$	18,922	$	15,634

For the three and six months ended June 30, 2013 and 2012, we incurred expenditures of $17.5 million and $37.7 million and $13.5 million and $15.6 million, respectively, related to our various related party agreements.

13. Subsequent events

In July 2013, we entered into the Amendment to the Purchase Agreement with Direct. The Company recorded the impact of the Amendment in the second quarter of 2013 as an adjusting subsequent event in accordance with ASC 855 (see Note 8).

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 June 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 June 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 second quarter of 2013 include:

•

We reported $2.9 million of net income from continuing operations for the three months ended June 30, 2013, as compared to $8.6 million for the same period in 2012.

•

We derived 68.2% of our revenues from the production of oil and 24.6% of our revenues from the production of natural gas during the three months ended June 30, 2013.

•

Total oil and natural gas sales revenues decreased 7.6% to $29.5 million for the quarter ended June 30, 2013 from $31.9 million in the same period in 2012. The decrease was primarily the result of lower production of 47 thousand barrels of oil equivalent (“Mboe”), which decreased revenues by $3.6 million. This decrease was partially offset by an increase in our average realized price per Boe, which increased revenues by $1.2 million.

•

Total net production was 230 thousand barrels (“Mbbls”) of oil and 816 million cubic feet (“Mmcf”) of natural gas, as compared to 233 Mbbls of oil and 1,081 Mmcf of natural gas for the same period in 2012.

•

For the quarter ended June 30, 2013, we produced an average of 4,022 net barrels of oil equivalent (“Boe”) per day, as compared to 4,538 Boe per day for the same period in 2012.

•

For the quarter ended June 30, 2013, we incurred $28.1 million in capital expenditures, including license acquisition and seismic expenditures from continuing operations, as compared to $14.7 million for the quarter ended June 30, 2012.

•

As of June 30, 2013, we had $39.8 million in outstanding debt and no short-term borrowings, as compared to $32.8 million in outstanding debt and no short-term borrowings as of June 30, 2012.

Recent Developments

Amendment of Purchase Agreement. In July 2013, our wholly owned subsidiary, TransAtlantic Worldwide, Ltd. (“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 will issue 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. 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. 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.

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 $40.9 million at June 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 June 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.

Second Quarter 2013 Operational Update

During the second 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 completed three horizontal wells during the first half of 2013, including the Bahar-2H well, our first attempt to drill a horizontal well within the targeted Bedinan H-1 sand that is one of the primary producing zones for the Bahar-1 well. We were unable to encounter and stay within the target zone, and a two-stage frac resulted in uneconomic production. We plugged back to test the Hazro section, which tested at 170 barrels (“Bbls”) of oil per day. We may re-drill the well below 8,000 feet as a vertical Bedinan H-1 well.

We completed drilling the Catak-1, a vertical well targeting the Dadas shales and Bedinan sandstones. The well encountered multiple oil shows in the Mardin, Hazro, Dadas shale and first and third Bedinan sands. We drilled the Oba-1H, a Mardin horizontal well, which we are currently completing. We are currently drilling the lateral portion of the Goksu-5H, our fifth horizontal well targeting the Mardin zone, and expect to achieve target depth by the end of August 2013.

In May 2013, we commenced an 800 square km 3D seismic program over Molla and the surrounding areas, including northwest Arpatepe, which we expect to complete by the end of 2013 and interpret in the first half of 2014.

Selmo. We completed the Selmo-13H, our first horizontal well in the Selmo oil field. The well is currently producing approximately 200 Bbls of oil per day from the LSD zone from a natural completion. This was our first completion in the LSD zone. As a result of the success of Selmo-13H well, we plan to add additional LSD horizontal wells to our drilling schedule for the second half of 2013, in addition to the four horizontal wells we plan to drill in the MSD formation of the Selmo oil field.

Gaziantep. We completed the Alibey-1H and are currently testing the well. We expect to commence production from the well during the third quarter of 2013.

Turkey-Northwest.

In the first half of 2013, we completed three new wells and fracture stimulated six wells. We also recompleted two wells, which increased our Thrace Basin gross natural gas production to 25 Mmcf per day (“Mmcf/d”) or net production of 14 Mmcf/d in July 2013. We drilled our first horizontal well in the Thrace Basin, the DTD-19HK, and we completed a seven-stage fracture stimulation on the well during the third quarter of 2013.

We drilled the Gocerler-7 well, a vertical well targeting the Osmancik formation, during the third quarter of 2013. We are currently completing the well. During the second half of 2013, we plan to drill six shallow, vertical natural gas prospects in the northern part of the Thrace Basin using efficient drilling techniques and three additional horizontal wells in the southern part of the Thrace Basin.

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

•

Continue to Expand Fracture Stimulation Program. In 2012, our Thrace Basin fracture simulation program tested and defined deeper intervals and provided important lessons regarding hydraulic fracture stimulation design. In 2013, we plan to expand our application of fracture stimulation techniques in several of our exploration licenses in southeastern Turkey.

•

Expand the Use of Horizontal Drilling. In 2012, we had initial horizontal drilling success with the Goksu-3H well on our Molla licenses and the Alibey-1 well on our Gaziantep licenses. During the second half of 2013, we anticipate our drilling in southeastern Turkey will include extensive use of horizontal drilling techniques, including seven wells on our Molla licenses and five wells at Selmo. We also plan to drill three 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 Bulgaria and Turkey and plan to continue this effort during the remainder of 2013.

Capital expenditures, including seismic expenditures, for the third and fourth quarters of 2013 are expected to range between $70 million and $90 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 third and fourth quarters of 2013:

Turkey. We plan to continue our three-part strategy in Turkey: (i) the Molla horizontal program, (ii) the Selmo field redevelopment program, and (iii) the Thrace Basin development program. We plan to drill approximately 34 gross wells, 16 of which are expected to be drilled horizontally and approximately 65% of which will be fracture stimulated. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill.

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

Other Matters

During our review procedures associated with our mid-year reserve analysis, we discovered that the future lease operating expenses used in our reserves calculation were overstated, resulting in an immaterial understatement of the present value of estimated future net revenues (“PV-10”) and standardized measure of discounted future net cash flows (“Standardized Measure”) as of December 31, 2012. The correction resulted in a proved reserve volume increase of approximately 19 Mboe, related to one of our oil fields where the economic life exceeds our remaining lease term. For the year ended December 31, 2012, this change in volumes had a negligible impact on the consolidated financial statements. A reconciliation of the reported and corrected PV-10 and Standardized Measure are presented below:


	As Reported			Change			As Corrected
	(in thousands
Total PV-10	$	511,078		$	52,679		$	563,757
Future income taxes		(106,411	)		(15,395	)		(121,806	)
Discount of future income taxes at 10% per annum		31,210			5,437			36,647

Standardized measure	$	435,877		$	42,721		$	478,598

Discontinued Operations in Morocco

On June 27, 2011, we decided to discontinue our Moroccan operations. We have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for the three and six months ended June 30, 2013 and June 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

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.

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

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


	Three Months Ended June 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			233		(3	)
Natural gas (Mmcf)		816			1,081		(265	)
Total production (Mboe)		366			413		(47	)
Average daily production (Boe/day)		4,022			4,538		(516	)
Average prices:
Oil (per Bbl)	$	94.13		$	97.49	$	(3.36	)
Natural gas (per Mcf)		9.57			8.49		1.08
Oil equivalent (per Boe)		80.48			77.22		3.26
Revenues:
Oil and natural gas sales	$	29,455		$	31,890	$	(2,435	)
Sales of purchased natural gas		1,966			2,001		(35	)
Other		342			537		(195	)
Costs and expenses:
Production	$	3,328		$	4,293	$	(965	)
Exploration, abandonment and impairment		11,885			6,883		5,002
Cost of purchased natural gas		1,866			1,900		(34	)
Seismic and other exploration		1,090			848		242
Revaluation of contingent consideration		(5,000	)		—		(5,000	)
General and administrative		6,893			9,280		(2,387	)
Depreciation, depletion and amortization		9,581			9,382		199
Interest and other expense		955			2,018		(1,063	)


	Three Months Ended June 30,						Change
	2013			2012			2013-2012
	(in thousands of U.S. dollars, except per unit prices and production volumes) (as adjusted)
Gain on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	(484	)	$	(773	)	$	289
Non-cash change in fair value on commodity derivative contracts		4,762			15,077			(10,315	)

Total gain on commodity derivative contracts	$	4,278		$	14,304		$	(10,026	)

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $2.4 million to $29.5 million for the three months ended June 30, 2013, from $31.9 million realized in the same period in 2012. Of this decrease, $3.6 million resulted from lower production volumes of 47 Mboe. This was partially offset by $1.2 million from higher average realized prices per Boe due to producing a higher percentage of oil and a 10% increase in the price of natural gas by Boru Hatlari ile Petrol Tasima A.S. (“BOTAŞ”), effective October 1, 2012. For the three months ended June 30, 2013, our average price was $80.48 per Boe, as compared to $77.22 per Boe for the same period in 2012.

Production. Production expenses for the three months ended June 30, 2013 decreased to $3.3 million, from $4.3 million for the same period in 2012. The decrease was primarily attributable to $1.1 million of operating expenses billed back to our TBNG joint venture partners following a redetermination of operating costs billable to our joint venture partners.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended June 30, 2013 increased approximately $5.0 million to $11.9 million, from $6.9 million for the same period in 2012. Of the $11.9 million of exploration, abandonment and impairment costs, approximately $0.5 million was cash spent during the quarter. During the three months ended June 30, 2013, there were write-offs of three wells for $4.3 million, $1.9 million and $0.9 million. During the three months ended June 30, 2012, there were write-offs of two wells for $2.1 and $1.7 million. Additionally, during the three months ended June 30, 2013, we recorded $4.6 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 $1.1 million for the three months ended June 30, 2013, as compared to $0.9 million for the same period in 2012.

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

General and Administrative. General and administrative expense was $6.9 million for the three months ended June 30, 2013, as compared to $9.3 million for the same period in 2012. The decrease was primarily due to a decrease in employee-related costs of $0.9 million, which was partially offset by an increase of $0.6 million in accounting and consulting expenses. Employee-related costs decreased due to a reduction in headcount. Accounting and consulting expenses were higher during the three months ended June 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 the $2.0 million contingency related to the Aglen exploration permit in Bulgaria, which was recognized during the three months ended June 30, 2012. The remaining decrease of $0.1 million was attributable to our overall cost reduction efforts.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $9.6 million for the three months ended June 30, 2013, as compared to $9.4 million in the same period of 2012.

Interest and Other Expense. Interest and other expense decreased to $1.0 million for the three months ended June 30, 2013, as compared to $2.0 million for the same period in 2012. The decrease was primarily due to decreased debt levels for the three months ended June 30, 2013 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.

Gain on Commodity Derivative Contracts. During the three months ended June 30, 2013, we recorded a gain on commodity derivative contracts of approximately $4.3 million, as compared to a gain of $14.3 million for the same period in 2012. We recorded a $4.8 million unrealized gain and a $0.5 million realized loss on our derivative contracts for the three months ended June 30, 2013, as compared to a $15.1 million unrealized gain and a $0.8 million realized loss for the three months ended June 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 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 June 30, 2013 decreased to a loss of $13.5 million from a gain of $1.1 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 for the three months ended June 30, 2013 and 2012 and oilfield services business for the three months ended June 30, 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 June 30,
	2013			2012
	(in thousands)
Revenues:
Oilfield services	$	—		$	10,672

Total revenues		—			10,672
Costs and expenses:
Production		41			361
Oilfield services costs		—			6,664
General and administrative		11			8,300

Total costs and expenses		52			15,325

Operating loss		(52	)		(4,653	)
Other income (expense):
Interest and other expense		(6	)		(111	)
Interest and other income		58			154
Foreign exchange gain		—			125

Total other income		52			168

Loss from discontinued operations before income taxes		—			(4,485	)
Gain on disposal of discontinued operations		—			27,214
Income tax provision		—			(6,193	)

Net income from discontinued operations	$	—		$	16,536

Results of Operations—Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

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


	Six Months Ended June 30,				Change
	2013		2012		2013-2012
	(in thousands of U.S. dollars, except per unit prices and production volumes) (as adjusted)
Production:
Oil (Mbbl)		470		457		13
Natural gas (Mmcf)		1,616		2,448		(832	)
Total production (Mboe)		739		865		(126	)
Average daily production (Boe/day)		4,083		4,753		(670	)
Average prices:
Oil (per Bbl)	$	98.44	$	103.31	$	(4.87	)
Natural gas (per Mcf)		9.85		7.90		1.95
Oil equivalent (per Boe)		84.14		76.94		7.20
Revenues:
Oil and natural gas sales	$	62,180	$	66,557	$	(4,377	)
Sales of purchased natural gas		4,240		3,663		577
Other		855		1,714		(859	)
Costs and expenses:
Production	$	8,855	$	7,928	$	927
Exploration, abandonment and impairment		15,749		9,679		6,070
Cost of purchased natural gas		4,046		3,636		410


	Six Months Ended June 30,						Change
	2013			2012			2013-2012
	(in thousands of U.S. dollars, except per unit prices and production volumes) (as adjusted)
Seismic and other exploration		1,333			1,511			(178	)
Revaluation of contingent consideration		(5,000	)		—			(5,000	)
General and administrative		14,416			18,557			(4,141	)
Depreciation, depletion and amortization		18,557			18,551			6
Interest and other expense		1,845			5,277			(3,432	)
Gain on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	(1,736	)	$	(2,247	)	$	511
Non-cash change in fair value on commodity derivative contracts		5,238			4,116			1,122

Total gain on commodity derivative contracts	$	3,502		$	1,869		$	1,633

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $4.4 million to $62.2 million for the six months ended June 30, 2013, from $66.6 million realized in the same period in 2012. Of this decrease, $9.7 million was due to a decrease in production volumes of 126 Mboe. Production volumes decreased primarily on our Thrace Basin wells due to depletion of wells recompleted in the second half of 2011. This was partially offset by an increase of $5.3 million, primarily due to higher average realized prices per Boe resulting from the production of a higher percentage of oil and realization of higher natural gas prices. Our average price received increased $7.20 to $84.14 per Boe for the six months ended June 30, 2013, from $76.94 per Boe for the same period in 2012.

Production. Production expenses for the six months ended June 30, 2013 increased to $8.9 million, from $7.9 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 intercompany whereas they are now classified as third-party.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the six months ended June 30, 2013 increased approximately $6.0 million to $15.7 million, from $9.7 million for the same period in 2012. During the six months ended June 30, 2013, there were write-offs of four wells for $4.3 million, $2.9 million, $1.9 million and $0.9 million. In the first half of 2012, there were write-offs of four wells at an average of approximately $1.8 million per well. Additionally, during the six months ended June 30, 2013, we recorded $4.6 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 decreased to $1.3 million for the six months ended June 30, 2013, as compared to $1.5 million for the same period in 2012.

General and Administrative. General and administrative expense was $14.4 million for the six months ended June 30, 2013, as compared to $18.6 million for the same period in 2012. The decrease was primarily due to a decrease in employee-related costs of $1.3 million, a $0.3 million decrease in rents on offices and corporate apartments, and a decrease of $0.6 million in consulting expenses, which was partially offset by an increase of $0.4 million in accounting and legal expenses. Employee-related costs decreased due to a reduction in headcount. Accounting and legal expenses were higher during the six months ended June 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 the $2.0 million accrual for a contingency related to the Aglen exploration permit in Bulgaria, which was recognized during the six months ended June 30, 2012. The remaining decrease of $0.4 million was attributable to our overall cost reduction efforts.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization was unchanged at $18.6 million for the six months ended June 30, 2013 and 2012.

Interest and Other Expense. Interest and other expense decreased to $1.8 million for the six months ended June 30, 2013, as compared to $5.3 million for the same period in 2012. The decrease is primarily due to decreased debt levels for the six months ended June 30, 2013 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.

Gain on Commodity Derivative Contracts. During the six months ended June 30, 2013, we recorded a gain on commodity derivative contracts of approximately $3.5 million, as compared to a gain of $1.9 million for the same period in 2012. We recorded a $5.2 million unrealized gain and a $1.7 million realized loss on our derivative contracts for the six months ended June 30, 2013, as compared to a $4.1 million unrealized gain and a $2.2 million realized loss on our derivative contracts for the six months ended June 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 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 six months ended June 30, 2013 decreased to a loss of $16.4 million from a gain of $14.5 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 for the six months ended June 30, 2013 and 2012 and oilfield services business for the six months ended June 30, 2012 have been included in discontinued operations.

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


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

Total revenues		—			20,956
Costs and expenses:
Production		110			649
Oilfield services costs		—			13,736
General and administrative		28			10,466

Total costs and expenses		138			24,851

Operating loss		(138	)		(3,895	)
Other income (expense):
Interest and other expense		(8	)		(176	)
Interest and other income		53			172
Foreign exchange loss		—			(763	)

Total other income (expense)		45			(767	)

Loss from discontinued operations before income taxes		(93	)		(4,662	)
Gain on disposal of discontinued operations		—			27,214
Income tax provision		—			(8,173	)

Net (loss) income from discontinued operations	$	(93	)	$	14,379

Capital Expenditures

Capital expenditures, including seismic expenditures, for the third and fourth quarters of 2013 are expected to range between $70 million and $90 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 second quarter of 2013 were our cash and cash equivalents, cash flow from operations and net borrowings under our Amended and Restated Credit Facility. At June 30, 2013, we had cash and cash equivalents of $15.9 million, no short-term debt, $39.8 million in long-term debt, and working capital of $3.2 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 six months ended June 30, 2013 increased to $55.7 million, as compared to net cash provided by operating activities from continuing operations of $48.0 million for the six months ended June 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 June 30, 2013, the outstanding principal amount of our debt was $39.8 million. In addition to cash, cash equivalents and cash flow from operations, at June 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 June 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 July 4, 2013, our borrowing base was $58.2 million.

At June 30, 2013, we had outstanding borrowings of $39.8 million and availability of $18.4 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 $40.9 million at June 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 June 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 agreed to issue 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.

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.

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 June 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 second 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 June 30, 2013:


Type	Period		Quantity (Bbl/ day)		Weighted Average Minimum Price (per Bbl)		Weighted Average Maximum Price (per Bbl)		Estimated Fair Value of Asset
									(in thousands)
Collar		July 1, 2013—December 31, 2013		775	$	82.26	$	121.36	$	13
Collar		January 1, 2014—December 31, 2014		662	$	80.83	$	118.07		134

									$	147


			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		July 1, 2013—December 31, 2013		831	$	85.00	$	97.13	$	162.13	$	(837	)
Three-way collar contract		January 1, 2014—December 31, 2014		726	$	85.00	$	97.13	$	162.13		(1,292	)
Three-way collar contract		January 1, 2015—December 31, 2015		1,016	$	85.00	$	91.88	$	151.88		(1,572	)

											$	(3,701	)

Item 4.

Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

As of June 30, 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 June 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 second quarter of 2013 that have affected, or are reasonably likely to materially affect, our internal control over financial reporting, except for the following:

In April 2013, we hired a vice president of accounting and corporate controller with 12 years of “Big 4” public accounting experience, including several years of public company oil and natural gas accounting experience, to manage the accounting function beginning in May 2013.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

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

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

None.

Item 6. Exhibits



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

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

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

10.1		Office Lease dated effective April 5, 2013, by and between TransAtlantic Petroleum (USA) Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 8, 2013, filed with the SEC on May 14, 2013).

10.2*		Letter Agreement dated April 24, 2013, by and between TransAtlantic Petroleum Ltd. and Chad W. Potter.

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

Signatures

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


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

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

Date: August 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		Office Lease dated effective April 5, 2013, by and between TransAtlantic Petroleum (USA) Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 8, 2013, filed with the SEC on May 14, 2013).

10.2*		Letter Agreement dated April 24, 2013, by and between TransAtlantic Petroleum Ltd. and Chad W. Potter.

10.3		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.

†

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company