TransAtlantic Petroleum 10Q 2015 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: March 31, 2015

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

For the transition period from to

Commission file number: 001-34574

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

Large accelerated filer	¨	Accelerated filer	x

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

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

As of May 5, 2015, the registrant had 40,956,234 common shares outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	2

Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2015 and 2014	3

Consolidated Statement of Equity for the Three Months Ended March 31, 2015	4

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2015 and 2014	5

Notes to Consolidated Financial Statements	6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	19

Item 3. Quantitative and Qualitative Disclosures About Market Risk	26

Item 4. Controls and Procedures	26

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	28

Item 1A. Risk Factors	28

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	28

Item 3. Defaults Upon Senior Securities	28

Item 4. Mine Safety Disclosures	28

Item 5. Other Information	28

Item 6. Exhibits	30

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

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

	March 31,			December 31,
	2015			2014
ASSETS	(unaudited)
Current assets:
Cash and cash equivalents	$	28,151		$	35,132
Accounts receivable, net
Oil and natural gas sales		26,938			29,673
Joint interest and other		6,287			19,918
Related party		557			602
Prepaid and other current assets		6,949			8,930
Deferred income taxes		854			329
Derivative asset		12,560			12,518
Restricted cash		1,742			1,917
Assets held for sale		26			28
Total current assets		84,064			109,047
Property and equipment:
Oil and natural gas properties (successful efforts methods)
Proved		389,962			424,031
Unproved		64,105			65,438
Equipment and other property		41,312			42,343
		495,379			531,812
Less accumulated depreciation, depletion and amortization		(137,458	)		(141,977	)
Property and equipment, net		357,921			389,835
Other long-term assets:
Other assets		8,741			8,836
Note receivable - related party		11,500			11,500
Derivative asset		18,455			19,069
Deferred income taxes		1,088			1,181
Goodwill		6,161			6,935
Total other assets		45,945			47,521
Total assets	$	487,930		$	546,403

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	35,689		$	39,407
Accounts payable - related party		4,628			18,488
Accrued liabilities		34,159			31,238
Deferred income taxes		2,005			2,138
Asset retirement obligations		282			323
Loans payable		32,887			45,806
Loan payable - related party		–			6,800
Liabilities held for sale		6,348			6,928
Total current liabilities		115,998			151,128
Long-term liabilities:
Asset retirement obligations		10,030			11,053
Accrued liabilities		10,631			12,336
Deferred income taxes		52,147			54,430
Loans payable		95,784			85,192
Loan payable - related party		20,800			20,800
Total long-term liabilities		189,392			183,811
Total liabilities		305,390			334,939
Commitments and contingencies
Shareholders' equity:
Common shares, $0.10 par value, 100,000,000 shares authorized; 40,789,087 shares and 40,708,120 shares issued and outstanding as of March 31, 2015 and December 31, 2014, respectively		4,079			4,071
Additional paid-in-capital		571,331			571,150
Accumulated other comprehensive loss		(102,929	)		(79,310	)
Accumulated deficit		(289,941	)		(284,447	)
Total shareholders' equity		182,540			211,464
Total liabilities and shareholders' equity	$	487,930		$	546,403

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

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)

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

	For the Three Months Ended
	March 31,
	2015			2014
Revenues:
Oil and natural gas sales	$	26,647		$	32,984
Sales of purchased natural gas		298			545
Other		51			117
Total revenues		26,996			33,646
Costs and expenses:
Production		5,946			4,131
Transportation costs		67			-
Exploration, abandonment and impairment		330			4,141
Cost of purchased natural gas		266			485
Seismic and other exploration		58			3,294
Revaluation of contingent consideration		-			(2,500	)
General and administrative		8,619			6,552
Depreciation, depletion and amortization		11,578			10,090
Accretion of asset retirement obligations		111			98
Total costs and expenses		26,975			26,291
Operating income		21			7,355
Other income (expense):
Interest and other expense		(3,310	)		(1,203	)
Interest and other income		653			273
Gain on commodity derivative contracts		3,812			962
Foreign exchange loss		(5,148	)		(1,344	)
Total other expense		(3,993	)		(1,312	)
(Loss) income from continuing operations before income taxes		(3,972	)		6,043
Current income tax expense		(1,521	)		(69	)
Deferred income tax expense		(1	)		(1,981	)
Net (loss) income from continuing operations		(5,494	)		3,993
Net loss from discontinued operations		-			(20	)
Net (loss) income	$	(5,494	)	$	3,973
Other comprehensive (loss) income:
Foreign currency translation adjustment		(23,619	)		(3,295	)
Comprehensive (loss) income	$	(29,113	)	$	678

Net (loss) income per common share
Basic net (loss) income per common share
Continuing operations	$	(0.13	)	$	0.11
Discontinued operations	$	-		$	(0.00	)
Weighted average common shares outstanding		40,767			37,392
Diluted net (loss) income per common share
Continuing operations	$	(0.13	)	$	0.11
Discontinued operations	$	-		$	(0.00	)
Weighted average common and common equivalent shares outstanding		40,767			37,392

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

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statement of Equity

(Unaudited)

(U.S. Dollars and shares in thousands)

										Accumulated
							Additional			Other						Total
	Common				Common		Paid-in			Comprehensive			Accumulated			Shareholders'
	Shares		Warrants		Shares ($)		Capital			Loss			Deficit			Equity
Balance at December 31, 2014		40,708	233		$	4,071	$	571,150		$	(79,310	)	$	(284,447	)	$	211,464
Issuance of restricted stock units		81		-		8		(8	)		-			-			-
Tax withholding on restricted stock units		-		-		-		(78	)		-			-			(78	)
Share-based compensation		-		-		-		267			-			-			267
Foreign currency translation adjustment		-		-		-		-			(23,619	)		-			(23,619	)
Net loss		-		-		-		-			-			(5,494	)		(5,494	)
Balance at March 31, 2015		40,789		233		4,079		571,331			(102,929	)		(289,941	)		182,540

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

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands of U.S. Dollars)

	For the Three Months Ended
	March 31,
	2015			2014
Operating activities:
Net (loss) income	$	(5,494	)	$	3,973
Adjustment for net loss from discontinued operations		–			20
Net (loss) income from continuing operations		(5,494	)		3,993
Adjustments to reconcile net income to net cash provided by operating activities:
Share-based compensation		267			396
Foreign currency loss		4,616			2,413
Gain on commodity derivative contracts		(3,812	)		(962	)
Cash settlement on commodity derivative contracts		4,384			(752	)
Amortization on loan financing costs		172			127
Deferred income tax expense		1			1,981
Exploration, abandonment and impairment		330			4,141
Depreciation, depletion and amortization		11,578			10,090
Accretion of asset retirement obligations		111			98
Revaluation of contingency consideration		–			(2,500	)
Changes in operating assets and liabilities:
Accounts receivable		12,418			5,207
Prepaid expenses and other assets		(183	)		(401	)
Accounts payable and accrued liabilities		(10,596	)		4,320
Net cash provided by operating activities from continuing operations		13,792			28,151
Net cash used in operating activities from discontinued operations		–			(20	)
Net cash provided by operating activities		13,792			28,131
Investing activities:
Additions to oil and natural gas properties		(6,702	)		(30,925	)
Additions to equipment and other properties		(3,528	)		(267	)
Net cash used in investing activities from continuing operations		(10,230	)		(31,192	)
Net cash provided by investing activities from discontinued operations		–			500
Net cash used in investing activities		(10,230	)		(30,692	)
Financing activities:
Tax withholding on restricted share units		(78	)		(60	)
Loan proceeds		7,600			12,013
Loan repayment		(9,927	)		(5,313	)
Loan repayment - related party		(6,800	)		–
Net cash (used in) provided by financing activities		(9,205	)		6,640
Effect of exchange rate on cash flows and cash equivalents		(1,338	)		(252	)
Net (decrease) increase in cash and cash equivalents		(6,981	)		3,827
Cash and cash equivalents, beginning of period		35,132			12,881
Cash and cash equivalents, end of period	$	28,151		$	16,708
Supplemental disclosures:
Cash paid for interest	$	1,823		$	766
Cash paid for taxes	$	738		$	–

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

Transatlantic Petroleum Ltd.

Notes to Consolidated Financial Statements

(Unaudited)

1. General

Nature of operations

TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the “Company” or “TransAtlantic”) is an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored petroleum systems, have stable governments, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey, Albania and Bulgaria. As of May 5, 2015, approximately 36% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

Basis of presentation

Our consolidated financial statements are expressed in U.S. Dollars and have been prepared by management in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). All amounts in these notes to the consolidated financial statements are in U.S. Dollars unless otherwise indicated. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews estimates, including those related to fair value measurements associated with acquisitions and financial derivatives, the recoverability and impairment of long-lived assets and goodwill, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with U.S. GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2014.

Decline in Oil Price

As a result of the decline in prices for Brent crude since June 2014, we have reduced our planned capital expenditures and deferred a significant amount of our planned exploration and development until prices for Brent crude improve. In order to mitigate the impact of reduced prices on our 2015 cash flows and liquidity, we have implemented cost reduction measures and will continue to implement cost-cutting initiatives to reduce our operating costs and general and administrative expenses. These initiatives include the negotiation of exploration and development and operating cost reductions with several key vendors and plans to continue to pursue further reductions. We believe this strategy will allow us to preserve our liquidity in order to execute our 2015 development program and continue to meet our contractual obligations.

We believe that our cash flows from operations and existing cash on hand are sufficient to conduct our planned operations through 2015 and meet our contractual requirements, including license obligations. Additionally, at current Brent crude prices, our current hedge positions provide additional liquidity on a monthly recurring basis.

Notwithstanding these measures, there remain risks and uncertainties that could negatively impact our results of operations and financial condition. For example, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by further declines in oil and natural gas prices. The next borrowing base redetermination is October 1, 2015.

2. Recent accounting pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods or services to a customer at an amount

that reflects the consideration a company expects to receive in exchange for those goods or services. The update is effective for periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2014-09 on our consolidated financial statements and results of operations.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern ("ASU 2014-15"), an amendment to FASB Accounting Standards Codification ("ASC") Topic 205, Presentation of Financial Statements. This update provides guidance on management's responsibility in evaluating whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. We do not expect the adoption of ASU 2014-15 to have a material impact on our consolidated financial statements or results of operations. If events occur in future periods that affect our ability to continue as a going concern, we will provide the disclosures required by ASU 2014-15.

In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. We currently recognize debt issuance costs as assets on our consolidated balance sheet. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. ASU 2015-03 is effective for annual and interim periods beginning after December 15, 2015 and early adoption is permitted. Currently, we do not expect the adoption of ASU 2015-03 to have a material impact on our consolidated financial statements or results of operations.

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

3. Acquisitions

Stream

On November 18, 2014, we acquired Stream Oil & Gas Ltd. (“Stream”) in exchange for (i) 3.2 million of our common shares issued at closing, and (ii) an additional 0.6 million of our common shares issuable if certain conditions are met (at a deemed price of $7.41 per common share). We engaged independent valuation experts to assist in the determination of the fair value of the assets and liabilities acquired in the acquisition. We are still assessing the assets acquired and liabilities assumed. Thus, the final determination of the value of assets acquired and liabilities assumed may result in adjustments to the values presented below. The following tables summarize the consideration paid in the acquisition and the preliminary amounts of assets acquired and liabilities assumed that have been recognized at the acquisition date:

	(in thousands)
Consideration:
Issuance of 3,218,641 common shares	$	23,850
Contingent payment event		4,188
Fair value of total consideration	$	28,038
Acquisition-Related Costs:
Included in general and administrative expenses on our consolidated statements of comprehensive income (loss) for the year ended December 31, 2014	$	1,129

Recognized Amounts of Identifiable Assets Acquired and Liabilities Assumed at Acquisition:
Assets:
Cash	$	66
Accounts receivable		6,672
Other current assets		347
Total current assets		7,085
Oil and natural gas properties:
Proved properties		99,927
Unproved properties		16,140
Equipment and other property		964
Total oil and natural gas properties and other equipment		117,031
Total assets		124,116
Liabilities:
Accounts payable		20,673
Accounts payable - related party		2,820
Other current liabilities		10,000
Viking International note - related party		6,800
Loans payable - current		11,732
Other non-current liabilities		5,036
Loans payable - non-current		6,123
Asset retirement obligations		827
Deferred income taxes		32,067
Total liabilities		96,078
Total identifiable net assets	$	28,038

The following table presents the unaudited pro forma results of operations as though the acquisition of Stream had occurred as of January 1, 2014 (see our Annual Report on Form 10-K for the year ended December 31, 2014 for a discussion of this acquisition):

	For the Three Months Ended
	March 31, 2014
	(in thousands, except per share data)
Total revenues	$	39,806
Income from continuing operations before income taxes		6,688
Income from continuing operations		5,103
Loss from discontinued operations		(20	)
Net income		5,083
Net income per common share from continuing operations
Basic and diluted	$	0.13

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:

	March 31, 2015			December 31, 2014
	(in thousands)
Oil and natural gas properties, proved:
Turkey	$	289,444		$	323,442
Albania		100,037			100,037
Bulgaria		481			552
Total oil and natural gas properties, proved		389,962			424,031
Oil and natural gas properties, unproved:
Turkey		41,849			43,090
Albania		18,674			18,301
Bulgaria		3,582			4,047
Total oil and natural gas properties, unproved		64,105			65,438
Gross oil and natural gas properties		454,067			489,469
Accumulated depletion		(129,105	)		(133,304	)
Net oil and natural gas properties	$	324,962		$	356,165

At March 31, 2015 and December 31, 2014, we excluded $0.8 million and $0.9 million, respectively, from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At March 31, 2015, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $123.7 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $136.4 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

At December 31, 2014, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $129.0 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $160.8 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

Exploratory well costs

During the three months ended March 31, 2015 and 2014, we recorded $0.3 million and $4.1 million of exploratory well costs, respectively. The $0.3 million of costs incurred during the three months ended March 31, 2015 was related to cash spent during the three months ended March 31, 2015.

Capitalized cost greater than one year

As of March 31, 2015, we had $1.4 million and $2.0 million of exploratory well costs capitalized for the Hayrabolu-10 and Bahar-2ST wells in Turkey, which we spud in February 2013 and March 2014, respectively. The Hayrabolu-10 and Bahar-2ST wells continue to be evaluated for completion pending more analysis. Additionally, we have $3.6 million of exploratory well costs for the Deventci-R2 well in Bulgaria, which we spud in October 2013, and we are still evaluating the results of an acid stimulation.

Equipment and other property

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

	March 31, 2015			December 31, 2014
	(in thousands)
Other equipment	$	2,650		$	2,983
Inventory		24,500			24,309
Gas gathering system and facilities		5,344			6,016
Vehicles		439			488
Leasehold improvements, office equipment and software		8,379			8,547
Gross equipment and other property		41,312			42,343
Accumulated depreciation		(8,353	)		(8,673	)
Net equipment and other property	$	32,959		$	33,670

We have reclassified certain prior year costs of equipment and other property to conform to current period presentation.

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

At March 31, 2015, we excluded $24.5 million of inventory from depreciation as the inventory had not been placed into service. At December 31, 2014, we excluded $24.3 million of inventory and $3.0 million of software from depreciation as the inventory and software had not been placed into service.

5. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations (“ARO”) for the three months ended March 31, 2015 and for the year ended December 31, 2014:

	March 31, 2015			December 31, 2014
	(in thousands)
Asset retirement obligations at beginning of period	$	11,376		$	10,896
Change in estimates		–			–
Liabilities settled		–			(373	)
Foreign exchange change effect		(1,184	)		(900	)
Additions		9			513
Accretion expense		111			413
Acquisitions		–			827
Asset retirement obligations at end of period		10,312			11,376
Less: current portion		282			323
Long-term portion	$	10,030		$	11,053

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.

6. Commodity derivative instruments

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

To the extent that a legal right of offset exists, we net the value of our derivative contracts with the same counterparty in our consolidated balance sheets. All of our oil derivative contracts are settled based upon Brent crude oil pricing. We recognize gains and losses related to these contracts on a fair value basis in our consolidated statements of comprehensive income (loss) under the caption “Gain on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on commodity derivative contracts.” We are required under our senior secured credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP Paribas”) and the International Finance Corporation (“IFC”) to hedge at least 30% of our anticipated oil production volumes in Turkey.

During the three months ended March 31, 2015 and 2014, we recorded a net gain on commodity derivative contracts of $3.8 million and $1.0 million, respectively.

At March 31, 2015 and December 31, 2014, we had outstanding contracts with respect to our future crude oil production as set forth in the tables below:

Fair Value of Derivative Instruments as of March 31, 2015

Weighted

Average

Quantity

Minimum

Maximum Price

Estimated Fair

Type

Period

(Bbl/day)

Price (per Bbl)

(per Bbl)

Value of Asset

(in thousands)

Collar

April 1, 2015—December 31, 2015

1,338

85.00

97.25

9,988

		Collars						Additional Call

				Weighted		Weighted		Weighted
				Average		Average		Average
				Minimum		Maximum		Maximum		Estimated Fair
		Quantity		Price		Price		Price		Value of
Type	Period	(Bbl/day)		(per Bbl)		(per Bbl)		(per Bbl)		Asset
										(in thousands)
Three-way collar contract	January 1, 2016—December 31, 2016		1,066	$	85.00	$	97.25	$	114.25	$	8,742
Three-way collar contract	January 1, 2017—December 31, 2017		888	$	85.00	$	97.25	$	114.25		6,382
Three-way collar contract	January 1, 2018—December 31, 2018		726	$	85.00	$	97.25	$	114.25		4,833
Three-way collar contract	January 1, 2019—March 31, 2019		663	$	85.00	$	97.25	$	114.25		1,070
										$	21,027

Fair Value of Derivative Instruments as of December 31, 2014

Weighted

Average

Quantity

Minimum

Maximum Price

Estimated Fair

Type

Period

(Bbl/day)

Price (per Bbl)

(per Bbl)

Value of Asset

(in thousands)

Collar

January 1, 2015—December 31, 2015

1,410

85.00

97.25

12,518

				Weighted		Weighted		Weighted
				Average		Average		Average
				Minimum		Maximum		Maximum		Estimated Fair
		Quantity		Price		Price		Price		Value of
Type	Period	(Bbl/day)		(per Bbl)		(per Bbl)		(per Bbl)		Asset
										(in thousands)
Three-way collar contract	January 1, 2016—December 31, 2016		1,066	$	85.00	$	97.25	$	114.25	$	7,609
Three-way collar contract	January 1, 2017—December 31, 2017		888	$	85.00	$	97.25	$	114.25		5,748
Three-way collar contract	January 1, 2018—December 31, 2018		726	$	85.00	$	97.25	$	114.25		4,659
Three-way collar contract	January 1, 2019—March 31, 2019		663	$	85.00	$	97.25	$	114.25		1,053
										$	19,069

Balance sheet presentation

The following table summarizes both: (i) the gross fair value of our commodity derivative instruments by the appropriate balance sheet classification even when the commodity derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at March 31, 2015 and December 31, 2014, and (ii) the net recorded fair value as reflected on our consolidated balance sheets at March 31, 2015 and December 31, 2014.

As of March 31, 2015

Gross

Amount

Net Amount of

Gross

Offset in the

Assets

Amount of

Consolidated

Presented in the

Recognized

Balance

Consolidated

Underlying Commodity

Location on Balance Sheet

Assets

Sheet

Balance Sheet

(in thousands)

Crude oil

Current Assets

12,560

–

12,560

Crude oil

Long-term Assets

18,455

–

18,455

As of December 31, 2014

Gross

Amount

Net Amount of

Gross

Offset in the

Assets

Amount of

Consolidated

Presented in the

Recognized

Balance

Consolidated

Underlying Commodity

Location on Balance Sheet

Assets

Sheet

Balance Sheet

(in thousands)

Crude oil

Current Assets

12,518

–

12,518

Crude oil

Long-term Assets

19,069

–

19,069

7. Loan payable

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

	March 31,		December 31,
	2015		2014
Fixed and floating rate loans	(in thousands)
Senior Credit Facility	$	68,298	$	68,298
Convertible Notes		34,200		26,600
TBNG credit facility		15,575		20,025
Term Loan Facility		8,163		10,452
Prepayment Facility		2,435		3,043
Convertible Notes - Related Party		20,800		20,800
Viking International Promissory Note - Related Party		–		6,800
Shareholder Loan		–		2,580
Loans payable		149,471		158,598
Less: current portion		32,887		52,606
Long-term portion	$	116,584	$	105,992

Senior Credit Facility

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

The borrowing base amount is re-determined semi-annually on April 1^st and October 1^st of each year, beginning April 1, 2015. The borrowing base was $68.3 million as of March 31, 2015. The borrowing base amount equals, for any calculation date, the lowest of:

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

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

Convertible notes

As of March 31, 2015, we had $55.0 million of outstanding 13.0% convertible notes due 2017 (the “Convertible Notes”). The Convertible Notes bear interest at a rate of 13.0% per annum and mature on July 1, 2017. The Convertible Notes are convertible, at the election of a holder, any time after July 1, 2015, into our common shares at a conversion price of $6.80 per share.

TBNG credit facility

Our subsidiary Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) has a fully drawn credit facility with a Turkish bank. During the first quarter of 2015, the facility was amended and now bears interest at a rate of 5.9% per annum and is due in monthly principal installments of $1.3 million each, ending March 31, 2016. The facility may be prepaid without penalty. The facility is secured by a lien on a hotel owned by Gundem Turizm Yatirim ve Isletmeleri Anonim Sirketi (“Gundem”), which is 97.5% beneficially owned by Mr. Mitchell and his children. At March 31, 2015, TBNG owed $15.6 million under the credit facility and had no availability.

Term Loan Facility

Our indirectly wholly owned subsidiary, Stream Oil & Gas Ltd., a Cayman Islands corporation (“Stream Sub”), has a term loan facility (the “Term Loan Facility”) with Raiffeisen Bank Sh.A (“Raiffeisen”). The Term Loan Facility matures on December 31, 2016 and bears interest at the rate of LIBOR plus 5.5%, with a minimum interest rate of 7.0%. Stream Sub is required to repay $1.0 million each quarter on the last business day of each of March, June, September and December. The loan is guaranteed by Stream. Stream Sub may prepay the loan at its option in whole or in part, subject to a 3.0% penalty plus breakage costs. The Term Loan Facility is secured by substantially all of the assets of Stream Sub. As of March 31, 2015, we had $8.2 million outstanding under the Term Loan Facility and no availability.

At March 31, 2015, we were not in compliance with certain conditions subsequent set forth in Section 4 of the Term Loan Facility, including the delivery to Raiffeisen of a copy of an agreement between Albpetrol and ourselves concerning postponement of capital expenditures. Raiffeisen has granted us a waiver on this requirement until June 5, 2015.

Prepayment Agreement

In April 2013, Stream and Stream Sub entered into the prepayment agreement (the “Prepayment Agreement”) with Trafigura PTE Ltd (“Trafigura”). In October 2013, Stream received a $7.0 million prepayment under the Prepayment Agreement. No further prepayment requests can be made under the Prepayment Agreement. The prepayment is to be repaid by Stream’s delivery of oil to Trafigura in accordance with an oil sales contract between Stream and Trafigura and bears interest at a rate equal to LIBOR plus 6% (6.17% at March 31, 2015). Stream must repay the prepayment at the times and in the quantities as set out in the oil sales contract, and all amounts must be repaid on or before August 31, 2015. At March 31, 2015, Stream had $2.4 million outstanding under the Prepayment Agreement and no availability.

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 TransAtlantic Exploration Mediterranean International Pty Ltd. (“TEMI”) and Turkish governmental authorities. We do not have enough information to estimate the potential additional operating costs we would incur in the event the purported surface owners’ claims are ultimately successful. Any adjustment arising out of the claims will be recorded when it becomes probable and measurable.

Morocco

During 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew down our $1.0 million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during 2012 for this contingency.

Aglen

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

Direct Petroleum

In July 2013, we entered into a second amendment (the “Amendment”) to the purchase agreement (the “Purchase Agreement”) with Direct Petroleum Exploration, LLC (“Direct”). The Amendment set forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. We completed the drilling and testing requirements pursuant to the Amendment during April 2014, which resulted in the reversal of a $2.5 million contingent liability recorded in 2011. The reversal is recognized in our consolidated statements of comprehensive income (loss) under the caption “Revaluation of contingent consideration” during the three months ended March 31, 2014.

In addition, the Amendment provides that we will issue $7.5 million in common shares if the Deventci-R2 well is a commercial success (as defined in the Purchase Agreement) on or prior to May 1, 2016. We will record any provision for this contingent consideration when it is estimable and probable. As of March 31, 2015, we had not recorded a contingent liability for this contingent consideration.

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

9. Shareholders’ equity

Reverse stock split

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

Restricted stock units

We recorded share-based compensation expense of $0.3 million and $0.4 million for awards of restricted stock units (“RSUs”) for the three months ended March 31, 2015 and 2014, respectively.

As of March 31, 2015, we had approximately $1.4 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.7 years.

Earnings per share

We account for earnings per share in accordance with ASC Subtopic 260-10, Earnings Per Share (“ASC 260-10”). ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted. Basic earnings per common share for the three months ended March 31, 2015 and 2014 equals net income (loss) 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 months ended March 31, 2015 and 2014 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes RSUs.

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

	Three Months Ended
	March 31,
(in thousands, except per share amounts)	2015			2014
Net (loss) income from continuing operations	$	(5,494	)	$	3,993
Net loss from discontinued operations	$	–		$	(20	)
Basic net (loss) income per common share:
Shares:
Weighted average common shares outstanding		40,767			37,392
Basic net (loss) income per common share:
Continuing operations	$	(0.13	)	$	0.11
Discontinued operations	$	–		$	(0.00	)
Diluted net (loss) income per common share:
Shares:
Weighted average common shares outstanding		40,767			37,392
Diluted net (loss) income per common share:
Continuing operations	$	(0.13	)	$	0.11
Discontinued operations	$	–		$	(0.00	)

10. Segment information

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

	Corporate			Turkey		Bulgaria			Albania			Total
	(in thousands)
For the three months ended March 31, 2015
Total revenues	$	-		$	25,757	$	-		$	1,239		$	26,996
Income (loss) from continuing operations before income taxes		(7,045	)		4,207		(101	)		(1,033	)		(3,972	)
Capital expenditures	$	55		$	6,240	$	41		$	1,444		$	7,780
For the three months ended March 31, 2014
Total revenues	$	-		$	33,639	$	7		$	-		$	33,646
Income (loss) from continuing operations before income taxes		(3,820	)		7,500		2,363			-			6,043
Capital expenditures	$	169		$	21,781	$	1,041		$	-		$	22,991
Segment assets(1)
March 31, 2015	$	29,178		$	326,375	$	4,192		$	128,159		$	487,904
December 31, 2014	$	51,919		$	363,162	$	4,675		$	126,619		$	546,375
Goodwill
March 31, 2015	$	-		$	6,161	$	-		$	-		$	6,161
December 31, 2014	$	-		$	6,935	$	-		$	-		$	6,935

(1)	Excludes assets held for sale from our discontinued Moroccan operations of $26,000 and $28,000 at March 31, 2015 and December 31, 2014, respectively.

11. Financial instruments

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities and our loans payable were each estimated to have a fair value approximating the carrying amount at March 31, 2015 and December 31, 2014, due to the short maturity of those instruments.

Interest rate risk

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

Foreign currency risk

We have underlying foreign currency exchange rate exposure. Our currency exposures relate to transactions denominated in the Canadian Dollar, Bulgarian Lev, European Union Euro, Romanian New Leu, Moroccan Dirham, Albanian Lek, and Turkish New Lira (“TRY”). We are also subject to foreign currency exposures resulting from translating the functional currency of our foreign subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At March 31, 2015, we had 16.7 million TRY (approximately $6.4 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY.

Commodity price risk

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including, but not limited to, supply and demand. At March 31, 2015 and December 31, 2014, 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 purchases all of our oil production. The receivables are not collateralized. To date, we have experienced minimal bad debts. The majority of our cash and cash equivalents are held by three financial institutions in the United States and Turkey.

Fair value measurements

The following table summarizes the valuation of our financial assets and liabilities as of March 31, 2015:

Fair Value Measurement Classification

Quoted Prices in

Active Markets for

Identical Assets or

Significant Other

Significant

Liabilities

Observable Inputs

Unobservable Inputs

(Level 1)

(Level 2)

(Level 3)

Total

(in thousands)

Assets:

Commodity derivative contracts

–

31,015

–

31,015

Total

–

31,015

–

31,015

The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2014:

Fair Value Measurement Classification

Quoted Prices in

Active Markets for

Identical Assets or

Significant Other

Significant

Liabilities

Observable Inputs

Unobservable Inputs

(Level 1)

(Level 2)

(Level 3)

Total

(in thousands)

Assets:

Commodity derivative contracts

–

31,587

–

31,587

Total

–

31,587

–

31,587

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 the dates indicated:

	March 31,		December 31,
	2015		2014
	(in thousands)
Related party accounts receivable:
Viking International master services agreement	$	352	$	355
Riata Management Service Agreement		125		159
Dalea promissory note		80		88
Total related party accounts receivable	$	557	$	602
Related party accounts payable:
Viking International master services agreement	$	3,477	$	16,754
Riata Management Service Agreement		1,151		1,734
Total related party accounts payable	$	4,628	$	18,488

13. Subsequent events

On April 24, 2015, TransAtlantic Petroleum Ltd. (the “Company”) issued 134,168 common share purchase warrants (the “Warrants”) to Mr. Mitchell pursuant to a warrant agreement (the “Warrant Agreement”). These Warrants were issued to Mr. Mitchell as a shareholder of the entity Gundem, which agreed to pledge its primary asset, a Turkish resort, in exchange for an extension of the maturity date of a credit agreement between the Company and a Turkish bank. As consideration for the pledge of the Gundem resort, the independent members of the Company’s board of directors approved the issuance of the Warrants to be allocated in accordance with each shareholder’s ownership percentage of Gundem. Pursuant to the Warrant Agreement, the Warrants are immediately exercisable, expire 18 months from the date of the release of the pledge on the Gundem resort, and entitle the holder to purchase one common share for each Warrant at an exercise price of $5.65 per share.

Item 2.

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

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

Executive Overview

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established yet underexplored petroleum systems, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of March 31, 2015, we held interests in approximately 1.8 million net acres of developed and undeveloped oil and natural gas properties in Turkey, Albania and Bulgaria. As of May 5, 2015, approximately 36% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

Decline in Oil Prices

In the first quarter of 2015, we have undertaken significant cost saving efforts including staff reductions, office relocations, negotiations of exploration and development and operating cost reductions with several key vendors and optimization of well designs. We believe this strategy will allow us to preserve our liquidity in order to execute our 2015 development program and continue to meet our contractual obligations.

Financial and Operational Performance Highlights

Highlights of our financial and operational performance for the first quarter of 2015 include:

•	We reported a $5.5 million net loss from continuing operations. This includes a $3.8 million gain on our commodity derivative contracts and a $5.1 million foreign currency loss.

•	We derived 77.0% of our oil and natural gas revenues from the production of oil and 23.0% from the production of natural gas.

•

Total oil and natural gas sales revenues decreased 19.2% to $26.6 million for the quarter ended March 31, 2015 from $33.0 million in the same period in 2014. The decrease was primarily the result of a decrease in the average price received of $30.91 per barrel of oil equivalent (“Boe”). This decrease was partially offset by an increase in sales volumes of 135 one thousand Boe (“Mboe”).

•	For the quarter ended March 31, 2015, we incurred $7.8 million in capital expenditures, including seismic and corporate expenditures, as compared to capital expenditures of $26.1 million for the quarter ended March 31, 2014.

•	As of March 31, 2015, we had $116.6 million in long-term debt and $32.9 million in short-term debt, as compared to $106.0 million in long-term debt and $52.6 million in short-term debt as of December 31, 2014.

First Quarter 2015 Operational Update

During the first quarter of 2015, we further developed our oil fields in southeastern Turkey and our Thrace Basin natural gas fields in northwestern Turkey. We installed a new management team in Albania and continued to make progress on the development of a work-over plan for the Albanian fields we acquired in late 2014. The following summarizes our operations by location during the first quarter of 2015:

Turkey-Southeast

Selmo. We continued our secondary recovery program and plan to convert several additional wells to injection during the remainder of 2015.

Molla. Utilizing our 3D seismic, we have focused on high grading our projects, which resulted in the identification of over 20 new field leads.

Idil Exploration. We drilled and completed the Ebyat-2 well on our 50% working interest Idil license to a depth of 7,880 feet. The well tested non-commercial and was plugged and abandoned. Our 50% joint venture partner, Onshore Petroleum Company AS, funded approximately 96% of this well.

Arpatepe. We did not engage in any new drilling activities during the first quarter of 2015.

Turkey-Thrace Basin, Northwest

We drilled the Gurgen-3 well to a depth of 5,910 feet in the Osmancik formation. Initial production was 1.5 million cubic feet per day gross.

Albania

We installed new management in Albania and have begun integrating the well and geological data from the fields in order to prioritize a workover program.

Bulgaria

We continue to evaluate our position in Bulgaria with updated geologic models.

Planned Operations

We continue to actively explore and develop our existing oil and natural gas properties in Turkey and Albania and evaluate opportunities for further activities in Bulgaria. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. For the remainder of 2015, we are focused on accomplishing the following objectives:

Operate within Existing Cash Flows and Maintain Core Acreage. With the dramatic decline in oil prices, we are cutting our overhead and capital expenditures in an effort to operate within existing cash flow. Notwithstanding the decline in oil prices, we plan to drill at least five gross obligation wells in 2015 to hold our most promising licenses.

Increase Reserves and Production. Once oil prices stabilize and begin to recover, we plan to resume more robust investing in exploration and development to increase our oil and natural gas reserves and production in Turkey on our Arpatepe, Molla, Selmo and Thrace Basin exploration licenses and production leases, including the application of 3D seismic, horizontal drilling, fracture stimulation and enhanced oil recovery techniques. In Albania, we plan to complete the drilling and completion of the D34H1 well and, depending upon the results, re-enter two other gas wells in the Delvina gas field. We also plan to revitalize our oilfields in Albania through well recompletions and reactivations, enlarging and lowering pumps and expanding waterfloods. We may also deepen and core several oil wells to better measure oil saturations and understand the potential of the oilfields.

Utilize New 3D Seismic Data to Improve Well Targeting. For the year ended December 31, 2014, we spent $3.7 million finalizing our 3D seismic survey over areas of Turkey where 3D seismic data did not previously exist. We received the processed data in the third quarter of 2014 and drilled several wells in the fourth quarter of 2014 based on the 3D seismic data, all resulting in successful wells, which are either producing or expected to be productive. We expect this new data will improve our ability to target well locations, drill wells and ultimately delineate hydrocarbon reservoirs during 2015.

Expand the Use of Horizontal Drilling. During 2014, we extensively used horizontal drilling techniques on our wells in the Selmo field to more effectively extract hydrocarbons and increase our returns on invested capital. We expect to continue using horizontal drilling techniques during 2015 in the Selmo and Bahar fields.

Further Optimize Fracture Stimulation Program. In 2013 and 2014, we expanded our use of hydraulic fracturing technology to complete otherwise low porosity and permeability formations in Turkey. The evolution of fracturing fluids and stimulation designs has yielded positive results in southeastern Turkey. During 2015, we plan to continue optimizing our hydraulic fracturing techniques to improve well performance and economics.

Pursue Other Growth or Financing Opportunities. In addition to growing our reserves and production through exploration and development of our substantial acreage in Turkey and Albania, we continually evaluate acquisition, joint venture and farm-in/out opportunities. We are focused on both strengthening our positions in Turkey and Albania as well as identifying opportunities in new countries, as we did in 2014 with our acquisition of Stream Oil & Gas, Ltd. (“Stream”).

Capital Expenditures

We expect our net field capital expenditures for 2015 to range between $20.0 million and $38.0 million. We expect net field capital expenditures during 2015 to include approximately $20.0 million of drilling and completion costs for five gross obligation wells to hold our most promising licenses in Turkey. We expect cash on hand, proceeds from the sale of our convertible notes, and cash flow from operations will be sufficient to fund our 2015 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2015 capital expenditure budget is subject to change.

We currently plan to execute the following drilling and exploration activities during the remainder of 2015:

Turkey. We plan to drill five gross license obligations wells. Depending upon oil pricing, we may resume drilling in our Molla area or the Selmo field. We also plan to complete the Pinar-1 well during the second quarter of 2015.

Bulgaria. We plan to evaluate additional completion activities on the Deventci-R2 well.

Albania. We resumed drilling the D34H1 obligation well during the second quarter of 2015 and expect to commence a workover program.

Discontinued Operations in Morocco

In June 2011, we decided to discontinue our Moroccan operations. We have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for the three months ended March 31, 2015 and March 31, 2014.

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, 2014 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, 2014.

Results of Operations—Three Months Ended March 31, 2015 Compared to Three Months Ended March 31, 2014

Our results of operations for the three months ended March 31, 2015 and 2014 were as follows:

��	Three Months Ended March 31,						Change
	2015			2014			2015-2014
	(in thousands of U.S. Dollars, except per unit amounts and production volumes)
Sales volumes:
Oil (Mbbl)		429			260			169
Natural gas (Mmcf)		733			934			(201	)
Total production (Mboe)		551			416			135
Average daily sales volumes (Boepd)		6,122			4,622			1,500
Average prices:
Oil (per Bbl)	$	47.97		$	97.05		$	(49.08	)
Natural gas (per Mcf)	$	8.30		$	8.30		$	–
Oil equivalent (per Boe)	$	48.38		$	79.29		$	(30.91	)
Revenues:
Oil and natural gas sales	$	26,647		$	32,984		$	(6,337	)
Sales of purchased natural gas		298			545			(247	)
Other		51			117			(66	)
Total revenues		26,996			33,646			(6,650	)
Costs and expenses:
Production		5,946			4,131			1,815
Exploration, abandonment and impairment		330			4,141			(3,811	)
Cost of purchased natural gas		266			485			(219	)
Seismic and other exploration		58			3,294			(3,236	)
Revaluation of contingent consideration		-			(2,500	)		2,500
General and administrative		8,619			6,552			2,067
Depletion		10,939			9,559			1,380
Depreciation and amortization		639			531			108
Interest and other expense		3,310			1,203			2,107
Foreign exchange loss		5,148			1,344			3,804
Deferred income tax expense		1			1,981			(1,980	)
Gain on commodity derivative contracts:
Cash settlements on commodity derivative contracts		4,384			(752	)		5,136
Change in fair value on commodity derivative contracts		(572	)		1,714			(2,286	)
Total gain on commodity derivative contracts		3,812			962			2,850
Oil and natural gas costs per Boe:
Production	$	9.46		$	8.70		$	0.76
Depletion	$	17.41		$	20.12		$	(2.71	)

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $6.3 million to $26.6 million for the three months ended March 31, 2015, from $33.0 million realized in the same period in 2014. Of the decrease, $17.1 million was due to a decrease in the average realized price per Boe. Our average price received decreased $30.91 per Boe to $48.38 per Boe for the three months ended March 31, 2015, from $79.29 per Boe for the same period in 2014. This was partially offset by an increase in sales volumes of 135 Mboe, which resulted in higher revenues of $10.6 million. Sales volumes increased primarily on our southeast Turkey oil wells due to our successful horizontal drilling program in 2014 and increased as a result of the acquisition of Stream.

Production. Production expenses for the three months ended March 31, 2015 increased to $5.9 million or $9.46 per Boe from $4.1 million or $8.70 per Boe for the same period in 2014. The increase was primarily due to increased production costs as a result of the acquisition of Stream, and was partially offset by less workover activity of $0.3 million during the three months ended March 31, 2015.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended March 31, 2015 decreased $3.8 million to $0.3 million, from $4.1 million for the same period in 2014. During the three months ended March 31, 2015, we wrote off one well for $0.3 million compared to the three months ended March 31, 2014, when we impaired one well for $3.5 million.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $0.1 million for the three months ended March 31, 2015, compared to $3.3 million for the same period in 2014. The decrease was primarily due to seismic acquisition activities conducted on our West Molla license during the three months ended March 31, 2014.

General and Administrative. General and administrative expense was $8.6 million for the three months ended March 31, 2015, compared to $6.6 million for the same period in 2014. The increase was primarily due to the acquisition of Stream, as well as severance and office relocation costs of $1.1 million and $0.8 million, respectively.

Depletion. Depletion increased to $10.9 million or $17.41 per Boe for the three months ended March 31, 2015, compared to $9.6 million or $20.12 per Boe for the same period of 2014. The increase was primarily due to additions to proved properties during 2014.

Depreciation and Amortization. Depreciation and amortization increased to $0.6 million for the three months ended March 31, 2015, compared to $0.5 million for the same period of 2014.

Interest and Other Expense. Interest and other expense increased to $3.3 million for the three months ended March 31, 2015, compared to $1.2 million for the same period in 2014. The increase was primarily due to an increase in our average level of debt outstanding during the three months ended March 31, 2015 compared to the same period in 2014. At March 31, 2015, we had $149.5 million of total debt outstanding, as compared to $76.5 million at March 31, 2014.

Foreign Exchange Loss. We recorded a foreign exchange loss of $5.1 million during the three months ended March 31, 2015, compared to a loss of $1.3 million in the same period in 2014. The change in foreign exchange is primarily unrealized (non-cash) in nature and results from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the New Turkish Lira (“TRY”) amount if it has not been settled previously. The increase in foreign exchange loss for the three months ended March 31, 2015 was due to a 12.5% decrease in the value of the TRY compared to the U.S. Dollar, compared to a 2.6% decrease in the value of the TRY for the three months ended March 31, 2014.

Deferred Income Tax Expense. Deferred income tax expense decreased to $1,000 for the three months ended March 31, 2015, compared to $1.9 million for 2014. The decrease was primarily due to changes in temporary differences between our U.S. GAAP and statutory balances in Turkey.

Gain on Commodity Derivative Contracts. During the three months ended March 31, 2015, we recorded a net gain on commodity derivative contracts of approximately $3.8 million, compared to a net gain of $1.0 million for the same period in 2014. During the three months ended March 31, 2015, we recorded a $0.6 million loss to mark our commodity derivative contracts to their fair value and a $4.4 million gain on settled contracts. During the same period in 2014, we recorded a $1.7 million gain to mark our derivative contracts to their fair value and a $0.7 million loss on settled contracts. We are required under our Senior Credit Facility to hedge between 30% and 75% of our anticipated oil production volumes in our oil fields in Turkey.

Other Comprehensive Loss. We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. dollar reporting currency. Foreign currency translation adjustment for the three months ended March 31, 2015 increased to a loss of $23.6 million from a loss of $3.3 million for the same period in 2014. The increase in foreign translation loss in the three months ended March 31, 2015 was due to a 12.5% decrease in the value of the TRY compared to the U.S. Dollar, compared to a 2.6% decrease in the value of the TRY for the three months ended March 31, 2014.

Capital Expenditures

For the quarter ended March 31, 2015, we incurred $7.8 million in capital expenditures, including seismic and corporate expenditures, compared to $26.1 million for the quarter ended March 31, 2014. The decrease was due to the planned reduction in our capital expenditures during the quarter ended March 31, 2015 as a result of the impact of lower oil prices.

Liquidity and Capital Resources

Our primary sources of liquidity for the first quarter of 2015 were our cash and cash equivalents, cash flow from operations, proceeds from the issuance of our convertible notes and borrowings under our Senior Credit Facility. At March 31, 2015, we had cash and cash equivalents of $28.2 million, $116.6 million in long-term debt, $32.9 million in short-term debt and a working capital deficit of $31.9 million, compared to cash and cash equivalents of $35.1 million, $106.0 million in long-term debt, $52.6 million in short-term debt and working capital deficit of $42.1 million at December 31, 2014. Cash provided by operating activities from continuing operations during the first quarter of 2015 was $13.8 million, compared to cash provided by operating activities from continuing operations of $28.2 million in the first quarter of 2014. The decrease is primarily due to a decrease in oil revenues and a decrease in accounts payable.

Cash used in investing activities from continuing operations during the first quarter of 2015 decreased to $10.2 million, compared to cash used in investing activities from continuing operations of $31.2 million in the first quarter of 2014, due primarily to a decrease in drilling operations in Turkey due to the low commodity price environment. Additionally, cash used in financing activities from continuing operations was $9.2 million in the first quarter of 2015, as compared to cash provided by financing activities from continuing operations of $6.6 million in the first quarter 2014. This was due primarily to the repayment of a portion of our current outstanding debt during the period.

As a result of the decline in prices for Brent crude, we have reduced our planned capital expenditures and deferred a significant amount of our planned exploration and development until prices for Brent crude improve. In order to mitigate the impact of reduced prices on our 2015 cash flows and liquidity, we have implemented cost reduction measures and will continue to implement cost-cutting initiatives to reduce our operating costs and general and administrative expenses. These initiatives include the negotiation of exploration and development and operating cost reductions with several key vendors and plans to continue to pursue further reductions. We believe this strategy will allow us to preserve our liquidity in order to execute our 2015 development program and continue to meet our contractual obligations.

We believe that our cash flows from operations and existing cash on hand are sufficient to conduct our planned operations through the next 12 months and meet our contractual requirements, including license obligations. Additionally, at current Brent crude prices, our current hedge positions provide additional liquidity on a monthly recurring basis.

As of March 31, 2015, the outstanding principal amount of our debt was $149.5 million. In addition to cash, cash equivalents and cash flow from operations, at March 31, 2015, we had a Senior Credit Facility, a credit facility with a Turkish bank, convertible notes, a term loan facility and a prepayment agreement, all of which are discussed below.

Senior Credit Facility. On May 6, 2014, DMLP, Ltd. (“DMLP”), TransAtlantic Exploration Mediterranean International Pty Ltd. (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”), Amity Oil International Pty. Ltd., (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Urunleri Insaat Sanayi ve Ticaret A.S. (“Petrogas”) (collectively the “Borrowers”) entered into the Senior Credit Facility with BNP Paribas (Suisse) SA (“BNP Paribas”) and the International Finance Corporation (“IFC”). Each of the Borrowers is our wholly owned subsidiary. The Senior Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide (each, a “Guarantor”). At March 31, 2015, we had borrowings of $68.3 million under the Senior Credit Facility and no availability for additional borrowings. At March 31, 2015 we were in compliance with all covenants under the Senior Credit Facility.

TBNG Credit Facility. Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) has a fully drawn credit facility with a Turkish bank. During the first quarter of 2015, the facility was amended and now bears interest at a rate of 5.9% per annum and is due in monthly principal installments of $1.3 million each, ending March 31, 2016. The facility may be prepaid without penalty. The facility is secured by a lien on a hotel owned by Gundem Turizm Yatirim ve Isletme A.S. (“Gundem”), which is 97.5% beneficially owned by Mr. Mitchell and his children. At March 31, 2015, TBNG owed $15.6 million under the credit facility and had no availability.

Convertible Notes. At March 31, 2015, we sold $55.0 million of outstanding 13.0% convertible notes due 2017 (the “Convertible Notes”). The Convertible Notes were issued pursuant to an indenture, dated as of February 20, 2015 (the “Indenture”), between us and U.S. Bank National Association, as trustee (the “Trustee”). The Convertible Notes bear interest at an annual rate of 13.0%, payable semi-annually, in arrears, on January 1 and July 1 of each year, commencing on July 1, 2015. The Convertible Notes mature on July 1, 2017, unless earlier redeemed or converted.

Holders may, at any time after July 1, 2015 and from time to time at such holder’s option, convert, subject to certain terms and conditions, any or all of the principal of any Convertible Note into fully paid and nonassessable common shares at the conversion price. The initial conversion price is $6.80 per common share, subject to adjustment as described in the Indenture. Prior to or contemporaneously with the conversion of any of the principal of a Convertible Note, all accrued but unpaid interest on the principal amount being converted will be paid in cash. The Convertible Notes may not be converted into common shares on the maturity date or the redemption date.

At any time on or after July 1, 2015, we may redeem all or part of the Convertible Notes at the redemption prices specified below (expressed in percentages of principal amount on the redemption date), plus accrued and unpaid interest to the redemption date.


Period Beginning	Redemption Price
July 1, 2015	107.5%
January 1, 2016	105.0%
July 1, 2016	102.5%
January 1, 2017	100.0%

If we experience a fundamental change (as defined in the Indenture), we will be required to make an offer to repurchase the Convertible Notes at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, to but excluding the date of repurchase. Additionally, if we sell certain assets in exchange for $50.0 million or more in cash consideration, in certain circumstances, we will be required to use a portion of the net cash proceeds of such sale to make an offer to repurchase Convertible Notes at a price equal to the price we would be required to pay for an optional redemption at such time, plus accrued and unpaid interest, if any, up to but excluding the date of repurchase. The Indenture provides for customary events of default. The Indenture contains limited covenants.

Term Loan Facility. On September 17, 2014, Our indirectly wholly owned subsidiary, Stream Oil & Gas Ltd., a Cayman Islands corporation (“Stream Sub”), entered into a term loan facility (the “Term Loan Facility”) with Raiffeisen Bank Sh.A (“Raiffeisen”). The Term Loan Facility matures on December 31, 2016 and bears interest at the rate of LIBOR plus 5.5%, with a minimum interest rate of 7.0%. Stream Sub is required to repay $1.0 million each quarter on the last business day of each of March, June, September and December. The loan is guaranteed by Stream. Stream Sub may prepay the loan at its option in whole or in part, subject to a 3.0% penalty plus breakage costs. The Term Loan Facility is secured by substantially all of the assets of Stream Sub. As of March 31, 2015, we had $8.2 million outstanding under the Term Loan Facility and no availability. At March 31, 2015, we were not in compliance with certain conditions subsequent set forth in Section 4 of the Term Loan Facility, including the delivery to Raiffeisen of a copy of an agreement between Albpetrol and ourselves concerning postponement of capital expenditures. Raiffeisen has granted us a waiver on this requirement until June 5, 2015.

Prepayment Agreement. In April 2013, Stream and Stream Sub entered into the prepayment agreement (the “Prepayment Agreement”) with Trafigura PTE Ltd (“Trafigura”). In October 2013, Stream received a $7.0 million prepayment under the Prepayment Agreement. No further prepayment requests can be made under the Prepayment Agreement. The prepayment is to be repaid by Stream’s delivery of oil to Trafigura in accordance with an oil sales contract between Stream and Trafigura and bears interest at a rate equal to LIBOR plus 6% (6.17% at March 31, 2015). Stream must repay the prepayment at the times and in the quantities as set out in the oil sales contract, and all amounts must be repaid on or before August 31, 2015. At March 31, 2015, we had $2.4 million outstanding under the Prepayment Agreement and no availability.

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

During the first quarter of 2015, 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, 2014. Our oil derivatives contracts are settled based on Brent crude oil pricing. The following tables set forth our outstanding derivatives contracts with respect to future crude oil production as of March 31, 2015:

Fair Value of Derivative Instruments as of March 31, 2015

Weighted

Average

Quantity

Minimum

Maximum Price

Estimated Fair

Type

Period

(Bbl/day)

Price (per Bbl)

(per Bbl)

Value of Asset

(in thousands)

Collar

April 1, 2015—December 31, 2015

1,338

85.00

97.25

9,988

		Collars						Additional Call

				Weighted		Weighted		Weighted
				Average		Average		Average
				Minimum		Maximum		Maximum		Estimated Fair
		Quantity		Price		Price		Price		Value of
Type	Period	(Bbl/day)		(per Bbl)		(per Bbl)		(per Bbl)		Asset
										(in thousands)
Three-way collar contract	January 1, 2016—December 31, 2016		1,066	$	85.00	$	97.25	$	114.25	$	8,742
Three-way collar contract	January 1, 2017—December 31, 2017		888	$	85.00	$	97.25	$	114.25		6,382
Three-way collar contract	January 1, 2018—December 31, 2018		726	$	85.00	$	97.25	$	114.25		4,833
Three-way collar contract	January 1, 2019—March 31, 2019		663	$	85.00	$	97.25	$	114.25		1,070
										$	21,027

Item 4.

Controls and Procedures

Acquisition of Stream

In November 2014, we acquired Stream. For purposes of determining the effectiveness of our disclosure controls and procedures, management has excluded the internal control over financial reporting of Stream from its evaluation. The acquired business represents approximately 26.3% of our consolidated total assets at March 31, 2015 and 16.8% of our consolidated net loss for the three months ended March 31, 2015.

Evaluation of Disclosure Controls and Procedures

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

As of March 31, 2015, 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, our chief executive officer and chief financial officer concluded that, as of March 31, 2015, our disclosure controls and procedures were 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

During the three months ended March 31, 2015, we implemented a new Enterprise Resource Planning system. There were no additional changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

During the first quarter of 2015, 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, 2014.

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

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges for the three months ended March 31, 2015. You should read this ratio in connection with our consolidated financial statements and the related notes included in this Quarterly Report on Form 10-Q. Because we did not have preferred stock outstanding during this period, our ratio of earnings to combined fixed charges and preferred dividends for any given period is equivalent to our ratio of earnings to fixed charges.

	Three
	Months
	Ended
	March 31,
	2015
Ratio of earnings to fixed charges		-
Deficiency of earnings to fixed charges (in thousands)	$	7,282

For purposes of calculating the ratio of earnings to fixed charges, “earnings” represents income (loss) from continuing operations before income taxes plus fixed charges. “Fixed charges” includes interest expense, capitalized interest, amortization of discount and capitalized expenses related to indebtedness and the portion of rental expense that management believes is representative of the interest component of rental expense. The ratio of earnings to fixed charges presented in this prospectus may not be comparable to similarly titled measures presented by other companies, and may not be comparable to corresponding measures used in our various agreements, including the Senior Credit Facility.

PRICE RANGE OF OUR COMMON SHARES

Canada

Our Common Shares are traded in Canada on the Toronto Stock Exchange (the “TSX”) under the trading symbol “TNP”. The following table sets forth the quarterly high and low sales prices per Common Share in Canadian dollars on the TSX for the period indicated.

	High		Low
2015:
First Quarter	$	6.80	$	5.30

United States

Our Common Shares are traded in the United States on the NYSE MKT under the trading symbol “TAT”. The following table sets forth the high and low sales price per Common Share in U.S. Dollars on the NYSE MKT for the period indicated.

	High		Low
2015:
First Quarter	$	5.65	$	4.04

Item 6.

Exhibits

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

3.2		Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).

3.3		Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).

12.1*		Ratio of Earnings to Fixed Charges

31.1*		Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of the Chief Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of the Chief Executive Officer and Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

*	Filed herewith.

**	Furnished herewith.

Signatures

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

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

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

Date: May 11, 2015

INDEX TO EXHIBITS

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

3.2		Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).

3.3		Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).

12.1*		Ratio of Earnings to Fixed Charges

31.1*		Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of the Chief Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of the Chief Executive Officer and Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

*	Filed herewith.

**	Furnished herewith.

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Litigous
Readability	H.S. freshman Good

TransAtlantic Petroleum (TAT) 10-Q2015 Q1 Quarterly report

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