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 ☒ 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 ☒ No ☐

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐

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

As of ~~November 6, 2017,~~May 7, 2018, the registrant had ~~50,319,156~~50,384,698 common shares outstanding.

	September 30, 2017			December 31, 2016			March 31, 2018			December 31, 2017
ASSETS	(unaudited)						(unaudited)
Current assets:
Cash and cash equivalents	$	2,757		$	10,034		$	16,251		$	18,926
Restricted cash		–			2,555
Accounts receivable, net
Oil and natural gas sales		12,891			17,885			15,554			15,808
Joint interest and other		1,914			3,230			1,569			1,576
Related party		1,063			762			1,269			1,023
Prepaid and other current assets		2,557			4,756			4,957			3,866
Inventory		3,613			3,647			7,158			7,494
Assets held for sale		–			25,217
Total current assets		24,795			68,086			46,758			48,693
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		204,895			197,214			194,577			193,647
Unproved		25,730			21,109			19,359			24,445
Equipment and other property		19,399			20,273			14,223			14,075
		250,024			238,596			228,159			232,167
Less accumulated depreciation, depletion and amortization		(132,899	)		(120,638	)		(127,894	)		(129,183	)
Property and equipment, net		117,125			117,958			100,265			102,984
Other long-term assets:
Other assets		2,104			2,725			571			2,247
Note receivable - related party		7,027			7,624			6,507			6,726
Total other assets		9,131			10,349			7,078			8,973
Total assets	$	151,051		$	196,393		$	154,101		$	160,650
LIABILITIES, SERIES A PREFERRED SHARES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	3,518		$	7,036		$	5,082		$	4,853
Accounts payable - related party		4,363			1,844			4,554			3,141
Accrued liabilities		8,660			12,492
Accrued liabilities (1)								11,131			10,014
Derivative liability		571			596			1,633			2,215
Asset retirement obligations - current								2			-
Loans payable		12,375			34,750			15,100			15,625
Loan payable - related party		–			3,444
Liabilities held for sale		–			15,938
Total current liabilities		29,487			76,100			37,502			35,848
Long-term liabilities:
Asset retirement obligations		4,940			4,833
Asset retirement obligations less current portion								4,680			4,727
Accrued liabilities		9,138			8,126			8,721			8,810
Deferred income taxes		20,494			18,806			19,161			19,611
Loans payable		–			3,750			9,400			13,000
Derivative liability		–			242
Total long-term liabilities		34,572			35,757			41,962			46,148
Total liabilities		64,059			111,857			79,464			81,996
Commitments and contingencies
Series A preferred shares - third-parties, $0.01 par value, 950,000 shares authorized (third-parties and related parties), 426,000 shares issued to third-parties and outstanding with a liquidation preference of $50 per share as of September 30, 2017 and December 31, 2016, respectively		21,300			21,300
Series A preferred shares - related parties, $0.01 par value, 495,000 shares issued to related parties and outstanding with a liquidation preference of $50 per share as of September 30, 2017 and December 31, 2016, respectively		24,750			24,750
Series A preferred shares, $0.01 par value, 426,000 shares authorized; 426,000 shares issued and outstanding with a liquidation preference of $50 per share as of March 31, 2018 and December 31, 2017, respectively								21,300			21,300
Series A preferred shares-related party, $0.01 par value, 495,000 shares authorized; 495,000 shares issued and outstanding with a liquidation preference of $50 per share as of March 31, 2018 and December 31, 2017, respectively								24,750			24,750
Shareholders' equity:
Common shares, $0.10 par value, 200,000,000 shares authorized; 47,727,772 shares and 47,220,525 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively		4,773			4,722
Common shares, $0.10 par value, 100,000,000 shares authorized; 50,383,870 shares and 50,319,156 shares issued and outstanding as of March 31, 2018 and December 31, 2017, respectively								5,038			5,032
Treasury stock		(970	)		(970	)		(970	)		(970	)
Additional paid-in-capital		573,691			573,278			575,506			575,411
Accumulated other comprehensive loss		(118,488	)		(140,316	)		(127,109	)		(124,766	)
Accumulated deficit		(418,064	)		(398,228	)		(423,878	)		(422,103	)
Total shareholders' equity		40,942			38,486			28,587			32,604
Total liabilities, Series A preferred shares and shareholders' equity	$	151,051		$	196,393		$	154,101		$	160,650

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

	For the Three Months Ended						For the Nine Months Ended						For the Three Months Ended
	September 30,						September 30,						March 31,
	2017			2016			2017			2016			2018			2017
Revenues:
Oil and natural gas sales	$	12,424		$	15,483		$	40,475		$	46,171		$	16,661		$	15,768
Sales of purchased natural gas		-			1,171			654			3,717			-			654
Other		251			5			323			35			265			14
Total revenues		12,675			16,659			41,452			49,923			16,926			16,436
Costs and expenses:
Production		2,997			3,070			8,798			9,025			2,869			3,087
Transportation and processing														1,193			-
Exploration, abandonment and impairment		141			1,531			249			2,964			40			106
Cost of purchased natural gas		-			1,027			568			3,264			-			568
Seismic and other exploration		2,966			3			3,046			84			159			15
General and administrative		2,532			2,659			9,303			11,401			3,337			3,590
Depreciation, depletion and amortization		4,272			7,280			13,024			23,053			4,459			4,497
Accretion of asset retirement obligations		49			97			144			285			46			48
Total costs and expenses		12,957			15,667			35,132			50,076			12,103			11,911
Operating (loss) income		(282	)		992			6,320			(153	)
Operating income (loss)														4,823			4,525
Other income (expense):
Loss on sale of TBNG		-			-			(15,226	)		-			-			(15,226	)
Interest and other expense		(2,322	)		(3,836	)		(6,981	)		(9,106	)		(2,782	)		(2,371	)
Interest and other income		182			1,009			663			1,411			254			293
(Loss) gain on commodity derivative contracts		(1,365	)		(187	)		299			(2,419	)		(725	)		988
Foreign exchange loss		(48	)		(390	)		(1,055	)		(659	)
Foreign exchange (loss)														(2,058	)		(2,123	)
Total other expense		(3,553	)		(3,404	)		(22,300	)		(10,773	)		(5,311	)		(18,439	)
Loss from continuing operations before income taxes		(3,835	)		(2,412	)		(15,980	)		(10,926	)		(488	)		(13,914	)
Income tax expense		(518	)		(2,224	)		(3,856	)		(5,820	)		(1,287	)		(2,135	)
Net loss from continuing operations		(4,353	)		(4,636	)		(19,836	)		(16,746	)
Income from discontinued operations before income taxes		-			6,886			-			5,830
Gain on disposal of discontinued operations		-			9,419			-			10,168
Income tax benefit		-			-			-			204
Net income from discontinued operations		-			16,305			-			16,202
Net (loss) income	$	(4,353	)	$	11,669		$	(19,836	)	$	(544	)
Other comprehensive (loss) income:
Net loss														(1,775	)		(16,049	)
Other comprehensive income (loss):
Foreign currency translation adjustment		(1,223	)		(3,986	)		21,828			(3,277	)		(2,343	)		20,919
Comprehensive (loss) income	$	(5,576	)	$	7,683		$	1,992		$	(3,821	)
Comprehensive income (loss)													$	(4,118	)	$	4,870

Net (loss) income per common share
Basic net (loss) income per common share
Net loss per common share
Basic net loss per common share
Continuing operations	$	(0.09	)	$	(0.10	)	$	(0.42	)	$	(0.39	)	$	(0.04	)	$	(0.34	)
Discontinued operations	$	(0.00	)	$	0.35		$	(0.00	)	$	0.38
Weighted average common shares outstanding		47,725			46,854			47,480			42,879			50,374			47,298
Diluted net (loss) income per common share
Diluted net loss per common share
Continuing operations	$	(0.09	)	$	(0.10	)	$	(0.42	)	$	(0.39	)	$	(0.04	)	$	(0.34	)
Discontinued operations	$	(0.00	)	$	0.35		$	(0.00	)	$	0.38
Weighted average common and common equivalent shares outstanding		47,725			46,854			47,480			42,879			50,374			47,298

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

															Accumulated																								Accumulated
												Additional			Other						Total															Additional			Other						Total
	Common		Treasury				Common		Treasury			Paid-in			Comprehensive			Accumulated			Shareholders'			Common		Treasury					Common		Treasury			Paid-in			Comprehensive			Accumulated			Shareholders'
	Shares		Shares		Warrants		Shares		Stock			Capital			Loss			Deficit			Equity			Shares		Shares		Warrants			Shares		Stock			Capital			Loss			Deficit			Equity
Balance at December 31, 2016		47,220		333		699	$	4,722	$	(970	)	$	573,278		$	(140,316	)	$	(398,228	)	$	38,486
Balance at December 31, 2017																									50,319		333		700		$	5,032	$	(970	)	$	575,411		$	(124,766	)	$	(422,103	)	$	32,604
Expiration of warrants																									-		-		(700	)	$	-	$	-		$	-		$	-		$	-		$	-
Issuance of restricted stock units		508		-		-		51		-			(51	)		-			-			-			64		-		-			6		-			(6	)		-			-			-
Tax withholding on restricted stock units		-		-		-		-		-			(92	)		-			-			(92	)
Share-based compensation		-		-		-		-		-			556			-			-			556			-		-		-			-		-			101			-			-			101
Foreign currency translation adjustment		-		-		-		-		-			-			21,828			-			21,828			-		-		-			-		-			-			(2,343	)		-			(2,343	)
Net loss		-		-		-		-		-			-			-			(19,836	)		(19,836	)		-		-		-			-		-			-			-			(1,775	)		(1,775	)
Balance at September 30, 2017		47,728		333		699	$	4,773	$	(970	)	$	573,691		$	(118,488	)	$	(418,064	)	$	40,942
Balance at March 31, 2018																									50,383		333		0		$	5,038	$	(970	)	$	575,506		$	(127,109	)	$	(423,878	)	$	28,587

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

	For the Nine Months Ended						For the Three Months Ended
	September 30,						March 31,
	2017			2016			2018			2017
Operating activities:
Net loss	$	(19,836	)	$	(544	)	$	(1,775	)	$	(16,049	)
Adjustment for net loss from discontinued operations		-			(16,202	)
Net loss from continuing operations		(19,836	)		(16,746	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-based compensation		556			496			101			136
Foreign currency loss		434			593
(Gain) loss on commodity derivative contracts		(299	)		2,419
Foreign currency loss (gain)								2,634			1,039
Loss (gain) on commodity derivative contracts								725			(988	)
Cash settlement on commodity derivative contracts		32			4,188			(1,339	)		-
Loss on sale of TBNG		15,226			–			-			15,226
Amortization on loan financing costs		72			1,015			10			37
Deferred income tax expense		2,780			1,239			767			1,251
Exploration, abandonment and impairment		249			2,964			40			106
Depreciation, depletion and amortization		13,024			23,053			4,459			4,497
Accretion of asset retirement obligations		144			285			46			48
Interest on Series A Preferred Shares		1,842			–
Gain on sale of gas gathering facility		–			(620	)
Changes in operating assets and liabilities:
Accounts receivable		5,546			(4,643	)		(548	)		(1,665	)
Prepaid expenses and other assets		901			(1,528	)		(1,091	)		(1,151	)
Accounts payable and accrued liabilities		(4,592	)		6,892			3,781			(628	)
Net cash provided by operating activities from continuing operations		16,079			19,607
Net cash used in operating activities from discontinued operations		-			(822	)
Net cash provided by operating activities		16,079			18,785			7,810			1,859
Investing activities:
Additions to oil and natural gas properties		(14,317	)		(4,664	)		(6,337	)		(6,383	)
Additions to equipment and other properties		(366	)		(139	)		(677	)		(155	)
Restricted cash		1,776			6,398
Proceeds from asset sale		17,779			1,104
Net cash provided by investing activities		4,872			2,699
Proceeds from the sale of TBNG								-			17,779
Net cash provided by (used in) investing activities								(7,014	)		11,241
Financing activities:
Issuance of common shares		-			1,658
Tax withholding on restricted share units		(92	)		(59	)		-			(35	)
Loan proceeds		-			30,076
Loan repayment		(26,350	)		(39,517	)		(4,125	)		(8,650	)
Loan repayment - related party		(3,219	)		-			-			(2,694	)
Net cash used in financing activities		(29,661	)		(7,842	)		(4,125	)		(11,379	)
Effect of exchange rate on cash flows and cash equivalents		(118	)		(517	)
Net increase (decrease) in cash and cash equivalents		(8,828	)		13,125
Cash and cash equivalents, beginning of period (1)		11,585			7,480
Cash and cash equivalents, end of period	$	2,757		$	20,605
Effect of exchange rate on cash flows, cash equivalents, and restricted cash								(716	)		(369	)
Net increase (decrease) in cash, cash equivalents and restricted cash								(4,045	)		1,352
Cash, cash equivalents and restricted cash, beginning of period (1)								20,431			15,071
Cash, cash equivalents and restricted cash, end of period (2)							$	16,386		$	16,423
Supplemental disclosures:
Cash paid for interest	$	5,353		$	4,057		$	3,104		$	2,713
Cash paid for taxes	$	2,065		$	3,423		$	657		$	989
Supplemental non-cash financing activities:
Issuance of common shares	$	-		$	2,312
(1) Includes TBNG cash held for sale of $1.6 million at December 31, 2016.

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

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, 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 ~~November 6, 2017,~~May 7, 2018, approximately ~~47.3%~~47% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

TransAtlantic is a holding company with two operating segments – Turkey and Bulgaria. Its assets consist of its ownership interests in subsidiaries that primarily own assets in Turkey and Bulgaria.

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 the 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, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. During the nine months ended September 30, 2017, we reclassified certain balance sheet amounts previously reported on our consolidated balance sheet at December 31, 2016 to conform to current year presentation.

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, ~~2016.~~2017.

On February 24, 2017, we closed the sale of our ownership interests in our subsidiary Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) for gross proceeds of $20.7 million, and approximate net cash proceeds of $16.1 million, ~~effective as of March 31, 2016.~~which amounts reflect a $0.2 million post-closing purchase price adjustment.

We classified the assets and liabilities of TBNG within the captions “Assets held for sale” and “Liabilities held for sale” on our consolidated balance sheets as of December 31, 2016. Although the sale of TBNG met the threshold to classify its assets and liabilities as held for sale, it ~~did not~~didn’t meet the requirements to classify its operations as discontinued as the sale ~~was not~~wasn’t considered a strategic shift in ~~the Company’s~~our operations. As such, TBNG’s results of operations are classified as continuing operations for all periods presented (See Note ~~13.~~13, “Assets and liabilities held for sale and discontinued operations”).

As explained below, on January 1, 2018, the Company adopted Financial Accounting Standards Board (“FASB”) ~~issued~~ Accounting Standards Update (“ASU”) ~~2016-08,~~ No. 2014-09, Revenue from Contracts with Customers (Topic 606), under the modified retrospective method. Under this method, the Company recognizes the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no adjustment was required as a result of adopting the new revenue standard. Results for reporting periods beginning after January 1, 2018 are presented under the new standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods. The Company does not expect any impact to its net income from the adoption of ASU 2014-09 on an ongoing basis.

The Company’s revenue consists of sales under two contracts, one for crude oil and one for natural gas. The crude oil is delivered to the inlet of a processing center and control is passed through a custodian to the customer at that point. The Company is paid for crude oil at the inlet plus or minus an adjustment for quality. The Company’s natural gas is metered at the inlet of a transportation pipeline and control is passed at that point. The Company records natural gas sales at the delivery point to the customer, net of any pricing differentials. There is no material inventory remaining at the end of each reporting period.

The Company has previously deducted any transportation costs, processing fees, or adjustments from revenue and recorded the net amount. Under the new revenue guidance, on January 1, 2018, the Company now records the gross amount of the revenue and records any fees, or deductions as expenses. The Company’s revenue excludes any amounts collected on behalf of third parties.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, its final standard on revenue from contracts with customers. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In applying the revenue model to contracts within its scope, an entity identifies the contract(s) with a customer, identifies the performance obligations in the contract, determines the transaction price, allocates the transaction price to the performance obligations in the contract and recognizes revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 applies to all contracts with customers and requires significantly expanded disclosures about revenue recognition. ASU 2014-09 has been amended several times with subsequent ASUs including ASU 2015-14 Revenue from Contracts with Customers (Topic 606): ~~Principal versus Agent Considerations (Reporting Revenue Gross versus Net)~~ ~~(“ASU 2016-08”). ASU 2016-08 does not change~~Deferral of the ~~core principle~~Effective Date.

We have adopted the standard on January 1, 2018 using the modified retrospective approach. We have a small number of ~~Topic 606, but clarifies~~contracts with customers and have identified transactions within the ~~implementation guidance on principal versus agent considerations. ASU 2016-08 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing~~scope of the ~~potential impact~~standard. As a result of adoption of ASU ~~2016-08~~2014-09, we have determined that it will change our method of recording certain transportation and processing charges that were previously recorded as a reduction of revenues to record such charges as an expense under the new standard. The result of this change was an increase to both revenue and expenses of $1.2 million for the three months ended March 31, 2018. The application of the new standard has no impact on our ~~consolidated financial statements~~retained earnings and ~~results~~no impact to our net income on an ongoing basis. As of ~~operations.~~the three months ended December 31, 2017, this change would have been an increase to both revenue and expenses of $1.1 million.

Contracts for the sale of natural gas and crude oil are evidenced by (1) base contracts for the sale and purchase of natural gas or crude oil, which document the general terms and conditions for the sale, and (2) transaction confirmations, which document the terms of each specific sale.

Revenue is measured based on consideration specified in the contract with the customer. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues. The contract consideration in the Company’s contracts are typically allocated to specific performance obligations in the contract according to the price stated in the contract which usually sets the base oil and gas prices based on benchmark prices based on volumes and adjustments for product quality. Payment is generally received one or two months after the sale has occurred.

*As noted above, prior period amounts have not been adjusted under the modified retrospective method.

All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer and are generated in Turkey.

Transaction Price Allocated to Remaining Performance Obligations. A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Contract Balances. Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $15.6 million and $15.8 million as of March 31, 2018 and December 31, 2017, respectively, and are reported in accounts receivable, net on the Consolidated Balance Sheet. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.

Practical Expedients. The Company has made use of certain practical expedients in adopting the new revenue standard, including the value of unsatisfied performance obligations are not disclosed for (i) contracts with an original expected length of one year or less, (ii) contracts for which the Company recognizes revenue at the amount to which the Company has the right to invoice, (iii) variable consideration which is allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (iv) only contracts that are not completed at transition. The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less.

In ~~April~~February 2016, the FASB issued ASU ~~2016-10, Revenue from Contracts with Customers~~2016-02, Leases (Topic ~~606):~~ 842) (“ASU 2016-02”)~~Identifying Performance Obligations~~, which requires companies to recognize the assets and ~~Licensing~~ ~~(“ASU 2016-10”). ASU 2016-10 does not change~~liabilities for the ~~core principle~~rights and obligations created by long-term leases of ~~Topic 606, but clarifies~~assets on the ~~following two aspects~~balance sheet. The guidance requires adoption by application of ~~Topic 606: identifying performance obligations~~a modified retrospective transition approach for existing long-term leases and ~~the licensing implementation guidance, while retaining the related principles for those areas. ASU 2016-10~~ is effective for ~~annual and interim periods~~fiscal years beginning after December 15, ~~2017. We~~2018, including interim periods within those years. Oil and natural gas leases are excluded from the provisions of ASU 2016-02. As of March 31, 2018, we currently have 19 operating leases within the scope of this standard, the last lease expiring in 2022. The effect of ASU 2016-02 is expected to require additional disclosures, and we are currently ~~assessing~~evaluating the ~~potential~~ impact ofthat ASU ~~2016-10~~2016-02 would have on our consolidated financial statements and results of operations.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the ~~standard's~~standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. We are currently assessing the potential impact of ASU 2016-13 on our consolidated financial statements and results of operations.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning after December 15, 2017. We ~~are currently assessing the potential impact~~have adopted ASU 2016-15, effective January 1, 2018. The adoption of ASU 2016-15 had no impact on our ~~consolidated financial statements and results of operations.~~retained earnings or net income.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”). ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statements of cash flows.

We adopted ASU 2016-18 effective January 1, 2018. The ~~amended guidance will~~adoption of ASU 2016-18 had no impact on our retained earnings, and no impact to our net income on an ongoing basis. Adoption of the new standard requires that a statement of cash flows explain the change

during the period in the total of cash, cash equivalents and amounts generally described as restricted cash, or restricted cash equivalents. The amounts generally described as restricted cash and restricted cash equivalents should be ~~effective for annual periods beginning after December 15, 2017.~~included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statements of cash flows. The amendments ~~should be~~have been applied using a retrospective transition method to each period ~~presented. Early~~presented, as required. The period ended March 31, 2017 has been reclassified to reflect this change.

In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, which clarifies Topic 718, Compensation – Stock Compensation, such that an entity must apply modification accounting to changes in the terms or conditions of a share-based payment award unless all of the following criteria are met: (1) the fair value of the modified award is the same as the fair value of the original award immediately before the modification and the ASU indicates that if the modification does not affect any of the inputs to the valuation technique used to value the award, the entity is not required to estimate the value immediately before and after the modification; (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the modification; and (3) the classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the modification. The ASU is effective for fiscal years beginning after December 15, 2017. We expect the adoption ~~is permitted for any entity in any interim or annual period. We are currently evaluating the potential~~of this ASU will only impact ~~of ASU 2016-18 on our~~ consolidated financial statements if there is a modification to our share-based award agreements in the future.

In August 2017, the FASB issued ASU 2017-12, Derivatives and ~~results~~Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in Accounting Standards Codification (“ASC”) Topic 815. The new standard provides partial relief on the timing of ~~operations.~~certain aspects of hedge documentation and eliminates the requirement to recognize hedge ineffectiveness separately in income. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018 and for interim periods therein. Early adoption as of the date of issuance is permitted. The new standard does not impact accounting for derivatives that are not designated as accounting hedges. We do not currently account for any of our derivative position as accounting hedges.

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.

As of March 31, 2018 and 2017, we ~~issued~~had 921,000 outstanding shares of our 12.0% Series A Convertible Redeemable Preferred Shares (“Series A Preferred Shares”). Of the 921,000 Series A Preferred Shares, (i) 815,000 shares were issued in exchange for $40.75 million of our 13.0% Convertible Notes due 2017 (“2017 Notes”), at an exchange rate of 20 Series A Preferred Shares for each $1,000 principal amount of 2017 Notes, and (ii) 106,000 shares were issued and sold for $5.3 million of cash to certain holders of the 2017 Notes. All of the Series A Preferred Shares were issued at a value of $50.00 per share. We used $4.3 million of the gross proceeds to redeem a portion of the remaining 2017 Notes on January 1, 2017. The remaining proceeds were used for general corporate purposes. The Series A Preferred Shares contain a substantive conversion option, are mandatorily redeemable and convert into a fixed number of common shares. As a result, under U.S GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of ~~September 30, 2017,~~March 31, 2018, there were $21.3 million of Series A Preferred Shares and $24.8 million of Series A Preferred Shares – related party ~~outstanding.~~outstanding (see Note 12 “Related party transactions”).

Pursuant to the Certificate of Designations for the Series A Preferred Shares (the “Certificate of Designations”), each Series A Preferred Share may be converted at any time, at the option of the holder, into 45.754 common shares ~~of the Company~~ (which is equal to an initial conversion price of approximately $1.0928 per common share and is subject to customary adjustments for stock splits, stock dividends, recapitalizations or other fundamental changes). During the period ending on November 4, 2017, the conversion rate will be adjusted on an economic weighted average anti-dilution basis for the issuance of common shares for cash at a price below the conversion price then in effect. Such anti-dilution protection excludes (i) dividends paid on the Series A Preferred Shares in common shares, (ii) issuances of common shares in connection with acquisitions, (iii) issuances of common shares under currently outstanding convertible notes and warrants and (iv) issuances of common shares in connection with employee compensation arrangements and employee benefit plans. This non-standard dilution adjustment clause results in a contingent beneficial conversion feature.

If not converted sooner, on November 4, 2024, we are required to redeem the outstanding Series A Preferred Shares in cash at a price per share equal to the liquidation preference plus accrued and unpaid dividends. At any time on or after November 4, 2020, we may redeem all or a portion of the Series A Preferred Shares at the redemption prices listed below (expressed as a percentage of the liquidation preference amount per share) plus accrued and unpaid dividends to the date of redemption, if the closing sale price of the common shares equals or exceeds 150% of the conversion price then in effect for at least 10 trading days (whether or not consecutive) in a period of 20 consecutive trading days, including the last trading day of such 20 trading day period, ending on, and including, the trading day immediately preceding the business day on which we issue a notice of optional redemption. The redemption prices for the 12-month period starting on the ~~date~~dates below are:

Additionally, upon the occurrence of a change of control, we are required to offer to redeem the Series A Preferred Shares within 120 days after the first date on which such change of control occurred, for cash at a redemption price equal to the liquidation preference per share, plus any accrued and unpaid dividends.

Dividends on the Series A Preferred Shares are payable quarterly at our election in cash, common shares or a combination of cash and common shares at an annual dividend rate of 12.0% of the liquidation preference if paid all in cash or 16.0% of the liquidation preference if paid in common shares. If paid partially in cash and partially in common shares, the dividend rate on the cash portion is 12.0%, and the dividend rate on the common share portion is 16.0%. Dividends are payable quarterly on March 31, June 30, September 30, and December 31 of each year. The holders of the Series A Preferred Shares also are entitled to participate pro-rata in any dividends paid on the common shares on an as-converted-to-common shares basis. For the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2018, we ~~accrued $1~~.8paid $1.3 million ~~and $4.6~~ ~~million, respectively,~~in cash dividends on the Series A Preferred Shares, which is recorded in our consolidated statements of comprehensive (loss) income under the caption “Interest and other expense.” On October 2, 2017, we issued an aggregate of 2,591,384 common shares to holders of the Series A Preferred Shares as payment of the September 30, 2017 quarterly dividend on the Series A Preferred Shares (see Note 14. “Subsequent Events”)expense”.

Except as required by Bermuda law, the holders of Series A Preferred Shares have no voting rights, except that for so long as at least 400,000 Series A Preferred Shares are outstanding, the holders of the Series A Preferred Shares voting as a separate class have the right to elect two directors to our Board of Directors. For so long as between 80,000 and 399,999 Series A Preferred Shares are outstanding, the holders of the Series A Preferred Shares voting as a separate class have the right to elect one director to our Board of Directors. Upon less than 80,000 Series A Preferred Shares remaining outstanding, any directors elected by the holders of Series A Preferred Shares shall immediately resign from our Board of Directors.

The Certificate of Designation also provides that without the approval of the holders of a majority of the outstanding Series A Preferred Shares, we will not issue indebtedness for money borrowed or other securities which are senior to the Series A Preferred Shares in excess of the greater of (i) $100 million or (ii) 35% of our PV-10 of proved reserves as disclosed in our most recent independent reserve report filed or furnished by us on EDGAR.

The following table sets forth the capitalized costs under the successful efforts method for our oil and natural gas properties as of:

	September 30, 2017			December 31, 2016			March 31, 2018			December 31, 2017
	(in thousands)						(in thousands)
Oil and natural gas properties, proved:
Turkey	$	204,367		$	196,743		$	194,026		$	193,111
Bulgaria		528			471			551			536
Total oil and natural gas properties, proved		204,895			197,214			194,577			193,647
Oil and natural gas properties, unproved:
Turkey		25,730			21,109			19,359			24,445
Total oil and natural gas properties, unproved		25,730			21,109			19,359			24,445
Gross oil and natural gas properties		230,625			218,323			213,936			218,092
Accumulated depletion		(126,923	)		(115,401	)		(121,995	)		(123,225	)
Net oil and natural gas properties	$	103,702		$	102,922		$	91,941		$	94,867

For the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2018, we recorded foreign currency translation adjustments, which ~~increased~~decreased proved properties and ~~decreased~~increased accumulated other comprehensive loss within shareholders’ equity on our consolidated balance ~~sheet.~~sheets.

At ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, we excluded ~~$0.4~~$3.0 million and ~~$1.9~~$0.5 million, respectively, from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At ~~September 30, 2017,~~March 31, 2018, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included ~~$12.3~~$10.1 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and ~~$65.3~~$58.8 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, ~~2016,~~2017, the capitalized costs of our oil and natural gas properties included ~~$13.2~~$11.2 million relating to acquisition costs of proved properties, which are being ~~depleted~~amortized by the unit-of-production method using total proved reserves, and ~~$66.7~~$58.7 million relating

to well costs and additional development costs, which are being ~~depleted~~amortized by the unit-of-production method using proved developed reserves.

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. We primarily use Level 3 inputs to determine fair value, including but ~~are~~ not limited to, estimates of proved reserves, future commodity prices, the timing and amount of future production and capital expenditures and discount rates commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties.

During the ~~nine~~three months ended ~~September 30,~~March 31, 2018 and 2017, we recorded ~~$0.2~~$0.04 million and $0.1 million, respectively, of impairment of proved properties and exploratory well costs which are primarily measured using Level 3 inputs.

As of ~~September 30, 2017,~~March 31, 2018, we had ~~$3.9~~$2.3 million of exploratory well costs capitalized for the ~~Pinar-1~~Pinar-1ST well in Turkey, which we spud in March 2014. ~~During~~The Pinar-1ST well started producing in the ~~second~~first quarter of 2017, we side-tracked the Pinar-1 well to a total depth of 11,650 feet. Testing of the well began during the third quarter of 2017. However, we suspended testing to perform priority repair and maintenance workover operations in the Bahar and Selmo fields. We expect testing to resume in the fourth quarter of 2017.2018.

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

	September 30, 2017			December 31, 2016			March 31, 2018			December 31, 2017
	(in thousands)						(in thousands)
Inventory	$	9,488		$	10,704		$	4,924		$	4,619
Leasehold improvements, office equipment and software		7,543			7,280			7,062			7,214
Gas gathering system and facilities								259			135
Vehicles		361			364			331			343
Other equipment		2,007			1,925			1,647			1,764
Gross equipment and other property		19,399			20,273			14,223			14,075
Accumulated depreciation		(5,976	)		(5,237	)		(5,899	)		(5,958	)
Net equipment and other property	$	13,423		$	15,036		$	8,324		$	8,118

At ~~September 30, 2017,~~March 31, 2018, we have classified ~~$3.6~~$7.2 million of inventory as a current asset, which represents our expected inventory consumption in the next twelve months. We classify our materials and supply inventory as a long-term ~~assets~~asset because such materials will ultimately be classified as a long-term ~~assets~~asset when the material is used in the drilling of a well.

At ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, we excluded ~~$13.1~~$12.1 million and ~~$14.4~~$12.1 million of inventory, respectively, from depreciation as the inventory had not been placed into service.

The following table summarizes the changes in our asset retirement obligations (“ARO”) for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 and for the year ended December 31, ~~2016:~~2017:

	September 30, 2017			December 31, 2016			March 31, 2018			December 31, 2017
	(in thousands)						(in thousands)
Asset retirement obligations at beginning of period	$	4,833		$	9,237		$	4,727		$	4,833
Change in estimates		–			(7	)
Liabilities settled		(37	)		–			-			(37	)
Foreign exchange change effect		–			(1,604	)		(182	)		(259	)
Additions		–			16			91			-
Accretion expense		144			373			46			190
Asset retirement obligations at end of period		4,940			8,015		$	4,682		$	4,727
Less: TBNG		-			3,182
Long-term portion	$	4,940		$	4,833

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.

We use collar and put 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 (loss) income under the caption “(Loss) gain on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on commodity derivative contracts.”

During the three months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ we recorded a net loss on commodity derivative contracts of ~~$1.4 million and $0.2 million, respectively. During the nine months ended September 30, 2017 and 2016, we recorded a net gain on commodity derivative contracts of $0.3~~$0.7 million and a net ~~loss~~gain of ~~$2.4~~$1.0 million, respectively.

At ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, we had outstanding derivative contracts with respect to our future crude oil production as set forth in the tables below:

Fair Value of Derivative Instruments as of September 30, 2017

Weighted

Weighted

Average

Average

Quantity

Minimum

Maximum Price

Estimated Fair

Type

Period

(Bbl/day)

Price (per Bbl)

(per Bbl)

Value of Liability

(in thousands)

Collar

October 1, 2017 — December 31, 2017

293

$
47.50

$
61.00

$
(14
)
Collar

October 1, 2017 — December 31, 2017

440

$
50.00

$
61.50

(6
)
Collar

October 1, 2017 — December 31, 2017

489

$
47.00

$
59.65

(40
)
Collar

October 1, 2017 — December 31, 2017

734

$
47.50

$
57.10

(130
)
Collar

January 1, 2018 — February 28, 2018

458

$
50.00

$
61.50

(4
)
Collar

January 1, 2018 — March 31, 2018

500

$
47.00

$
59.65

(50
)
Collar

January 1, 2018 — May 31, 2018

298

$
47.50

$
61.00

(32
)
Collar

January 1, 2018 — June 30, 2018

746

$
47.50

$
57.10

(295
)
Total estimated fair value of liability

$
(571
)

Fair Value of Derivative Instruments as of December 31, 2016
																	Weighted			Weighted
																	Average			Average
														Quantity			Minimum			Maximum Price			Additional Call			Estimated Fair
Type												Period		(Bbl/day)			Price (per Bbl)			(per Bbl)			Ceiling			Value of Liability
																										(in thousands)
Collar												April 1, 2018 - May 31, 2018			295		$	47.50		$	61.00		$	-		$	(200	)
Collar												April 1, 2018 - June 30, 2018			742		$	47.50		$	57.10		$	-			(1,016	)
Collar												April 1, 2018 - December 31, 2018			442		$	55.00		$	70.00		$	-			(229	)
Collar												April 1, 2018 - December 31, 2018			491		$	56.00		$	70.00		$	84.00			(189	)
Total Estimated Fair Value of Liability																										$	(1,633	)

Fair Value of Derivative Instruments as of December 31, 2017											Fair Value of Derivative Instruments as of December 31, 2017

				Weighted		Weighted										Weighted			Weighted
				Average		Average										Average			Average
		Quantity		Minimum		Maximum Price		Estimated Fair					Quantity			Minimum			Maximum Price			Estimated Fair
Type	Period	(Bbl/day)		Price (per Bbl)		(per Bbl)		Value of Liability			Period		(Bbl/day)			Price (per Bbl)			(per Bbl)			Value of Liability
								(in thousands)														(in thousands)
Collar	January 1, 2017 — December 31, 2017		296	$	47.50	$	61.00	$	(289	)	January 1, 2018 — February 28, 2018			458		$	50.00		$	61.50		$	(178	)
Collar	January 2, 2017 — December 31, 2017		445	$	50.00	$	61.50		(307	)	January 1, 2018 — March 31, 2018			500		$	47.00		$	59.65			(376	)
Collar	January 1, 2018 — February 28, 2018		458	$	50.00	$	61.50		(74	)	January 1, 2018 — May 31, 2018			298		$	47.50		$	61.00			(286	)
Collar	January 1, 2018 — May 31, 2018		298	$	47.50	$	61.00		(168	)	January 1, 2018 — June 30, 2018			746		$	47.50		$	57.10			(1,375	)
Total estimated fair value of liability								$	(838	)
Total Estimated Fair Value of Liability																							$	(2,215	)

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 ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, and (ii) the net recorded fair value as reflected on our consolidated balance sheets at ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016.~~2017.

As of September 30, 2017

As of March 31, 2018

Gross

Amount

Net Amount of

Amount

Net Amount of

Gross

Offset in the

Liabilities

Gross

Offset in the

Liabilities

Amount of

Consolidated

Presented in the

Amount of

Consolidated

Presented in the

Location on Consolidated

Recognized

Balance

Consolidated

Location on Consolidated

Recognized

Balance

Consolidated

Underlying Commodity

Balance Sheets

Liabilities

Sheets

Balance Sheets

Liabilities

Sheets

Balance Sheets

(in thousands)

Crude oil

Current liabilities

571

Current liabilities

1,633

Crude oil

Long-term liabilities

As of December 31, 2016

As of December 31, 2017

Gross

Amount

Net Amount of

Amount

Net Amount of

Gross

Offset in the

Liabilities

Gross

Offset in the

Liabilities

Amount of

Consolidated

Presented in the

Amount of

Consolidated

Presented in the

Location on Consolidated

Recognized

Balance

Consolidated

Location on Consolidated

Recognized

Balance

Consolidated

Underlying Commodity

Balance Sheets

Liabilities

Sheets

Balance Sheets

Liabilities

Sheets

Balance Sheets

(in thousands)

Crude oil

Current liabilities

596

Current liabilities

2,215

Crude oil

Long-term liabilities

242

Long-term liabilities

	September 30,		December 31,		March 31,		December 31,
	2017		2016		2018		2017
Fixed and floating rate loans	(in thousands)				(in thousands)
Term Loan(1)	$	12,375	$	25,000	$	24,500	$	28,625
2017 Notes		-		13,500
2017 Notes - Related Party		-		750
ANBE Note		-		2,694
Loans payable		12,375		41,944
Less: current portion		12,375		38,194		15,100		15,625
Long-term portion	$	-	$	3,750	$	9,400	$	13,000

On August 23, 2016, the Turkish branch of TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”)~~, our wholly-owned subsidiary,~~ entered into a Credit Agreement (the “Credit Agreement”) with DenizBank, A.S. (“DenizBank”). The Credit Agreement is a master agreement pursuant to which DenizBank may make loans to TEMI from time to time pursuant to additional loan agreements.

On August 31, 2016, DenizBank entered into a $30.0 million term loan with TEMI (the “2016 Term Loan”) under the Credit ~~Agreement (the “Term Loan”).~~Agreement. In addition, we and DenizBank entered into additional agreements with respect to up to $20.0 million of non-cash facilities, including guarantee letters and treasury instruments for future hedging transactions.

The 2016 ~~TEMI used approximately $22.9 million of the proceeds from the Term Loan to repay our prior senior credit facility in full.~~

~~The~~ Term Loan bears interest at a fixed rate of 5.25% (plus 0.2625% for Banking and Insurance Transactions Tax per the Turkish government) per ~~annum. Amounts repaid under the Term Loan may not be re-borrowed,~~annum and ~~early repayments under the Term Loan are subject to early repayment fees.~~

was payable in six monthly installments of $1.25 million each through February 2017 and thereafter in twelve monthly installments of $1.88 million each through February 2018. On April 27, 2017, TEMI and DenizBank approved a revised amortization schedule for the 2016 Term Loan. Pursuant to the revised amortization schedule, the maturity date of the 2016 Term Loan was extended from February 2018 to June 2018, and the monthly principal payments were reduced from $1.88 million to $1.38 million. The other terms of the 2016 Term Loan remain unchanged.Amounts repaid under the 2016 Term Loan may not be re-borrowed and early repayments under the 2016 Term Loan are subject to early repayment fees.

The 2016 Term Loan is guaranteed by DMLP, Ltd. (“DMLP”), TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”), Talon Exploration, Ltd. (“Talon Exploration”) and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) (collectively, the “Guarantors”).

The 2016 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting of liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain investments, selling assets or transferring revenue, and other similar matters. In addition, the 2016 Term Loan prohibits Amity Oil International Pty Ltd (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Urunleri Insaat Sanayi ve Ticaret A.S. (“Petrogas”) from incurring additional debt. An event of default under the 2016 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and the occurrence of a material adverse effect.

The 2016 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate owned by Gundem Turizm Yatirim ve Isletmeleri A.S. (“Gundem”) and (v) certain Diyarbakir real estate owned 80% by N. Malone Mitchell 3^rd and 20% by Selami Erdem Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2016 Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.

At ~~September 30, 2017,~~March 31, 2018, we had ~~$12.4~~$4.1 million outstanding under the 2016 Term Loan and no availability and were in compliance with ~~all of~~ the covenants in the 2016 Term Loan.

On November 17, 2017, Denizbank entered into a $20.4 million term loan with TEMI (the “2017 Term Loan”) under the Credit Agreement. We will use the proceeds from the 2017 Term Loan for general corporate purposes.

The 2017 Term Loan bears interest at a fixed rate of 6.0% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2017 Term Loan has a grace period which bears no interest or payments due until July 2018 and then is payable in one monthly installment of $1.38 million, nine monthly installments of $1.2 million each through April 2019 and thereafter in eight monthly installments of $1.0 million each through December 2019, with the exception of one monthly installment of $1.2 million occurring in October 2019. The 2017 Term Loan matures in December 2019. Amounts repaid under the 2017 Term Loan may not be re-borrowed, and early repayments under the 2017 Term Loan are subject to early repayment fees. The 2017 Term Loan is guaranteed by the Guarantors.

The 2017 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting of liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain investments, selling assets or transferring revenue, and other similar matters. In addition, the 2017 Term Loan prohibits Amity and Petrogas from incurring additional debt. An event of default under the 2017 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and the occurrence of a material adverse effect.

The 2017 Term Loan is be secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate owned by Gundem, (v) certain Diyarbakir real estate owned 80% by N. Malone Mitchell 3rd and 20% Selami Erdem Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2017 Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.

At March 31, 2018, we had $20.4 million outstanding under the 2017 Term Loan and no availability, and we were in compliance with the covenants in the 2017 Term Loan.

The 2017 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 2017 Notes bore interest at an annual rate of 13.0%, payable semi-annually, in arrears, on January 1 and July 1 of each year. The 2017 Notes matured on July 1, 2017, and on July 3, 2017, we paid off and retired all remaining outstanding 2017 ~~Notes.~~ Notes.

On December 30, 2015, TransAtlantic Petroleum (USA) Corp (“TransAtlantic USA”) entered into a $5.0 million draw down convertible promissory note (the ~~“Note”~~“ANBE Note”) with ANBE Holdings, L.P. (“ANBE”), an entity owned by the adult children of ~~the Company’s~~our chairman and chief executive officer, N. Malone Mitchell 3rd, and controlled by an entity managed by Mr. Mitchell and his wife. The ANBE Note bore interest at a rate of 13.0% per annum. On December 30, 2015, ~~the Company~~we borrowed $3.6 million under the ANBE Note ~~(the “Initial Advance”). The Initial Advance was used~~ for general corporate purposes. On June 30, 2016, we issued 355,826 common shares in a private placement to ANBE in lieu of paying cash interest on the ANBE Note.

On October 31, 2016, TransAtlantic USA entered into an amendment of the ANBE Note with ANBE (the “ANBE Amendment”). The ANBE Amendment extended the maturity date of the Note from October 31, 2016 to September 30, 2017, provided for the ANBE Note to be repaid in four quarterly installments of $0.9 million each in December 2016 and March, June and September 2017, and provided for monthly payments of interest.

On February 27, 2017, we repaid the ANBE Note in full with proceeds from the sale of TBNG and terminated it.

Our wholly-owned subsidiaries operating in Turkey are party to unsecured, non-interest bearing lines of credit with a Turkish bank. At ~~September 30, 2017,~~March 31, 2018, we had no outstanding borrowings under these lines of credit.

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

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, during 2012, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit for this contingency. In September 2016, management determined that, because it had received no communication from the Moroccan government since early 2013, the probability of payment of this contingency is remote. Therefore, the Company reversed the $6.0 million in contingent liabilities previously classified as liabilities held for sale.

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.

In October 2015, the Bulgarian Ministry of Energy and Economy filed a suit against our subsidiary, Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”), claiming a $200,000 penalty for Direct Bulgaria’s alleged failure to fulfill the work program associated with the Aglen exploration permit. Direct Bulgaria received a force majeure recognition in 2012 from the Bulgarian Ministry of Energy and Economy, and the force majeure event has not been rectified. WeWhile we believe that Direct Bulgaria is not under any obligation to fulfill the work program until the force majeure event is rectified and continue to vigorously defend this ~~claim.~~claim, we continue to engage in discussions with the Ministry of Energy and Economy regarding settlement possibilities.

We recorded share-based compensation expense of $0.1 million and $0.1 million for awards of restricted stock units (“RSUs”) for ~~each of~~ the three months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016. We recorded share-based compensation expense $0.6 million and $0.5 million for awards of RSUs for each of the nine months ended September 30, 2017 and 2016,~~ respectively.

As of ~~September 30, 2017,~~March 31, 2018, we had approximately ~~$0.5~~$0.2 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of ~~0.7~~0.5 years.

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 nine~~ months ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~ equals net ~~income (loss)~~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 unvested RSUs. Diluted earnings per common share for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~ 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, preferred shares and warrants (prior to January 6, 2018), whether exercisable or not. For the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2018, there were no dilutive securities included in the calculation of diluted earnings per share.

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

Three Months Ended

Nine Months Ended

September 30

September 30

(in thousands, except per share amounts)
2017

2016

2017

2016

Net (loss) income from continuing operations
$
(4,353
)

$
(4,636
)

$
(19,836
)

$
(16,746
)
Net income from discontinued operations
$
-

$
16,305

$
-

$
16,202

Basic net (loss) income per common share:

Shares:

Weighted average common shares outstanding

47,725

46,854

47,480

42,879

Basic net (loss) income per common share:

Continuing operations
$
(0.09
)

$
(0.10
)

$
(0.42
)

$
(0.39
)
Discontinued operations
$
(0.00
)

$
0.35

$
(0.00
)

$
0.38

Diluted net (loss) income per common share:

Shares:

Weighted average common shares outstanding

47,725

46,854

47,480

42,879

Dilutive effect of:

Restricted stock units

-

-

-

-

Weighted average common shares outstanding

47,725

46,854

47,480

42,879

Diluted net (loss) income per common share:

Continuing operations
$
(0.09
)

$
(0.10
)

$
(0.42
)

$
(0.39
)
Discontinued operations
$
(0.00
)

$
0.35

$
(0.00
)

$
0.38

On December 31, 2014, April 24, 2015 and August 13, 2015, we issued 233,334, 233,333 and 233,333 common share purchase warrants (“Warrants”), respectively, to the shareholders of Gundem as consideration for the pledge of Turkish real estate in exchange for an extension of the maturity of a credit agreement between us and a Turkish bank. As consideration for the pledge of Turkish real estate, the independent members of our board of directors approved the issuance of the Warrants to be allocated in accordance with each shareholder’s ownership percentage of Gundem. The Warrants were issued pursuant to a warrant agreement, whereby the Warrants were immediately exercisable and entitled the holder to purchase one common share for each Warrant. The Warrants were issued in December 2014, April 2015 and August 2015 at an exercise price of $5.99, $5.65 and $2.99 per share, respectively. The Warrants expired, unexercised, pursuant to their terms on January 6, 2018.

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

	Corporate			Turkey			Bulgaria			Total			Corporate			Turkey		Bulgaria			Total
	(in thousands)												(in thousands)
For the three months ended September 30, 2017
Total revenues	$	-		$	12,675		$	-		$	12,675
Loss from continuing operations before income taxes		(3,262	)		(529	)		(44	)		(3,835	)
Capital expenditures	$	-		$	2,986		$	-		$	2,986
For the three months ended September 30, 2016
For the three months ended March 31, 2018
Total revenues	$	-		$	16,659		$	-		$	16,659		$	-		$	16,926	$	-		$	16,926
(Loss) income from continuing operations before income taxes		(3,102	)		734			(44	)		(2,412	)		(3,806	)		3,364		(46	)		(488	)
Capital expenditures	$	-		$	1,484		$	-		$	1,484					$	5,246				$	5,246
For the nine months ended September 30, 2017
Total revenues	$	-		$	41,452		$	-		$	41,452
(Loss) income from continuing operations before income taxes		(26,460	)		10,673			(193	)		(15,980	)
Capital expenditures	$	-		$	14,317		$	-		$	14,317
For the nine months ended September 30, 2016
For the three months ended March 31, 2017
Total revenues	$	-		$	49,923		$	-		$	49,923		$	-		$	16,436	$	-		$	16,436
(Loss) income from continuing operations before income taxes		(12,092	)		1,413			(247	)		(10,926	)		(18,921	)		5,077		(70	)		(13,914	)
Capital expenditures	$	-		$	4,675		$	-		$	4,675		$	-		$	6,538	$	-		$	6,538
Segment assets
September 30, 2017	$	9,905		$	140,509		$	637		$	151,051
December 31, 2016 (1)	$	17,007		$	153,560		$	609		$	171,176
March 31, 2018													$	9,643		$	143,727	$	731		$	154,101
December 31, 2017													$	10,966		$	149,185	$	499		$	160,650

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 September 30, 2017 and December 31, 2016, due to the short maturity of those instruments.

We are exposed to interest rate risk as a result of our variable rate short-term cash holdings.

We have underlying foreign currency exchange rate exposure. Our currency exposures primarily relate to transactions denominated in the Bulgarian Lev, the European Union Euro, and the New Turkish 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 ~~September 30, 2017,~~March 31, 2018, we had ~~5.4~~15.8 million TRY (approximately ~~$1.5~~$4.0 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY.

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including, but not limited to, supply and demand. At ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, we were a party to commodity derivative contracts (See Note 6.6 “Commodity derivative instruments”).

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 (“TPAO”), the national oil company of Turkey, ~~and Turkiye Petrol Rafinerileri A.Ş.~~Zorlu Dogal Gaz Ithalat Ihracat ve Toptan Ticaret A.S. (“Zorlu”), a privately owned ~~oil refinery~~natural gas distributor in Turkey, and TUPRAS, which ~~purchases all~~purchase the majority of our oil and natural gas production. The receivables are not collateralized. To date, we have experienced minimal bad debts ~~from customers in Turkey.~~and have no allowance for doubtful accounts for TUPRAS. The majority of our cash and cash equivalents are held by three financial institutions in the United States and Turkey.

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, 2018 and December 31, 2017, due to the short maturity of those instruments.

The following table summarizes the valuation of our financial assets and liabilities as of ~~September 30, 2017:~~March 31, 2018:

	Fair Value Measurement Classification											Fair Value Measurement Classification
	Quoted Prices in											Quoted Prices in
	Active Markets for											Active Markets for
	Identical Assets or		Significant Other			Significant						Identical Assets or		Significant Other			Significant
	Liabilities		Observable Inputs			Unobservable Inputs						Liabilities		Observable Inputs			Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)			Total			(Level 1)		(Level 2)			(Level 3)			Total
	(in thousands)											(in thousands)
Measured on a recurring basis
Liabilities:
Commodity derivative contracts	$	–	$	(571	)	$	–		$	(571	)	$	-	$	(1,633	)	$	-		$	(1,633	)
Disclosed but not carried at fair value
Liabilities:
Term Loan		-		-			(11,563	)		(11,563	)
2017 Term Loan													-		-			(17,309	)		(17,309	)
2016 Term Loan													-		-			(4,014	)		(4,014	)
Total	$	–	$	(571	)	$	(11,563	)	$	(12,134	)	$	-	$	(1,633	)	$	(21,323	)	$	(22,956	)

The following table summarizes the valuation of our financial assets and liabilities as of December 31, ~~2016:~~2017:

	Fair Value Measurement Classification											Fair Value Measurement Classification
	Quoted Prices in											Quoted Prices in
	Active Markets for											Active Markets for
	Identical Assets or		Significant Other			Significant						Identical Assets or		Significant Other			Significant
	Liabilities		Observable Inputs			Unobservable Inputs						Liabilities		Observable Inputs			Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)			Total			(Level 1)		(Level 2)			(Level 3)			Total
	(in thousands)											(in thousands)
Measured on a recurring basis
Liabilities:
Commodity derivative contracts	$	–	$	(838	)	$	–		$	(838	)	$	-	$	(2,215	)	$	-		$	(2,215	)
Disclosed but not carried at fair value
Liabilities:
Term Loan		-		-			(22,500	)		(22,500	)
2017 Notes		-		-			(13,554	)		(13,554	)
2017 Term Loan													-		-			(16,613	)		(16,613	)
2016 Term Loan													-		-			(7,866	)		(7,866	)
Total	$	–	$	(838	)	$	(36,054	)	$	(36,892	)	$	-	$	(2,215	)	$	(24,479	)	$	(26,694	)

We remeasure our derivative contracts on a recurring basis, with changes flowing through earnings. At ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, both of the fair values of ~~our~~the 2017 Term Loan and the ~~2017 Notes~~2016 Term Loan were estimated using a discounted cash flow analysis based on unobservable Level 3 inputs, including our own credit risk associated with the loans payable.

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

	September 30,		December 31,		March 31,		December 31,
	2017		2016		2018		2017
	(in thousands)				(in thousands)
Related party accounts receivable:
Riata Management Service Agreement	$	715	$	528	$	527	$	576
PSIL MSA		348		234		742	447
Total related party accounts receivable		1,063		762	$	1,269	$	1,023
Related party accounts payable:
Riata Management Service Agreement	$	332	$	346	$	352	$	341
PSIL MSA		3,041		1,315		4,202		2,119
Interest payable on 2017 Notes and Series A Preferred Shares		990		183
Interest payable on Series A Preferred						-		681
Total related party accounts payable	$	4,363	$	1,844	$	4,554	$	3,141

Effective May 1, 2008, we entered into a service agreement (as amended, the “Service Agreement”), with Longfellow Energy, LP (“Longfellow”), Viking Drilling LLC (“Viking Drilling”), MedOil Supply, LLC and Riata Management, LLC (“Riata Management”) (collectively, the “Service Entities”). Mr. Mitchell and his wife own 100% of Riata Management. In addition, Mr. Mitchell, his wife and his children indirectly own 100% of Longfellow. Riata Management owns 100% of MedOil Supply, LLC. Dalea Partners, LP (“Dalea”), an affiliate of Mr. Mitchell, owns 100% of Viking Drilling. Under the terms of the Service Agreement, we pay, or are paid, for the actual cost of the services rendered plus the actual cost of reasonable expenses on a monthly basis. Under the terms of the Service Agreement, the Service Entities agreed to provide the Company upon its request certain computer services, payroll and benefits services, insurance administration services and entertainment services, and the Company and the Service Entities agreed to provide to each other certain management consulting services, oil and natural gas services and general accounting services (collectively, the “Services”). Under the terms of the Service Agreement, the Company pays, or is paid, for the actual cost of the Services ~~transactions~~rendered plus the actual cost of reasonable expenses on a monthly basis. The Company or the Service Entities may terminate the Service Agreement at any time by providing advance notice of termination to the other party.

On March 20, 2017, ~~the Company~~we entered into a second amendment to the Service Agreement among ~~the Company~~us and Longfellow, ~~Energy, LP, a Texas limited partnership (“Longfellow”),~~ Viking Drilling, ~~LLC, a Nevada limited liability company, RIATA~~Riata Management, ~~LLC, an Oklahoma limited liability company,~~ Longfellow Nemaha, LLC, a Texas limited liability company, Red Rock Minerals, LP, a Delaware limited partnership, Red Rock Advisors, LLC, a Texas limited liability company, Production Solutions International Limited, a Bermuda exempted company, and Nexlube Operating, LLC, a Delaware limited liability company, and their subsidiaries (collectively, the “Riata Entities”), adding and removing certain of the Service Entities and the Riata Entities and expanding the scope of ~~services. Because~~Services. As this agreement is a related party transaction, the independent members of ~~the Board~~our board of ~~Directors~~directors reviewed and approved this amendment.

As of ~~September 30, 2017, the Company~~March 31, 2018, we had $~~0.7~~$0.5 million of outstanding receivables and $~~0.3~~$0.4 million of outstanding payables pursuant to ~~this~~the Service Agreement.

On March 3, 2016, Mr. Mitchell closed a transaction whereby he sold his interests in Viking Services B.V. (“Viking Services”), the beneficial owner of Viking International Limited (“Viking International”), Viking Petrol Sahasi Hizmetleri A.S. (“VOS”) and Viking Geophysical Services Ltd. (“Viking Geophysical”), to a third party. As part of the transaction, Mr. Mitchell acquired certain equipment used in the performance of stimulation, wireline, workover and similar services, ~~(the “Services”),~~ which equipment iswill be owned and operated by a new entity, Production Solutions International Petrol Arama Hizmetleri Anonim Sirketi (“PSIL”). PSIL is beneficially owned by Dalea Investment Group, LLC, which is controlled by Mr. Mitchell. Consequently, on March 3, 2016, TEMI entered into a master services agreement (the “PSIL MSA”) with PSIL on substantially similar terms to our then current master services agreements with Viking International, VOS and Viking Geophysical. Pursuant to the PSIL MSA, PSIL ~~performs~~will perform the ~~Services~~services on behalf of TEMI and its affiliates. The master services ~~agreements~~agreement with each of Viking International, VOS and Viking Geophysical currently remain in ~~effect in accordance with the terms of the agreements.~~ effect.

As of ~~September 30, 2017, the Company~~March 31, 2018, we had $~~0.3~~$0.7 million of outstanding receivables and $3.0$4.2 million of outstanding payables pursuant to the PSIL MSA.

On ~~February 27,~~June 26, 2017, ~~we repaid~~and effective as of January 1, 2017, our wholly owned subsidiary, TransAtlantic USA entered into an Amended and Restated Office Lease (the “Office Lease”) with Longfellow to lease approximately 10,000 square feet of corporate office space in Addison, Texas. The initial lease term under the ~~ANBE Note~~Office Lease commenced on January 1, 2017 (the “Commencement Date”), and expires five years after the Commencement Date, unless earlier terminated in ~~full~~accordance with ~~proceeds from~~ the ~~sale~~Office Lease. TransAtlantic USA has the option to extend the lease term for two additional periods of ~~TBNG~~five years each. If TransAtlantic USA exercises its option to extend the lease term, the monthly rent payable during such extended term shall be at a mutually agreed upon amount for monthly rent during the renewal term. During the first five months of the initial lease term, TransAtlantic USA is required to pay monthly rent of $14,745.16 to Longfellow, plus utilities, real property taxes and ~~terminated it.~~liability insurance (to the extent that TransAtlantic does not obtain its own liability insurance). Monthly rent increases by $2,754.84 the sixth month of the initial lease term, by $833.33 the second year of the initial lease term and by approximately $417 each year thereafter during the initial lease term.

On April 19, 2016, we entered into a note amendment agreement (the “Note Amendment Agreement”) with Mr. Mitchell, and Dalea Partners, LP (“Dalea”), pursuant to which Dalea agreed to deliver an amended and restated promissory note (the “Amended Note”) in favor of us, in the principal sum of ~~$8.0 million,~~$7,964,053, which Amended Note would amend and restate that certain Promissory Note, dated June 13, 2012, made by Dalea in favor of us in the principal amount of $11.5 million (the “Original Note”). The Note Amendment Agreement reduced the principal amount of the Original Note to ~~$8.0 million~~$7,964,053 in exchange for the cancellation of an account payable of approximately $3.5 million (the “Account Payable”) owed by TransAtlantic Albania Ltd. (“TransAtlantic Albania”), a former subsidiary of ~~the Company,~~TransAtlantic, to Viking International Limited. We have indemnified a third party for any liability relating to the payment of the Account Payable.

Pursuant to the Note Amendment Agreement, on April 19, 2016, we entered into the Amended Note, which amended and restated the Original Note that was issued in connection with our sale of ~~its~~our subsidiaries, Viking International and Viking Geophysical Services, to a joint venture owned by Dalea and Abraaj Investment Management Limited in June 2012. In the Amended Note, we and Dalea

acknowledged that (i) while the sale of Dalea’s interest in Viking Services enabled us to take the position that the Original Note was accelerated in accordance with its terms, the principal purpose of including the acceleration events in the Original Note was to ensure that certain oilfield services provided by Viking Services to us would continue to be available to us, and (ii) such services will now be provided pursuant to the PSIL MSA. PSIL is beneficially owned by Dalea Investment Group, LLC, which is controlled by Mr. Mitchell. As a result, the Amended Note revised the events triggering acceleration of the repayment of the Original Note to the following: (i) a reduction of ownership by Dalea (and other controlled affiliates of Mr. Mitchell) of equity interest in PSIL to less than 50%; (ii) the sale or transfer by Dalea or PSIL of all or substantially all of its assets to any person (a “Transferee”) that does not own a controlling interest in Dalea or PSIL and is not controlled by Mr. Mitchell (an “Unrelated Person”), or the subsequent transfer by any Transferee that is not an Unrelated Person of all or substantially all of its assets to an Unrelated Person; (iii) the acquisition by an Unrelated Person of more than 50% of the voting interests of Dalea or PSIL; (iv) termination of the PSIL MSA other than as a result of an uncured default thereunder by TEMI; (v) default by PSIL under the PSIL MSA, which default is not remedied within a period of 30 days after notice thereof to PSIL; and (vi) insolvency or bankruptcy of PSIL. The maturity date of the Amended Note was extended to June 13, 2019. The interest rate on the Amended Note remains at 3.0% per annum and continues to be guaranteed by Mr. Mitchell. The Amended Note contains customary events of default.

In addition, pursuant to the Note Amendment Agreement, on April 19, 2016, we entered into a pledge agreement (the “Pledge Agreement”) with Dalea, whereby Dalea pledged the ~~$2.1~~$2.0 million principal amount of the 2017 Notes ~~issued by us and~~ owned by Dalea (the “Dalea Convertible Notes”), including any future securities for which the Dalea Convertible Notes are converted or exchanged, as security for the performance of Dalea’s obligations under the Amended Note. The Pledge Agreement provides that interest payable to Dalea under the Dalea Convertible Notes (or any future securities for which the Dalea Convertible Notes are converted or exchanged) will be credited first against the outstanding principal balance of the Amended Note and, upon full repayment of the outstanding principal balance of the Amended Note, any accrued and unpaid interest on the Amended Note. The Pledge Agreement contains customary events of default.

On November 4, 2016, Dalea exchanged $2.0 million of 2017 Notes for 40,000 Series A Preferred ~~Shares, which were pledged as security for the performance of Dalea’s obligations~~Shares.

On June 30, 2016, we entered into a waiver with Dalea, whereby we waived our right under the ~~Amended Note pursuant~~Pledge Agreement to receive the interest payment due July 1, 2016 under the Dalea Convertible Notes in connection with the payment of 201,459 common shares to Dalea with respect to the ~~terms of~~2017 Note interest payment paid on June 30, 2016.

During the ~~Pledge Agreement.~~ ~~During nine~~three months ended ~~September 30, 2017,~~March 31, 2018, we reduced the principal amount of the Amended Note by $~~0.1~~$0.1 million for cash dividends paid on the Series A Preferred Shares.

As of March 31, 2018, the amount receivable under the Amended Note was $6.5 million.

In connection with the pledge of the Gundem real estate and Muratli real estate to DenizBank as collateral for the 2016 Term Loan, on August 31, 2016, ~~the Company~~we entered into a pledge fee agreement with Gundem (the “Gundem Fee Agreement”) pursuant to which ~~the Company pays~~we pay Gundem a fee equal to 5% per annum of the collateral value of the Gundem real estate and Muratli real estate. Pursuant to the Gundem Fee Agreement, the Gundem real estate has a deemed collateral value of $10.0 million and the Muratli real estate has a deemed collateral value of $5.0 million.

In connection with the pledge of the Diyarbakir real estate to DenizBank as collateral for the 2016 Term Loan, on August 31, 2016, ~~the Company~~we entered into a pledge fee agreement with ~~Mr.~~Messrs. Mitchell and ~~Selami Erdem~~ Uras (the “Diyarbakir Fee Agreement”) pursuant to which ~~the Company pays Messrs.~~we pay Mr. Mitchell and Selami Erdem Uras a fee of 5% per annum of the collateral value of the Diyarbakir real estate. Mr. Uras is our vice president, Turkey. Pursuant to the Diyarbakir Fee Agreement, the Diyarbakir real estate has a deemed collateral value of $5.0 million.

Amounts payable to Mr. Mitchell under the Gundem Fee Agreement and the Diyarbakir Fee Agreement are used to reduce the outstanding principal amount of the Amended Note. During the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2018, we reduced the principal amount of the Amended Note by $~~0.2~~$0.2 million ~~and $0~~.5 ~~million, respectively,~~ for amounts payable under the pledge fee agreements.

On June 26, 2017, and effective as of January 1, 2017, the Company’s wholly owned subsidiary, TransAtlantic USA entered into an Amended and Restated Office Lease (the “Office Lease”) with Longfellow to lease approximately 10,000 square feet of corporate office space in Addison, Texas. The initial lease term under the Office Lease commenced on January 1, 2017 (the “Commencement Date”), and expires five years after the Commencement Date, unless earlier terminated in accordance with the Office Lease. TransAtlantic USA has the option to extend the lease term for two additional periods of five years each. If TransAtlantic USA exercises its option to extend the lease term, the monthly rent payable during such extended term shall be at a mutually agreed upon amount for monthly rent during the renewal term. During the first five months of the initial lease term, TransAtlantic USA is required to pay monthly rent of $14,745.16 to Longfellow, plus utilities, real property taxes and liability insurance (to the extent that TransAtlantic does not obtain its own liability insurance). Monthly rent increases by $2,754.84 the sixth month of the initial lease term, by $833.33 the second year of the initial lease term and by approximately $417 each year thereafter during the initial lease term.

~~On October 2, 2017, we issued an aggregate of 2,591,384 common shares to holders of the Series A Preferred Shares as payment of~~ ~~the September 30, 2017~~ quarterly dividend on the Series A Preferred Shares (see Note 14. “Subsequent Events”). Of the 2,591,384 common shares, 1,156,419 common shares were issued to Dalea, the trusts of Mr. Mitchell’s four children and Pinon Foundation, a nonprofit entity controlled by Mrs. Mitchell.

On October 13, 2016, we entered into a share purchase agreement (the “Purchase Agreement”) with Valeura Energy Netherlands B.V. (“~~Valeura”~~Valeura Netherlands”) for the sale of all of the equity interests in TBNG, our wholly-owned subsidiary. TBNG owned a portion of ~~the Company’s~~our interests in the Thrace Basin area in Turkey.

On February 24, 2017, we closed on the sale of TBNG for gross proceeds of $20.7 million, and approximate net cash proceeds of $16.1 million, effective as of March 31, 2016. The purchase price was subject to post-closing adjustments, and we agreed to escrow $3.1 million of the purchase price for 30 days to satisfy any agreed upon purchase price adjustments. We agreed towhich amounts reflect a $0.2 million ~~reduction to the~~post-closing purchase price ~~and, on April 10, 2017, we collected $2.9 million of the escrowed funds.~~adjustment.

For the ~~nine~~three months ~~ended September 30,~~March 31, 2017, we recorded a non-cash net loss of $15.2 million on the sale of TBNG. The loss related to the reclassification of the TBNG accumulated foreign currency translation adjustment that was realized into earnings from accumulated other comprehensive loss within shareholders’ ~~equity. The calculation of the loss on sale is~~equity, and presented below:

~~Our~~As a result of the TBNG sale, there were no remaining assets ~~and~~or liabilities held for sale atas of December 31, ~~2016~~2017. As of March 31, 2018, there were ~~as follows:~~

sale.In February 2016, we sold all of the outstanding equity in our wholly-owned subsidiary, Stream Oil & Gas Ltd. (“Stream”), to GBC Oil Company (“GBC Oil”). We have presented the Albanian segment operating results as discontinued operations for For the three ~~and nine~~ months ended ~~September 30, 2016.~~

~~On September 1, 2016,~~March 31, 2018 and March 31, 2017, we completed a joint venture transaction with respect to the assets in the Delvina gas field in Albania (the “Delvina Assets”). We transferred (the “Transfer”) 75% of the outstanding shares of Delvina Gas Company Ltd. (“DelvinaCo”), which owns the Delvina Assets, to Ionian Gas Company Ltd. (“Ionian”) in exchange for Ionian’s agreement to pay $12.0 million to DelvinaCo, which was to be used primarily to repay debt and for general corporate purposes with respect to the Delvina Assets. After the Transfer, we retained a 25% equity interest in DelvinaCo and agreed to pay 25% of the operating costs of DelvinaCo, subject to a three-year deferral of capital expenditures.

On August 9, 2017, due to continued failures by our joint venture partners to timely meet their obligations, uncompleted local governmental ratifications, and our prioritization of funds, we transferred our 25% equity interest in DelvinaCo to Delvina Investment Partners Ltd. in exchange for a release of all claims with respect to DelvinaCo and a cash payment of $300,000 for amounts owed to us under agreements entered into in connection with the DelvinaCo joint venture transaction. Additionally, we terminated all of our responsibilities as operator and our obligations to pay any operating costs or any other expenditures with respect to DelvinaCo. This divestiture completed our departure from all Albanian operations and assets.

~~Our~~had no significant operating results from discontinued ~~operations for the three and nine months ended September 30, 2016 are summarized as follows:~~operations.

~~On October 2, 2017, we issued an aggregate of 2,591,384 common shares to holders of the Series A Preferred Shares as payment of the September 30, 2017 quarterly dividend~~

Exploration License 5046 in West Molla expires in June 2018. Based on the Series A Preferred Shares. Each common share was issued at a value of $0.7108 per common share, which was equal to the 15-day volume weighted average price through the close of trading of the common sharessuccessful discovery on the ~~NYSE American~~Pinar-1ST exploration well, we applied to convert the exploration license to a production license in the first quarter of 2018. In March 2018, we spud the Yeniev-1 exploration well on ~~September 13, 2017.~~Exploration License 5046. If a successful discovery is made on the Yeniev-1 exploration well, the southern portion of Exploration License 5046 may also convert to a production license.

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.

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 ~~September 30, 2017,~~March 31, 2018, we held interests in approximately ~~0.5 million~~367,000 and 163,000 net acres of developed and undeveloped oil and natural gas properties in Turkey and ~~Bulgaria.~~Bulgaria, respectively. As of ~~November 6, 2017,~~May 7, 2018, approximately ~~47.3%~~47% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

TransAtlantic is a holding company with two operating segments – Turkey and Bulgaria. Its assets consist of its ownership interests in subsidiaries that primarily own assets in Turkey and Bulgaria.

On January 16, 2018, a strategic committee of the board of directors engaged Tudor Pickering Holt & Co. to act as financial advisor to market the Company and explore strategic alternatives to increase shareholder value. There is no assurance that the strategic alternatives process will result in us completing a sale of the Company or any of its assets.

~~A summary of~~The following summarizes our financial and operational performance for the ~~third~~first quarter of ~~2017 include:~~2018:

During the ~~third~~first quarter of ~~2017,~~2018, we ~~further developed our oil fields~~spud two wells and continued workover and recompletion production optimizations in Southeastern ~~Turkey, where we tested three wells.~~Turkey. The following summarizes our operations by location during the ~~third~~first quarter of ~~2017:~~2018:

In January 2018, we spud the ~~Bahar-11~~Selmo-81H2 well, ~~throughout~~which is the first of a six-well Selmo development program. Completion is ongoing, and we expect to commence production in the second quarter of 2018. We expect to resume drilling in the Selmo field in the third quarter of ~~2017 in the Bedinan, Dadas, and Hazro formations. Commercial oil was discovered in all three formations with a combined test rate of 280 barrels of oil per day (“Bopd”). The~~2018.

We expect to drill one development well ~~was brought on production at a commingled rate of 140 Bopd.~~

Testing continued on the Cavulsu-1 well throughout the third quarter 2017. The well flowed high API gravity hydrocarbon in two Bedinan benches. Testing will continue throughout the fourth quarter of 2017 to establish the potential of these intervals as well as up-hole potential in the Dadas, Hazro, and Mardin formations.

~~Operations on the Pinar-1ST well were temporarily suspended during the third quarter of 2017 due to priority repair and maintenance workover operations~~ in the Bahar ~~and Selmo fields. Testing will resume~~field in 2018. We may drill an additional Bahar development well in the fourth quarter of ~~2017.~~2018, contingent on financing.

In March 2018, we spud the Yeniev-1 exploration well, targeting the Bedinan, Hazro and Mardin formations. We expect to complete drilling in the second quarter of 2018. We have completed 3-D on the eastern Molla Block extension. We expect to complete processing of this data in the second quarter of 2018. We expect to complete interpretation and analysis in the third quarter of 2018.

Northwestern Turkey. We continue to evaluate our ~~position~~prospects in ~~Bulgaria~~the Thrace Basin, in light of the recent positive production test results at the Yamalik-1 exploration well, operated by Valeura Energy Inc. (“Valeura”) with ~~updated geologic models~~their partner Statoil Banarli Turkey B.V. (“Statoil”). The Yamalik-1 exploration well is directly adjacent to our 120,000 net acres in the Thrace Basin of which we believe approximately 50,000 net acres (100% working interest, 87.5% net revenue interest) is analogous to the Valeura and ~~continue~~Statoil acreage. We expect to ~~market~~resume production operations on our Yildurm-1 well on the Temrez license in 2018. Contingent on financing, we may commence a ~~joint venture exploration~~three-well drilling program ~~for~~on our ~~assets~~Temrez license starting in the fourth quarter of 2018.

Bulgaria.We have prepared plans to side track and re-drill the Devinci R-1 well, which we plan to commence during 2018, contingent on financing.

~~We currently plan to execute the following activities under our development plan during the remainder of 2017:~~

~~Turkey.~~We expect our net field capital expenditures for the remainder of ~~2017~~2018 to range between ~~$3.0~~$18.0 million and ~~$4.5 million.~~ $21.0 million. We expect net field capital expenditures during the remainder ~~2017~~of 2018 to include between ~~$0.5~~$14.0 million and ~~$1.0~~$17.0 million in drilling and completion expense for ~~two gross~~eight wells ~~between $1.0 million~~ and ~~$2.0~~approximately $4.0 million in ~~capital recompletions~~recompletions. We expect that any additional 2018 expenditures would be invested in the Selmo, Bahar and ~~approximately $1.5 million for 3D seismic. Additionally, expenses for~~Molla fields in southeastern Turkey and the Koynare license in Bulgaria. We expect that cash on hand and cash flow from operations will be sufficient to fund the remainder of ~~2017 associated with the~~our 2018 ~~drilling program are anticipated to be $1.0 million.~~

~~Bulgaria.~~ ~~We intend to drill on~~net field capital expenditures. If not, we will either curtail our ~~Koynare license during~~discretionary capital expenditures or seek other funding sources. Our projected remaining 2018 ~~and plan to continue working on our geologic model for additional prospects. In addition, we continue to market a joint venture exploration program for our assets in Bulgaria.~~

In February 2016, we sold all of the outstanding equity in our wholly-owned subsidiary, Stream Oil & Gas Ltd., to GBC Oil Company. We have presented the Albanian segment operating results as discontinued operations for the three and nine months ended September 30, 2016.

On September 1, 2016, we completed a joint venture transaction with respect to the assets in the Delvina gas field in Albania (the “Delvina Assets”). We transferred (the “Transfer”) 75% of the outstanding shares of Delvina Gas Company Ltd. (“DelvinaCo”), which owns the Delvina Assets, to Ionian Gas Company Ltd. (“Ionian”) in exchange for Ionian’s agreement to pay $12.0 million to DelvinaCo, which was to be used primarily to repay debt and for general corporate purposes with respect to the Delvina Assets. After the Transfer, we retained a 25% equity interest in DelvinaCo and agreed to pay 25% of the operating costs of DelvinaCo,capital expenditure budget is subject to ~~a three-year deferral of capital expenditures.~~

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”).~~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, ~~2016~~2017 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.

Effective January 1, 2018, the ~~significant~~Company adopted new accounting ~~policies disclosed~~standards for revenue, statement of cash flows and restricted cash disclosures in ~~our Annual Report on Form 10-K for the year ended December 31, 2016.~~statement of cash flows. (See Note 2. “Recent accounting pronouncements”)

Results of Continuing Operations—Three Months Ended ~~September 30, 2017~~March 31, 2018 Compared to Three Months Ended ~~September 30, 2016~~March 31, 2017

Our results of continuing operations for the three months ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~ were as follows:

	Three Months Ended September 30,						Change			Three Months Ended March 31,						Change
	2017			2016			2017-2016			2018			2017			2018-2017
	(in thousands of U.S. Dollars, except per unit amounts and production volumes)									(in thousands of U.S. Dollars, except per unit amounts and production volumes)
Sales volumes:
Oil (Mbbl)		254			338			(84	)		248			314			(66	)
Natural gas (Mmcf)		58			283			(225	)		67			184			(117	)
Total production (Mboe)		263			386			(123	)		260			345			(85	)
Average daily sales volumes (Boepd)		2,862			4,191			(1,329	)		2,885			3,833			(948	)
Average prices:
Oil (per Bbl)	$	47.88		$	39.99		$	7.89		$	65.71		$	47.26		$	18.45
Natural gas (per Mcf)	$	4.82		$	6.89		$	(2.07	)	$	5.00		$	4.96		$	0.04
Oil equivalent (per Boe)	$	47.18		$	40.15		$	7.03		$	64.17		$	45.70		$	18.47
Revenues:
Oil and natural gas sales	$	12,424		$	15,483		$	(3,059	)	$	16,661		$	15,768		$	893
Sales of purchased natural gas		-			1,171			(1,171	)		-			654			(654	)
Other		251			5			246			265			14			251
Total revenues	$	12,675		$	16,659		$	(3,984	)		16,926			16,436			490
Costs and expenses (income):
Production	$	2,997		$	3,070		$	(73	)		2,869			3,087			(218	)
Transportation and processing											1,193			-			1,193
Exploration, abandonment and impairment		141			1,531			(1,390	)		40			106			(66	)
Cost of purchased natural gas		-			1,027			(1,027	)		-			568			(568	)
Seismic and other exploration		2,966			3			2,963
Seismic and other geological and geophysical											159			15			144
General and administrative		2,532			2,659			(127	)		3,337			3,590			(253	)
Depletion		4,015			6,918			(2,903	)		4,197			4,310			(113	)
Depreciation and amortization		257			362			(105	)		262			187			75
Interest and other expense		2,322			3,836			(1,514	)		2,782			2,371			411
Interest and other income		(182	)		(1,009	)		827			(254	)		(293	)		39
Foreign exchange loss	$	48		$	390		$	(342	)		2,058			2,123			(65	)
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	-		$	2,729		$	(2,729	)		(1,339	)		-			(1,339	)
Change in fair value on commodity derivative contracts		(1,365	)		(2,916	)		1,551			614			988			(374	)
Total loss on commodity derivative contracts	$	(1,365	)	$	(187	)	$	(1,178	)
Total (loss) gain on commodity derivative contracts											(725	)		988			(1,713	)
Oil and natural gas costs per Boe:
Production	$	9.84		$	6.96		$	2.88		$	10.28		$	7.74		$	2.54
Depletion	$	13.34		$	15.70		$	(2.36	)	$	14.53		$	10.93		$	3.60

Oil and Natural Gas Sales. Total oil and natural gas sales revenues ~~decreased $3.1~~increased $0.9 million to ~~$12.4~~$16.7 million for the three months ended ~~September 30, 2017,~~March 31, 2018, from ~~$15.5~~$15.8 million realized in the same period in ~~2016.~~2017. The ~~decrease~~increase was primarily due to a decrease in our sales volumes of 123 Mboe for the three months ended September 30, 2017 compared to the same period in 2016, primarily due to a 43 Mboe decrease in oil production in the Bahar oil field, a 36 Mboe decrease in oil production in the Selmo oil field and a 33 Mboe decrease from the divestiture of TBNG in February 2017. This was partially offset by an increase in the average realized price per Boe. Our average price received increased ~~$7.03~~$18.47 per Boe to ~~$47.18~~$64.17 per Boe for the three months ended ~~September 30, 2017,~~March 31, 2018, from ~~$40.15~~$45.70 per Boe for the same period in ~~2016.~~

~~Sales~~2017. This was partially offset by a decrease in our average daily sales volumes of ~~Purchased Natural Gas.~~ ~~Sales of purchased natural gas~~948 Boepd for the three months ended ~~September 30, 2017 decreased~~March 31, 2018 compared to ~~zero from $1.2 million for~~ the same period in ~~2016. The decrease was due to the divestiture of TBNG in February~~ 2017.

Production. Production expenses for the three months ended ~~September 30, 2017~~March 31, 2018 decreased to ~~$3.0~~$2.9 million, or ~~$9.84~~$10.28 per Boe, from $3.1 million, or ~~$6.81~~$7.74 per Boe, for the same period in ~~2016.~~2017. The ~~increase in production expense per Boe~~decrease was primarily due to ~~a decrease in our sales volumes~~less workovers during the ~~period.~~three months ended March 31, 2018, as compared to the same period in 2017.

Transportation and processing. Transportation and processing expense for the three months ended March 31, 2018 increased to $1.2 million from zero for the same period in 2017. The increase is due to the new revenue reporting regulation, ASC 606, which requires cost, previously netted in revenue, to be reported separately. For the three months ended March 31, 2017, the transportation and processing costs were $1.2 million and were netted against oil and natural gas sales.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended ~~September 30, 2017 decreased $1.4 million to $0.1 million~~March 31, 2018 did not significantly change from ~~$1.5 million for~~ the same period in ~~2016. During the three months ended September 30, 2017, we incurred $0.1 million in proved property impairment, minimal exploratory dry hole costs and no unproved property impairment.~~

~~Cost of Purchased Natural Gas.~~ Cost of purchased natural gas for the three months ended September 30, 2017 decreased to zero from $1.0 million for the same period in 2016. The decrease was due to the divestiture of TBNG in February 2017.

~~Seismic and Other Exploration.~~ Seismic and other exploration for the three months ended September 30, 2017 increased to $3.0 million from $3,000 for the same period in 2016. The increase was due to seismic acquisition activity on our Molla license during the three months ended September 30, 2017.

General and Administrative. General and administrative expense was ~~$2.5~~$3.3 million for the three months ended ~~September 30, 2017,~~March 31, 2018, compared to ~~$2.7~~$3.6 million for the same period in ~~2016.~~2017. Our general and administrative expenses decreased $0.3 million primarily due to a $0.2 million ~~due to~~decrease in legal and a $0.1 million decrease in ~~in personnel expenses and a $0.1 million decrease legal, accounting and other services.~~insurance expenses.

Depletion. Depletion decreased to ~~$4.0~~$4.2 million, or ~~$13.34~~$14.53 per Boe, for the three months ended ~~September 30, 2017,~~March 31, 2018, compared to ~~$6.9~~$4.3 million, or ~~$15.70~~$10.93 per Boe, for the same period of ~~2016.~~2017. The decrease was primarily due to a reduction in production ~~volumes as well as no depletion expense recorded for TBNG as a result of the divestiture in February 2017.~~volumes.

Interest and Other Expense. Interest and other expense ~~decreased~~increased to ~~$2.3~~$2.8 million for the three months ended ~~September 30, 2017,~~March 31, 2018, compared to ~~$3.8~~$2.4 million for the same period in ~~2016.~~2017. The ~~decrease~~increase was primarily due to our ~~lower~~higher average debt balances during the three months ended ~~September 30, 2017~~March 31, 2018 versus the same period in ~~2016.~~2017.

Interest and Other Income. Interest and other income decreased to $0.2 million for the three months ended September 30, 2017, as compared to $1.0 million for the same period in 2016, primarily due to a $0.7 million gain on the sale of our Edirne gas gathering system and facilitiesdid not significantly change during the three months ended ~~September 30, 2016.~~March 31, 2018 from the same period in 2017.

Foreign Exchange Loss. We recorded a foreign exchange loss of ~~$48,000~~$2.1 million during each of the three months ended ~~September 30, 2017, as compared to a loss of $0.4 million in the same period in 2016.~~March 31, 2018 and 2017. Foreign exchange gains and losses are primarily unrealized (non-cash) in nature and result 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 TRY amount if it has not been settled previously. The foreign exchange loss for the three months ended September 30, 2017 was due to a decrease in the value of the TRY compared to the U.S. Dollar.

~~Gain on Commodity Derivative Contracts.~~ During the three months ended September 30, 2017, we recorded a net loss on commodity derivative contracts of $1.4 million, as compared to a net loss of $0.2 million for the same period in 2016. During the three months ended September 30, 2017, we recorded a $1.4 million loss to mark our commodity derivative contracts to their fair value. During the same period in 2016, we recorded a $2.9 million loss to mark our derivative contracts to their fair value and a $2.7 million gain on settled contracts.

~~Other Comprehensive Income (Loss).~~ We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. Dollar reporting currency. Foreign currency translation adjustment for the three months ended September 30, 2017 decreased to a loss of $1.2 million from a loss of $4.0 million for the same period in 2016. ~~The change was due to a 1.3% decrease in the value of the TRY as compared to the U.S. Dollar, versus a 3.5% decrease in the value of the TRY for the three months ended September 30, 2016.~~

~~Discontinued Operations.~~ ~~All revenues and expenses associated with our Albanian operations have been classified as discontinued operations. Our operating~~ results ~~from discontinued operations in Albania are summarized as follows:~~

~~Results of Continuing Operations—Nine Months Ended September 30, 2017 Compared to Nine Months Ended September 30, 2016~~

~~Our results of continuing operations for the nine months ended September 30, 2017 and 2016 were as follows:~~

Nine Months Ended September 30,

Change

2017

2016

2017-2016

(in thousands of U.S. Dollars, except per
unit amounts and volumes)

Sales volumes:

Oil (Mbbl)

858

1,024

(166
)
Natural gas (Mmcf)

308

1,152

(844
)
Total production (Mboe)

909

1,216

(307
)
Average daily sales volumes (Boepd)

3,331

4,437

(1,106
)
Average prices:

Oil (per Bbl)
$
45.42

$
37.20

$
8.22

Natural gas (per Mcf)
$
4.89

$
7.02

$
(2.13
)
Oil equivalent (per Boe)
$
44.51

$
37.98

$
6.53

Revenues:

Oil and natural gas sales
$
40,475

$
46,171

$
(5,696
)
Sales of purchased natural gas

654

3,717

(3,063
)
Other

323

35

288

Total revenues
$
41,452

$
49,923

$
(8,471
)
Costs and expenses (income):

Production
$
8,798

$
9,025

$
(227
)
Exploration, abandonment and impairment

249

2,964

(2,715
)
Cost of purchased natural gas

568

3,264

(2,696
)
Seismic and other exploration

3,046

84

2,962

General and administrative

9,303

11,401

(2,098
)
Depletion

12,330

21,745

(9,415
)
Depreciation and amortization

694

1,308

(614
)
Interest and other expense

6,981

9,106

(2,125
)
Interest and other income

(663
)

(1,411
)

748

Foreign exchange loss
$
1,055

$
659

$
396

Gain (loss) on commodity derivative contracts:

Cash settlements on commodity derivative contracts
$
32

$
4,188

$
(4,156
)
Change in fair value on commodity derivative contracts

267

(6,607
)

6,874

Total gain (loss) on commodity derivative contracts
$
299

$
(2,419
)

$
2,718

Oil and natural gas costs per Boe:

Production
$
8.43

$
6.50

$
1.93

Depletion
$
11.86

$
16.65

$
(4.79
)

~~Oil and Natural Gas Sales.~~ Total oil and natural gas sales revenues decreased $5.7 million to $40.5 million for the nine months ended September 30, 2017, from $46.2 million realized in the same period in 2016. The decrease was primarily due to a decrease in our sales volumes of 307 Mboe for the nine months ended September 30, 2017 compared to the same period in 2016, primarily due to a decrease of 116 Mboe in oil production in the Selmo oil field and a 110 Mboe decrease from the divestiture of TBNG in February 2017. This was partially offset by an increase in the average realized price per Boe. Our average price received increased $6.53 per Boe to $44.51 per Boe for the nine months ended September 30, 2017, from $37.98 per Boe for the same period in 2016.

~~Sales of Purchased Natural Gas.~~ Sales of purchased natural gas for the nine months ended September 30, 2017 decreased to $0.7 million from $3.7 million for the same period in 2016. The decrease was due to the divestiture of TBNG in February 2017.

~~Production.~~ Production expenses for the nine months ended September 30, 2017 decreased to $8.8 million, or $8.43 per Boe, from $9.0 million, or $6.50 per Boe, for the same period in 2016. The increase in production expense per Boe was primarily due to a decrease in our sales volumes during the period.

~~Exploration, Abandonment and Impairment.~~ Exploration, abandonment and impairment costs for the nine months ended September 30, 2017 decreased $2.7 million to $0.2 million, from $3.0 million for the same period in 2016. During the nine months ended September 30, 2017, we incurred $0.2 million in proved property impairment, minimal exploratory dry hole costs and no unproved property impairment.

~~Cost of Purchased Natural Gas.~~ Cost of purchased natural gas for the nine months ended September 30, 2017 decreased to $0.6 million from $3.3 million for the same period in 2016. The decrease was due to the divestiture of TBNG in February 2017.

~~Seismic and Other Exploration.~~ Seismic and other exploration for the nine months ended September 30, 2017 increased to $3.0 million from $0.1 million for the same period in 2016. The increase was due to seismic acquisition activity on our Molla license during the nine months ended September 30, 2017.

~~General and Administrative.~~ General and administrative expense was $9.3 million for the nine months ended September 30, 2017, compared to $11.4 million for the same period in 2016. Our general and administrative expenses decreased $2.1 million due to a $1.6 million decrease in legal, accounting and other services and a $0.8 million decrease in personnel expenses, which was partially offset by an increase in office expenses of $0.3 million.

~~Depletion.~~ Depletion decreased to $12.3 million, or $11.86 per Boe, for the nine months ended September 30, 2017, compared to $21.7 million, or $16.65 per Boe, for the same period of 2016. The decrease was primarily due to a reduction in production volumes as well as no depletion expense recorded for TBNG after the divestiture in February 2017.

~~Interest and Other Expense.~~ Interest and other expense decreased to $7.0 million for the nine months ended September 30, 2017, compared to $9.1 million for the same period in 2016. The decrease was primarily due to our lower average debt balances during the nine months ended September 30, 2017 versus the same period in 2016.

~~Interest and Other Income.~~ Interest and other income decreased to $0.7 million for the nine months ended September 30, 2017, as compared to $1.4 million for the same period in 2016, primarily due to a $0.7 million gain on the sale of our Edirne gas gathering system and facilities during the nine months ended September 30, 2016.

~~Foreign Exchange Loss.~~ We recorded a foreign exchange loss of $1.1 million during the nine months ended September 30, 2017, as compared to a loss of $0.7 million in the same period in 2016. Foreign exchange gains and losses are primarily unrealized (non-cash) in nature and result from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the TRY amount if it has not been settled previously. ~~The foreign exchange loss for the nine months ended September 30, 2017 was due to a decrease in the value of the TRY compared to the U.S. Dollar.~~

Gain (Loss) on Commodity Derivative Contracts. During the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2018, we recorded a net ~~gain~~loss on commodity derivative contracts of ~~$0.3~~$0.7 million, as compared to a net ~~loss~~gain of ~~$2.4~~$1.0 million for the same period in ~~2016.~~2017. During the ~~nine~~three months ended ~~September 30,~~March 31, 2018, we recorded a $0.6 million gain to mark our derivative contracts to their fair value and a $1.3 million loss on settled contracts. During the same period in 2017, we recorded a ~~$0.3~~$1.0 million gain to mark our commodity derivative contracts to their fair value and a $32,000 gain on settled contracts. During the same period in 2016, we recorded a $6.6 million loss to mark our derivative contracts to their fair value and a $4.2 million gain on settled contracts.value.

~~Other Comprehensive Income (Loss).~~ We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. Dollar reporting currency. Foreign currency translation adjustment for the nine months ended September 30, 2017 increased to a gain of $21.8 million from a loss of $3.3 million for the same period in 2016. Of the $21.4 million gain, $23.1 million was due to ~~the loss related to the TBNG accumulated foreign~~

~~currency translation adjustment that was realized into earnings from accumulated other comprehensive loss within shareholders’ equity. The remaining change was due to a decrease in the value of the TRY as compared to the U.S. Dollar.~~

~~Discontinued Operations.~~ All revenues and expenses associated with our Albanian operations have been classified as discontinued operations. Our operating results from discontinued operations in Albania are summarized as follows:

For the quarter ended ~~September 30, 2017,~~March 31, 2018, we incurred ~~$6.0~~$5.2 million in capital expenditures, including seismic and corporate expenditures, as compared to ~~$1.5~~$6.5 million for the quarter ended September 30, 2016. The increase was due to our planned increase in capital expenditures, which included $3.0 million of 3D seismic on our Molla license, during the quarter ended September 30, 2017 compared to the same period in 2016.March 31, 2017.

We expect our net field capital expenditures for the remainder of ~~2017~~2018 to range between ~~$3.0~~$18.0 million and ~~$4.5 million.~~ $21.0 million. We expect net field capital expenditures during the remainder ~~2017~~of 2018 to include between ~~$0.5~~$14.0 million and ~~$1.0~~$17.0 million in drilling and completion expense for ~~two gross~~eight wells ~~between $1.0 million~~ and ~~$2.0~~approximately $4.0 million in ~~capital recompletions~~recompletions. We expect that any additional 2018 expenditures would be invested in the Selmo, Bahar and ~~approximately $1.5 million for 3D seismic. Additionally, expenses for~~Molla fields in southeastern Turkey and the ~~remainder of 2017 associated with the 2018 drilling program are anticipated to be $1.0 million.~~Koynare license in Bulgaria. We expect that cash on hand and cash flow from operations will be sufficient to fund the remainder of our ~~2017~~2018 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected ~~2017~~remaining 2018 capital expenditure budget is subject to change.

Net cash provided by operating activities ~~from continuing operations~~ during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 was $16.1 million, a decrease from net cash provided by operating activities from continuing operations of $19.6 million for the same period in 2016. The decrease was primarily due to a decrease in our total revenues.

~~Net cash provided by investing activities from continuing operations during the nine months ended September 30, 2017 was $4.9~~$7.8 million, an increase from net cash provided by ~~investing~~operating activities ~~from continuing operations~~ of ~~$2.7~~$1.9 million for the same period in ~~2016.~~2017. The increase was primarily due to the timing of collecting our receivables and paying our accounts payable.

Net cash used in investing activities during the three months ended March 31, 2018 was $7.0 million, as compared to net cash provided by investing activities of $11.2 million for the same period in 2017. The change in net cash was primarily due to the proceeds received from the sale of TBNG ~~partially offset by an increase in capital expenditures.~~of $17.8 million during the quarter ended March 31, 2017.

Net cash used in financing activities ~~from continuing operations~~ during the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 was ~~$29.7~~$4.1 million, ~~an increase~~a decrease from net cash used in financing activities ~~from continuing operations~~ of ~~$7.8~~$11.4 million for the same period in ~~2016.~~2017. The ~~increase~~change in net cash was ~~primarily~~ due to a decrease in ~~our outstanding indebtedness.~~debt principal repayments.

As of ~~September 30, 2017,~~March 31, 2018, we had ~~$12.4~~$24.5 million of indebtedness, not including ~~$7.9~~$9.6 million of trade payables, as further described below. We believe that our cash flow from operations will be sufficient to meet our normal operating requirements and to fund planned capital expenditures during the next 12 months. As of March 31, 2018, we had a working capital surplus of $9.3 million.

2016 Term Loan. On August 23, 2016, the Turkish branch of ~~TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), our wholly-owned subsidiary,~~TEMI entered into athe Credit Agreement with DenizBank. The Credit Agreement is a master agreement pursuant to which DenizBank ~~S.A. (“DenizBank”).~~ may make loans to TEMI from time to time pursuant to additional loan agreements.

On August 31, 2016, DenizBank entered ~~into a $30.0 million term loan with TEMI~~the 2016 Term Loan under the Credit ~~Agreement (the “Term Loan”).~~Agreement. In addition, we and DenizBank entered into additional agreements with respect to up to $20.0 million of non-cash facilities, including guarantee letters and treasury instruments for future hedging transactions.

~~On September 7,~~The 2016 ~~TEMI used approximately $22.9 million of the proceeds from the Term Loan to repay our former senior credit facility in full.~~

~~The~~ Term Loan bears interest at a fixed rate of 5.25% (plus 0.2625% for Banking and Insurance Transactions Tax per the Turkish government) per ~~annum.~~annum and is payable in monthly installments of $1.38 million through June 2018. Amounts repaid under the 2016 Term Loan may not be re-borrowed and early repayments under the 2016 Term Loan are subject to early repayment fees. The 2016 Term Loan is guaranteed by the Guarantors.

The 2016 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting of liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain investments, selling assets or transferring revenue, and other similar matters. In addition, the 2016 Term Loan prohibits Amity and Petrogas from incurring additional debt. An event of default under the 2016 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and the occurrence of a material adverse effect.

The 2016 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate owned by Gundem and (v) certain Diyarbakir real estate owned 80% by N. Malone Mitchell 3^rd and 20% by Selami Erdem Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank ~~approved a revised amortization schedule~~as additional security for the 2016 Term Loan. ~~Pursuant to the revised amortization schedule, the maturity date~~Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of ~~the Term Loan was extended from February~~our board of directors. Mr. Uras is our vice president, Turkey.

At March 31, 2018, ~~to June 2018, and the monthly principal payments were reduced from $1.88 million to $1.38 million. The other terms of the Term Loan remain unchanged.~~

~~At September 30, 2017,~~ we had ~~$12.4~~$4.1 million outstanding under the 2016 Term Loan and no availability and were in compliance with ~~all of~~ the covenants in the 2016 Term Loan.

2017 Term Loan. On November 17, 2017, Denizbank entered into the 2017 Term Loan under the Credit Agreement. We will use the proceeds from the 2017 Term Loan for general corporate purposes.

The 2017 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate owned by Gundem, (v) certain Diyarbakir real estate owned 80% by N. Malone Mitchell 3rd and 20% Selami Erdem Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2017 Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.

At March 31, 2018, we had $20.4 million outstanding under the 2017 Term Loan and no availability, and we were in compliance with the covenants in the 2017 Term Loan.

2017 Notes. The 2017 Notes were issued pursuant to the Indenture. The 2017 Notes bore interest at an annual rate of 13.0% ~~per annum. Interest was~~, payable semi-annually, in arrears, on January 1 and July 1 of each year. The 2017 Notes matured on July 1, 2017, and on July 3, 2017, we paid off and retired all remaining outstanding 2017 Notes.

ANBE Note. On December 30, 2015, TransAtlantic USA entered into the ANBE Note. The ANBE Note bore interest at a rate of 13.0% per annum.On December 30, 2015, we borrowed $3.6 million under the ANBE Note for general corporate purposes.On June 30, 2016, we issued 355,826 common shares in a private placement to ANBE in lieu of paying cash interest on ~~July 3, 2017.~~the ANBE Note.

On October 31, 2016, TransAtlantic USA entered into the ANBE Amendment, which extended the maturity date of the Note from October 31, 2016 to September 30, 2017, provided for the ANBE Note to be repaid in four quarterly installments of $0.9 million each in December 2016 and March, June and September 2017, and provided for monthly payments of interest.

On February 27, 2017, we repaid the ANBE Note in full with proceeds from the sale of TBNG and terminated it.

Series A Preferred Shares. ~~On November 4, 2016,~~As of March 31, 2018, we ~~issued 921,000 shares of our 12% Series A Convertible Redeemable Preferred Shares (“Series A Preferred Shares”). Of the~~have 921,000 Series A Preferred Shares (i) 815,000 shares were issued in exchange for $40.75 million of our 2017 Notes, at an exchange rate of 20 Series A Preferred Shares for each $1,000 principal amount of 2017 Notes, and (ii) 106,000 shares were issued and sold for $5.3 million of cash to certain holders of the 2017 Notes. All of the Series A Preferred Shares were issued at a value of $50.00 per share. We used $4.3 million of the gross proceeds to redeem a portion of the remaining 2017 Notes on January 1, 2017. The remaining proceeds were used for general corporate purposes.outstanding. The Series A Preferred Shares contain a substantive conversion option, are mandatorily redeemable and convert into a fixed number of common shares. As a result, under U.S GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of ~~September 30, 2017,~~March 31, 2018, there were $21.3 million of Series A Preferred Shares and $24.8 million of Series A Preferred Shares – related party outstanding. ~~For the nine months ended September 30, 2017, we paid $4.6 million in dividends on the Series A Preferred Shares, which is recorded~~ ~~in our consolidated statements of comprehensive (loss) income under the caption~~ “Interest and other expense.” On October 2, 2017, we issued an aggregate of 2,591,384 common shares to holders of the Series A Preferred Shares as payment of the September 30, 2017 quarterly dividend on the Series A Preferred Shares (see Note 14. “Subsequent Events” to our consolidated financial statements). For information on the terms of the Series A Preferred Shares, see(See Note 3. “Series A Preferred Shares” ~~to our consolidated financial statements.~~)

Certain statements in this Quarterly Report on Form 10-Q constitute “forward-looking statements” within the meaning of applicable U.S. and Canadian securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “plans,” “expects,” “estimates,” “budgets,” “intends,” “anticipates,” “believes,” “projects,” “indicates,” “targets,” “objective,” “could,” “should,” “may” or other similar words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, but are not limited to, the following: our ability to access sufficient capital to fund our operations; fluctuations in and volatility of the market prices for oil and natural gas products; the ability to produce and transport oil and natural gas; the results of exploration and development drilling and related activities; global economic conditions, particularly in the countries in which we carry on business, especially economic slowdowns; actions by governmental authorities including increases in taxes, legislative and regulatory initiatives related to fracture stimulation activities, changes in environmental and other regulations and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflicts; the negotiation and closing of material contracts or sale of assets; future capital requirements and the availability of financing; estimates and economic assumptions used in connection with our acquisitions; risks associated with drilling, operating and decommissioning wells; actions of third-party co-owners of interests in properties in which we also own an interest; our ability to effectively integrate companies and properties that we acquire; and the other factors discussed in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”) and Canadian securities regulatory authorities. 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 and our course of action would depend upon our assessment of the future, considering all information then available. In that regard, any statements as to: future oil or natural gas production levels; capital expenditures; asset sales; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital expenditure programs or operations; drilling of new wells; marketing of joint venture transactions; demand for oil and natural gas 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, including the ability to convert probable and possible reserves to proved reserves; dates by which transactions are expected to close; future cash flows, uses of cash flows, collectability of receivables and availability of trade credit; expected operating costs; changes in any of the foregoing; and other statements using forward-looking terminology are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.

Readers should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law.

Our derivative contracts may expose us to credit risk in the event of nonperformance by our counterparty. ~~The lender under our Term Loan~~Denizbank is a counterparty to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty.

During the ~~third~~first quarter of ~~2017,~~2018, there were no material changes in market risk exposures or their management that would affect the Quantitative or Qualitative Disclosures About Market Risk disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2017. The following table sets forth our derivatives contracts, which are settled based on Brent oil pricing, with respect to future crude oil production as of ~~September 30, 2017:~~March 31, 2018:

Fair Value of Derivative Instruments as of September 30, 2017
Fair Value of Derivative Instruments as of March 31, 2018											Fair Value of Derivative Instruments as of March 31, 2018

				Weighted		Weighted									Weighted		Weighted
				Average		Average									Average		Average
		Quantity		Minimum		Maximum Price		Estimated Fair					Quantity		Minimum		Maximum Price		Additional Call		Estimated Fair
Type	Period	(Bbl/day)		Price (per Bbl)		(per Bbl)		Value of Liability				Period	(Bbl/day)		Price (per Bbl)		(per Bbl)		Ceiling		Value of Liability
								(in thousands)													(in thousands)
Collar	October 1, 2017 — December 31, 2017		293	$	47.50	$	61.00	$	(14	)		April 1, 2018 - May 31, 2018		295	$	47.50	$	61.00	$	-	$	(200	)
Collar	October 1, 2017 — December 31, 2017		440	$	50.00	$	61.50		(6	)		April 1, 2018 - June 30, 2018		742	$	47.50	$	57.10	$	-		(1,016	)
Collar	October 1, 2017 — December 31, 2017		489	$	47.00	$	59.65		(40	)		April 1, 2018 - December 31, 2018		442	$	55.00	$	70.00	$	-		(229	)
Collar	October 1, 2017 — December 31, 2017		734	$	47.50	$	57.10		(130	)		April 1, 2018 - December 31, 2018		491	$	56.00	$	70.00	$	84.00		(189	)
Collar	January 1, 2018 — February 28, 2018		458	$	50.00	$	61.50		(4	)
Collar	January 1, 2018 — March 31, 2018		500	$	47.00	$	59.65		(50	)
Collar	January 1, 2018 — May 31, 2018		298	$	47.50	$	61.00		(32	)
Collar	January 1, 2018 — June 30, 2018		746	$	47.50	$	57.10		(295	)
Total estimated fair value of liability								$	(571	)
Total Estimated Fair Value of Liability																					$	(1,633	)

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 principal accounting and financial officer, as appropriate to allow timely decisions regarding required disclosure.

As of ~~September 30, 2017,~~March 31, 2018, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and principal accounting and 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 principal accounting and financial officer concluded that, as of ~~September 30, 2017,~~March 31, 2018, 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.

There were no changes in our internal control over financial reporting that occurred during the quarter ended ~~September 30, 2017~~March 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

During the ~~third~~first quarter of ~~2017,~~2018, 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, ~~2016.~~2017.

During the ~~third~~first quarter of ~~2017,~~2018, there were no material changes to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2017.

~~On October 2, 2017, we issued an aggregate of 2,591,384 common to holders of the Series A Preferred Shares as payment of the~~ ~~September 30, 2017~~ quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of $0.7108 per common share, which was equal to the 15-day volume weighted average price through the close of trading of the common shares on the NYSE American on September 13, 2017.

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.

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)

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017	3

Consolidated Statements of Comprehensive (Loss) Income for the Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~	4

Consolidated Statement of Equity for the ~~Nine~~Three Months Ended ~~September 30, 2017~~March 31, 2018	5

Consolidated Statements of Cash Flows for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~	6

Notes to Consolidated Financial Statements	7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2223

Item 3. Quantitative and Qualitative Disclosures About Market Risk	3028

Item 4. Controls and Procedures	3128

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	3230

Item 1A. Risk Factors	3230

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	3230

Item 3. Defaults Upon Senior Securities	3230

Item 4. Mine Safety Disclosures	3230

Item 5. Other Information	3230

Item 6. Exhibits	3331


Period Commencing	Redemption Price
November 4, 2020	105.000%
November 4, 2021	103.000%
November 4, 2022	101.000%
November 4, 2023 and thereafter	100.000%

	Loss on Sale
	(in thousands)
Total cash proceeds for TBNG	$	20,707
Less: TBNG net assets		12,869
Gain on sale before accumulated foreign currency translation adjustment		7,838
Less: TBNG accumulated foreign currency translation adjustment		(23,064	)
Net loss on sale of TBNG	$	(15,226	)

	Three Months Ended
	March 31,		December 31,
	2018		2017
	(in thousands)
Disaggregation of revenue
Product type
Oil	$	16,324	$	15,827
Gas		337		298
Total revenue from customers	$	16,661	$	16,125

	Three Months Ended						Nine Months Ended
	September 30						September 30
(in thousands, except per share amounts)	2017			2016			2017			2016
Net (loss) income from continuing operations	$	(4,353	)	$	(4,636	)	$	(19,836	)	$	(16,746	)
Net income from discontinued operations	$	-		$	16,305		$	-		$	16,202
Basic net (loss) income per common share:
Shares:
Weighted average common shares outstanding		47,725			46,854			47,480			42,879
Basic net (loss) income per common share:
Continuing operations	$	(0.09	)	$	(0.10	)	$	(0.42	)	$	(0.39	)
Discontinued operations	$	(0.00	)	$	0.35		$	(0.00	)	$	0.38
Diluted net (loss) income per common share:
Shares:
Weighted average common shares outstanding		47,725			46,854			47,480			42,879
Dilutive effect of:
Restricted stock units		-			-			-			-
Weighted average common shares outstanding		47,725			46,854			47,480			42,879
Diluted net (loss) income per common share:
Continuing operations	$	(0.09	)	$	(0.10	)	$	(0.42	)	$	(0.39	)
Discontinued operations	$	(0.00	)	$	0.35		$	(0.00	)	$	0.38

	Held for Sale
	(in thousands)
For the year ended December 31, 2016
Assets
Cash	$	1,551
Other current assets		7,511
Property and equipment, net		16,155
Total current assets held for sale	$	25,217

Liabilities
Accounts payable and other accrued liabilities	$	11,240
Deferred tax liability		4,698
Total current liabilities held for sale	$	15,938

	Discontinued Operations
	(in thousands)
For the three months ended September, 2016
Total revenues	$	-
Production and transportation expense		-
Total other costs and expenses		(6,886	)
Income before income taxes	$	6,886
Gain on disposal of discontinued operations		9,419
Income tax benefit		-
Income from discontinued operations	$	16,305

For the nine months ended September, 2016
Total revenues	$	626
Production and transportation expense		1,155
Total other costs and expenses		(6,359	)
Income before income taxes	$	5,830
Gain on disposal of discontinued operations		10,168
Income tax benefit		204
Income from discontinued operations	$	16,202

	Nine Months Ended September 30,						Change
	2017			2016			2017-2016
	(in thousands of U.S. Dollars, except per unit amounts and volumes)
Sales volumes:
Oil (Mbbl)		858			1,024			(166	)
Natural gas (Mmcf)		308			1,152			(844	)
Total production (Mboe)		909			1,216			(307	)
Average daily sales volumes (Boepd)		3,331			4,437			(1,106	)
Average prices:
Oil (per Bbl)	$	45.42		$	37.20		$	8.22
Natural gas (per Mcf)	$	4.89		$	7.02		$	(2.13	)
Oil equivalent (per Boe)	$	44.51		$	37.98		$	6.53
Revenues:
Oil and natural gas sales	$	40,475		$	46,171		$	(5,696	)
Sales of purchased natural gas		654			3,717			(3,063	)
Other		323			35			288
Total revenues	$	41,452		$	49,923		$	(8,471	)
Costs and expenses (income):
Production	$	8,798		$	9,025		$	(227	)
Exploration, abandonment and impairment		249			2,964			(2,715	)
Cost of purchased natural gas		568			3,264			(2,696	)
Seismic and other exploration		3,046			84			2,962
General and administrative		9,303			11,401			(2,098	)
Depletion		12,330			21,745			(9,415	)
Depreciation and amortization		694			1,308			(614	)
Interest and other expense		6,981			9,106			(2,125	)
Interest and other income		(663	)		(1,411	)		748
Foreign exchange loss	$	1,055		$	659		$	396
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	32		$	4,188		$	(4,156	)
Change in fair value on commodity derivative contracts		267			(6,607	)		6,874
Total gain (loss) on commodity derivative contracts	$	299		$	(2,419	)	$	2,718
Oil and natural gas costs per Boe:
Production	$	8.43		$	6.50		$	1.93
Depletion	$	11.86		$	16.65		$	(4.79	)

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~~)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).

3.4						Certificate of Designations of 12.0% Series A Convertible Redeemable Preferred Shares of TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 31, 2016, filed with the SEC on November 4, 2016).

4.1						Amended and Restated Registration Rights Agreement, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Riata Management, LLC (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009).

4.2						Specimen Common Share certificate (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated March 4, 2014, filed with the SEC on March 6, 2014).

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

31.2*						Certification of the Principal Accounting and 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 Principal Accounting and Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of ~~2002~~.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.

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

By:		/s/ G. FABIAN ANDA
		G. Fabian Anda Principal Accounting and Financial Officer

Date: ~~November 8, 2017~~May 9, 2018

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