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,~~August 2, 2019, the registrant had ~~50,319,156~~55,044,534 common shares outstanding.

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, including the factors discussed under Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018. 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; 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; 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; 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.

							June 30, 2019			December 31, 2018
	September 30, 2017			December 31, 2016			(unaudited)
ASSETS	(unaudited)
Current assets:
Cash and cash equivalents	$	2,757		$	10,034		$	13,707		$	9,892
Restricted cash		–			2,555
Accounts receivable, net
Oil and natural gas sales		12,891			17,885			22,339			12,912
Joint interest and other		1,914			3,230			1,113			982
Related party		1,063			762			885			878
Prepaid and other current assets		2,557			4,756			11,431			8,696
Derivative asset								218			–
Note receivable - related party								–			5,828
Inventory		3,613			3,647			4,707			5,167
Assets held for sale		–			25,217
Total current assets		24,795			68,086			54,400			44,355
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		204,895			197,214			155,392			163,006
Unproved		25,730			21,109			17,486			15,695
Equipment and other property		19,399			20,273			12,918			14,408
		250,024			238,596			185,796			193,109
Less accumulated depreciation, depletion and amortization		(132,899	)		(120,638	)		(103,917	)		(105,850	)
Property and equipment, net		117,125			117,958			81,879			87,259
Other long-term assets:
Other assets		2,104			2,725			3,457			986
Note receivable - related party		7,027			7,624			4,451			–
Total other assets		9,131			10,349			7,908			986
Total assets	$	151,051		$	196,393		$	144,187		$	132,600
LIABILITIES, SERIES A PREFERRED SHARES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	3,518		$	7,036		$	6,554		$	3,896
Accounts payable - related party		4,363			1,844			3,007			2,922
Accrued liabilities		8,660			12,492			16,759			13,073
Derivative liability		571			596			651			–
Loans payable		12,375			34,750			19,772			22,000
Loan payable - related party		–			3,444
Liabilities held for sale		–			15,938
Total current liabilities		29,487			76,100			46,743			41,891
Long-term liabilities:
Asset retirement obligations		4,940			4,833			4,506			4,667
Accrued liabilities		9,138			8,126			9,667			7,259
Deferred income taxes		20,494			18,806			21,845			20,314
Loans payable		–			3,750			11,428			–
Derivative liability		–			242
Total long-term liabilities		34,572			35,757			47,446			32,240
Total liabilities		64,059			111,857			94,189			74,131
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 June 30, 2019 and December 31, 2018								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 June 30, 2019 and December 31, 2018								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, 200,000,000 shares authorized; 52,722,966 shares and 52,413,588 shares issued and outstanding as of June 30, 2019 and December 31, 2018, respectively								5,273			5,241
Treasury stock		(970	)		(970	)		(970	)		(970	)
Additional paid-in-capital		573,691			573,278			577,538			577,488
Accumulated other comprehensive loss		(118,488	)		(140,316	)		(146,663	)		(142,021	)
Accumulated deficit		(418,064	)		(398,228	)		(431,230	)		(427,319	)
Total shareholders' equity		40,942			38,486			3,948			12,419
Total liabilities, Series A preferred shares and shareholders' equity	$	151,051		$	196,393		$	144,187		$	132,600

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

	For the Three Months Ended						For the Nine Months Ended						For the Three Months Ended						For the Six Months Ended
	September 30,						September 30,						June 30,						June 30,
	2017			2016			2017			2016			2019			2018			2019			2018
Revenues:
Oil and natural gas sales	$	12,424		$	15,483		$	40,475		$	46,171		$	17,134		$	18,100		$	35,994		$	34,761
Sales of purchased natural gas		-			1,171			654			3,717
Other		251			5			323			35			81			98			262			363
Total revenues		12,675			16,659			41,452			49,923			17,215			18,198			36,256			35,124
Costs and expenses:
Production		2,997			3,070			8,798			9,025			2,712			2,804			5,214			5,673
Transportation and processing														1,221			1,138			2,540			2,331
Exploration, abandonment and impairment		141			1,531			249			2,964			666			191			5,779			231
Cost of purchased natural gas		-			1,027			568			3,264
Seismic and other exploration		2,966			3			3,046			84			108			59			185			218
General and administrative		2,532			2,659			9,303			11,401			2,690			3,786			5,744			7,123
Depreciation, depletion and amortization		4,272			7,280			13,024			23,053			3,442			3,276			7,158			7,735
Accretion of asset retirement obligations		49			97			144			285			49			43			101			89
Total costs and expenses		12,957			15,667			35,132			50,076			10,888			11,297			26,721			23,400
Operating (loss) income		(282	)		992			6,320			(153	)
Operating income														6,327			6,901			9,535			11,724
Other income (expense):
Loss on sale of TBNG		-			-			(15,226	)		-
Interest and other expense		(2,322	)		(3,836	)		(6,981	)		(9,106	)		(2,753	)		(2,091	)		(5,231	)		(4,873	)
Interest and other income		182			1,009			663			1,411			221			377			395			631
(Loss) gain on commodity derivative contracts		(1,365	)		(187	)		299			(2,419	)
Loss on derivative contracts														(323	)		(3,141	)		(433	)		(3,866	)
Foreign exchange loss		(48	)		(390	)		(1,055	)		(659	)		(115	)		(1,938	)		(1,388	)		(3,996	)
Total other expense		(3,553	)		(3,404	)		(22,300	)		(10,773	)		(2,970	)		(6,793	)		(6,657	)		(12,104	)
Loss from continuing operations before income taxes		(3,835	)		(2,412	)		(15,980	)		(10,926	)
Income (loss) from operations before income taxes														3,357			108			2,878			(380	)
Income tax expense		(518	)		(2,224	)		(3,856	)		(5,820	)		(3,366	)		(1,114	)		(6,789	)		(2,401	)
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														(9	)		(1,006	)		(3,911	)		(2,781	)
Other comprehensive loss:
Foreign currency translation adjustment		(1,223	)		(3,986	)		21,828			(3,277	)		(416	)		(9,109	)		(4,642	)		(11,452	)
Comprehensive (loss) income	$	(5,576	)	$	7,683		$	1,992		$	(3,821	)
Comprehensive loss													$	(425	)	$	(10,115	)	$	(8,553	)	$	(14,233	)

Net (loss) income per common share
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
Net loss per common share
Basic net loss per common share													$	(0.00	)	$	(0.02	)	$	(0.07	)	$	(0.06	)
Weighted average common shares outstanding		47,725			46,854			47,480			42,879			52,529			50,420			52,506			50,397
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
Diluted net loss per common share													$	(0.00	)	$	(0.02	)	$	(0.07	)	$	(0.06	)
Weighted average common and common equivalent shares outstanding		47,725			46,854			47,480			42,879			52,529			50,420			52,506			50,397

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

Consolidated Statement of Equity for the Three and Six Months Ended June 30, 2019 and 2018

															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
Balance at December 31, 2016		47,220		333		699	$	4,722	$	(970	)	$	573,278		$	(140,316	)	$	(398,228	)	$	38,486
Three months ended June 30, 2019																								Shares		Shares		Warrants			Shares		Stock			Capital			Loss			Deficit			Equity
Balance at March 31, 2019																									52,496		333		-		$	5,249	$	(970	)	$	577,493		$	(146,247	)	$	(431,221	)	$	4,304
Issuance of restricted stock units		508		-		-		51		-			(51	)		-			-			-			227		-		-			24		-			(24	)		-			-			-
Tax withholding on restricted stock units		-		-		-		-		-			(92	)		-			-			(92	)
Share-based compensation		-		-		-		-		-			556			-			-			556			-		-		-			-		-			77			-			-			77
Tax effect of restricted stock																									-		-		-			-		-			(8	)		-			-			(8	)
Foreign currency translation adjustment		-		-		-		-		-			-			21,828			-			21,828			-		-		-			-		-			-			(416	)		-			(416	)
Net loss		-		-		-		-		-			-			-			(19,836	)		(19,836	)		-		-		-			-		-			-			-			(9	)		(9	)
Balance at September 30, 2017		47,728		333		699	$	4,773	$	(970	)	$	573,691		$	(118,488	)	$	(418,064	)	$	40,942
Balance at June 30, 2019																									52,723		333		-		$	5,273	$	(970	)	$	577,538		$	(146,663	)	$	(431,230	)	$	3,948
Six Months Ended June 30, 2019
Balance at December 31, 2018																									52,413		333		-		$	5,241	$	(970	)	$	577,488		$	(142,021	)	$	(427,319	)	$	12,419
Issuance of restricted stock units																									310		-		-			32		-			(32	)		-			-			-
Share-based compensation																									-		-		-			-		-			179			-			-			179
Tax effect of restricted stock																									-		-		-			-		-			(97	)		-			-			(97	)
Foreign currency translation adjustment																									-		-		-			-		-			-			(4,642	)		-			(4,642	)
Net loss																									-		-		-			-		-			-			-			(3,911	)		(3,911	)
Balance at June 30, 2019																									52,723		333		-		$	5,273	$	(970	)	$	577,538		$	(146,663	)	$	(431,230	)	$	3,948
Three months ended June 30, 2018
Balance at March 31, 2018																									50,383		333		-		$	5,038	$	(970	)	$	575,506		$	(127,109	)	$	(423,878	)	$	28,587
Issuance of restricted stock units																									208		-		-			21		-			(21	)		-			-			-
Share-based compensation																									-		-		-			-		-			117			-			-			117
Tax effect of restricted stock																									-		-		-			-		-			(11	)		-			-			(11	)
Foreign currency translation adjustment																									-		-		-			-		-			-			(9,109	)		-			(9,109	)
Net loss																									-		-		-			-		-			-			-			(1,006	)		(1,006	)
Balance at June 30, 2018																									50,591		333		-		$	5,059	$	(970	)	$	575,591		$	(136,218	)	$	(424,884	)	$	18,578
Six Months Ended June 30, 2018
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																									272		-		-			27		-			(27	)		-			-			-
Share-based compensation																									-		-		-			-		-			218			-			-			218
Tax effect of restricted stock																									-		-		-			-		-			(11	)		-			-			(11	)
Foreign currency translation adjustment																									-		-		-			-		-			-			(11,452	)		-			(11,452	)
Net loss																									-		-		-			-		-			-			-			(2,781	)		(2,781	)
Balance at June 30, 2018																									50,591		333		-		$	5,059	$	(970	)	$	575,591		$	(136,218	)	$	(424,884	)	$	18,578

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

	For the Nine Months Ended						For the Six Months Ended
	September 30,						June 30,
	2017			2016			2019			2018
Operating activities:
Net loss	$	(19,836	)	$	(544	)	$	(3,911	)	$	(2,781	)
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			179			218
Foreign currency loss		434			593			3,011			6,928
(Gain) loss on commodity derivative contracts		(299	)		2,419
Cash settlement on commodity derivative contracts		32			4,188
Loss on sale of TBNG		15,226			–
Gain on derivative contracts								433			3,866
Cash settlement on derivative contracts								–			(3,199	)
Amortization on loan financing costs		72			1,015			21			21
Deferred income tax expense		2,780			1,239			3,713			1,431
Exploration, abandonment and impairment		249			2,964			5,779			231
Depreciation, depletion and amortization		13,024			23,053			7,158			7,735
Accretion of asset retirement obligations		144			285			101			89
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	)		(10,630	)		(4,971	)
Prepaid expenses and other assets		901			(1,528	)		(6,205	)		(4,558	)
Accounts payable and accrued liabilities		(4,592	)		6,892			10,973			7,224
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			10,622			12,234
Investing activities:
Additions to oil and natural gas properties		(14,317	)		(4,664	)		(15,538	)		(10,898	)
Additions to equipment and other properties		(366	)		(139	)		(188	)		(548	)
Restricted cash		1,776			6,398
Proceeds from asset sale		17,779			1,104
Net cash provided by investing activities		4,872			2,699
Net cash used in investing activities								(15,726	)		(11,446	)
Financing activities:
Issuance of common shares		-			1,658
Tax withholding on restricted share units		(92	)		(59	)		(97	)		(15	)
Note receivable - related party								1,000			–
Loan proceeds		-			30,076			20,000			10,000
Loan repayment		(26,350	)		(39,517	)		(10,800	)		(8,250	)
Loan repayment - related party		(3,219	)		-
Net cash used in financing activities		(29,661	)		(7,842	)
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
Net cash provided by financing activities								10,103			1,735
Effect of exchange rate on cash flows, cash equivalents, and restricted cash								(1,184	)		(4,104	)
Net increase (decrease) in cash, cash equivalents and restricted cash								3,815			(1,581	)
Cash, cash equivalents and restricted cash, beginning of period (1)								10,032			20,431
Cash, cash equivalents and restricted cash, end of period (2)							$	13,847		$	18,850
Supplemental disclosures:
Cash paid for interest	$	5,353		$	4,057		$	2,269		$	5,236
Cash paid for taxes	$	2,065		$	3,423		$	1,565		$	534
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 unaudited consolidated financial statements.

TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the ~~“Company”~~“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,~~August 2, 2019, 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~~We are a holding company with two operating segments – Turkey and Bulgaria. ~~Its~~Our assets consist of ~~its~~our ownership interests in subsidiaries that primarily own assets in Turkey and Bulgaria.

Our consolidated financial statements are expressed in U.S. Dollars (“USD”) 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~~USD unless otherwise indicated. The unaudited consolidated financial statements include accounts of the Company and its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. 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”).~~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.~~2018.

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 net cash proceeds of $16.1 million, effective as of March 31, 2016.

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 meet the requirements to classify its operations as discontinued as the sale was not considered a strategic shift in the Company’s operations. As such, TBNG’s results of operations are classified as continuing operations for all periods presented (See Note 13. “Assets and liabilities held for sale and discontinued operations”).

In ~~March~~February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) ~~2016-08, Revenue~~No. 2016-02, Leases (Topic 842), which establishes a new lease accounting model for leases. The most significant changes include the clarification of the definition of a lease, the requirement for lessees to recognize for all leases a right-of-use asset and a lease liability in the consolidated balance sheet, and additional quantitative and qualitative disclosures which are designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from ~~Contracts with Customers (Topic 606):~~ ~~Principal versus Agent Considerations (Reporting Revenue Gross versus Net)~~ ~~(“ASU 2016-08”). ASU 2016-08 does not change~~leases. Expenses are recognized in the ~~core principle~~consolidated statement of ~~Topic 606, but clarifies~~income in a manner similar to current accounting guidance. Lessor accounting under the ~~implementation guidance on principal versus agent considerations. ASU 2016-08~~new standard is substantially unchanged. The new standard became effective for ~~annual~~us beginning with the first quarter of 2019. We adopted the accounting standard using a prospective transition approach, which applied the provisions of the new guidance at the effective date without adjusting the comparative periods presented. We elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed us to carry forward the historical accounting relating to lease identification and ~~interim periods beginning after December 15, 2017.~~classification for existing leases upon adoption. We ~~are currently assessing~~also made an accounting policy election to keep leases with an initial term of twelve months or less off of the ~~potential impact~~consolidated balance sheet. On January 1, 2019, we recognized $2.7 million of ~~ASU 2016-08~~additional right-of-use assets and liabilities on our consolidated ~~financial statements and results of operations.~~

~~In April 2016, the FASB issued ASU 2016-10, Revenue from Contracts with Customers (Topic 606):~~ ~~Identifying Performance Obligations and Licensing~~ (“ASU 2016-10”). ASU 2016-10 does not change the core principle of Topic 606, but clarifies the following two aspects of Topic 606: identifying performance obligations and the licensing implementation guidance, while retaining the related principles for those areas. ASU 2016-10 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-10 on our consolidated financial statements and results of operations.balance sheet.

In June 2016, the FASB issued ASU ~~2016-13,~~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,~~May 2017, the FASB issued ASU ~~2016-15, Statement~~2017-09, Scope of ~~Cash Flows (Topic 230):~~ Modification Accounting~~Classification of Certain Cash Receipts and Cash Payments~~, which clarifies Topic 718, Compensation – Stock Compensation (“ASU ~~2016-15”~~2017-09”)~~. ASU 2016-15 reduces diversity in practice in how certain transactions are classified~~, such that an entity must apply modification accounting to changes in the ~~statement~~terms or conditions of ~~cash flows. The amendments in~~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 ~~2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement~~indicates that if the modification does not affect any of ~~zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation~~the inputs to the ~~effective interest rate~~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 ~~borrowing, contingent consideration payments made after~~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 ~~business combination, proceeds from~~liability instrument is the ~~settlement~~same as the classification of ~~insurance claims, proceeds from~~ the ~~settlement of corporate-owned life insurance policies, and distributions received from equity method investees.~~original award immediately before the modification. The ASU ~~2016-15~~ is effective for ~~annual and interim periods~~fiscal years beginning after December 15, 2017. We adopted ASU 2017-09 effective January 1, 2018. The adoption of this update had no impact our consolidated financial statements and results of operations.

In August 2017, the FASB issued ASU 2017-12, Derivatives and 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 certain aspects of hedge documentation and eliminates the requirement to recognize hedge ineffectiveness separately in income. The amendments in this ASU are ~~currently assessing~~effective for fiscal years beginning after December 15, 2018 and for interim periods therein. The Company adopted this standard effective January 1, 2019. The adoption of this update had no impact our consolidated financial statements and results of operations.

In June 2018, the ~~potential~~FASB issued ASU 2018-07, Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting. This update applied the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. This update is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. The Company adopted this standard effective January 1, 2019. The adoption of this update had no impact ~~of ASU 2016-15~~ on our consolidated financial statements and results of operations.

In November ~~2016,~~2018, the FASB issued ASU ~~2016-18, Statement~~2018-19, Codification Improvements to Topic 326, Financial Instruments-Credit Losses. This update clarifies that receivables arising from operating leases are not in scope 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. The amended guidancethis topic, but rather Topic 842, Leases. This update will be effective for ~~annual periods~~financial statements issued for fiscal years beginning after December 15, ~~2017. The amendments should~~2019, including interim periods within those fiscal years. This update will be applied ~~using~~through a ~~retrospective transition method~~cumulative-effect adjustment to ~~each~~retained earnings as of the beginning of the first reporting period ~~presented. Early~~in which the guidance is effective. The Company does not believe the adoption ~~is permitted for any entity in any interim or annual period. We are currently evaluating the potential~~of this standard will have an impact ~~of ASU 2016-18~~ on ~~our~~its consolidated financial ~~statements and results of operations.~~statements.

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.

~~On November 4, 2016,~~As of June 30, 2019 and 2018, 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~~U.S. GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of ~~September~~June 30, ~~2017,~~2019, 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 13. “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~~six months ended ~~September~~June 30, ~~2017,~~2019, we accrued $1.8$1.8 million and ~~$4.6~~$3.2 million, respectively, in dividends on the Series A Preferred Shares, which is recorded in our consolidated statements of operations and comprehensive (loss) income under the caption “Interest and other ~~expense.”~~expense”. Such amounts were paid in cash and in common shares. On ~~October~~July 2, ~~2017,~~2019, we issued an aggregate of ~~2,591,384~~2,321,568 common shares to holders of the Series A Preferred Shares as payment of the ~~September~~June 30, ~~2017~~2019 quarterly dividend on the Series A Preferred Shares (see Note 14. ~~“Subsequent Events”~~“Subsequent Events”).

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			June 30, 2019			December 31, 2018
	(in thousands)						(in thousands)
Oil and natural gas properties, proved:
Turkey	$	204,367		$	196,743		$	154,883		$	162,494
Bulgaria		528			471			509			512
Total oil and natural gas properties, proved		204,895			197,214			155,392			163,006
Oil and natural gas properties, unproved:
Turkey		25,730			21,109			17,486			14,965
Bulgaria								–			730
Total oil and natural gas properties, unproved		25,730			21,109			17,486			15,695
Gross oil and natural gas properties		230,625			218,323			172,878			178,701
Accumulated depletion		(126,923	)		(115,401	)		(98,704	)		(100,582	)
Net oil and natural gas properties	$	103,702		$	102,922		$	74,174		$	78,119

The decline in oil and natural gas properties during the six months ended June 30, 2019 was primarily driven by the devaluation of the New Turkish Lira (“TRY”) versus the USD. From December 31, 2018 to June 30, 2019, the TRY to the USD declined 9.4%. At June 30, 2019, the exchange rate was 5.7751 as compared to 5.2609 at December 31, 2018. For the ~~nine~~six months ended ~~September~~June 30, ~~2017, we recorded~~2019, foreign currency ~~translation adjustments, which increased proved~~translations reduced oil and natural gas properties and ~~decreased~~increased accumulated other comprehensive loss within shareholders’ equity on our consolidated balance sheet.

At ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016,~~2018, we excluded ~~$0.4~~$0.1 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~~June 30, ~~2017,~~2019, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included ~~$12.3~~$5.7 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~~$53.3 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,~~2018, the capitalized costs of our oil and natural gas properties included ~~$13.2~~$6.5 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~~June 30, ~~2017,~~2019 and 2018, we recorded $0.7 million of exploratory dry-hole costs and $0.2 million of impairment of proved properties and exploratory well costs, respectively, which are primarily measured using Level 3 inputs.

During the six months ended June 30, 2019 and 2018, we recorded $5.8 million of exploratory dry-hole costs and $0.2 million of impairment of proved properties and exploratory well costs, respectively, which are primarily measured using Level 3 inputs.

As of ~~September~~June 30, ~~2017, we had $3.9 million of~~2019, there were no exploratory well costs capitalized for the Pinar-1 well in Turkey, which we spud in March 2014. During the second 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.greater than one year.

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			June 30, 2019			December 31, 2018
	(in thousands)						(in thousands)
Other equipment							$	1,136		$	1,240
Land								137			149
Inventory	$	9,488		$	10,704			5,788			6,791
Gas gathering system and facilities								178			194
Vehicles								311			336
Leasehold improvements, office equipment and software		7,543			7,280			5,368			5,698
Vehicles		361			364
Other equipment		2,007			1,925
Gross equipment and other property		19,399			20,273			12,918			14,408
Accumulated depreciation		(5,976	)		(5,237	)		(5,213	)		(5,268	)
Net equipment and other property	$	13,423		$	15,036		$	7,705		$	9,140

At ~~September~~June 30, ~~2017,~~2019, in addition to the above, we have classified ~~$3.6~~$4.7 million of inventory as a current asset, which represents our expected inventory consumption induring the next twelve months. We classify our remaining 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~~June 30, ~~2017~~2019 and December 31, ~~2016,~~2018, we excluded ~~$13.1~~$10.5 million and ~~$14.4~~$12.0 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~~six months ended ~~September~~June 30, ~~2017~~2019 and for the year ended December 31, ~~2016:~~2018:

	September 30, 2017			December 31, 2016			June 30, 2019			December 31, 2018
	(in thousands)						(in thousands)
Asset retirement obligations at beginning of period	$	4,833		$	9,237		$	4,667		$	4,727
Change in estimates		–			(7	)
Liabilities settled		(37	)		–
Foreign exchange change effect		–			(1,604	)		(371	)		(1,270	)
Additions		–			16			109			1,036
Accretion expense		144			373			101			174
Asset retirement obligations at end of period		4,940			8,015		$	4,506		$	4,667
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~~ derivative ~~contracts~~instruments to ~~economically hedge against the variability in cash flows associated~~manage certain risks related to commodity prices and foreign currency exchange rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by our senior management. We do not hold any derivatives for speculative purposes and do not use derivatives with ~~the forecasted sale of a portion of our future oil production.~~leveraged or complex features. 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 operations and comprehensive (loss) income under the caption ~~“(Loss) gain~~“Loss 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~~At June 30, 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 million and a net loss of $2.4 million, respectively.

~~At September 30, 2017 and December 31, 2016,~~2019, we had outstanding derivative contracts with respect to our future crude oil production as set forth in the ~~tables~~table 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 Commodity Derivative Instruments as of June 30, 2019

Weighted

Average

Quantity

Minimum

Maximum Price

Additional Call

Estimated Fair

Type

Period

(Bbl/day)

Price (per Bbl)

(per Bbl)

Ceiling

Value of Asset

(in thousands)

Three-way collar

July 1, 2019 - April 30, 2020

1,000

55.00

72.90

80.00

218

Total Estimated Fair Value of Asset

218

As of December 31, 2018, we had no outstanding derivative contracts with respect to our future crude oil production.

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 foreign exchange derivative contracts are settled based upon the contract rate. We recognize gains and losses related to these contracts on a fair value basis in our consolidated statements of operations and comprehensive (loss) income under the caption “Loss on derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on derivative contracts.”

At June 30, 2019, we had outstanding foreign exchange derivative contracts as set forth in the table below:

Fair Value of Foreign Exchange Derivative Instruments as of June 30, 2019



						Buy			Sell		Estimated Fair
Type	Buy/Sell	Rate		Settlement Date	Buy Currency	Currency Amount		Sell Currency	Currency Amount		Value of Asset (Liability)
											(in thousands)
FXOPT	Buy		5.750	07/01/19	TRY		8,625,000	USD		1,500,000		11
FXOPT	Sell		5.750	07/01/19	USD		2,250,000	TRY		12,937,500		(2	)
FXOPT	Sell		5.750	07/01/19	TRY		8,625,000	USD		1,500,000		(11	)
FXOPT	Buy		5.750	07/01/19	USD		2,250,000	TRY		12,937,500		2
FXOPT	Buy		6.030	07/01/19	TRY		9,045,000	USD		1,500,000		-
FXOPT	Sell		6.030	07/01/19	USD		2,250,000	TRY		13,567,500		(95	)
FXOPT	Buy		5.870	09/03/19	USD		1,500,000	TRY		8,805,000		(52	)
FXOPT	Buy		6.090	10/28/19	USD		1,400,000	TRY		8,526,000		(504	)
Total Estimated Fair Value of Liability											$	(651	)

During the three months ended June 30, 2019 and 2018, we recorded a net loss on derivative contracts of $0.3 million and $3.1 million, respectively. During the six months ended June 30, 2019 and 2018, we recorded a net loss on derivative contracts of $0.4 million and $3.9 million, respectively.

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~~June 30, ~~2017 and December 31, 2016,~~2019, and (ii) the net recorded fair value as reflected on our consolidated balance ~~sheets~~sheet at ~~September~~June 30, ~~2017 and December 31, 2016.~~2019.

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 (the “2016 Term Loan”) with TEMI 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 prior senior credit facility in full.~~

~~The Term Loan bears~~bore 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~~remained unchanged.Amounts repaid under the 2016 Term Loan could not be re-borrowed and early repayments under the 2016 Term Loan were subject to early repayment fees.

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

The 2016 Term Loan contained 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 prohibited 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 included, 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 was 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) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim ve Ticaret A.S. (“Gundem Yatirim”), and (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell 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 Yatirim 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 executive vice president, Turkey.

On June 28, 2018, we repaid the 2016 Term Loan in full in accordance with its terms.

On November 17, 2017, DenizBank entered into a $20.4 million term loan (the “2017 Term Loan”) with TEMI under the Credit Agreement.

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 had a grace period which bore no interest or payments due until July 2018. Thereafter, the 2017 Term Loan 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 Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.

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.

At ~~September~~June 30, ~~2017,~~2019, we had ~~$12.4~~$6.2 million outstanding under the 2017 Term Loan and no availability, and we were in compliance with ~~all of~~ 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.

On ~~December 30, 2015, TransAtlantic Petroleum (USA) Corp (“TransAtlantic USA”)~~May 28, 2018, DenizBank entered into a ~~$5.0~~$10.0 million ~~draw down convertible promissory note~~term loan (the ~~“Note”~~“2018 Term Loan”) with ~~ANBE Holdings, L.P. (“ANBE”), an entity~~TEMI under the Credit Agreement.

The 2018 Term Loan bears interest at a fixed rate of 7.25% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2018 Term Loan had a grace period through July 2018 during which no payments were due. Thereafter, accrued interest on the 2018 Term Loan is payable monthly and the principal on the 2018 Term Loan is payable in five monthly installments of $0.2 million each through December 2018, four monthly installments of $0.5 million each through April 2019, four monthly installments of $1.0 million each through August 2019, and four monthly installments of $0.75 million each through December 2019. The 2018 Term Loan matures in December 2019. Amounts repaid under the 2018 Term Loan may not be reborrowed, and early repayments under the 2018 Term Loan are subject to early repayment fees. The 2018 Term Loan is guaranteed by Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.

The 2018 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on encumbering or creating restrictions or limitations on all or a part of its assets, revenues, or properties, giving guaranties or sureties, selling assets or transferring revenues, dissolving, liquidating, merging, or consolidating, incurring additional debt, paying dividends, making certain investments, undergoing a change of control, and other similar matters. In addition, the 2018 Term Loan prohibits Amity, Talon Exploration, DMLP, and TransAtlantic Turkey from incurring additional debt. An event of default under the 2018 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 2018 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 ~~the adult children of the Company’s chairman~~Petrogas, (iv) certain Gundem real estate and ~~chief executive officer, N. Malone Mitchell 3rd, and controlled~~Muratli real estate owned by ~~an entity managed~~Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% 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 borrowed $3.6 million under the ANBE Note (the “Initial Advance”). The Initial Advance was used for general corporate purposes. On February 27, 2017, we repaid the ANBE Note in full with proceeds20% by Mr. 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 ~~TBNG~~oil to DenizBank as additional security for the 2018 Term Loan.

At June 30, 2019, we had $5.0 million outstanding under the 2018 Term Loan and ~~terminated it.~~no availability, and we were in compliance with the covenants in the 2018 Term Loan.

On February 22, 2019, DenizBank entered into a $20.0 million term loan (the “2019 Term Loan”) with TEMI under the Credit Agreement.

The 2019 Term Loan bears interest at a fixed rate of 7.5% (plus 0.375% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2019 Term Loan has a grace period through December 2019 during which no payments are due. Thereafter, accrued interest on the 2019 Term Loan is payable monthly, and the principal on the 2019 Term Loan is payable in 14 monthly installments of $1.4 million each. The 2019 Term Loan matures in February 2021. Amounts repaid under the 2019 Term Loan may not be reborrowed, and early repayments under the 2019 Term Loan are subject to early repayment fees. The 2019 Term Loan is guaranteed by Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.

The 2019 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on encumbering or creating restrictions or limitations on all or a part of its assets, revenues, or properties, giving guaranties or sureties, selling assets or transferring revenues, dissolving, liquidating, merging, or consolidating, incurring additional debt, paying dividends, making certain investments, undergoing a change of control, and other similar matters. In addition, the 2019 Term Loan prohibits Amity, Talon Exploration, DMLP, and TransAtlantic Turkey from incurring additional debt. An event of default under the 2019 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 2019 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) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. 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 2019 Term Loan.

At June 30, 2019, we had $20.0 million outstanding under the 2019 Term Loan and no availability, and we were in compliance with the covenants in the 2019 Term Loan.

Our wholly-owned subsidiaries operating in Turkey are party to unsecured, non-interest bearing lines of credit with a Turkish bank. At ~~September~~June 30, ~~2017,~~2019, we had no outstanding borrowings under these lines of credit.

We lease office space in Dallas, Texas, Bulgaria, and Turkey. We also lease apartments, vehicles, and operations yards in Turkey. The terms of our lease agreements generally range from one to five years, and some contain options to renew or cancel. We determine if an arrangement meets the definition of a lease at inception, at which time we also perform an analysis to determine whether the lease qualifies as an operating or financing lease. We currently do not have any financing leases.

Operating leases are included in prepaid and other current assets and other assets and accrued liabilities (current and long-term) on our consolidated balance sheet. Lease expense for our operating leases is recognized in our consolidated statements of operations and comprehensive (loss) income under the caption “General and administrative”. Lease expense for our operating leases for our operations yards in Turkey is recognized in our consolidated statements of operations and comprehensive (loss) income under the caption “Production”.

Lease right-of-use assets and lease liabilities are measured using the present value of future minimum lease payments over the lease term at commencement date. The right-of-use asset also includes any lease payments made on or before the commencement date of the lease, less any lease incentives received. As the rate implicit in the lease is not readily determinable in our leases, we use our incremental borrowing rates based on the information available at the lease commencement date in determining the present value of lease payments.

For leases with an initial non-cancelable lease term of less than one year and no option to purchase, we have elected not to recognize the lease on our consolidated balance sheets and instead recognize lease payments on a straight-line basis over the lease term.

Future non-cancelable minimum lease payments under our operating lease commitments as of June 30, 2019 were as follows for each of the next five years and thereafter:

As of June 30, 2019, the weighted average remaining lease term in years is 4.0 years and the weighted average discount rate used was 7.55%.

Future non-cancelable minimum lease payments under our operating lease commitments as of December 31, 2018 were as follows for each of the next five years and thereafter:

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 Bulgarian 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~~Minister of Energy ~~and Economy~~ filed a suit in the Sofia City Court against ~~our subsidiary,~~ Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”), claiming a $200,000 ~~penalty~~in liquidated damages for Direct Bulgaria’s alleged failure to fulfill ~~the work program associated with~~its obligations under the Aglen exploration ~~permit.~~permit work program. In May 2018, the Sofia City Court concluded that Direct Bulgaria did not fail to fulfill its obligations under the Aglen exploration permit work program as Direct Bulgaria received a force majeure event recognition as a result of a fracture stimulation ban in 2012, ~~from~~imposed by the Bulgarian ~~Ministry~~Parliament, which force majeure event had not been terminated before the expiry of Direct Bulgaria’s obligations under the Aglen exploration permit work program. Additionally, the Sofia City Court concluded that, even if Direct Bulgaria had failed to fulfill its obligations under the Aglen exploration permit work program, the Bulgarian Minister of Energy failed to file suit within the three-year limitation period. Therefore, the Sofia City Court dismissed all claims of the Bulgarian Minister of Energy and ~~Economy,~~ordered the Bulgarian Minister of Energy to pay Direct Bulgaria’s attorney’s fees and legal costs for court experts. In June 2018, the ~~force majeure event has not been rectified.~~Bulgarian Minister of Energy filed an appeal in the Sofia Court of Appeal. In November 2018, the Sofia Court of Appeal concluded that the judgement of the Sofia City Court was correct and, therefore, dismissed the Bulgarian Minister of Energy’s appeal. In January 2019, the Bulgarian Minister of Energy filed an appeal in the Supreme Court of Cassation. 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 against this claim.

14As a result of the judgement of the Sofia Court of Appeal, we are currently evaluating an adjustment to our contingencies relating to production leases and exploration permits.

We recorded share-based compensation expense of $0.1 million for awards of restricted stock units (“RSUs”) for each of the three months ended ~~September~~June 30, ~~2017~~2019 and ~~2016.~~2018. We recorded share-based compensation expense ~~$0.6 million and $0.5~~of $0.2 million for awards of RSUs for each of the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016, respectively.~~2018.

As of ~~September~~June 30, ~~2017,~~2019, 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~~1.6 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~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 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~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 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 and preferred shares, ~~and warrants,~~ whether exercisable or not. For the ~~nine~~three and six months ended ~~September~~June 30, ~~2017,~~2019, 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:

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

Corporate

Turkey

Bulgaria

Total

(in thousands)

For the three months ended 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

Total revenues
$
-

$
16,659

$
-

$
16,659

(Loss) income from continuing operations before income taxes

(3,102
)

734

(44
)

(2,412
)
Capital expenditures
$
-

$
1,484

$
-

$
1,484

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

Total revenues
$
-

$
49,923

$
-

$
49,923

(Loss) income from continuing operations before income taxes

(12,092
)

1,413

(247
)

(10,926
)
Capital expenditures
$
-

$
4,675

$
-

$
4,675

Segment assets

September 30, 2017
$
9,905

$
140,509

$
637

$
151,051

December 31, 2016 (1)
$
17,007

$
153,560

$
609

$
171,176

	Corporate			Turkey		Bulgaria			Total
	(in thousands)
For the three months ended June 30, 2019
Total revenues	$	-		$	17,215	$	-		$	17,215
(Loss) income from operations before income taxes		(2,667	)		6,756		(732	)		3,357
Capital expenditures	$	-		$	5,509	$	667		$	6,176
For the three months ended June 30, 2018
Total revenues	$	-		$	18,198	$	-		$	18,198
(Loss) income from operations before income taxes		(4,429	)		4,612		(75	)		108
Capital expenditures	$	-		$	5,625	$	-		$	5,625
For the six months ended June 30, 2019
Total revenues	$	-		$	36,256	$	-		$	36,256
(Loss) income from operations before income taxes		(5,540	)		14,372		(5,954	)		2,878
Capital expenditures	$	-		$	10,728	$	5,050		$	15,778
For the six months ended June 30, 2018
Total revenues	$	-		$	35,124	$	-		$	35,124
(Loss) income from operations before income taxes		(8,222	)		7,963		(121	)		(380	)
Capital expenditures	$	-		$	10,835	$	-		$	10,835
Segment assets
June 30, 2019	$	6,674		$	136,363	$	1,150		$	144,187
December 31, 2018	$	8,358		$	122,325	$	1,917		$	132,600

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 ~~Turkish Lira (“TRY”).~~the 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~~USD reporting currency. ~~We have not used foreign currency forward contracts to manage exchange rate fluctuations.~~ At ~~September~~June 30, ~~2017,~~2019, we had ~~5.4~~1.0 million TRY (approximately ~~$1.5~~$0.2 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY. At June 30, 2019, we were a party to foreign exchange derivative contracts (See Note 6. “Derivative instruments”).

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~~June 30, ~~2017 and December 31, 2016,~~2019, we were a party to commodity derivative contracts (See Note 6. ~~“Commodity~~“Derivative instruments”). At December 31, 2018, we were not party to any commodity derivative ~~instruments”).~~contracts.

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~~four 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 June 30, 2019 and December 31, 2018, due to the short maturity of those instruments.

The following table summarizes the valuation of our financial assets and liabilities as of ~~September~~June 30, ~~2017:~~2019:

	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
Assets:
Commodity derivative contracts												$	-	$	218		$	-		$	218
Liabilities:
Commodity derivative contracts	$	–	$	(571	)	$	–		$	(571	)
Foreign exchange derivative contracts												$	-	$	(651	)	$	-		$	(651	)
Disclosed but not carried at fair value
Liabilities:
Term Loan		-		-			(11,563	)		(11,563	)
2019 Term Loan													-		-			(16,651	)		(16,651	)
2018 Term Loan													-		-			(4,781	)		(4,781	)
2017 Term Loan													-		-			(5,910	)		(5,910	)
Total	$	–	$	(571	)	$	(11,563	)	$	(12,134	)	$	-	$	-		$	(27,342	)	$	(27,342	)

The following table summarizes the valuation of our financial assets and liabilities as of December 31, ~~2016:~~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	$	–	$	(838	)	$	–		$	(838	)
Disclosed but not carried at fair value
Liabilities:
Term Loan		-		-			(22,500	)		(22,500	)
2017 Notes		-		-			(13,554	)		(13,554	)
2018 Term Loan													-		-		(8,192	)		(8,192	)
2017 Term Loan													-		-		(11,938	)		(11,938	)
Total	$	–	$	(838	)	$	(36,054	)	$	(36,892	)	$	-	$	-	$	(20,130	)	$	(20,130	)

We remeasure our derivative contracts on a recurring basis, with changes flowing through earnings. At ~~September~~June 30, ~~2017~~2019 and December 31, ~~2016,~~2018, the fair values of ~~our~~the 2019 Term Loan, the 2018 Term Loan, and the 2017 ~~Notes~~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:

~~On March 20, 2017, the Company entered into~~We are a ~~second amendment~~party to ~~the~~a Service Agreement ~~among~~(as amended, the ~~Company and~~“Service Agreement”) with Longfellow Energy, LP ~~a Texas limited partnership~~ (“Longfellow”), Viking Drilling, LLC ~~a Nevada limited liability company, RIATA~~(“Viking Drilling”), Riata Management, LLC ~~an Oklahoma limited liability company, Longfellow Nemaha,~~(“Riata”), LFN Holdco LLC ~~a Texas limited liability company,~~(“LFN”), Red Rock Minerals, LP ~~a Delaware limited partnership,~~(“RRM”), Red Rock Minerals II, LP (“RRM II”), Red Rock Advisors, LLC ~~a Texas limited liability company,~~(“RRA”), Production Solutions International Limited ~~a Bermuda exempted company,~~(“PSIL”), and ~~Nexlube~~NexLube Operating, LLC ~~a Delaware limited liability company,~~(“NexLube”) and their subsidiaries (collectively, the “Riata Entities”), ~~adding~~under which we and ~~removing certain of~~ the Riata Entities agreed to provide technical and ~~expanding~~administrative services to each other from time to time on an as-needed basis. Under the ~~scope of services. Because this agreement is a related party transaction, the independent members~~terms of the ~~Board~~Service Agreement, the Riata Entities agree to provide us upon our request certain computer services, payroll and benefits services, insurance administration services, and entertainment services, and we and the Riata Entities agree 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 ~~Directors reviewed and approved this amendment.~~ 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. We or any Riata Entity may terminate the Service Agreement at any time by providing advance notice of termination to the other parties.

As of ~~September~~June 30, ~~2017, the Company~~2019, 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 is owned and operated by Production Solutions International Petrol Arama Hizmetleri Anonim Sirketi (“~~PSIL”~~PSI”). PSI is beneficially owned by PSIL, which 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~~“PSI MSA”) with ~~PSIL~~PSI on substantially similar terms to our then current master services agreements with Viking International, VOS, and Viking Geophysical. Pursuant to the ~~PSIL~~PSI MSA, ~~PSIL~~PSI performs the ~~Services~~services on behalf of TEMI and its affiliates. On February 28, 2019, TEMI and PSI entered into an amendment (the “PSI MSA Amendment”) to the PSI MSA, pursuant to which PSI and TEMI agreed to extend the primary term of the PSI MSA to February 26, 2021, with automatic successive renewal terms of one (1) year each, unless terminated by PSI or TEMI by written notice at least sixty (60) days prior to the end of the primary term or any successive renewal term. 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~~June 30, ~~2017, the Company~~2019, we had $~~0.3~~$0.4 million of outstanding receivables and $3.0$1.6 million of outstanding payables pursuant to the ~~PSIL~~PSI MSA.

On ~~February 27,~~August 7, 2018 and effective as of June 14, 2018, TransAtlantic USA entered into a sublease agreement (the “Sublease”) with Longfellow to lease corporate office space located at 16803 North Dallas Parkway, Addison, Texas. The Sublease was approved by the audit committee of the board of directors.

TransAtlantic USA subleases approximately 10,000 square feet of corporate office space in Addison, Texas. The initial lease term under the Sublease commenced on June 14, 2018 (the “Commencement Date”) and expires on June 30, 2020, unless earlier terminated in accordance with the Sublease. From the Commencement Date until June 30, 2019, TransAtlantic USA was required to pay monthly rent of $18,333.33 to Longfellow, plus utilities, real property taxes, and liability insurance (to the extent that TransAtlantic USA does not obtain its own liability insurance). The monthly rent increases by $416.67 for the period commencing June 30, 2019 and ending June 30, 2021.

Pursuant to the Sublease, effective as of June 14, 2018, TransAtlantic USA and Longfellow agreed to terminate the Amended and Restated Office Lease, dated June 26, 2017, by and between TransAtlantic USA and Longfellow.

On July 2, 2019, we ~~repaid~~issued an aggregate of 2,321,568 common shares to holders of the ~~ANBE~~Series A Preferred Shares as payment of the June 30, 2019 quarterly dividend on the Series A Preferred Shares (see Note ~~in full with proceeds from~~14. “Subsequent Events”). Of the 2,321,568 common shares, 1,036,010 common shares were issued to Dalea, Longfellow, and the trusts of Mr. Mitchell’s four adult children.

On June 13, 2012, we closed the sale of ~~TBNG~~our oilfield services business, which was substantially comprised of our wholly owned subsidiaries, Viking International and ~~terminated it.~~

Viking Geophysical, to a joint venture owned by Dalea ~~Amended Note~~Partners, LP (“Dalea”) and ~~Pledge Agreement~~funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $168.5 million, consisting of approximately $157.0 million in cash and a $11.5 million promissory note from Dalea (the “Original Note”). The promissory note bore interest at a rate of 3.0% per annum and was guaranteed by Mr. Mitchell. The promissory note was payable five years from the date of issuance or earlier upon the occurrence of certain specified events.

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”), aour former subsidiary, ~~of the Company,~~ to Viking ~~International Limited.~~ International.

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 PSI MSA. PSI is beneficially owned by PSIL, ~~MSA. PSIL~~which 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~~PSI to less than 50%; (ii) the sale or transfer by Dalea or ~~PSIL~~PSI of all or substantially all of its assets to any person (a “Transferee”) that does not own a controlling interest in Dalea or ~~PSIL~~PSI 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;~~PSI; (iv) termination of the ~~PSIL~~PSI MSA other than as a result of an uncured default thereunder by TEMI; (v) default by ~~PSIL~~PSI under the ~~PSIL~~PSI MSA, which default is not remedied within a period of 30 days after notice thereof to ~~PSIL;~~PSI; and (vi) insolvency or bankruptcy of ~~PSIL. The maturity date of the Amended Note was extended to June 13, 2019.~~PSI. 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. On February 28, 2019, we and Dalea entered into an amendment (the “Note Amendment”) to the Amended Note (as amended by the Note Amendment, the “Note”), pursuant to which we and Dalea agreed to extend the maturity date of the Note to February 26, 2021 (unless otherwise accelerated in accordance with the terms of the Note).

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 Company’s 13.0% Senior Convertible Notes due 2017 ~~Notes issued by us and~~(“Convertible Notes”) 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~~contains customary events of default. On November 4, 2016, Dalea exchanged $2.0 million of Convertible Notes for 40,000 Series A Preferred Shares.

On June 28, 2019, we and Dalea entered into an amendment to the Pledge Agreement, pursuant to which we and Dalea agreed that any interest payable toon the Series A Preferred Shares held by Dalea and pledged under the ~~Dalea Convertible Notes (or any future securities for which the Dalea Convertible Notes are converted or exchanged)~~Pledge Agreement (i) if paid in cash, 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~~Note, and (ii) if paid other than in cash, will be paid to Dalea and, within five business days of ~~default.~~

~~On November 4, 2016,~~such payment to Dalea, ~~exchanged $2.0 million of 2017 Notes for 40,000 Series A Preferred Shares, which were pledged as security for~~Dalea will pay $61,500 toward the ~~performance of Dalea’s obligations under the Amended Note pursuant to the terms~~principal and, upon full repayment of the ~~Pledge Agreement.~~ outstanding principal balance of the Note, any accrued and unpaid interest on the Note.

During ~~nine~~the six months ended ~~September~~June 30, ~~2017,~~2019, we reduced the principal amount of the ~~Amended~~ Note by $~~0.1~~$1.0 million for amounts prepaid by Dalea on February 28, 2019 in conjunction with the Note Amendment and by $0.1 million for cash dividends paid on the Series A Preferred Shares.

In connection with the pledge of ~~the~~certain 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~~with Gundem Turizm Yatirim ve Isletme A.S., predecessor-in-interest to ~~which~~Gundem Yatirim with respect to the ~~Company pays~~ Gundem real estate and Muratli real estate pledged as collateral for the Term Loans (“Gundem”). Pursuant to the Gundem Fee Agreement, we pay Gundem Yatirim a fee equal to 5% per annum of the collateral value of the Gundem real estate and Muratli real ~~estate.~~estate pledged as collateral for the Term Loans. 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 Mr. 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~~six months ended ~~September~~June 30, ~~2017,~~2019, we reduced the principal amount of the ~~Amended~~ Note by $~~0.2~~$0.3 million ~~and $0~~.5 ~~million, respectively,~~ for amounts ~~payable~~paid 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~~July 2, ~~2017,~~2019, 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”) for the sale of all of the equity interests in TBNG, our wholly-owned subsidiary. TBNG owned a portion of the Company’s 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 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 to a $0.2 million reduction to the purchase price, and, on April 10, 2017, we collected $2.9 million of the escrowed funds.

For the nine months ended September 30, 2017, we recorded a 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 presented below:

~~Our assets and liabilities held for sale at December 31, 2016 were as follows:~~

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 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, 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 operating results from discontinued operations for the three and nine months ended September 30, 2016 are summarized as follows:~~

~~On October 2, 2017, we issued an aggregate of 2,591,384~~2,321,568 common shares to holders of the Series A Preferred Shares as payment of the ~~September~~June 30, ~~2017~~2019 quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of ~~$0.7108~~$0.7934 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.~~June 14, 2019.

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.~~USD.

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~~June 30, ~~2017,~~2019, we held interests in ~~approximately 0.5 million~~373,948 and 162,500 net acres of developed and undeveloped oil and natural gas properties in Turkey and ~~Bulgaria.~~Bulgaria, respectively. As of ~~November 6, 2017,~~August 2, 2019, 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.

~~A summary of~~The following summarizes our financial and operational performance for the ~~third~~second quarter of ~~2017 include:~~2019:

During the second quarter of 2019, we spud three wells and continued workover and recompletion production optimizations in southeastern Turkey.

Yeniev Field. Both the Yeniev-1 and West Yeniev-1 wells continue flowing naturally from the Bedinan formation with little water.

The East Yeniev-1 well was put on production in the first quarter of 2019 and completed in the Mardin formation.

In the second quarter of 2019, we drilled the Yeniev-4 well to a total measured depth of 9,520 feet targeting the Bedinan, Hazro, and Mardin formations. We successfully recovered approximately 120 feet of core from the Bedinan sandstone, which is currently undergoing analysis to assist in infill development planning and secondary recovery evaluation. We plan to commence completion operations in the third quarter of ~~2017, we~~2019.

We plan to spud the Yeniev-5 and Yeniev-6 wells in the third and fourth quarter of 2019, respectively, to test the Mardin, Hazro, and Bedinan formations. We expect to core approximately 150 feet of the Mardin formation in the Yeniev-5 well to assist in infill development planning and secondary recovery evaluation.

Bahar Field. The Southeast Bahar-1 well was drilled to a total measured depth of 11,000 feet in the second quarter of 2019. Oil shows were observed in the Bedinan and Mardin formations, and oil was swab tested from the Bedinan formation. Completion operations are currently ongoing.

We commenced drilling the Bahar-12 well in July 2019 targeting the Bedinan and Hazro formations. We successfully recovered approximately 150 feet of core from the Hazro formation and expect to core the well in the Bedinan formation to further ~~developed~~assist in infill development planning and secondary recovery evaluation for the Bahar field.

Blackeye Field. The Blackeye-1 well continues to produce at a stable rate with low water cut from the Hazro F4 formation. We are evaluating testing additional formations within the well and drilling additional appraisal wells to develop the field.

During the second quarter of 2019, our ~~oil fields~~application for conversion of the New Molla exploration license into a production lease was approved.

Pinar Field. We plan to stimulate the Pinar-1 side-track well in ~~Southeastern Turkey, where we tested three wells. The following summarizes our operations by location during~~ the third quarter of ~~2017:~~2019. The well is currently producing commercial oil with low productivity from the Bedinan formation.

~~Testing continued on the Bahar-11 well throughout~~Bati-Yasince Field. In the third quarter of ~~2017 in~~2019, we plan to re-enter the ~~Bedinan, Dadas,~~Bati-Yasince-1 well and deepen the well to the Hazro formations. Commercial oil was discovered in all three formations with a combined test rate of 280 barrels of oil per day (“Bopd”). The well was brought on production at a commingled rate of 140 Bopd.formation.

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~~Arpatepe Field. In the third quarter of ~~2017 due~~2019, we plan to ~~priority repair~~recomplete the Arpatepe-2 well as a water injection well and ~~maintenance workover operations~~execute the first phase of a water-flood of the Arpatepe field. Subject to the results of the initial phase, we intend to expand to full-field flooding in the ~~Bahar~~future.

During the second quarter of 2019, we have continued a recompletion, workover, and ~~Selmo fields. Testing will resume~~production optimization campaign in the ~~fourth quarter of 2017.~~Selmo field.

We continue to evaluate our ~~position~~prospects in ~~Bulgaria~~the Thrace Basin’s Basin Center Gas Accumulation (“Thrace Basin BCGA”) in light of the recent exploration activity by Valeura Energy Inc. (“Valeura”) with ~~updated geologic models~~its partner Equinor ASA (formerly Statoil ASA) (“Equinor”) on a license 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 in the Thrace Basin BCGA.

In the second quarter of 2019, we drilled the Karli-1 well to a total measured depth of 1,289 feet and ~~continue~~encountered several shallow gas sand intervals. We are currently evaluating completion options.

Valeura and Equinor. According to ~~market~~Valeura and Equinor, in the third quarter of 2018 the Yamalik-1 well was recompleted and was flowing gas, condensate, and water. In the second quarter of 2019, Valeura and Equinor announced that they are developing a ~~joint venture exploration program for our assets~~plan to re-enter the well in order to isolate a portion of the column to conduct further selective zonal flow testing.

In the first quarter of 2019, Valeura and Equinor announced that the Inanli-1 well was drilled to a total depth of 4,885 meters and encountered 1,615 meters of high net-to-gross sandstone, which they interpreted to contain over-pressured gas. According to Valeura and Equinor, completion operations are ongoing.

In the second quarter of 2019, Valeura and Equinor announced that they drilled the Devepinar-1 appraisal well to a total depth of 4,796 meters after drilling a 1,066-meter gross column of indicated over-pressured gas. According to Valeura and Equinor, the Devepinar-1 appraisal well is designed as a 20-kilometer step-out well to test the lateral extent of the Thrace Basin BCGA.

~~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~~2019 to range between ~~$3.0~~$10.0 million and ~~$4.5~~$15.0 million. We expect net field capital expenditures during the remainder ~~2017~~of 2019 to include between ~~$0.5~~$9.0 million and $14.0 million in drilling and completion expense and approximately $1.0 million in ~~completion expense for two gross wells, between $1.0 million~~recompletion expense.

We expect that cash on hand and ~~$2.0 million in capital recompletions and approximately $1.5 million for 3D seismic. Additionally, expenses for~~cash flow from operations will be sufficient to fund the remainder of ~~2017 associated with the 2018 drilling program are anticipated to be $1.0 million.~~

~~Bulgaria.~~ ~~We intend to drill on~~ our ~~Koynare license during 2018 and plan to continue working on~~2019 net field capital expenditures. If not, we will either curtail 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,discretionary capital expenditures or seek other funding sources. Our projected remaining 2019 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~~2018 and are of particular importance to the portrayal of our financial position and results of operations and require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

~~There have been no changes to the significant accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.~~

Results of ~~Continuing~~ Operations—Three Months Ended ~~September~~June 30, ~~2017~~2019 Compared to Three Months Ended ~~September~~June 30, ~~2016~~2018

Our results of ~~continuing~~ operations for the three months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 were as follows:

	Three Months Ended September 30,						Change			Three Months Ended June 30,						Change
	2017			2016			2017-2016			2019			2018			2019-2018
	(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	)		253			241			12
Natural gas (Mmcf)		58			283			(225	)		48			56			(8	)
Total production (Mboe)		263			386			(123	)		261			250			11
Average daily sales volumes (Boepd)		2,862			4,191			(1,329	)		2,873			2,746			127
Average prices:
Oil (per Bbl)	$	47.88		$	39.99		$	7.89		$	66.57		$	74.10		$	(7.53	)
Natural gas (per Mcf)	$	4.82		$	6.89		$	(2.07	)	$	5.41		$	4.84		$	0.57
Oil equivalent (per Boe)	$	47.18		$	40.15		$	7.03		$	65.54		$	72.42		$	(6.88	)
Revenues:
Oil and natural gas sales	$	12,424		$	15,483		$	(3,059	)	$	17,134		$	18,100		$	(966	)
Sales of purchased natural gas		-			1,171			(1,171	)
Other		251			5			246			81			98			(17	)
Total revenues	$	12,675		$	16,659		$	(3,984	)		17,215			18,198			(983	)
Costs and expenses (income):
Production	$	2,997		$	3,070		$	(73	)		2,712			2,804			(92	)
Transportation and processing											1,221			1,138			83
Exploration, abandonment and impairment		141			1,531			(1,390	)		666			191			475
Cost of purchased natural gas		-			1,027			(1,027	)
Seismic and other exploration		2,966			3			2,963
Seismic and other geological and geophysical											108			59			49
General and administrative		2,532			2,659			(127	)		2,690			3,786			(1,096	)
Depletion		4,015			6,918			(2,903	)		3,314			3,039			275
Depreciation and amortization		257			362			(105	)		128			237			(109	)
Interest and other expense		2,322			3,836			(1,514	)		2,753			2,091			662
Interest and other income		(182	)		(1,009	)		827			(221	)		(377	)		156
Foreign exchange loss	$	48		$	390		$	(342	)		115			1,938			(1,823	)
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	-		$	2,729		$	(2,729	)
Change in fair value on commodity derivative contracts		(1,365	)		(2,916	)		1,551
Total loss on commodity derivative contracts	$	(1,365	)	$	(187	)	$	(1,178	)
Loss on derivative contracts:
Cash settlements on derivative contracts											-			(1,860	)		1,860
Change in fair value on derivative contracts											(323	)		(1,281	)		958
Total loss on derivative contracts											(323	)		(3,141	)		2,818
Oil and natural gas costs per Boe:
Production	$	9.84		$	6.96		$	2.88		$	9.07		$	9.18		$	(0.11	)
Depletion	$	13.34		$	15.70		$	(2.36	)	$	11.09		$	10.64		$	0.45

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased ~~$3.1 million~~ to ~~$12.4~~$17.1 million for the three months ended ~~September~~June 30, ~~2017,~~2019 from ~~$15.5~~$18.1 million ~~realized in~~for the same period in ~~2016.~~2018. The decrease 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~~decreased $6.88 per Boe to ~~$47.18~~$65.54 per Boe for the three months ended ~~September~~June 30, ~~2017,~~2019 from ~~$40.15~~$72.42 per Boe for the same period in ~~2016.~~

~~Sales~~2018. The decrease was partially offset due to an increase in our average daily sales volumes of ~~Purchased Natural Gas.~~ ~~Sales of purchased natural gas~~127 Boe per day (“Boepd”) for the three months ended ~~September~~June 30, ~~2017 decreased~~2019 as 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.~~2018.

Production. Production expenses decreased to $2.7 million, or $9.07 per Boe, for the three months ended ~~September~~June 30, ~~2017 decreased to $3.0~~2019 from $2.8 million, or ~~$9.84 per Boe, from $3.1 million, or $6.81~~$11.09 per Boe, for the same period in ~~2016.~~2018. The decrease was primarily due to a devaluation of the TRY to the USD, as most of our production expenses are denominated in TRY.

Transportation and Processing. Transportation and processing expense increased to $1.2 million for the three months ended June 30, 2019 from $1.1 million for the same period in 2018. The increase in ~~production~~transportation expenses was primarily due to the increase in our average daily sales volumes of 127 Boepd.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment cost increased to $0.7 million for the three months ended June 30, 2019 from $0.2 million for the same period in 2018. The increase was due to the exploratory dry hole write-off of the Deventci R-1 well.

General and Administrative. General and administrative expense ~~per Boe~~decreased to $2.7 million for the three months ended June 30, 2019 from $3.8 million for the same period in 2018. The decrease was primarily due to a decrease in ~~our sales volumes during~~professional and accounting fees associated with the ~~period.~~

~~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 from $1.5 million for the same period~~evaluation of strategic alternatives 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 million for the three months ended September 30, 2017, compared to $2.7 million for the same period in 2016. Our general and administrative expenses decreased $0.2 million due to a $0.1 million decrease in in personnel expenses and a $0.1 million decrease legal, accounting and other services.2018.

Depletion. Depletion ~~decreased~~expense increased to ~~$4.0~~$3.3 million, or ~~$13.34~~$11.09 per Boe, for the three months ended ~~September~~June 30, ~~2017, compared to $6.9~~2019 from $3.0 million, or ~~$15.70~~$10.64 per Boe, for the same period of ~~2016.~~2018. The ~~decrease~~increase was primarily due to ~~a reduction~~the increase in ~~production~~our average daily sales volumes ~~as well as no depletion expense recorded for TBNG as a result~~ of 127 Boepd and an increase to our proved properties during the ~~divestiture in February 2017.~~three months ended June 30, 2019.

Interest and Other Expense. Interest and other expense ~~decreased~~increased to ~~$2.3~~$2.7 million for the three months ended ~~September~~June 30, ~~2017, compared to $3.8~~2019 from $2.1 million for the same period in ~~2016.~~2018. The ~~decrease~~increase was ~~primarily~~ due to our ~~lower~~higher average debt balances outstanding during the three months ended ~~September~~June 30, ~~2017~~2019 versus the same period in ~~2016.~~

~~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 facilities during the three months ended September 30, 2016.2018.

Foreign Exchange Loss. We recorded a foreign exchange loss of ~~$48,000 during~~$0.1 million for the three months ended ~~September~~June 30, ~~2017,~~2019 as compared to ~~a loss of $0.4~~$1.9 million infor the same period in ~~2016.~~2018. 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~~USD transaction which occurs in Turkey is re-measured at the period-end to the ~~New~~ TRY amount if it has not been settled previously. Generally, a strengthening of the USD relative to the TRY increases our foreign exchange loss. The foreign exchange loss for the three months ended ~~September~~June 30, ~~2017~~2019 was due to a decrease in the value of the TRY compared to the ~~U.S. Dollar.~~USD. From March 31, 2019 to June 30, 2019, the TRY to the USD declined 2.3%. At June 30, 2019, the exchange rate was 5.7551 as compared to 5.6284 at March 31, 2019.

~~Gain~~Loss on ~~Commodity~~ Derivative Contracts. ~~During the three months ended September 30, 2017, we~~We recorded a net loss on ~~commodity~~ derivative contracts of ~~$1.4~~$0.3 million for the three months ended June 30, 2019 as compared to ~~a net loss of $0.2~~$3.1 million for the same period in ~~2016.~~2018. During the three months ended ~~September~~June 30, ~~2017,~~2019, we recorded a ~~$1.4~~$0.3 million loss to mark our currency derivative contracts to their fair value. During the same period in 2018, we recorded a $1.3 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~~$1.9 million ~~gain~~loss 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~~Six Months Ended ~~September~~June 30, ~~2017~~2019 Compared to ~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~2018

Our results of ~~continuing~~ operations for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018 were as follows:

	Nine Months Ended September 30,						Change			Six Months Ended June 30,						Change
	2017			2016			2017-2016			2019			2018			2019-2018
	(in thousands of U.S. Dollars, except per unit amounts and volumes)									(in thousands of U.S. Dollars, except per unit amounts and production volumes)
Sales volumes:
Oil (Mbbl)		858			1,024			(166	)		523			489			34
Natural gas (Mmcf)		308			1,152			(844	)		98			123			(25	)
Total production (Mboe)		909			1,216			(307	)		539			510			29
Average daily sales volumes (Boepd)		3,331			4,437			(1,106	)		2,977			2,800			177
Average prices:
Oil (per Bbl)	$	45.42		$	37.20		$	8.22		$	67.82		$	69.84		$	(2.02	)
Natural gas (per Mcf)	$	4.89		$	7.02		$	(2.13	)	$	5.68		$	4.92		$	0.76
Oil equivalent (per Boe)	$	44.51		$	37.98		$	6.53		$	66.81		$	68.22		$	(1.41	)
Revenues:
Oil and natural gas sales	$	40,475		$	46,171		$	(5,696	)	$	35,994		$	34,761		$	1,233
Sales of purchased natural gas		654			3,717			(3,063	)
Other		323			35			288			262			363			(101	)
Total revenues	$	41,452		$	49,923		$	(8,471	)		36,256			35,124			1,132
Costs and expenses (income):
Production	$	8,798		$	9,025		$	(227	)		5,214			5,673			(459	)
Transportation and processing											2,540			2,331			209
Exploration, abandonment and impairment		249			2,964			(2,715	)		5,779			231			5,548
Cost of purchased natural gas		568			3,264			(2,696	)
Seismic and other exploration		3,046			84			2,962
Seismic and other geological and geophysical											185			218			(33	)
General and administrative		9,303			11,401			(2,098	)		5,744			7,123			(1,379	)
Depletion		12,330			21,745			(9,415	)		6,894			7,350			(456	)
Depreciation and amortization		694			1,308			(614	)		264			385			(121	)
Interest and other expense		6,981			9,106			(2,125	)		5,231			4,873			358
Interest and other income		(663	)		(1,411	)		748			(395	)		(631	)		236
Foreign exchange loss	$	1,055		$	659		$	396			1,388			3,996			(2,608	)
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
Loss on derivative contracts:
Cash settlements on derivative contracts											-			(3,200	)		3,200
Change in fair value on derivative contracts											(433	)		(667	)		234
Total loss on derivative contracts											(433	)		(3,867	)		3,434
Oil and natural gas costs per Boe:
Production	$	8.43		$	6.50		$	1.93		$	8.47		$	9.74		$	(1.27	)
Depletion	$	11.86		$	16.65		$	(4.79	)	$	11.20		$	12.62		$	(1.42	)

Oil and Natural Gas Sales. Total oil and natural gas sales revenues ~~decreased $5.7 million~~increased to ~~$40.5~~$36.0 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019 from ~~$46.2~~$34.8 million ~~realized in~~for the same period in ~~2016.~~2018. The ~~decrease~~increase was primarily due to ~~a decrease~~an increase in our average daily sales volumes of ~~307 Mboe~~177 Boepd for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 as 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.~~2018. This was partially offset by ~~an increase~~a decrease in the average realized price per Boe. Our average price received ~~increased $6.53~~decreased $1.41 per Boe to ~~$44.51~~$66.81 per Boe for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019 from ~~$37.98~~$68.22 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 2017.2018.

Production. Production expenses decreased to $5.2 million, or $8.47 per Boe, for the ~~nine~~six months ended ~~September~~June 30, ~~2017 decreased to $8.8~~2019 from $5.7 million, or ~~$8.43 per Boe, from $9.0 million, or $6.50~~$9.74 per Boe, for the same period in ~~2016.~~2018. The ~~increase in production expense per Boe~~decrease was primarily due to a ~~decrease~~devaluation of the TRY to the USD, as most of our production expenses are denominated in TRY.

Transportation and Processing. Transportation and processing expense increased to $2.5 million for the six months ended June 30, 2019 from $2.3 million for the same period in 2018. The increase in transportation expenses was primarily due to the increase in our average daily sales volumes ~~during the period.~~of 177 Boepd.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment ~~costs~~cost increased to $5.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017 decreased $2.7 million to~~2019 from $0.2 ~~million, from $3.0~~ million for the same period in ~~2016. During~~2018. The increase was due to the ~~nine months ended September 30, 2017, we incurred $0.2 million in proved property impairment, minimal~~ exploratory dry hole ~~costs~~write-off of the Deventci R-1 well.

~~Cost of Purchased Natural Gas.~~ ~~Cost of purchased natural gas~~ General and administrative expense decreased to $5.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017 decreased to $0.6 million~~2019 from ~~$3.3~~$7.1 million for the same period in ~~2016.~~2018. 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 millionprimarily due to a ~~$1.6 million~~ decrease in ~~legal,~~professional and accounting ~~and other services and a $0.8 million decrease~~fees associated with the evaluation of strategic alternatives in ~~personnel expenses, which was partially offset by an increase in office expenses of $0.3 million.~~2018.

Depletion. Depletion expense decreased to ~~$12.3~~$6.9 million, or ~~$11.86~~$11.20 per Boe, for the ~~nine~~six months ended ~~September~~June 30, ~~2017, compared to $21.7~~2019 from $7.4 million, or ~~$16.65~~$12.62 per Boe, for the same period of ~~2016.~~2018. 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.~~devaluation of the TRY to the USD.

Interest and Other Expense. Interest and other expense ~~decreased~~increased to ~~$7.0~~$5.2 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017, compared to $9.1~~2019 from $4.9 million for the same period in ~~2016.~~2018. The ~~decrease~~increase was ~~primarily~~ due to our ~~lower~~higher average debt balances outstanding during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 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. 2018.

Foreign Exchange Loss. We recorded a foreign exchange loss of ~~$1.1~~$1.4 million ~~during~~for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019 as compared to ~~a loss of $0.7~~$4.0 million infor the same period in ~~2016.~~2018. 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~~USD transaction which occurs in Turkey is re-measured at the period-end to the TRY amount if it has not been settled previously. Generally, a strengthening of the USD relative to the TRY increases our foreign exchange loss. The foreign exchange loss for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 was due to a decrease in the value of the TRY compared to the ~~U.S. Dollar.~~USD. From December 31, 2018 to June 30, 2019, the TRY to the USD declined 9.4%. At June 30, 2019, the exchange rate was 5.7551 as compared to 5.2609 at December 31, 2018.

~~Gain~~Loss on ~~Commodity~~ Derivative Contracts. ~~During the nine months ended September 30, 2017, we~~We recorded a net ~~gain~~loss on ~~commodity~~ derivative contracts of ~~$0.3~~$0.4 million for the six months ended June 30, 2019 as compared to ~~a net loss of $2.4~~$3.9 million for the same period in ~~2016.~~2018. During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2019, we recorded a ~~$0.3~~$0.4 million ~~gain~~loss to mark our currency derivative contracts to their fair value. During the same period in 2018, we recorded a $0.7 million loss to mark our commodity derivative contracts to their fair value and a ~~$32,000 gain~~$3.2 million loss 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.~~

~~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.~~

For the ~~quarter~~three months ended ~~September~~June 30, ~~2017,~~2019, we incurred ~~$6.0~~$6.2 million in capital expenditures, including seismic and corporate expenditures, as compared to ~~$1.5~~$5.6 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.~~2018.

We expect our net field capital expenditures for the remainder of ~~2017~~2019 to range between ~~$3.0~~$10.0 million and ~~$4.5~~$15.0 million. We expect net field capital expenditures during the remainder ~~2017~~of 2019 to include between ~~$0.5~~$9.0 million and $14.0 million in drilling and completion expense and approximately $1.0 million in completion expense for two gross wells, between $1.0 million and $2.0 million in capital recompletions and approximately $1.5 million for 3D seismic. Additionally, expenses for the remainder of 2017 associated with the 2018 drilling program are anticipated to be $1.0 million.recompletion expense. We expect that cash on hand and cash flow from operations will be sufficient to fund the remainder of our ~~2017~~2019 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected ~~2017~~remaining 2019 capital expenditure budget is subject to change.

Net cash provided by operating activities ~~from continuing operations~~ during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 was ~~$16.1~~$10.6 million, a decrease from net cash provided by operating activities ~~from continuing operations~~ of ~~$19.6~~$12.2 million for the same period in ~~2016.~~2018. The decrease was primarily due to ~~a decrease~~an increase in our ~~total~~accounts receivable due to early collections on our oil and natural gas receivables in December of 2018, which was partially offset by an increase in our revenues.

Net cash used in investing activities during the six months ended June 30, 2019 was $15.7 million, an increase from net cash used in investing activities of $11.4 million for the same period in 2018. The increase was primarily due to an increase in our capital expenditures as compared to the same period in 2018.

Net cash provided by ~~investing~~financing activities ~~from continuing operations~~ during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2019 was ~~$4.9~~$10.1 million, an increase from net cash provided by ~~investing~~financing activities ~~from continuing operations~~ of ~~$2.7~~$1.7 million for the same period in ~~2016.~~2018. The ~~increase~~change was primarily due to ~~the proceeds received from the sale of TBNG partially offset by~~ an increase in ~~capital expenditures.~~

Net cash used in financing activities from continuing operations during the nine months ended September 30, 2017 was $29.7 million, an increase from net cash used in financing activities from continuing operations of $7.8 million for the same period in 2016. The increase was primarily due to a decrease in our outstanding ~~indebtedness.~~loans.

As of ~~September~~June 30, ~~2017,~~2019, we had ~~$12.4~~$31.2 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 June 30, 2019, we had a working capital surplus of $7.7 million.

2017 Term Loan. On August 23, 2016, the Turkish branch of TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), our wholly-owned subsidiary, entered into a Credit Agreement with DenizBank S.A. (“DenizBank”).

~~On August 31, 2016,~~November 17, 2017, DenizBank entered into ~~a $30.0 million term loan with TEMI~~the 2017 Term Loan under the Credit Agreement (the “Term Loan”). 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, 2016, TEMI used approximately $22.9 million of the proceeds from the Term Loan to repay our former senior credit facility in full.~~

Agreement. The 2017 Term Loan bears interest at a fixed rate of ~~5.25%~~6.0% (plus ~~0.2625%~~0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2017 Term Loan had a grace period which bore no interest or payments due until July 2018. Thereafter, the 2017 Term Loan 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 Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.

~~On April 27,~~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 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) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. 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 ~~approved a revised amortization schedule~~as additional security for the 2017 Term Loan. Pursuant to the revised amortization schedule, the maturity date of the 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 Term Loan remain unchanged.

~~2017 Notes.~~2018 Term Loan. On May 28, 2018, DenizBank entered into the 2018 Term Loan under the Credit Agreement. The ~~2017 Notes bore~~2018 Term Loan bears interest at ~~an annual~~a fixed rate of ~~13.0%~~7.25% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. ~~Interest was~~The 2018 Term Loan had a grace period through July 2018 during which no payments were due. Thereafter, accrued interest on the 2018 Term Loan is payable ~~semi-annually,~~monthly and the principal on the 2018 Term Loan is payable in ~~arrears,~~five monthly installments of $0.2 million each through December 2018, four monthly installments of $0.5 million each through April 2019, four monthly installments of $1.0 million each through August 2019, and four monthly installments of $0.75 million each through December 2019. The 2018 Term Loan matures in December 2019. Amounts repaid under the 2018 Term Loan may not be reborrowed, and early repayments under the 2018 Term Loan are subject to early repayment fees. The 2018 Term Loan is guaranteed by Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.

The 2018 Term Loan contains standard prohibitions on ~~January 1~~the activities of TEMI as the borrower, including prohibitions on encumbering or creating restrictions or limitations on all or a part of its assets, revenues, or properties, giving guaranties or sureties, selling assets or transferring revenues, dissolving, liquidating, merging, or consolidating, incurring additional debt, paying dividends, making certain investments, undergoing a change of control, and ~~July 1~~other similar matters. In addition, the 2018 Term Loan prohibits Amity, Talon Exploration, DMLP, and Transatlantic Turkey from incurring additional debt. An event of ~~each year.~~ default under the 2018 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 Notes matured on July 1, 2017,~~2018 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) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI will assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2018 Term Loan.

At June 30, 2019, we had $5.0 million outstanding under the 2018 Term Loan and no availability, and we ~~paid off~~were in compliance with the covenants in the 2018 Term Loan.

2019 Term Loan. On February 22, 2019, DenizBank entered into the 2019 Term Loan under the Credit Agreement.

The 2019 Term Loan bears interest at a fixed rate of 7.5% (plus 0.375% for Banking and ~~retired~~Insurance Transactions Tax per the Turkish government) per annum. The 2019 Term Loan had a grace period through December 2019 during which no payments are due. Thereafter, accrued interest on the 2019 Term Loan is payable monthly and the principal on the 2019 Term Loan is payable in 14 monthly installments of $1.4 million each. The 2019 Term Loan matures in February 2021. Amounts repaid under the 2019 Term

Loan may not be reborrowed, and early repayments under the 2019 Term Loan are subject to early repayment fees. The 2019 Term Loan is guaranteed by Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.

The 2019 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on encumbering or creating restrictions or limitations on all ~~remaining~~or a part of its assets, revenues, or properties, giving guaranties or sureties, selling assets or transferring revenues, dissolving, liquidating, merging, or consolidating, incurring additional debt, paying dividends, making certain investments, undergoing a change of control, and other similar matters. In addition, the 2019 Term Loan prohibits Amity, Talon Exploration, DMLP, and Transatlantic Turkey from incurring additional debt. An event of default under the 2019 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 2019 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) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI will assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2019 Term Loan.

At June 30, 2019, we had $20.0 million outstanding ~~2017 Notes on July 3, 2017.~~under the 2019 Term Loan and no availability, and we were in compliance with the covenants in the 2019 Term Loan.

Series A Preferred Shares. ~~On November 4, 2016,~~As of June 30, 2019, we ~~issued 921,000 shares of our 12% Series A Convertible Redeemable Preferred Shares (“Series A Preferred Shares”). Of the~~had 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~~U.S. GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of ~~September~~June 30, ~~2017, there were~~2019, we had $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, seeoutstanding (See Note 3. “Series A Preferred Shares” ~~to our consolidated financial statements.~~).

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.

Our derivative contracts may expose us to credit risk in the event of nonperformance by our counterparty. The lender under our Term Loan 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.Not applicable.

During the third quarter of 2017, 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. 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:

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~~June 30, ~~2017,~~2019, 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~~June 30, ~~2017,~~2019, 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~~June 30, ~~2017~~2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

During the ~~third~~second quarter of ~~2017,~~2019, 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.~~ 2018.

During the ~~third~~second quarter of ~~2017,~~2019, 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.~~2018.

On ~~October~~July 2, ~~2017,~~2019, we issued an aggregate of ~~2,591,384~~2,321,568 common shares to holders of the Series A Preferred Shares as payment of the ~~September~~June 30, ~~2017~~2019 quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of ~~$0.7108~~$0.7934 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.~~June 14, 2019.

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, Suite 200 Addison, Texas	75001
(Address of Principal Executive Offices)	(Zip Code)

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of ~~September~~June 30, ~~2017~~2019 (Unaudited) and December 31, ~~2016~~	3

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

Unaudited Consolidated ~~Statement~~Statements of ~~Equity~~Operations and Comprehensive (Loss) Income for the ~~Nine~~Three and Six Months Ended ~~September~~June 30, ~~2017~~2019 and 2018	5

Unaudited Consolidated ~~Statements~~Statement of ~~Cash Flows~~Equity for the ~~Nine~~Three and Six Months Ended ~~September~~June 30, ~~2017~~2019 and ~~2016~~2018	6

Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2019 and 2018	7

Notes to Unaudited Consolidated Financial Statements	78

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk	3031

Item 4. Controls and Procedures	31

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	32

Item 1A. Risk Factors	32

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	32

Item 3. Defaults Upon Senior Securities	32

Item 4. Mine Safety Disclosures	32

Item 5. Other Information	32

Item 6. Exhibits	33



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%

	September 30,		December 31,
	2017		2016
	(in thousands)
Related party accounts receivable:
Riata Management Service Agreement	$	715	$	528
PSIL MSA		348		234
Total related party accounts receivable		1,063		762
Related party accounts payable:
Riata Management Service Agreement	$	332	$	346
PSIL MSA		3,041		1,315
Interest payable on 2017 Notes and Series A Preferred Shares		990		183
Total related party accounts payable	$	4,363	$	1,844

	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	)

Large accelerated filer	☐	☐	Accelerated filer	☐

Non-accelerated filer	☒	☐ ~~(Do not check if a smaller reporting company)~~	Smaller reporting company	☒

			Emerging growth company	☐

	June 30, 2019
	(in thousands)
Operations yards	$	292
Office rent		115
Vehicles		70
Other		42
Total lease costs	$	519

	June 30, 2019
	(in thousands)
Remainder of 2019	$	500
2020		731
2021		658
2022		648
2023		327
2024		-
Thereafter		-
Total	$	2,864
Less: Imputed interest		440
Present value of lease liabilities	$	2,424

	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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands, except per share amounts)	2019			2018			2019			2018
Net loss	$	(9	)	$	(1,006	)	$	(3,911	)	$	(2,781	)
Basic net loss earnings per common share:
Shares:
Weighted average common shares outstanding		52,529			50,420			52,506			50,397
Basic net loss per common share:	$	(0.00	)	$	(0.02	)	$	(0.07	)	$	(0.06	)
Diluted net loss per common share:
Shares:
Weighted average common shares outstanding		52,529			50,420			52,506			50,397
Diluted net loss per common share:	$	(0.00	)	$	(0.02	)	$	(0.07	)	$	(0.06	)

	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

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).

3.5		Memorandum of Increase of Share Capital of TransAtlantic Petroleum Ltd., dated July 2017 (incorporated by reference to Exhibit 3.5 to the Company’s Annual Report on Form 10-K filed with the SEC on March 26, 2019).

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).

10.1		Third Amendment to Service Agreement, dated April 17, 2019 and effective as of August 1, 2017, by and among TransAtlantic Petroleum Ltd. and its subsidiaries and Longfellow Energy, LP, Viking Drilling, LLC, Riata Management, LLC, LFN Holdco LLC, Red Rock Minerals, LP, Red Rock Minerals II, LP, Red Rock Advisors, LLC, Production Solutions International Limited, and NexLube Operating, LLC and their subsidiaries (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated April 17, 2019, filed with the SEC on April 17, 2019).

10.2		TransAtlantic Petroleum Ltd. 2019 Long-Term Incentive Plan (incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement filed with the SEC on April 18, 2019).

10.3		Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated June 4, 2019, filed with the SEC on June 7, 2019).

10.4		Amendment No. 1 to the Pledge Agreement, dated June 28, 2019, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated June 28, 2019, filed with the SEC on June 28, 2019).

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~~MICHAEL P. HILL
		~~G. Fabian Anda~~Michael P. Hill ~~Principal~~Chief Accounting ~~and Financial~~ Officer

Date: ~~November 8, 2017~~August 7, 2019