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 7, 2020, the registrant had ~~50,319,156~~68,586,290‬ 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, 2019 and our subsequent Quarterly Reports on Form 10-Q. Such factors include, but are not limited to, the following: the occurrence of any event, change, or other circumstances that could give rise to the termination of the Merger Agreement (as defined in Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operations); the inability to obtain the requisite shareholder approval for the proposed merger or the failure to satisfy other conditions to completion of the proposed merger; risks that the proposed transaction disrupts current plans and operations; the ability to recognize the benefits of the merger; the amount of the costs, fees, and expenses and charges related to the merger; our ability to continue as a going concern; well development results; access to sufficient capital; market prices for natural gas, natural gas liquids, and oil products, including price changes resulting from COVID-19 fears as well as oil oversupply concerns; estimates of reserves and economic assumptions; the ability to produce and transport natural gas, natural gas liquids, and oil products, including price changes resulting from coronavirus fears as well as oil oversupply concerns; the results of exploration and development drilling and related activities; the effects of the coronavirus on our operations, demand for oil and natural gas as well as governmental actions in response to the coronavirus; economic conditions in the countries and provinces in which we carry on business, especially economic slowdowns; actions by governmental authorities; the unwinding of our hedges against a decline in the price of oil; receipt of required approvals; increases in taxes; legislative and regulatory initiatives relating to fracture stimulation activities; changes in environmental and other regulations; renegotiations of contracts; political uncertainty, including sanctions, armed conflicts, and actions by insurgent groups; outcomes of litigation; the negotiation and closing of material contracts; and the other factors discussed in other documents that we file with or furnish to 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: liquidity; ability to continue as a going concern; COVID-19; access to sufficient capital; 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, 2020			December 31, 2019
	September 30, 2017			December 31, 2016			(unaudited)
ASSETS	(unaudited)
Current assets:
Cash and cash equivalents	$	2,757		$	10,034		$	8,598		$	9,664
Restricted cash		–			2,555
Accounts receivable, net
Oil and natural gas sales		12,891			17,885			6,796			13,299
Joint interest and other		1,914			3,230			1,106			1,218
Related party		1,063			762			478			561
Prepaid and other current assets		2,557			4,756			12,497			12,375
Note receivable - related party								3,492			–
Derivative asset								10			–
Inventory		3,613			3,647			3,249			7,091
Assets held for sale		–			25,217
Total current assets		24,795			68,086			36,226			44,208
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		204,895			197,214			120,915			167,948
Unproved		25,730			21,109			10,414			12,978
Equipment and other property		19,399			20,273			13,136			10,202
		250,024			238,596			144,465			191,128
Less accumulated depreciation, depletion and amortization		(132,899	)		(120,638	)		(89,529	)		(106,610	)
Property and equipment, net		117,125			117,958			54,936			84,518
Other long-term assets:
Other assets		2,104			2,725			3,524			3,827
Note receivable - related party		7,027			7,624			–			3,951
Total other assets		9,131			10,349			3,524			7,778
Total assets	$	151,051		$	196,393		$	94,686		$	136,504
LIABILITIES, SERIES A PREFERRED SHARES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	3,518		$	7,036		$	1,611		$	4,555
Accounts payable - related party		4,363			1,844			5,120			4,262
Accrued liabilities		8,660			12,492			13,993			15,244
Derivative liability		571			596			3,227			966
Loans payable		12,375			34,750			11,269			17,143
Loan payable - related party		–			3,444
Liabilities held for sale		–			15,938
Total current liabilities		29,487			76,100			35,220			42,170
Long-term liabilities:
Asset retirement obligations		4,940			4,833			3,505			4,749
Accrued liabilities		9,138			8,126			9,455			10,370
Deferred income taxes		20,494			18,806			17,721			22,728
Loans payable		–			3,750			–			2,857
Derivative liability		–			242
Total long-term liabilities		34,572			35,757			30,681			40,704
Total liabilities		64,059			111,857			65,901			82,874
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, 100,000 shares authorized; 100,000 shares issued and outstanding with a liquidation preference of $50 per share as of June 30, 2020 and December 31, 2019								5,000			5,000
Series A preferred shares-related party, $0.01 par value, 821,000 shares authorized; 821,000 shares issued and outstanding with a liquidation preference of $50 per share as of June 30, 2020 and December 31, 2019								41,050			41,050
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; 62,759,347 shares and 62,230,058 shares issued and outstanding as of June 30, 2020 and December 31, 2019, respectively								6,276			6,223
Treasury stock		(970	)		(970	)		(970	)		(970	)
Additional paid-in-capital		573,691			573,278			582,484			582,359
Accumulated other comprehensive loss		(118,488	)		(140,316	)		(140,671	)		(147,347	)
Accumulated deficit		(418,064	)		(398,228	)		(464,384	)		(432,685	)
Total shareholders' equity		40,942			38,486
Total shareholders' equity (deficit)								(17,265	)		7,580
Total liabilities, Series A preferred shares and shareholders' equity	$	151,051		$	196,393		$	94,686		$	136,504

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			2020			2019			2020			2019
Revenues:
Oil and natural gas sales	$	12,424		$	15,483		$	40,475		$	46,171		$	6,483		$	17,134		$	14,826		$	35,994
Sales of purchased natural gas		-			1,171			654			3,717
Other		251			5			323			35			17			81			34			262
Total revenues		12,675			16,659			41,452			49,923			6,500			17,215			14,860			36,256
Costs and expenses:
Production		2,997			3,070			8,798			9,025			2,380			2,712			5,899			5,214
Transportation and processing														961			1,221			2,121			2,540
Exploration, abandonment and impairment		141			1,531			249			2,964			-			666			20,338			5,779
Cost of purchased natural gas		-			1,027			568			3,264
Seismic and other exploration		2,966			3			3,046			84			-			108			45			185
General and administrative		2,532			2,659			9,303			11,401			2,394			2,690			4,746			5,744
Depreciation, depletion and amortization		4,272			7,280			13,024			23,053			2,517			3,442			5,506			7,158
Accretion of asset retirement obligations		49			97			144			285			44			49			97			101
Total costs and expenses		12,957			15,667			35,132			50,076			8,296			10,888			38,752			26,721
Operating (loss) income		(282	)		992			6,320			(153	)		(1,796	)		6,327			(23,892	)		9,535
Other income (expense):
Loss on sale of TBNG		-			-			(15,226	)		-
Loss on sale														-			-			(10,128	)		-
Interest and other expense		(2,322	)		(3,836	)		(6,981	)		(9,106	)		(2,396	)		(2,753	)		(4,608	)		(5,231	)
Interest and other income		182			1,009			663			1,411			292			221			413			395
(Loss) gain on commodity derivative contracts		(1,365	)		(187	)		299			(2,419	)
Gain (loss) on derivative contracts														(3,217	)		(323	)		4,296			(433	)
Foreign exchange loss		(48	)		(390	)		(1,055	)		(659	)		(356	)		(115	)		(484	)		(1,388	)
Total other expense		(3,553	)		(3,404	)		(22,300	)		(10,773	)		(5,677	)		(2,970	)		(10,511	)		(6,657	)
Loss from continuing operations before income taxes		(3,835	)		(2,412	)		(15,980	)		(10,926	)
Income tax expense		(518	)		(2,224	)		(3,856	)		(5,820	)
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:
(Loss) income from operations before income taxes														(7,473	)		3,357			(34,403	)		2,878
Income tax (expense) benefit														(261	)		(3,366	)		2,704			(6,789	)
Net loss														(7,734	)		(9	)		(31,699	)		(3,911	)
Other comprehensive loss:
Foreign currency translation adjustment		(1,223	)		(3,986	)		21,828			(3,277	)		(1,245	)		(416	)		6,676			(4,642	)
Comprehensive (loss) income	$	(5,576	)	$	7,683		$	1,992		$	(3,821	)
Comprehensive loss													$	(8,979	)	$	(425	)	$	(25,023	)	$	(8,553	)

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													$	(0.12	)	$	(0.00	)	$	(0.51	)	$	(0.07	)
Weighted average common shares outstanding		47,725			46,854			47,480			42,879			62,502			52,529			62,406			52,506
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													$	(0.12	)	$	(0.00	)	$	(0.51	)	$	(0.07	)
Weighted average common and common equivalent shares outstanding		47,725			46,854			47,480			42,879			62,502			52,529			62,406			52,506

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

Consolidated ~~Statement~~Statements of Equity for the Three and Six Months Ended June 30, 2020 and 2019

															Accumulated																					Accumulated						Total
												Additional			Other						Total												Additional			Other						Shareholders'
	Common		Treasury				Common		Treasury			Paid-in			Comprehensive			Accumulated			Shareholders'			Common		Treasury		Common		Treasury			Paid-in			Comprehensive			Accumulated			Equity
	Shares		Shares		Warrants		Shares		Stock			Capital			Loss			Deficit			Equity
Balance at December 31, 2016		47,220		333		699	$	4,722	$	(970	)	$	573,278		$	(140,316	)	$	(398,228	)	$	38,486
Three months ended June 30, 2020																								Shares		Shares		Shares		Stock			Capital			Loss			Deficit			(Deficit)
Balance at March 31, 2020																									62,349		333	$	6,235	$	(970	)	$	582,426		$	(139,426	)	$	(456,650	)	$	(8,385	)
Issuance of restricted stock units		508		-		-		51		-			(51	)		-			-			-			410		-		41		-			(41	)		-			-			-
Tax withholding on restricted stock units		-		-		-		-		-			(92	)		-			-			(92	)
Share-based compensation		-		-		-		-		-			556			-			-			556			-		-		-		-			114			-			-			114
Tax effect of restricted stock																									-		-		-		-			(15	)		-			-			(15	)
Foreign currency translation adjustment		-		-		-		-		-			-			21,828			-			21,828			-		-		-		-			-			(1,245	)		-			(1,245	)
Net loss		-		-		-		-		-			-			-			(19,836	)		(19,836	)		-		-		-		-			-			-			(7,734	)		(7,734	)
Balance at September 30, 2017		47,728		333		699	$	4,773	$	(970	)	$	573,691		$	(118,488	)	$	(418,064	)	$	40,942
Balance at June 30, 2020																									62,759		333	$	6,276	$	(970	)	$	582,484		$	(140,671	)	$	(464,384	)	$	(17,265	)
Six Months Ended June 30, 2020
Balance at December 31, 2019																									62,230		333	$	6,223	$	(970	)	$	582,359		$	(147,347	)	$	(432,685	)	$	7,580
Issuance of restricted stock units																									529		-		53		-			(53	)		-			-			-
Share-based compensation																									-		-		-		-			229			-			-			229
Tax effect of restricted stock																									-		-		-		-			(51	)		-			-			(51	)
Foreign currency translation adjustment																									-		-		-		-			-			6,676			-			6,676
Net loss																									-		-		-		-			-			-			(31,699	)		(31,699	)
Balance at June 30, 2020																									62,759		333	$	6,276	$	(970	)	$	582,484		$	(140,671	)	$	(464,384	)	$	(17,265	)
Three Months Ended June 30, 2019
Balance at March 31, 2019																									52,496		333	$	5,249	$	(970	)	$	577,493		$	(146,247	)	$	(431,221	)	$	4,304
Issuance of restricted stock units																									227		-		24		-			(24	)		-			-			-
Share-based compensation																									-		-		-		-			77			-			-			77
Tax effect of restricted stock																									-		-		-		-			(8	)		-			-			(8	)
Foreign currency translation adjustment																									-		-		-		-			-			(416	)		-			(416	)
Net loss																									-		-		-		-			-			-			(9	)		(9	)
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

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			2020			2019
Operating activities:
Net loss	$	(19,836	)	$	(544	)	$	(31,699	)	$	(3,911	)
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			229			179
Foreign currency loss		434			593			427			3,011
(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) loss on derivative contracts								(4,296	)		433
Cash settlement on derivative contracts								6,468			–
Loss on sale								10,128			–
Amortization on loan financing costs		72			1,015			21			21
Deferred income tax expense		2,780			1,239
Deferred income tax (benefit) expense								(1,776	)		3,713
Exploration, abandonment and impairment		249			2,964			20,338			5,779
Depreciation, depletion and amortization		13,024			23,053			5,506			7,158
Accretion of asset retirement obligations		144			285			97			101
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	)		5,457			(10,630	)
Prepaid expenses and other assets		901			(1,528	)		(1,635	)		(6,205	)
Accounts payable and accrued liabilities		(4,592	)		6,892			996			10,973
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			10,261			10,622
Investing activities:
Additions to oil and natural gas properties		(14,317	)		(4,664	)		(3,472	)		(15,538	)
Additions to equipment and other properties		(366	)		(139	)		(158	)		(188	)
Restricted cash		1,776			6,398
Proceeds from asset sale		17,779			1,104
Net cash provided by investing activities		4,872			2,699
Proceeds from sale								1,451			–
Net cash used in investing activities								(2,179	)		(15,726	)
Financing activities:
Issuance of common shares		-			1,658
Tax withholding on restricted share units		(92	)		(59	)		(51	)		(97	)
Note receivable - related party								–			1,000
Loan proceeds		-			30,076			626			20,000
Loan repayment		(26,350	)		(39,517	)		(9,357	)		(10,800	)
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 (used in) provided by financing activities								(8,782	)		10,103
Effect of exchange rate on cash flows, cash equivalents, and restricted cash								(366	)		(1,184	)
Net (decrease) increase in cash, cash equivalents and restricted cash								(1,066	)		3,815
Cash, cash equivalents and restricted cash, beginning of period (1)								9,804			10,032
Cash, cash equivalents and restricted cash, end of period (2)							$	8,738		$	13,847
Supplemental disclosures:
Cash paid for interest	$	5,353		$	4,057		$	2,229		$	2,269
Cash paid for taxes	$	2,065		$	3,423		$	414		$	1,565
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 7, 2020, approximately ~~47.3%~~50.5% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors. Persons and entities associated with Mr. Mitchell also owned 739,000 of our 12.0% Series A Convertible Redeemable Preferred Shares (“Series A Preferred Shares”). Mr. Mitchell’s affiliates are currently prohibited from converting any of their Series A Preferred Shares to common shares if such conversion would cause Mr. Mitchell or his affiliates to obtain beneficial ownership in excess of 49.9% of the outstanding common shares; however, Mr. Mitchell, upon 61 days’ prior notice, may increase or decrease such percentage cap.

~~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 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 Annual Report on Form 10-K for the year ended December 31, ~~2016.~~2019.

These consolidated financial statements have been prepared on the basis of accounting principles applicable to a going concern. These principles assume that we will be able to realize our assets and discharge our obligations in the normal course of operations for the foreseeable future.

We incurred a net loss of $31.7 million for the six months ended June 30, 2020. At June 30, 2020, we had cash and cash equivalents of $8.6 million, $11.3 million in short-term debt, and a working capital surplus of $1.0 million, compared to cash and cash equivalents of $9.7 million, $2.9 million in long-term debt, $17.1 million in short-term debt and a working capital surplus of $2.0 million at December 31, 2019.

In March 2020, crude oil prices declined to approximately $25 per barrel for Brent crude as a result of market concerns about the economic impact from the COVID-19 as well as the ability of OPEC and Russia to agree on a perceived need to implement further production cuts in response to weaker worldwide demand. Since then, Brent crude prices have rebounded to approximately $45.00 per barrel as of August 10, 2020 and remain unpredictable.

As a result of the decline in Brent crude prices, the current near term price outlook and resulting lower current and projected cash flows from operations, we have reduced our planned capital expenditures to those necessary for production lease maintenance and those projecting a return on invested capital at current prices. In order to mitigate the impact of reduced prices on our 2020 cash flows and liquidity, we implemented cost reduction measures to reduce our operating costs and general and administrative expenses. In connection therewith, we intend to prioritize funding operating expenditures over general and administrative expenditures, whenever possible.

On March 9, 2020, we unwound our commodity derivative contracts with respect to our future crude oil production. In connection with these transactions, we received $6.5 million. In order to reduce future interest expense, we used these proceeds to pay down the 2019 Term Loan (as defined in Note 8. “Loans Payable”). On April 3, 2020, we entered into a new swap contract with DenizBank, A.S. (“DenizBank”), which hedged approximately 2,000 barrels of oil per day. The swap contract is in place from May 2020 through February 2021, has an ICE Brent Index strike price of $36.00 per barrel, and is settled monthly. Therefore, DenizBank is required to make a payment to us if the average monthly ICE Brent Index price is less than $36.00 per barrel, and we are required to make a payment to DenizBank if the average monthly ICE Brent Index price is greater than $36.00 per barrel.

Türkiye Petrol Rafinerileri A.Ş. (“TUPRAS”), a privately-owned oil refinery in Turkey, purchases substantially all of our crude oil production. The price of substantially all of the oil delivered pursuant to the purchase and sale agreement with TUPRAS is tied to Arab Medium oil prices adjusted upward based on an API adjustment, Suez Canal tariff costs, and freight charges. Between March 2020 and May 2020, there was a significant widening of the differential between the average monthly ICE Brent Index price and our realized oil prices. In 2018 and 2019, the average monthly ICE Brent Index Price exceeded our realized oil prices by $2.44 and $0.17 per barrel, respectively. The differential between the average monthly ICE Brent Index Price and our realized oil prices widened from $3.40 per barrel in March 2020 to $8.34 per barrel in May 2020. The widening of the differential between the average monthly ICE Brent Index Price and our realized oil prices rendered our hedges less effective, resulting in significantly lowered revenues from March 2020 through May 2020. In June 2020, the differential between the average monthly ICE Brent Index Price and our realized oil prices contracted to $0.74 per barrel, and, in July 2020, our realized oil prices exceeded the average monthly ICE Brent Index Price by $3.71 per barrel. The differential between the average monthly ICE Brent Index Price and our realized oil prices remains unpredictable and may expand or contract in the future.

The price of the oil delivered pursuant to the purchase and sale agreement with TUPRAS is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. In November 2019, TUPRAS filed a lawsuit seeking restitution from us for alleged overpayments resulting from a February 2019 amendment to the Turkish domestic crude oil pricing formula under Petroleum Market Law No. 5015 (the “Pricing Amendment”). TUPRAS also claimed that the Pricing Amendment violates the Constitution of the Republic of Turkey and seeks to have the Pricing Amendment cancelled. Additionally, in April 2020, TUPRAS notified us that it intends to extend payment terms for oil purchases by 60 days. The outcome of the TUPRAS lawsuit and negotiations regarding the extension of payment terms is uncertain; however, a conclusion of the lawsuit in TUPRAS’s favor or an extension of payment terms would reduce or delay our cash flow and decrease our cash balances.

In the second quarter of 2020, we borrowed approximately $626,000 pursuant to the U.S. Paycheck Protection Program (the “PPP”) to cover certain payroll, benefit, and rent expenses. We have forecast that amounts borrowed or received pursuant to the PPP will be forgiven for cash flow purposes. New guidance on the criteria for forgiveness continues to be released, and we currently expect that we will meet the conditions for forgiveness for a majority of the loan. Additionally, in the second quarter of 2020, the Turkish government passed legislation permitting employers to reduce the working hours of employees, reducing payroll and benefit expenses, through the end of August 2020. The actual reduction in payroll and benefit expenses due to this legislation is approximately $533,000.

As of June 30, 2020, we had $10.6 million of outstanding principal under the 2019 Term Loan. The 2019 Term Loan is payable in seven monthly installments of $1.4 million plus accrued interest from July 2020 through the maturity date in February 2021. In addition, dividends on our 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 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%. In order to conserve cash, we elected to pay the 2020 second quarter dividend in common shares, and, as such, on July 30, 2020, we issued 5,819,908 common shares to holders of Series A Preferred Shares.

On ~~February 24, 2017,~~August 7, 2020, to supplement our liquidity, we ~~closed the sale~~entered into an up to $8.0 million loan with an affiliate 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~~Mr. Mitchell. The loan is due August 7, 2021. Even with this additional liquidity, as of ~~March 31, 2016.~~the date hereof, based on cash on hand and projected future cash flow from operations, our current liquidity position is severely constrained. As a result, substantial doubt exists regarding our ability to continue as a going concern. Our management is actively pursuing improving our working capital position in order to remain a going concern for the foreseeable future.

~~We classified~~Management believes the going concern assumption to be appropriate for these consolidated financial statements. If the going concern assumption was not appropriate, adjustments would be necessary to the carrying values of assets and liabilities, ~~of TBNG within the captions “Assets held for sale”~~reported revenues 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~~expenses 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”).balance sheet classifications used in these consolidated financial statements.

In ~~March~~June 2016, the Financial Accounting Standards Board (“FASB”) issued ~~Accounting Standards Update (“ASU”) 2016-08, Revenue from Contracts with Customers (Topic 606):~~ ~~Principal versus Agent Considerations (Reporting Revenue Gross versus Net)~~ (“ASU 2016-08”). ASU 2016-08 does not change the core principle of Topic 606, but clarifies the implementation guidance on principal versus agent considerations. ASU 2016-08 is effective for annual and interim periods beginning after December 15, 2017. We are currently assessing the potential impact of ASU 2016-08 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~~2 (“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.

~~In June 2016, the FASB issued ASU 2016-13,~~016-13, 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,~~November 2018, the FASB ASU 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 this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We adopted this standard effective January 1, 2020. The adoption of this update had no impact on our consolidated financial statements and results of operations.

In December 2019, the FASB issued ASU ~~2016-15, Statement of Cash Flows~~2019-12, Income Taxes (Topic ~~230):~~740) - ~~Classification of Certain Cash Receipts~~Simplifying the Accounting for Income Taxes. This update removes certain exceptions to the general principles in Topic 740 and ~~Cash Payments~~ ~~(“ASU 2016-15”). ASU 2016-15 reduces diversity~~provides clarifications related to certain franchise taxes, transactions with a government that result in ~~practice in how certain transactions are classified~~a step-up in the ~~statement~~tax basis of ~~cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement~~goodwill, allocation of ~~zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to~~current and deferred income tax expense and the annual effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. ASU 2016-15tax rate. This update is effective ~~for annual and interim periods beginning after December 15, 2017.~~January 1, 2021. We are currently assessing the potential impact of ~~ASU 2016-15 on our consolidated financial statements and results of operations.~~

~~In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230):~~ ~~Restricted Cash~~ (“ASU 2016-18”). ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statements of cash flows. The amended guidance will be effective for annual periods beginning after December 15, 2017. The amendments should be applied using a retrospective transition method to each period presented. Early adoption is permitted for any entity in any interim or annual period. We are currently evaluating the potential impact of ASU 2016-18this update on our consolidated financial statements and results of operations.

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

~~On November 4, 2016, we issued 921,000 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~~

As of ~~our 13.0% Convertible Notes due 2017 (“2017 Notes”), at an exchange rate of 20~~June 30, 2020 and 2019, we had 921,000 outstanding 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.Shares. 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,~~2020, there were ~~$21.3~~$5.0 million of Series A Preferred Shares and ~~$24.8~~$41.1 million of Series A Preferred Shares – related party ~~outstanding.~~outstanding (See Note 15. “Related party transactions”).

Pursuant to the Certificate of Designations for the Series A Preferred Shares ~~(the~~(as amended to date, 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 (as defined in the Certificate of Designations), 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. A change of control excludes a transaction with Mr. Mitchell, his family members, and their affiliates.

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,~~2020, we ~~accrued $1~~.8recorded $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 comprehensive (loss) income under the caption “Interest and other ~~expense.” On October 2, 2017,~~expense”. For the three and six months ended June 30, 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~~recorded $1.8 million and $3.2 million, respectively, in dividends on the Series A Preferred Shares, ~~(see Note 14. “Subsequent Events”)~~which is recorded in our consolidated statements of comprehensive (loss) income under the caption “Interest and other expense”.

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

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

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

	September 30, 2017			December 31, 2016			June 30, 2020			December 31, 2019
	(in thousands)						(in thousands)
Oil and natural gas properties, proved:
Turkey	$	204,367		$	196,743		$	120,414		$	167,446
Bulgaria		528			471			501			502
Total oil and natural gas properties, proved		204,895			197,214			120,915			167,948
Oil and natural gas properties, unproved:
Turkey		25,730			21,109			10,414			12,978
Total oil and natural gas properties, unproved		25,730			21,109			10,414			12,978
Gross oil and natural gas properties		230,625			218,323			131,329			180,926
Accumulated depletion		(126,923	)		(115,401	)		(84,606	)		(101,232	)
Net oil and natural gas properties	$	103,702		$	102,922		$	46,723		$	79,694

At June 30, 2017, we recorded foreign currency translation adjustments, which increased proved properties and decreased accumulated other comprehensive loss within shareholders’ equity on our consolidated balance sheet.

~~At September 30, 2017~~2020 and December 31, ~~2016,~~2019, we excluded ~~$0.4~~$0.3 million and ~~$1.9~~$0.2 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,~~2020, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included ~~$12.3~~$3.4 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~~$56.8 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

At December 31, ~~2016,~~2019, the capitalized costs of our oil and natural gas properties included ~~$13.2~~$5.0 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~~$63.8 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~~six months ended ~~September~~June 30, ~~2017,~~2020, we recorded ~~$0.2~~$2.1 million of exploratory dry-hole costs and $18.2 million of impairment of proved properties, ~~and exploratory well costs~~ which are primarily measured using Level 3 inputs. During the three and six months ended June 30, 2019, we recorded $0.7 million and $5.8 million of exploratory dry-hole costs, respectively, which are primarily measured using Level 3 inputs.

As of ~~September~~June 30, ~~2017, we had $3.9 million of~~2020, 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, 2020			December 31, 2019
	(in thousands)						(in thousands)
Other equipment							$	1,101		$	1,121
Land								115			132
Inventory	$	9,488		$	10,704			7,032			3,209
Gas gathering system and facilities								76			172
Vehicles								242			304
Leasehold improvements, office equipment and software		7,543			7,280			4,570			5,264
Vehicles		361			364
Other equipment		2,007			1,925
Gross equipment and other property		19,399			20,273			13,136			10,202
Accumulated depreciation		(5,976	)		(5,237	)		(4,923	)		(5,378	)
Net equipment and other property	$	13,423		$	15,036		$	8,213		$	4,824

At ~~September~~June 30, ~~2017,~~2020, in addition to the above, we have classified ~~$3.6~~$3.2 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~~2020 and December 31, ~~2016,~~2019, we excluded ~~$13.1~~$10.3 million and ~~$14.4~~$10.3 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~~2020 and for the year ended December 31, ~~2016:~~2019:

	September 30, 2017			December 31, 2016			June 30, 2020			December 31, 2019
	(in thousands)						(in thousands)
Asset retirement obligations at beginning of period	$	4,833		$	9,237		$	4,749		$	4,667
Change in estimates		–			(7	)
Liabilities settled		(37	)		–			(791	)		–
Foreign exchange change effect		–			(1,604	)		(550	)		(519	)
Additions		–			16			–			388
Accretion expense		144			373			97			213
Asset retirement obligations at end of period		4,940			8,015		$	3,505		$	4,749
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~~loss under the caption “(Loss) gain on ~~commodity~~ derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on ~~commodity~~ derivative contracts.”

~~During the three months ended September 30, 2017 and 2016,~~On March 9, 2020, we ~~recorded~~unwound our three-way collar contract with DenizBank, which hedged approximately 1,000 Bbl/d of our oil production in Turkey. The three-way collar contract had a ~~net loss on commodity derivative contracts~~Brent floor of ~~$1.4 million and $0.2 million, respectively. During the nine months ended September 30, 2017 and 2016, we recorded~~$55.00, a ~~net gain on commodity derivative contracts~~Brent ceiling of ~~$0.3 million~~$72.90, and a ~~net loss~~Brent long call of ~~$2.4 million, respectively.~~$80.00, and was in place through April 30, 2020. We also unwound our swap contract with DenizBank, which hedged approximately 1,000 Bbl/d of our oil production in Turkey. The swap contract had a Brent strike price of $60.30 and was in place through December 31, 2020. In connection with these transactions, we received approximately $6.5 million. We used these proceeds to pay down the 2019 Term Loan to reduce our future interest expense.

On April 3, 2020, we entered into a new swap contract DenizBank, which hedged 1,975 barrels of oil per day. The swap contract is in place from May 2020 through February 2021, has an ICE Brent Index strike price of $36.00 per barrel, and is settled monthly.

At ~~September~~June 30, ~~2017 and December 31, 2016,~~2020, we had outstanding commodity 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, 2020

Weighted

Average

Quantity

Minimum

Maximum Price

Additional Call

Estimated Fair

Type

Period

(Bbl/day)

Price (per Bbl)

(per Bbl)

Ceiling

Value of Liability

(in thousands)

Swap

July 1, 2020 - February 28, 2021

1,975

36.00

(3,227

)

Total Estimated Fair Value of Liability

(3,227

)

At December 31, 2019, we had outstanding commodity derivative contracts with respect to our future crude oil production as set forth in the table below:

Fair Value of Derivative Instruments as of December 31, 2016

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

January 1, 2017 — December 31, 2017

296

$
47.50

$
61.00

$
(289
)
Collar

January 2, 2017 — December 31, 2017

445

$
50.00

$
61.50

(307
)
Collar

January 1, 2018 — February 28, 2018

458

$
50.00

$
61.50

(74
)
Collar

January 1, 2018 — May 31, 2018

298

$
47.50

$
61.00

(168
)
Total estimated fair value of liability

$
(838
)


				Weighted		Weighted
				Average		Average		Additional		Estimated Fair
		Quantity		Minimum		Maximum Price		Call Ceiling		Value of Asset
Type	Period	(Bbl/day)		Price (per Bbl)		(per Bbl)		(per Bbl)		(Liability)
										(in thousands)
Three-way collar	January 1, 2020 - April 30, 2020		1,000	$	55.00	$	72.90	$	80.00		21
Swap	January 1, 2020 - December 31, 2020		986	$	60.30		-		-		(987	)
Total Estimated Fair Value of Liability										$	(966	)

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) gain 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.”

On May 20, 2020, we entered into foreign exchange forward contracts to hedge against currency fluctuations between the TRY and USD. The forward contract settlement dates are from July through August, 2020 for $1.0 million at a strike price of 6.84 TRY to $1.00 USD.

At June 30, 2020, we had outstanding foreign exchange derivative contracts as set forth in the table below:

We did not have any outstanding foreign currency derivatives outstanding as of December 31, 2019.

During the three months ended June 30, 2020 and 2019, we recorded a net loss on derivative contracts of $3.2 million and $0.3 million, respectively.

During the six months ended June 30, 2020 and 2019, we recorded a net gain on derivative contracts of $4.3 million and a net loss of $0.4 million, respectively.

The following ~~table~~tables 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~~2020 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~~2020 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. The Credit Agreement is a master agreement pursuant to which DenizBank ~~A.S. (“DenizBank”).~~may make loans to TEMI from time to time pursuant to additional loan agreements.

On August 31, 2016, ~~DenizBank entered into a $30.0 million term loan with TEMI 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,~~November 17, 2017, DenizBank entered into a $20.4 million term loan (the “2017 Term Loan”) with TEMI ~~used approximately $22.9 million of~~under the ~~proceeds from the~~Credit Agreement.

~~The Term Loan bears~~bore 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 was 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.

On December 30, 2019, we repaid the 2017 Term Loan in full in accordance with its terms.

On May 28, 2018, DenizBank entered into a $10.0 million term loan (the “2018 Term Loan”) with TEMI under the Credit Agreement.

The 2018 Term Loan bore 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 was payable monthly and the principal on the 2018 Term Loan was 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.

On December 30, 2019, we repaid the 2018 Term Loan in full in accordance with its terms.

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 had a grace period through December 2019 during which no payments were due. Thereafter, accrued interest on the 2019 Term Loan was payable monthly, and the principal on the 2019 Term Loan was payable in 14 monthly installments of $1.4 million each.

On March 9, 2020, we unwound our three-way collar contract with DenizBank and received approximately $6.5 million in proceeds, which we used to pay down the 2019 Term Loan. As part of the pay down, DenizBank extended a grace period for principal repayments until July 2020, at which time we resumed principal payments for one monthly installment in July 2020 of $0.6 million and seven monthly installments of $1.4 million beginning in August 2020.The 2019 Term Loan matures in February 2021. Amounts repaid under the 2019 Term Loan may not be ~~re-borrowed,~~reborrowed, and early repayments under the 2019 Term Loan are subject to early

repayment fees. The 2019 Term Loan is guaranteed by Amity Oil International Pty Ltd (“Amity”), Talon Exploration, Ltd. (“Talon Exploration”), DMLP, Ltd. (“DMLP”), and TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”).

~~On April 27, 2017,~~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 Gundem real estate and Muratli real estate owned by Gundem (as defined in Note 15. “Related party transactions”), (iv) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras, and (v) 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 2019 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.

At ~~September~~June 30, ~~2017,~~2020, we had ~~$12.4~~$10.6 million outstanding under the 2019 Term Loan and no availability, and we were in compliance with ~~all of~~ the covenants in the 2019 Term ~~Loan~~Loan.

On April 10, 2020, we received loan proceeds in the amount of $626,000 under the PPP. The PPP, established as part of the Coronavirus Aid, Relief and Economic Security Act (“CARES Act”), provides for loans to qualifying businesses for amounts up to 2.5 times of the average monthly payroll expenses of the qualifying business. The loans are forgivable after 24 weeks as long as the borrower uses the loan proceeds for eligible purposes, including payroll, benefits, rent and utilities, and maintains its payroll levels. The amount of loan forgiveness will be reduced if the borrower terminates employees or reduces salaries during the 24-week period. The unforgiven portion of the PPP loan is payable over two years at an interest rate of 1%, with a deferral of payments for the first six months. We used the proceeds for purposes consistent with the PPP and believe that our use of the loan proceeds will meet the conditions for forgiveness for a majority of the loan.

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, with some containing 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.

Our operating and financing leases are included in 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 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 comprehensive (loss) income under the caption “Production”.

13Lease 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.

~~The 2017 Notes were issued pursuant to an indenture, dated~~Future non-cancelable minimum lease payments under our operating lease commitments as of ~~February 20, 2015 (the “Indenture”), between us and U.S. Bank National Association,~~June 30, 2020 were 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~~follows for 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”) entered into a $5.0 million draw down convertible promissory note (the “Note”) with ANBE Holdings, L.P. (“ANBE”), an entity owned by the adult children of the ~~Company’s chairman~~next five years and ~~chief executive officer, N. Malone Mitchell 3rd,~~thereafter:

As of June 30, 2020, the weighted average remaining lease term in years was 3.5 years, and ~~controlled by an entity managed by Mr. Mitchell~~the weighted average discount rate used was 7.55%.

Future non-cancelable minimum lease payments under our operating lease commitments as of December 31, 2019 were as follows for each of the next five years 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 proceeds from the sale of TBNG and terminated it.thereafter:

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

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

During 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew down our $1.0 million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we believe that the bank guarantee satisfies our contractual obligations, during 2012, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit for this contingency. In September 2016, management determined that, because it had received no communication from the Moroccan government since early 2013, the probability of payment of this contingency is remote. Therefore, the Company reversed the $6.0 million in contingent liabilities previously classified as liabilities held for sale.

During 2012, we were notified that the Bulgarian government may seek to recover approximately $2.0 million in contractual obligations under our Aglen exploration permit work program. Due to the Bulgarian government’s January 2012 ban on fracture stimulation and related activities, a force majeure event under the terms of the exploration permit was recognized by the 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~~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. The Supreme Court of Cessation held a court hearing on October 21, 2019. A ruling was issued on March 10, 2020, by virtue of which the Supreme Court of Cessation decided that the appeal of the Bulgarian Minister of Energy in its substance is inadmissible. The Bulgarian Minister of Energy has ~~not been rectified.~~ no further rights to appeal.

We ~~believe~~sell all of our Southeastern Turkey oil to TUPRAS pursuant to a domestic crude oil purchase and sale agreement between TUPRAS and TEMI. The price of the oil delivered pursuant to the purchase and sale agreement is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. In February 2019, Turkey entered into the Pricing Amendment to change the statutory pricing formula for purchases of Turkish domestic crude oil.

In November 2019, TUPRAS filed a lawsuit against us, and filed similar lawsuits against other domestic oil producers, in the Batman 4th Civil Court of First Instance seeking restitution from TEMI for alleged overpayments resulting from the implementation of the Pricing Amendment plus interest thereon. In addition, TUPRAS claimed that ~~Direct Bulgaria~~the Pricing Amendment violates the Constitution of the Republic of Turkey and seeks to have the Pricing Amendment cancelled. TEMI is ~~not under any obligation to fulfill~~vigorously defending against these allegations. Any adjustment arising out of the ~~work program until the force majeure event is rectified~~claims will be recorded when it becomes probable and ~~continue to vigorously defend this claim.~~measurable.

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~~2020 and ~~2016.~~2019, respectively. 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~~2020 and ~~2016, respectively.~~2019.

As of ~~September~~June 30, ~~2017,~~2020, we had approximately ~~$0.5~~$0.2 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of ~~0.7~~0.4 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~~2020 and ~~2016~~2019 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~~2020 and ~~2016~~2019 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,~~2020 and 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:

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

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, 2020
Total revenues	$	-		$	6,500		$	-		$	6,500
Loss from operations before income taxes		(3,456	)		(3,963	)		(54	)		(7,473	)
Capital expenditures	$	-		$	561		$	-		$	561
For the three months ended June 30, 2019
Total revenues	$	-		$	17,215		$	-		$	17,215
Loss from operations before income taxes		(2,667	)		6,756			(732	)		3,357
Capital expenditures	$	-		$	5,509		$	667		$	6,176
For the six months ended June 30, 2020
Total revenues	$	-		$	14,860		$	-		$	14,860
Loss from operations before income taxes		(6,972	)		(27,254	)		(177	)		(34,403	)
Capital expenditures	$	-		$	3,472		$	-		$	3,472
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
Segment assets
June 30, 2020	$	6,973		$	87,054		$	659		$	94,686
December 31, 2019	$	7,810		$	127,986		$	708		$	136,504

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,~~2020, we had ~~5.4~~14.6 million TRY (approximately ~~$1.5~~$2.1 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, 2020, we were a party to foreign exchange derivative contracts (See Note 7. “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~~2020 and December 31, ~~2016,~~2019, we were a party to commodity derivative contracts (See Note ~~6. “Commodity derivative~~7. “Derivative instruments”).

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

~~The following table summarizes~~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 ~~valuation~~carrying amount at June 30, 2020 and December 31, 2019, due to the short maturity of ~~our financial assets and liabilities as of September 30, 2017:~~those instruments.

The following table summarizes the valuation of our financial ~~assets and~~liabilities as of June 30, 2020:

The following table summarizes the valuation of our financial liabilities as of December 31, ~~2016:~~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
Liabilities:
Commodity derivative contracts	$	–	$	(838	)	$	–		$	(838	)	$	-	$	(966	)	$	-		$	(966	)
Disclosed but not carried at fair value
Liabilities:
Term Loan		-		-			(22,500	)		(22,500	)
2017 Notes		-		-			(13,554	)		(13,554	)
2019 Term Loan													-		-			(17,333	)		(17,333	)
Total	$	–	$	(838	)	$	(36,054	)	$	(36,892	)	$	-	$	-		$	(17,333	)	$	(17,333	)

We remeasure our derivative contracts on a recurring basis, with changes flowing through earnings. At ~~September~~June 30, ~~2017~~2020 and December 31, ~~2016,~~2019, the fair values of ~~our~~the 2019 Term Loan ~~and the 2017 Notes~~ were estimated using a discounted cash flow analysis based on unobservable Level 3 inputs, including our own credit risk associated with the loans payable.

17On February 24, 2020, we sold the shares in our wholly-owned subsidiary Petrogas Petrol Gaz ve Petrokemya Urunleri Insaat Sanayive Ticaret A.S. (“Petrogas”), which held the Edirne, Dogu Adatepe, Adatepe, and Gocerler production leases (the “Petrogas Leases”) and 14 employees, to Reform Ham Petrol Dogal Gaz Arama Uretim Sanayi ve Ticaret A.S. (“Reform”) in exchange for $1.5 million and a release of all plugging and abandonment obligations for 65 wells on the Petrogas leases and certain former leases.

For the three months ended March 31, 2020, we recorded a net loss of $10.1 million on the sale of Petrogas. The loss primarily related to the reclassification of the accumulated foreign currency translation adjustment that was realized into earnings from accumulated other comprehensive loss within shareholders’ equity and presented below:

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~~2020, we had $~~0.7~~0.2 million of outstanding receivables and $~~0.3~~0.2 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~~2020, we had $0.3 million of outstanding receivables and $3$.03.1 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.

On June 30, 2020, TransAtlantic USA entered into a landlord consent (the “Consent”) with Longfellow, pursuant to which Longfellow consented to the continuing of that Sublease on a month-to-month basis with the rights of each of TransAtlantic USA and Longfellow to terminate the Sublease upon thirty days’ written notice.

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 expired on June 30, 2020. 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 June 13, 2012, we ~~repaid the ANBE Note in full with proceeds from~~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, to Viking International. We have indemnified a third party for any liability relating to the payment of the ~~Company, to Viking International Limited.~~ Account Payable.

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

acknowledged that (i) while the sale of Dalea’s interest in Viking Services enabled us to take the position that the Original Note was accelerated in accordance with its terms, the principal purpose of including the acceleration events in the Original Note was to ensure that certain oilfield services provided by Viking Services to us would continue to be available to us, and (ii) such services will now be provided pursuant to the 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.~~PSI. The maturity date of the Amended Note was extended to June 13, 2019. The interest rate on the Amended Note remains at 3.0% per annum and continues to be guaranteed by Mr. Mitchell. The Amended Note contains customary events of default.

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

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

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 Dalea and we agreed to extend the maturity date of the Note to February 26, 2021 (unless otherwise accelerated in accordance with the terms of the ~~Pledge Agreement.~~ 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.

During the six months ended June 30, 2020, we reduced the principal amount of the Note by $0.2 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 Term Loan,~~certain loans, 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 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 Term Loan,~~certain loans, 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,~~2020, 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 2, 2017,~~July 30, 2020, 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.

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.

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~~5,819,908 common shares to holders of the Series A Preferred Shares as payment of the ~~September~~June 30, ~~2017~~2020 quarterly dividend on the Series A Preferred Shares. Each common share was issued at a ~~value~~price of ~~$0.7108~~$0.3165 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.~~July 8, 2020.

On August 7, 2020, we entered into an Agreement and Plan of Merger (the “Merger Agreement”), with TAT Holdco LLC, a Texas limited liability company (“Parent”) controlled by a group of holders (the “Preferred Shareholder Group”) representing 100% of our outstanding Series A Preferred Shares, and TAT Merger Sub LLC, a Texas limited liability company and wholly-owned subsidiary of Parent (“Merger Sub”), pursuant to which we will merge with and into Merger Sub and each of our issued and outstanding common shares (other than the Excluded Shares and Dissenting Shares (each as defined in the Merger Agreement)) will be canceled and will be converted automatically into the right to receive $0.13 in cash (the “Merger Consideration”).

The members of the Preferred Shareholder Group are Longfellow, Dalea, the Alexandria Nicole Mitchell Trust 2005, the Elizabeth Lee Mitchell Trust 2005, the Noah Malone Mitchell Trust 2005, Stevenson Briggs Mitchell, KMF Investments Partners, LP, West Investment Holdings, LLC, Randall I. Rochman, and Betsy Rochman. Longfellow and Dalea are affiliates of our chief executive officer and chairman of our board of directors, N. Malone Mitchell 3rd.

A special committee comprised entirely of independent and disinterested directors of our board of directors voted unanimously to recommend to our board of directors that it, and thereafter our board of directors (other than N. Malone Mitchell 3rd, Randall I. Rochman, and Jonathon T. Fite) voted unanimously to approve and declare, among other things, that (i) the merger, the Merger Agreement, a guaranty made in connection with the Merger Agreement (collectively, the “Merger Documents”) and the transactions contemplated by the Merger Documents are procedurally fair to, and advisable and in the best interests of, us and our shareholders, including our unaffiliated shareholders, and (ii) the Merger Consideration is fair to, both from a financial point of view and otherwise, advisable and in the best interests of our shareholders, including our unaffiliated shareholders. Seaport Gordian Energy LLC served as the financial advisor to the special committee in connection with the merger and the Merger Agreement.

If the merger is consummated, our common shares will be delisted from the NYSE American Exchange and Toronto Stock Exchange and deregistered under the Exchange Act as soon as practicable following the effective time of the merger.

Our shareholders will be asked to vote on the adoption and approval of the Merger Agreement, a Bermuda statutory merger agreement and the transactions contemplated thereby at a special meeting of our shareholders that will be held on a date to be announced. Consummation of the merger is subject to customary conditions, including without limitation, the adoption and approval of the Merger Agreement and the Bermuda statutory merger agreement by holders of our common shares by at least 75% of the votes cast and holders of Series A Preferred Shares with at least 75% of the votes cast, in each case at a duly convened meeting of our shareholders at which a quorum is present. In connection with the execution of the Merger Agreement, the members of the Preferred Shareholder Group have entered into a voting agreement pursuant to which such shareholders have agreed to vote in favor of the merger and the adoption of the Merger Agreement, subject to the limitations set forth in the voting agreement.

In addition, on August 7, 2020, we entered into a Loan and Security Agreement (the “Loan Agreement”) with Dalea Investment Group, LLC (the “Lender”), an entity controlled by the Preferred Shareholder Group. Pursuant to the Loan Agreement, the Lender has committed to lend us an aggregate principal amount of up to $8.0 million (the “Loan”). Advances shall be made available by Lender and applied by us in accordance with a budget agreed to by us and the Lender and subject to milestones set forth in the Loan Agreement. We intend to use the proceeds of the Loan to finance our and our subsidiaries working capital needs in accordance with the budget.

The outstanding borrowings under the Loan Agreement bear interest at a rate equal to 10% per annum. Principal on the Loan does not amortize and is required to be repaid in full on the maturity date of August 7, 2021. The Loan may be optionally prepaid in whole or in part from time to time without fee, premium, or penalty.

Our obligations under the Loan Agreement are secured by all of our present and future accounts, chattel paper, commercial tort claims, commodity accounts, commodity contracts, contracts receivable, deposit accounts, documents, financial assets, general intangibles, instruments, investment property (including all of our right, title, and interest in and to all of the capital stock of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide Ltd., each our wholly-owned direct subsidiary), letters of credit,

letter of credit rights, payment intangibles, securities, notes receivable, choses of action, security accounts, and security entitlements, now or hereafter owned, held, or acquired.

The Loan Agreement contains representations, warranties, covenants, and events of default.

On August 4, 2020, we entered into an agreement (the “Farmout Agreement”) with Longfellow, an affiliate of Mr. Mitchell, to farm-out a petroleum license held by TEMI, our wholly owned subsidiary, for the exploration and production of oil and natural gas resources covering approximately 14,500 total acres in the region of Southeast Turkey (the “License”).

Under the regulatory provisions governing the License, we must undertake operations to restore oil production or establish new production, from lands covered by the License on or before December 1, 2020, in order to perpetuate the term of the License past that date. We have decided not to undertake such operations and have agreed to farmout the License to Longfellow in accordance with the Farmout Agreement.

Under the terms of the Farmout Agreement, Longfellow has the right to re-enter the Goksu 3H wellbore, sidetrack the wellbore, and deepen the well to test the Bedinan formation, or other formations as encountered. In the event the operations for the Goksu 3H well result in a dry hole, Longfellow is required to reimburse us for all actual costs incurred by us with plugging the well and restoring the surface drillsite. Thereupon, the Farmout Agreement shall terminate.

In the event the operations for the Goksu 3H ST well result in a commercial producer of oil and/or gas, (i) (x) we shall install the appropriate equipment/facilities needed to produce the well and make such necessary arrangements to sell the oil and/or gas produced, utilizing such production contracts as we deem most favorable to maximize the commerciality of the well, and (y) Longfellow is required to reimburse us for all costs incurred by us to conduct such operations, and (ii) Longfellow shall grant us an overriding royalty interest of 5% in all sales of oil and gas from such well and any other wells thereafter drilled or produced on the License. The overriding royalty interest shall bear its share of production/severance taxes, and any gathering, transportation, processing, or marketing fees/costs but none of the well costs.

If completed operations for the Goksu 3H well result in perpetuation of the License, Longfellow is entitled to an assignment of all of the our rights in and to the License, and, upon earning such assignment, Longfellow shall assume all responsibility and liability from us as to the License. The terms of the Farmout Agreement shall apply to any such additional well drilled pursuant thereto in all respects as if such additional well was the Goksu 3H well. Longfellow shall have the right, at any time after a transfer has been approved pursuant to the provisions of the Farmout Agreement, and upon 30 days written notice, to take over as operator of the License from us.

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,~~2020, we held interests in ~~approximately 0.5 million~~365,171 and 162,800 net acres of developed and undeveloped oil and natural gas properties in Turkey and ~~Bulgaria.~~Bulgaria, respectively. As of ~~November 6, 2017,~~August 7, 2020, approximately ~~47.3%~~50.5% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors. Persons and entities associated with Mr. Mitchell also owned 739,000 Series A Preferred Shares. Mr. Mitchell’s affiliates are currently prohibited from converting any of their Series A Preferred Shares to common shares if such conversion would cause Mr. Mitchell or his affiliates to obtain beneficial ownership in excess of 49.9% of the outstanding common shares; however, Mr. Mitchell, upon 61 days’ prior notice, may increase or decrease such percentage cap.

Merger Agreement. On August 7, 2020, we entered into the Merger Agreement, with Parent, an entity controlled by the Preferred Shareholder Group, which represents 100% of our outstanding Series A Preferred Shares, and Merger Sub, pursuant to which we will merge with and into Merger Sub and each of our issued and outstanding common shares (other than the Excluded Shares and Dissenting Shares (each as defined in the Merger Agreement)) will be canceled and will be converted automatically into the right to receive the Merger Consideration.

A special committee comprised entirely of independent and disinterested directors of our board of directors voted unanimously to recommend to our board of directors that it, and thereafter our board of directors (other than N. Malone Mitchell 3rd, Randall I. Rochman, and Jonathon T. Fite) voted unanimously to approve and declare, among other things, that (i) the merger, the Merger Documents and the transactions contemplated by the Merger Documents are procedurally fair to, and advisable and in the best interests of, us and our shareholders, including our unaffiliated shareholders, and (ii) the Merger Consideration is fair to, both from a financial point of view and otherwise, advisable and in the best interests of our shareholders, including our unaffiliated shareholders.

There can be no assurance that the closing conditions will be satisfied, or that the merger will be completed within the required time period pursuant to the Merger Agreement. See Item 1A. “Risk Factors – Risks Related to the Merger.”

Loan Agreement. In addition, on August 7, 2020, we entered into the Loan Agreement with the Lender, an entity controlled by the Preferred Shareholder Group. Pursuant to the Loan Agreement, the Lender has committed to lend us the Loan. Advances shall be made available by Lender and applied by us in accordance with a budget agreed to by us and the Lender and subject to milestones set

forth in the Loan Agreement. We intend to use the proceeds of the Loan to finance our and our subsidiaries working capital needs in accordance with the budget.

The Loan Agreement contains representations, warranties, covenants, and events of default.

Farmout Agreement. On August 4, 2020, we entered into the Farmout Agreement with Longfellow, an affiliate of Mr. Mitchell, to farm-out the License. Under the regulatory provisions governing the License, we must undertake operations to restore oil production or establish new production, from lands covered by the License on or before December 1, 2020, in order to perpetuate the term of the License past that date. We have decided not to undertake such operations and have agreed to farmout the License to Longfellow in accordance with the Farmout Agreement.

~~A summary of~~The following summarizes our financial and operational performance for the ~~third~~second quarter of ~~2017 include:~~2020:

During the third quarter of 2017, we further developed our oil fields in Southeastern Turkey, where we tested three wells. The following summarizes our operations by location during the third quarter of 2017:

During 2020, we plan to continue our recompletion, workover, and production optimization plans in our producing fields, including Bahar, Yeniev, Goksu, Pinar, Southeast Bahar, Catak, and Karagoz. Drilling additional wells will be dependent on oil prices.

Bahar Field. In the ~~Bahar-11 well throughout the third~~second quarter of ~~2017~~2020, we completed construction and began operations of the second phase of electrification of the Bahar field to replace diesel generated power with gas generated power.

Arpatepe Field. In the second quarter of 2020, we started the initial phase of a full field waterflood project for the Arpatepe field. Ultimately, we plan to recomplete four wells in the ~~Bedinan, Dadas,~~field as water injection wells and ~~Hazro formations. Commercial oil was discovered in all three formations with~~one well as a ~~combined test rate of 280 barrels of oil per day (“Bopd”). The well was brought~~water source well. Additionally, we plan to build a central facility and gathering system to handle increased volumes. Based on ~~production at a commingled rate of 140 Bopd.~~budget and partner considerations the timeline for full implementation is subject to change.

~~Testing continued on~~During 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~~second quarter of ~~2017~~2020, we conducted extended reservoir injection tests to ~~establish the potential of these intervals as well as up-hole potential~~both test injectivity and confirm modelling assumptions. The test was consistent with expectations, and we expect to commence continuous injection starting in the ~~Dadas, Hazro,~~second half of 2020.

During 2020, we plan to continue our recompletion, workover, and ~~Mardin formations.~~

~~Operations on the Pinar-1ST well were temporarily suspended during the third quarter of 2017 due to priority repair and maintenance workover~~production optimization operations in the ~~Bahar and~~ Selmo ~~fields. Testing will resume in the fourth quarter of 2017.~~field.

We ~~continue to evaluate our position in Bulgaria with updated geologic models and continue to market a joint venture exploration program for our assets~~are currently evaluating future activity in Bulgaria.

~~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~~2020 to range between ~~$3.0~~$1.0 million and ~~$4.5~~$1.5 million. We expect net field capital expenditures during ~~the remainder 2017 to~~2020 will include between $0.5 million and ~~$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.~~

~~Bulgaria.~~ ~~We intend to drill on our Koynare license during 2018 and plan to continue working on our geologic model for additional prospects. In addition, we continue to market~~implement 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~~waterflood in the ~~Delvina gas~~Bedinan sandstone in the Arpatepe 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,~~and up to ~~Ionian Gas Company Ltd. (“Ionian”) in exchange~~$0.5 million 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,recompletions. Our projected 2020 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~~2019 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~~2020 Compared to Three Months Ended ~~September 30, 2016~~June 3, 2019

Our results of ~~continuing~~ operations for the three months ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019 were as follows:

	Three Months Ended September 30,						Change			Three Months Ended June 30,						Change
	2017			2016			2017-2016			2020			2019			2020-2019
	(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	)		199			253			(54	)
Natural gas (Mmcf)		58			283			(225	)		1			48			(47	)
Total production (Mboe)		263			386			(123	)		199			261			(62	)
Average daily sales volumes (Boepd)		2,862			4,191			(1,329	)		2,185			2,873			(688	)
Average prices:
Oil (per Bbl)	$	47.88		$	39.99		$	7.89		$	32.60		$	66.57		$	(33.97	)
Natural gas (per Mcf)	$	4.82		$	6.89		$	(2.07	)	$	5.46		$	5.41		$	0.05
Oil equivalent (per Boe)	$	47.18		$	40.15		$	7.03		$	32.60		$	65.54		$	(32.94	)
Revenues:
Oil and natural gas sales	$	12,424		$	15,483		$	(3,059	)	$	6,483		$	17,134		$	(10,651	)
Sales of purchased natural gas		-			1,171			(1,171	)
Other		251			5			246			17		$	81			(64	)
Total revenues	$	12,675		$	16,659		$	(3,984	)		6,500			17,215			(10,715	)
Costs and expenses (income):
Production	$	2,997		$	3,070		$	(73	)		2,380			2,712			(332	)
Transportation and processing											961			1,221			(260	)
Exploration, abandonment and impairment		141			1,531			(1,390	)		-			666			(666	)
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			(108	)
General and administrative		2,532			2,659			(127	)		2,394			2,690			(296	)
Depletion		4,015			6,918			(2,903	)		2,403			3,314			(911	)
Depreciation and amortization		257			362			(105	)		114			128			(14	)
Interest and other expense		2,322			3,836			(1,514	)		2,396			2,753			(357	)
Interest and other income		(182	)		(1,009	)		827			(292	)		(221	)		(71	)
Foreign exchange loss	$	48		$	390		$	(342	)		356			115			241
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	)
Gain (loss) on derivative contracts:
Cash settlements on derivative contracts											(79	)		-			(79	)
Change in fair value on derivative contracts											(3,138	)		(323	)		(2,815	)
Total loss on derivative contracts											(3,217	)		(323	)		(2,894	)
Oil and natural gas costs per Boe:
Production	$	9.84		$	6.96		$	2.88		$	10.51		$	9.07		$	1.44
Depletion	$	13.34		$	15.70		$	(2.36	)	$	10.58		$	11.09		$	(0.51	)

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased ~~$3.1 million~~ to ~~$12.4~~$6.5 million for the three months ended ~~September~~June 30, ~~2017,~~2020 from ~~$15.5~~$17.1 million ~~realized in~~for the same period in ~~2016.~~2019. 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 $32.94 per Boe to ~~$47.18~~$32.60 per Boe for the three months ended ~~September~~June 30, ~~2017,~~2020 from ~~$40.15~~$65.54 per Boe for the same period in ~~2016.~~

~~Sales~~2019. The decrease was also due to a decrease in our average daily sales volumes of ~~Purchased Natural Gas.~~ ~~Sales of purchased natural gas~~688 Boe per day (“Boepd”) for the three months ended ~~September~~June 30, ~~2017~~2020 as compared to the same period in 2019.

Production. Production expenses decreased to ~~zero~~$2.4 million, or $10.51 per Boe, for the three months ended June 30, 2020 from $2.7 million, or $9.07 per Boe, for the same period in 2019. The decrease was primarily due to a decrease in contract labor costs and personnel expenses.

Transportation and Processing. Transportation and processing expense decreased to $1.0 million for the three months ended June 30, 2020 from $1.2 million for the same period in ~~2016.~~2019. The decrease in transportation expenses was primarily due to the decrease in our average daily sales volumes of 688 Boepd.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment cost decreased to zero for the three months ended June 30, 2020 from $0.7 million for the same period in 2019. The decrease was due to the ~~divestiture~~exploratory dry hole write-off of ~~TBNG~~ the Deventci R-1 well in ~~February 2017.~~2019.

~~Production expenses~~General and Administrative. General and administrative expense decreased to $2.4 million for the three months ended ~~September~~June 30, ~~2017 decreased to $3.0~~2020 from $2.7 million ~~or $9.84 per Boe, from $3.1 million, or $6.81 per Boe,~~ for the same period in ~~2016.~~2019. The ~~increase in production expense per Boe~~decrease was primarily due to a decrease in ~~our sales volumes during the period.~~

~~Exploration, Abandonment~~personnel, travel and ~~Impairment.~~ ~~Exploration, abandonment and impairment costs for the three months ended September 30, 2017 decreased $1.4 million~~office expenses compared to ~~$0.1 million from $1.5 million for~~ the same period in ~~2016. During the three months ended September 30, 2017, we incurred $0.1 million in proved property impairment, minimal exploratory dry hole costs and no unproved property impairment.~~

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

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

~~General and Administrative.~~ General and administrative expense was $2.5 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.2019.

Depletion. Depletion expense decreased to ~~$4.0~~$2.4 million, or ~~$13.34~~$10.58 per Boe, for the three months ended ~~September~~June 30, ~~2017, compared to $6.9~~2020 from $3.3 million, or ~~$15.70~~$11.09 per Boe, for the same period of ~~2016.~~2019. The decrease was primarily due to a reduction in the depletable basis of our oil and gas properties and a decrease in production ~~volumes as well as no depletion expense recorded for TBNG as a result of the divestiture in February 2017.~~volumes.

Interest and Other Expense. Interest and other expense decreased to ~~$2.3~~$2.4 million for the three months ended ~~September~~June 30, ~~2017, compared to $3.8~~2020 from $2.8 million for the same period in ~~2016.~~2019. The decrease was ~~primarily~~ due to our lower average debt balances outstanding during the three months ended ~~September~~June 30, ~~2017~~2020 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, 2016.2019.

Foreign Exchange Loss. We recorded a foreign exchange loss of ~~$48,000 during~~$0.4 million for the three months ended ~~September~~June 30, ~~2017,~~2020 as compared to a loss of ~~$0.4~~$0.1 million infor the same period in ~~2016.~~2019. 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~~2020 was due to a decrease in the value of the TRY compared to the ~~U.S. Dollar.~~USD.

Gain (Loss) on ~~Commodity~~ Derivative Contracts. ~~During~~We recorded a net gain on derivative contracts of $3.2 million for the three months ended ~~September~~June 30, ~~2017, we recorded a net loss on commodity derivative contracts of $1.4 million,~~2020 as compared to a net loss of ~~$0.2~~$0.3 million for the same period in ~~2016.~~2019. During the three months ended ~~September~~June 30, ~~2017,~~2020, we recorded a ~~$1.4~~$3.1 million ~~loss~~gain to mark our ~~commodity~~currency derivative contracts to their fair ~~value.~~value and a $0.1 million loss on settled contracts. During the same period in ~~2016,~~2019, we recorded a ~~$2.9~~$0.3 million loss to mark our derivative contracts to their fair ~~value and a $2.7 million gain on settled contracts.~~value.

~~Other Comprehensive Income (Loss).~~ We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. Dollar reporting currency. Foreign currency translation adjustment for the 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~~2020 Compared to ~~Nine~~Six Months Ended ~~September~~June 30, ~~2016~~2019

Our results of ~~continuing~~ operations for the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019 were as follows:

	Nine Months Ended September 30,						Change			Six Months Ended June 30,						Change
	2017			2016			2017-2016			2020			2019			2020-2019
	(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	)		416			523			(107	)
Natural gas (Mmcf)		308			1,152			(844	)		58			98			(40	)
Total production (Mboe)		909			1,216			(307	)		426			539			(113	)
Average daily sales volumes (Boepd)		3,331			4,437			(1,106	)		2,341			2,977			(636	)
Average prices:
Oil (per Bbl)	$	45.42		$	37.20		$	8.22		$	34.99		$	67.82		$	(32.83	)
Natural gas (per Mcf)	$	4.89		$	7.02		$	(2.13	)	$	4.33		$	5.68		$	(1.35	)
Oil equivalent (per Boe)	$	44.51		$	37.98		$	6.53		$	34.79		$	66.81		$	(32.02	)
Revenues:
Oil and natural gas sales	$	40,475		$	46,171		$	(5,696	)	$	14,826		$	35,994		$	(21,168	)
Sales of purchased natural gas		654			3,717			(3,063	)
Other		323			35			288			34			262			(228	)
Total revenues	$	41,452		$	49,923		$	(8,471	)		14,860			36,256			(21,396	)
Costs and expenses (income):
Production	$	8,798		$	9,025		$	(227	)		5,899			5,214			685
Transportation and processing											2,121			2,540			(419	)
Exploration, abandonment and impairment		249			2,964			(2,715	)		20,338			5,779			14,559
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											45			185			(140	)
General and administrative		9,303			11,401			(2,098	)		4,746			5,744			(998	)
Depletion		12,330			21,745			(9,415	)		5,280			6,894			(1,614	)
Depreciation and amortization		694			1,308			(614	)		226			264			(38	)
Interest and other expense		6,981			9,106			(2,125	)		4,608			5,231			(623	)
Interest and other income		(663	)		(1,411	)		748			(413	)		(395	)		(18	)
Foreign exchange loss	$	1,055		$	659		$	396			484			1,388			(904	)
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
Gain (loss) on derivative contracts:
Cash settlements on derivative contracts											6,468			-			6,468
Change in fair value on derivative contracts											(2,172	)		(433	)		(1,739	)
Total (loss) gain on derivative contracts											4,296			(433	)		4,729
Oil and natural gas costs per Boe:
Production	$	8.43		$	6.50		$	1.93		$	12.13		$	8.47		$	3.66
Depletion	$	11.86		$	16.65		$	(4.79	)	$	10.84		$	11.20		$	(0.36	)

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased ~~$5.7 million~~ to ~~$40.5~~$14.8 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2020 from ~~$46.2~~$36.0 million ~~realized in~~for the same period in ~~2016.~~2019. The decrease was primarily due to a decrease in our sales volumes of 307 Mboe for the nine months ended September 30, 2017 compared to the same period in 2016, primarily due to a decrease of 116 Mboe in oil production in the Selmo oil field and a 110 Mboe decrease from the divestiture of TBNG in February 2017. This was partially offset by an increase in the average realized price per Boe. Our average price received ~~increased $6.53~~decreased $32.02 per Boe to ~~$44.51~~$34.79 per Boe for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2020 from ~~$37.98~~$66.81 per Boe for the same period in ~~2016.~~

~~Sales~~2019. The decrease was also due to a decrease in our average daily sales volumes of ~~Purchased Natural Gas.~~ ~~Sales of purchased natural gas~~636 Boepd for the ~~nine~~six months ended ~~September~~June 30, ~~2017 decreased~~2020 as compared 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.~~2019.

Production. Production expenses increased to $5.9 million, or $12.13 per Boe, for the ~~nine~~six months ended ~~September~~June 30, ~~2017 decreased to $8.8~~2020 from $5.2 million, or ~~$8.43 per Boe, from $9.0 million, or $6.50~~$8.47 per Boe, for the same period in ~~2016.~~2019. The increase ~~in production expense per Boe~~ was primarily due to aan increase in contract labor costs and personnel expenses.

Transportation and Processing. Transportation and processing expense decreased to $2.1 million for the six months ended June 30, 2020 from $2.5 million for the same period in 2019. The decrease in transportation expenses was primarily due to the decrease in our average daily sales volumes ~~during the period.~~of 636 Boepd.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment ~~costs~~cost increased to $20.3 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017 decreased $2.7 million to $0.2 million,~~2020 from ~~$3.0~~$5.8 million for the same period in ~~2016. During the nine months ended September 30, 2017, we incurred $0.2 million in~~2019. The increase was due to proved property ~~impairment, minimal~~impairments of our Selmo and Bahar fields due to the oil price decline and the exploratory dry hole ~~costs~~write-off of the Bati-Yasince well.

~~Cost of Purchased Natural Gas.~~ ~~Cost of purchased natural gas~~ General and administrative expense decreased to $4.7 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017 decreased to $0.6 million~~2020 from ~~$3.3~~$5.7 million for the same period in ~~2016.~~2019. The decrease was primarily due to ~~the divestiture of TBNG~~a decrease in ~~February 2017.~~

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

~~General and Administrative.~~ General and administrative expense was $9.3 million for the nine months ended September 30, 2017, compared to $11.4 million for the same period in 2016. Our general and administrative expenses decreased $2.1 million due to a $1.6 million decrease in legal, accounting and other services and a $0.8 million decrease in personnel expenses, which was partially offset by an increase in office expenses of $0.3 million.2019.

Depletion. Depletion expense decreased to ~~$12.3~~$5.3 million, or ~~$11.86~~$10.84 per Boe, for the ~~nine~~six months ended ~~September~~June 30, ~~2017, compared to $21.7~~2020 from $7.0 million, or ~~$16.65~~$11.20 per Boe, for the same period of ~~2016.~~2019. The decrease was primarily due to a reduction in the depletable basis of our oil and gas properties and a decrease in production ~~volumes as well as no depletion expense recorded for TBNG after the divestiture in February 2017.~~volumes.

Interest and Other Expense. Interest and other expense decreased to ~~$7.0~~$4.6 million for the ~~nine~~six months ended ~~September~~June 30, ~~2017, compared to $9.1~~2020 from $5.2 million for the same period in ~~2016.~~2019. The decrease was ~~primarily~~ due to our lower average debt balances outstanding during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 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. 2019.

Foreign Exchange Loss. We recorded a foreign exchange loss of ~~$1.1~~$0.5 million ~~during~~for the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2020 as compared to ~~a loss of $0.7~~$1.4 million infor the same period in ~~2016.~~2019. 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~~2020 was due to a decrease in the value of the TRY compared to the ~~U.S. Dollar.~~USD.

Gain (Loss) on ~~Commodity~~ Derivative Contracts. ~~During the nine months ended September 30, 2017, we~~We recorded a net gain on ~~commodity~~ derivative contracts of ~~$0.3~~$4.3 million for the six months ended June 30, 2020 as compared to a net loss of ~~$2.4~~$0.4 million for the same period in ~~2016.~~2019. During the ~~nine~~six months ended ~~September~~June 30, ~~2017,~~2020, we recorded a ~~$0.3~~$2.2 million ~~gain~~loss to mark our ~~commodity~~currency derivative contracts to their fair value and a ~~$32,000~~$6.5 million gain on settled contracts. During the same period in ~~2016,~~2019, we recorded a ~~$6.6~~$0.4 million loss to mark our derivative contracts to their fair ~~value and a $4.2 million gain on settled contracts.~~value.

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

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

For the ~~quarter~~three months ended ~~September~~June 30, ~~2017,~~2020, we incurred ~~$6.0~~$0.6 million in capital expenditures, including seismic and corporate expenditures, as compared to ~~$1.5~~$6.2 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.~~2019.

We expect our net field capital expenditures for the remainder of ~~2017~~2020 to range between ~~$3.0~~$1.0 million and ~~$4.5~~$1.5 million. We expect net field capital expenditures during ~~the remainder 2017 to~~2020 will include between $0.5 million and ~~$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 to implement a waterflood in the Bedinan sandstone in the Arpatepe field and up to $0.5 million for 3D seismic. Additionally, expenses for the remainder of 2017 associated with the 2018 drilling program are anticipated to be $1.0 million. We expect cash on hand and cash flow from operations will be sufficient to fund our 2017 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources.recompletions. Our projected ~~2017~~2020 capital expenditure budget is subject to ~~change.~~change.

Net cash provided by operating activities ~~from continuing operations~~ during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 was ~~$16.1~~$10.3 million, a decrease from net cash provided by operating activities ~~from continuing operations~~ of ~~$19.6~~$10.6 million for the same period in ~~2016.~~2019. The decrease was primarily due to a decrease in our ~~total revenues.~~revenues partially offset by changes in our current assets and current liabilities.

Net cash ~~provided by~~used in investing activities ~~from continuing operations~~ during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 was ~~$4.9~~$2.2 million, ~~an increase~~a decrease from net cash ~~provided by~~used in investing activities ~~from continuing operations~~ of ~~$2.7~~$15.7 million for the same period in ~~2016.~~2019. The ~~increase~~decrease was primarily due to a decrease in our capital expenditures compared to the ~~proceeds received from the sale of TBNG partially offset by an increase~~same period in ~~capital expenditures.~~2019.

Net cash used in financing activities ~~from continuing operations~~ during the ~~nine~~six months ended ~~September~~June 30, ~~2017~~2020 was ~~$29.7~~$8.8 million, ~~an increase~~a decrease from net cash ~~used in~~provided by financing activities ~~from continuing operations~~ of ~~$7.8~~$10.1 million for the same period in ~~2016.~~2019. The ~~increase~~decrease was primarily due to a decrease in our outstanding ~~indebtedness.~~loans.

AsOur primary sources of ~~September 30, 2017, we had $12.4 million of indebtedness, not including $7.9 million of trade payables, as further described below. We believe that~~liquidity for 2020 were our cash and cash equivalents, cash flow from operations, ~~will be sufficient~~the sale of assets and borrowings under the U.S. Paycheck Protection Program (“PPP”) loan. At June 30, 2020, we had cash and cash equivalents of $8.6 million, $11.3 million in short-term debt, and a working capital surplus of $1.0 million, compared to ~~meet~~cash and cash equivalents of $9.7 million, $2.9 million in long-term debt, $17.1 million in short-term debt and a working capital surplus of $2.0 million at December 31, 2019.

As a result of the decline in Brent crude prices, the current near term price outlook and resulting lower current and projected cash flows from operations, we have reduced our ~~normal operating requirements and to fund~~ planned capital expenditures ~~during~~to those necessary for production lease maintenance and those projecting a return on invested capital at current realized prices. In order to mitigate the ~~next 12 months.~~ impact of reduced prices on our 2020 cash flows and liquidity, we implemented cost reduction measures to reduce our operating costs and general and administrative expenses. In connection therewith, we intend to prioritize funding operating expenditures over general and administrative expenditures, whenever possible.

On March 9, 2020, we unwound our commodity derivative contracts with respect to our future crude oil production. In connection with these transactions, we received $6.5 million. In order to reduce future interest expense, we used these proceeds to pay down the 2019 Term Loan. On April 3, 2020, we entered into a new swap contract with DenizBank, which hedged approximately 2,000 barrels of oil per day. The swap contract is in place from May 2020 through February 2021, has an ICE Brent Index strike price of $36.00 per barrel, and is settled monthly. Therefore, DenizBank is required to make a payment to us if the average monthly ICE Brent Index price is less than $36.00 per barrel, and we are required to make a payment to DenizBank if the average monthly ICE Brent Index price is greater than $36.00 per barrel.

TUPRAS purchases substantially all of our crude oil production. The price of substantially all of the oil delivered pursuant to the purchase and sale agreement with TUPRAS is tied to Arab Medium oil prices adjusted upward based on an API adjustment, Suez Canal tariff costs, and freight charges. Between March 2020 and May 2020, there was a significant widening of the differential between the average monthly ICE Brent Index price and our realized oil prices. In 2018 and 2019, the average monthly ICE Brent Index Price exceeded our realized oil prices by $2.44 and $0.17 per barrel, respectively. The differential between the average monthly ICE Brent Index Price and our realized oil prices widened from $3.40 per barrel in March 2020 to $8.34 per barrel in May 2020. The widening of the differential between the average monthly ICE Brent Index Price and our realized oil prices rendered our hedges less effective, resulting in significantly lowered revenues from March 2020 through May 2020. In June 2020, the differential between the average monthly ICE Brent Index Price and our realized oil prices contracted to $0.74 per barrel, and, in July 2020, our realized oil prices exceeded the average monthly ICE Brent Index Price by $3.71 per barrel. The differential between the average monthly ICE Brent Index Price and our realized oil prices remains unpredictable and may expand or contract in the future.

The price of the oil delivered pursuant to the purchase and sale agreement with TUPRAS is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. In November 2019, TUPRAS filed a lawsuit seeking restitution from us for alleged overpayments resulting from the Pricing Amendment. TUPRAS also claimed that the Pricing Amendment violates the Constitution of the Republic of Turkey and seeks to have the Pricing Amendment cancelled. Additionally, in April 2020, TUPRAS notified us that it intends to extend payment terms for oil purchases by 60 days. The outcome of the TUPRAS lawsuit and negotiations regarding the extension of payment terms is uncertain; however, a conclusion of the lawsuit in TUPRAS’s favor or an extension of payment terms would reduce or delay our cash flow and decrease our cash balances.

In the second quarter of 2020, we borrowed approximately $626,000 pursuant to the PPP to cover certain payroll, benefit, and rent expenses. We have forecast that amounts borrowed or received pursuant to the PPP will be forgiven for cash flow purposes. New guidance on the criteria for forgiveness continues to be released, and we currently expect that we will meet the conditions for forgiveness for a majority of the loan. Additionally, in the second quarter of 2020, the Turkish government passed legislation permitting employers to reduce the working hours of employees, reducing payroll and benefit expenses, through the end of August 2020. The actual reduction in payroll and benefit expenses due to this legislation is approximately $533,000.

As of June 30, 2020, we had $10.0 million of outstanding principal under the 2019 Term Loan. The 2019 Term Loan is payable in seven monthly installments of $1.4 million plus accrued interest from July 2020 through the maturity date in February 2021. In addition, dividends on our 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 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%. In order to conserve cash, we elected to pay the 2020 second quarter dividend in common shares, and, as such, on July 30, 2020, we issued 5,819,908 common shares to holders of Series A Preferred Shares.

On August 7, 2020, to supplement our liquidity, we entered into an up to $8.0 million loan with an affiliate of Mr. Mitchell. The loan is due August 7, 2021. Even with this additional liquidity, as of the date hereof, based on cash on hand and projected future cash flow from operations, our current liquidity position is severely constrained. As a result, substantial doubt exists regarding our ability to continue as a going concern. Our management is actively pursuing improving our working capital position in order to remain a going concern for the foreseeable future.

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~~Agreement. The 2017 Term Loan ~~to repay our former senior credit facility in full.~~

On December 30, 2019 we repaid the 2017 Term Loan in full in accordance with its terms.

2018 Term Loan. On May 28, 2018, DenizBank entered into the 2018 Term Loan under the Credit Agreement. The 2018 Term Loan bore 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 was payable monthly and the principal on the 2018 Term Loan was 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.

On December 30, 2019 we repaid the 2018 Term Loan in full in accordance with its terms.

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 Insurance Transactions Tax per the Turkish government) per annum. The 2019 Term Loan had a grace period through December 2019 during which no payments were due. Thereafter, accrued interest on the 2019 Term Loan was payable monthly and the principal on the 2019 Term Loan was payable in 14 monthly installments of $1.4 million each.

On March 9, 2020, we unwound our three-way collar contract with DenizBank and received approximately $6.5 million in proceeds which we used to pay down the 2019 Term Loan. As part of the pay down, DenizBank extended a grace period for principal repayments until June 29, 2020 at which time we will resume principal payments for one monthly installment in June 2020 of $0.6 million and seven monthly installments of $1.4 million beginning in July 2020. The 2019 Term Loan matures in February 2021. Amounts repaid under the 2019 Term Loan may not be ~~re-borrowed,~~reborrowed, and early repayments under the 2019 Term Loan are subject to early repayment fees. The 2019 Term Loan is guaranteed by Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.

~~On April 27, 2017,~~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 Gundem real estate and Muratli real estate owned by Gundem, (iv) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras, and (v) 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 ~~approved a revised amortization schedule~~as additional security for the 2019 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.~~ Loan and Security Agreement. In addition, on August 7, 2020, we entered into the Loan Agreement with the Lender. Pursuant to the Loan Agreement, the Lender has committed to lend us an aggregate principal amount of up to $8.0 million. Advances shall be made available by Lender and applied by us in accordance with a budget agreed to by us and the Lender and subject to milestones set forth in the Loan Agreement. We intend to use the proceeds of the Loan to finance our and our subsidiaries working capital needs in accordance with the budget.

The ~~2017 Notes bore~~outstanding borrowings under the Loan Agreement bear interest at ~~an annual~~a rate ~~of 13.0%~~equal to 10% per annum. ~~Interest was payable semi-annually,~~Principal on the Loan does not amortize and is required to be repaid in ~~arrears,~~full on ~~January 1~~the maturity date of August 7, 2021. The Loan may be optionally prepaid in whole or in part from time to time without fee, premium, or penalty.

Our obligations under the Loan Agreement are secured by all of our present and ~~July 1~~future accounts, chattel paper, commercial tort claims, commodity accounts, commodity contracts, contracts receivable, deposit accounts, documents, financial assets, general intangibles, instruments, investment property (including all of our right, title, and interest in and to all of the capital stock of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide Ltd., each ~~year.~~our wholly-owned direct subsidiary), letters of credit, letter of credit rights, payment intangibles, securities, notes receivable, choses of action, security accounts, and security entitlements, now or hereafter owned, held, or acquired. The ~~2017 Notes matured on July 1, 2017,~~Loan Agreement contains representations, warranties, covenants, and ~~we paid off and retired all remaining outstanding 2017 Notes on July 3, 2017.~~events of default.

Series A Preferred Shares. ~~On November 4, 2016,~~As of June 30, 2020, 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 $21.3~~2020, we had $5.0 million of Series A Preferred Shares and ~~$24.8~~$41.1 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.~~).

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,On April 10, 2020, we received loan proceeds in the ~~future, by us or on our behalf. Such statements are generally identifiable by~~amount of $626,000 under the ~~terminology used such~~PPP. The PPP, established as “plans,” “expects,” “estimates,” “budgets,” “intends,” “anticipates,” “believes,” “projects,” “indicates,” “targets,” “objective,” “could,” “should,” “may” or other similar words.

~~statement is not determinable with certainty as such factors are interdependent upon other factors and our course of action would depend upon our assessment~~2.5 times of the ~~future, considering all information then available. In that regard, any statements~~average monthly payroll expenses of the qualifying business. The loans are forgivable after 24 weeks as ~~to: future oil or natural gas production levels; capital expenditures; asset sales;~~long as the ~~allocation~~borrower uses the loan proceeds for eligible purposes, including payroll, benefits, rent and utilities, and maintains its payroll levels. The amount 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 areasloan forgiveness will be ~~developed~~reduced if the borrower terminates employees or ~~will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves, including~~reduces salaries during 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 any24-week period. The unforgiven portion of the ~~foregoing;~~PPP loan is payable over two years at an interest rate of 1%, with a deferral of payments for the first six months. We used the proceeds for purposes consistent with the PPP 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 our use of the ~~expectations conveyed by~~loan proceeds will meet the ~~forward-looking statements are reasonable based on information available to us on~~conditions for forgiveness of a majority the ~~date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.~~

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,~~2020, 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,~~2020, 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~~2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

During the ~~third~~second quarter of ~~2017,~~2020, 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.~~ 2019 as supplemented by “Part II, Item 1. Legal Proceedings” in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.

During the ~~third~~second quarter of ~~2017,~~2020, 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.~~2019, other than as set forth below:

The consummation of the transactions contemplated by the Merger Agreement is contingent upon the satisfaction of a number of conditions, including approval by our shareholders, which may not be satisfied or completed on a timely basis, if at all. Failure to complete the transactions contemplated by the Merger Agreement could negatively impact our share price, business, financial condition, results of operations or prospects.

The closing of the transactions contemplated by the Merger Agreement is subject to conditions to closing which are not wholly within our control, including, among other things, adoption of the Merger Agreement by holders of common shares by at least 75% of the votes cast and holders of Series A Preferred Shares with at least 75% of the votes cast, in each case at a duly convened meeting of our shareholders at which a quorum is present. We cannot assure you that each of the conditions will be satisfied or waived in a timely manner, if at all, and the merger may be delayed or not consummated. If the conditions are not satisfied or waived in a timely manner and the merger is delayed or not consummated, we may lose some or all of the intended or perceived benefits of the merger, which could cause our stock price to decline and harm our business.

We are also subject to additional risks in connection with the merger, including, without limitation: (1) the parties’ ability to meet expectations regarding the timing and completion of the merger; (2) the occurrence of any event, change or other circumstance that could give rise to the termination of the Merger Agreement; (3) the effect of the announcement or pendency of the merger on our business relationships, operating results, and business generally; (4) risks that the proposed merger disrupts our current plans and operations; (5) the amount of the costs, fees, expenses and other charges related to the merger; (6) the outcome of any legal proceedings that may be instituted against us, our directors or others relating to the transactions contemplated by the Merger Agreement, which could result in significant defense costs, serve as a distraction to management and directors and delay completion of the merger in the expected timeframe or altogether; (7) the restrictions imposed on our business and operations pursuant to the affirmative and negative covenants set forth in the Merger Agreement and the potential impact of such covenants on our business; (8) the risk that the merger will divert management’s attention resulting in a potential disruption of our current business plan; and (9) potential difficulties in employee retention arising from the merger.

~~On October 2, 2017, we issued an aggregate of 2,591,384 common to holders of the Series A Preferred Shares as payment of the~~ ~~September 30, 2017~~ quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of $0.7108 per common share, which was equal to the 15-day volume weighted average price through the close of trading of the common shares on the NYSE American on September 13, 2017.None

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

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

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

Large accelerated filer		☐	Accelerated filer	☐

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

			Emerging growth company	☐

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of ~~September~~June 30, ~~2017~~2020 (Unaudited) and December 31, ~~2016~~	3

~~Consolidated Statements of Comprehensive (Loss) Income for the Three and Nine Months Ended September 30, 2017 and 2016~~2019	4

Unaudited Consolidated ~~Statement~~Statements of ~~Equity~~Operations and Comprehensive (Loss) Income for the ~~Nine~~Three and Six Months Ended ~~September~~June 30, ~~2017~~2020 and 2019	5

Unaudited Consolidated ~~Statements~~Statement of ~~Cash Flows~~Shareholders’ Equity for the ~~Nine~~Three and Six Months Ended ~~September~~June 30, ~~2017~~2020 and ~~2016~~2019	6

Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2020 and 2019	7

Notes to Unaudited Consolidated Financial Statements	78

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2227

Item 3. Quantitative and Qualitative Disclosures About Market Risk	3036

Item 4. Controls and Procedures	3136

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	3237

Item 1A. Risk Factors	3237

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	3237

Item 3. Defaults Upon Senior Securities	3237

Item 4. Mine Safety Disclosures	3237

Item 5. Other Information	3237

Item 6. Exhibits	3338


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%

	June 30, 2020
	(in thousands)
Remainder of 2020	$	461
2021		729
2022		861
2023		558
2024		202
2025		-
Thereafter		-
Total	$	2,811
Less: Imputed interest		87
Present value of lease liabilities	$	2,724

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

	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)	2020			2019			2020			2019
Net loss	$	(7,734	)	$	(9	)	$	(31,699	)	$	(3,911	)
Basic net loss earnings per common share:
Shares:
Weighted average common shares outstanding		62,502			52,529			62,406			52,506
Basic net loss per common share:	$	(0.12	)	$	(0.00	)	$	(0.51	)	$	(0.07	)
Diluted net loss per common share:
Shares:
Weighted average common shares outstanding		62,502			52,529			62,406			52,506
Diluted net loss per common share:	$	(0.12	)	$	(0.00	)	$	(0.51	)	$	(0.07	)

	Loss on Sale
	(in thousands)
Total cash proceeds for Petrogas	$	1,451
Less: Petrogas net liabilities		(652	)
Gain on sale before accumulated foreign currency translation adjustment		2,103
Less: Petrogas accumulated foreign currency translation adjustment		(12,231	)
Net loss on sale of Petrogas	$	(10,128	)

	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	)

	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

2.1		Agreement and Plan of Merger, dated August 7, 2020, by and among TAT Holdco LLC, TAT Merger Sub LLC, and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8‑K dated August 4, 2020, filed with the SEC on August 7, 2020).

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).

3.6		Amendment No. 1 to the 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 May 22, 2020, filed with the SEC on May 27, 2020).

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		Landlord Consent, dated June 30, 2020, by and between TransAtlantic Petroleum (USA) Corp. and Longfellow Energy LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated June 30, 2020, filed with the SEC on July 2, 2020).

10.2		Limited Guaranty, dated August 7, 2020, made by Dalea Partners, LP in favor of TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8‑K dated August 4, 2020, filed with the SEC on August 7, 2020).

10.3		Loan and Security Agreement, dated August 7, 2020, by and between TransAtlantic Petroleum Ltd. and Dalea Investment Group, LLC (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8‑K dated August 4, 2020, filed with the SEC on August 7, 2020).

10.4		Farmout Agreement, dated August 4, 2020, by and between TransAtlantic Petroleum Ltd. and Longfellow Energy, LP (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8‑K dated August 4, 2020, filed with the SEC on August 7, 2020).

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 12, 2020