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 every Interactive Data File required to be submitted 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 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.

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 ~~May 3,~~November 8, 2019, the registrant had ~~52,496,666~~57,708,698 common shares outstanding.

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

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity, and achievements to differ materially from those expressed or implied by such statements, including the factors discussed under Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2018. Such factors include, but are not limited to, the following: our ability to access sufficient capital to fund our operations; fluctuations in and volatility of the market prices for oil and natural gas products; the ability to produce and transport oil and natural gas; the results of exploration and development drilling and related activities; global economic conditions, particularly in the countries in which we carry on business, especially economic slowdowns; actions by governmental authorities including increases in taxes, legislative and regulatory initiatives related to fracture stimulation activities, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including sanctions, armed conflicts, and actions by insurgent ~~groups or other conflicts;~~groups; the negotiation and closing of material contracts or sale of assets; future capital requirements and the availability of financing; risks associated with drilling, operating and decommissioning wells; actions of third-party co-owners of interests in properties in which we also own an interest; and the other factors discussed in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”) and Canadian securities regulatory authorities. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors and our course of action would depend upon our assessment of the future, considering all information then available. In that regard, any statements as to: future oil or natural gas production levels; capital expenditures; asset sales; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital expenditure programs or operations; drilling of new wells; demand for oil and natural gas products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves, including the ability to convert probable and possible reserves to proved reserves; dates by which transactions are expected to close; future cash flows, uses of cash flows, collectability of receivables and availability of trade credit; expected operating costs; changes in any of the foregoing; and other statements using forward-looking terminology are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized.

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

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

	March 31, 2019			December 31, 2018			September 30, 2019			December 31, 2018
	(unaudited)						(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	19,734		$	9,892		$	14,452		$	9,892
Accounts receivable, net
Oil and natural gas sales		21,852			12,912			12,032			12,912
Joint interest and other		1,061			982			1,567			982
Related party		898			878			853			878
Prepaid and other current assets		9,304			8,696			12,331			8,696
Derivative asset								384			–
Note receivable - related party		–			5,828			–			5,828
Inventory		4,830			5,167			4,804			5,167
Total current assets		57,679			44,355			46,423			44,355
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		155,808			163,006			170,237			163,006
Unproved		15,195			15,695			14,911			15,695
Equipment and other property		13,559			14,408			13,091			14,408
		184,562			193,109			198,239			193,109
Less accumulated depreciation, depletion and amortization		(102,607	)		(105,850	)		(108,646	)		(105,850	)
Property and equipment, net		81,955			87,259			89,593			87,259
Other long-term assets:
Other assets		3,380			986			3,107			986
Note receivable - related party		4,609			–			4,150			–
Total other assets		7,989			986			7,257			986
Total assets	$	147,623		$	132,600		$	143,273		$	132,600
LIABILITIES, SERIES A PREFERRED SHARES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	6,074		$	3,896		$	6,067		$	3,896
Accounts payable - related party		2,667			2,922			3,552			2,922
Accrued liabilities		16,877			13,073			13,956			13,073
Derivative liability		110			–			414			–
Loans payable		21,186			22,000			18,912			22,000
Total current liabilities		46,914			41,891			42,901			41,891
Long-term liabilities:
Asset retirement obligations		4,490			4,667			4,836			4,667
Accrued liabilities		9,620			7,259			9,994			7,259
Deferred income taxes		20,531			20,314			22,720			20,314
Loans payable		15,714			–			7,143			–
Total long-term liabilities		50,355			32,240			44,693			32,240
Total liabilities		97,269			74,131			87,594			74,131
Commitments and contingencies
Series A preferred shares, $0.01 par value, 426,000 shares authorized; 426,000 shares issued and outstanding with a liquidation preference of $50 per share as of March 31, 2019 and December 31, 2018		21,300			21,300
Series A preferred shares-related party, $0.01 par value, 495,000 shares authorized; 495,000 shares issued and outstanding with a liquidation preference of $50 per share as of March 31, 2019 and December 31, 2018		24,750			24,750
Series A preferred shares, $0.01 par value, 426,000 shares authorized; 426,000 shares issued and outstanding with a liquidation preference of $50 per share as of September 30, 2019 and December 31, 2018								21,300			21,300
Series A preferred shares-related party, $0.01 par value, 495,000 shares authorized; 495,000 shares issued and outstanding with a liquidation preference of $50 per share as of September 30, 2019 and December 31, 2018								24,750			24,750
Shareholders' equity:
Common shares, $0.10 par value, 200,000,000 shares authorized; 52,496,666 shares and 52,413,588 shares issued and outstanding as of March 31, 2019 and December 31, 2018, respectively		5,249			5,241
Common shares, $0.10 par value, 200,000,000 shares authorized; 57,708,698 shares and 52,413,588 shares issued and outstanding as of September 30, 2019 and December 31, 2018, respectively								5,771			5,241
Treasury stock		(970	)		(970	)		(970	)		(970	)
Additional paid-in-capital		577,493			577,488			580,843			577,488
Accumulated other comprehensive loss		(146,247	)		(142,021	)		(145,855	)		(142,021	)
Accumulated deficit		(431,221	)		(427,319	)		(430,160	)		(427,319	)
Total shareholders' equity		4,304			12,419			9,629			12,419
Total liabilities, Series A preferred shares and shareholders' equity	$	147,623		$	132,600		$	143,273		$	132,600

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

	For the Three Months Ended						For the Three Months Ended						For the Nine Months Ended
	March 31,						September 30,						September 30,
	2019			2018			2019			2018			2019			2018
Revenues:
Oil and natural gas sales	$	18,861		$	16,661		$	14,543		$	20,098		$	50,537		$	54,859
Other		180			265			110			42			372			405
Total revenues		19,041			16,926			14,653			20,140			50,909			55,264
Costs and expenses:
Production		2,502			2,869			3,162			2,307			8,376			7,980
Transportation and processing		1,319			1,193			1,262			1,054			3,802			3,385
Exploration, abandonment and impairment		5,113			40			488			162			6,267			393
Seismic and other exploration		77			159			48			122			233			340
General and administrative		3,054			3,337			2,503			2,539			8,247			9,662
Depreciation, depletion and amortization		3,716			4,459			3,021			2,938			10,179			10,673
Accretion of asset retirement obligations		52			46			56			35			157			124
Total costs and expenses		15,833			12,103			10,540			9,157			37,261			32,557
Operating income (loss)		3,208			4,823
Operating income								4,113			10,983			13,648			22,707
Other income (expense):
Interest and other expense		(2,478	)		(2,782	)		(2,780	)		(2,776	)		(8,011	)		(7,649	)
Interest and other income		174			254			381			211			776			842
Loss on derivative contracts		(110	)		(725	)
Gain (loss) on derivative contracts								403			(1,290	)		(30	)		(5,156	)
Foreign exchange loss		(1,273	)		(2,058	)		(797	)		(2,991	)		(2,185	)		(6,987	)
Total other expense		(3,687	)		(5,311	)		(2,793	)		(6,846	)		(9,450	)		(18,950	)
Loss from operations before income taxes		(479	)		(488	)
Income from operations before income taxes								1,320			4,137			4,198			3,757
Income tax expense		(3,423	)		(1,287	)		(250	)		(5,857	)		(7,039	)		(8,258	)
Net loss		(3,902	)		(1,775	)
Net income (loss)								1,070			(1,720	)		(2,841	)		(4,501	)
Other comprehensive income (loss):
Foreign currency translation adjustment		(4,226	)		(2,343	)		808			(11,765	)		(3,834	)		(23,217	)
Comprehensive loss	$	(8,128	)	$	(4,118	)
Comprehensive income (loss)							$	1,878		$	(13,485	)	$	(6,675	)	$	(27,718	)

Net loss per common share
Basic net loss per common share	$	(0.07	)	$	(0.04	)
Net income (loss) per common share
Basic net income (loss) per common share							$	0.02		$	(0.03	)	$	(0.05	)	$	(0.09	)
Weighted average common shares outstanding		52,483			50,374			57,680			50,597			54,249			50,465
Diluted net loss per common share	$	(0.07	)	$	(0.04	)
Diluted net income (loss) per common share							$	0.02		$	(0.03	)	$	(0.05	)	$	(0.09	)
Weighted average common and common equivalent shares outstanding		52,483			50,374			57,680			50,597			54,249			50,465

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

Consolidated Statement of Equity for the Three and Nine Months Ended ~~March 31,~~September 30, 2019 and 2018

																Accumulated																								Accumulated
													Additional			Other						Total															Additional			Other						Total
	Common		Treasury					Common		Treasury			Paid-in			Comprehensive			Accumulated			Shareholders'			Common		Treasury					Common		Treasury			Paid-in			Comprehensive			Accumulated			Shareholders'
	Shares		Shares		Warrants			Shares		Stock			Capital			Loss			Deficit			Equity
Three months ended September 30, 2019																									Shares		Shares		Warrants			Shares		Stock			Capital			Loss			Deficit			Equity
Balance at June 30, 2019																										52,723		333		-		$	5,273	$	(970	)	$	577,538		$	(146,663	)	$	(431,230	)	$	3,948
Issuance of common shares																										4,986							498					3,186									3,684
Issuance of restricted stock units																										-		-		-			-		-			-			-			-			-
Share-based compensation																										-		-		-			-		-			119			-			-			119
Tax effect of restricted stock																										-		-		-			-		-			-			-			-			-
Foreign currency translation adjustment																										-		-		-			-		-			-			808			-			808
Net income																										-		-		-			-		-			-			-			1,070			1,070
Balance at September 30, 2019																										57,709		333		-		$	5,771	$	(970	)	$	580,843		$	(145,855	)	$	(430,160	)	$	9,629
Nine months ended September 30, 2019
Balance at December 31, 2018																										52,413		333		-		$	5,241	$	(970	)	$	577,488		$	(142,021	)	$	(427,319	)	$	12,419
Issuance of common shares																										4,986							498					3,186									3,684
Issuance of restricted stock units																										310		-		-			32		-			(32	)		-			-			-
Share-based compensation																										-		-		-			-		-			298			-			-			298
Tax effect of restricted stock																										-		-		-			-		-			(97	)		-			-			(97	)
Foreign currency translation adjustment																										-		-		-			-		-						(3,834	)		-			(3,834	)
Net loss																										-		-		-			-		-			-			-			(2,841	)		(2,841	)
Balance at September 30, 2019																										57,709		333		-		$	5,771	$	(970	)	$	580,843		$	(145,855	)	$	(430,160	)	$	9,629
Three months ended September 30, 2018
Balance at June 30, 2018																										50,591		333		-		$	5,059	$	(970	)	$	575,591		$	(136,218	)	$	(424,884	)	$	18,578
Issuance of restricted stock units																										14		-		-			1		-			(1	)		-			-			-
Share-based compensation																										-		-		-			-		-			122			-			-			122
Tax effect of restricted stock																										-		-		-			-		-			-			-			-			-
Foreign currency translation adjustment																										-		-		-			-		-			-			(11,765	)		-			(11,765	)
Net loss																										-		-		-			-		-			-			-			(1,720	)		(1,720	)
Balance at September 30, 2018																										50,605		333		-		$	5,060	$	(970	)	$	575,712		$	(147,983	)	$	(426,604	)	$	5,215
Nine Months Ended September 30, 2018
Balance at December 31, 2017		50,319		333		700		$	5,032	$	(970	)	$	575,411		$	(124,766	)	$	(422,103	)	$	32,604			50,319		333		700		$	5,032	$	(970	)	$	575,411		$	(124,766	)	$	(422,103	)	$	32,604
Expiration of warrants		-		-		(700	)		-		-			-			-			-			-			-		-		(700	)		-		-			-			-			-			-
Issuance of restricted stock units		64		-		-			6		-			(6	)		-			-			-			286		-		-			28		-			(28	)		-			-			-
Share-based compensation		-		-		-			-		-			101			-			-			101			-		-		-			-		-			340			-			-			340
Tax effect of restricted stock		-		-		-			-		-			-			-			-			-			-		-		-			-		-			(11	)		-			-			(11	)
Foreign currency translation adjustment		-		-		-			-		-			-			(2,343	)		-			(2,343	)		-		-		-			-		-			-			(23,217	)		-			(23,217	)
Net loss		-		-		-			-		-			-			-			(1,775	)		(1,775	)		-		-		-			-		-			-			-			(4,501	)		(4,501	)
Balance at March 31, 2018		50,383		333		-		$	5,038	$	(970	)	$	575,506		$	(127,109	)	$	(423,878	)	$	28,587

Balance at December 31, 2018		52,413		333		–		$	5,241	$	(970	)	$	577,488		$	(142,021	)	$	(427,319	)	$	12,419
Issuance of restricted stock units		83		-		-			8		-			(8	)		-			-			-
Share-based compensation		-		-		-			-		-			102			-			-			102
Tax effect of restricted stock		-		-		-			-		-			(89	)		-			-			(89	)
Foreign currency translation adjustment		-		-		-			-		-			-			(4,226	)		-			(4,226	)
Net loss		-		-		-			-		-			-			-			(3,902	)		(3,902	)
Balance at March 31, 2019		52,496		333		-		$	5,249	$	(970	)	$	577,493		$	(146,247	)	$	(431,221	)	$	4,304
Balance at September 30, 2018																										50,605		333		-		$	5,060	$	(970	)	$	575,712		$	(147,983	)	$	(426,604	)	$	5,215

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

	For the Three Months Ended						For the Nine Months Ended
	March 31,						September 30,
	2019			2018			2019			2018
Operating activities:
Net loss	$	(3,902	)	$	(1,775	)	$	(2,841	)	$	(4,501	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-based compensation		102			101			298			340
Foreign currency loss		1,637			2,634			1,776			20,748
Interest on Series A Preferred Shares paid in common shares								3,684			–
Loss on derivative contracts		110			725			30			5,156
Cash settlement on derivative contracts		–			(1,339	)		–			(3,710	)
Amortization on loan financing costs		10			10			31			31
Deferred income tax expense		1,769			767			4,396			5,577
Exploration, abandonment and impairment		5,113			40			6,267			393
Depreciation, depletion and amortization		3,716			4,459			10,179			10,673
Accretion of asset retirement obligations		52			46			157			124
Changes in operating assets and liabilities:
Accounts receivable		(10,216	)		(548	)		172			(14,920	)
Prepaid expenses and other assets		(3,757	)		(1,091	)		(6,567	)		(6,831	)
Accounts payable and accrued liabilities		9,880			3,781			8,122			12,136
Net cash provided by operating activities		4,514			7,810			25,704			25,216
Investing activities:
Additions to oil and natural gas properties		(9,326	)		(6,337	)		(24,847	)		(17,708	)
Additions to equipment and other properties		–			(677	)		(341	)		(3,254	)
Net used in provided by investing activities		(9,326	)		(7,014	)
Net cash used in investing activities								(25,188	)		(20,962	)
Financing activities:
Tax withholding on restricted share units		(88	)		–			(97	)		(15	)
Note receivable - related party		1,000			–			1,000			–
Loan proceeds		20,000			–			20,605			10,000
Loan repayment		(5,100	)		(4,125	)		(16,550	)		(12,425	)
Net cash provided by (used in) financing activities		15,812			(4,125	)		4,958			(2,440	)
Effect of exchange rate on cash flows, cash equivalents, and restricted cash		(1,018	)		(716	)		(914	)		(8,535	)
Net increase (decrease) in cash, cash equivalents and restricted cash		9,982			(4,045	)		4,560			(6,721	)
Cash, cash equivalents and restricted cash, beginning of period (1)		9,892			20,431			10,032			20,432
Cash, cash equivalents and restricted cash, end of period (2)	$	19,874		$	16,386		$	14,592		$	13,711
Supplemental disclosures:
Cash paid for interest	$	526		$	3,104		$	3,387		$	7,333
Cash paid for taxes	$	1,178		$	657		$	2,988		$	2,847

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,” 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 ~~May 3,~~November 8, 2019, approximately ~~48%~~46% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

We are a holding company with two operating segments – Turkey and Bulgaria. Our assets consist of our ownership interests in subsidiaries that primarily own assets in Turkey and Bulgaria.

Our consolidated financial statements are expressed in U.S. ~~Dollar~~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 USD unless otherwise indicated. The unaudited consolidated financial statements include accounts of the Company and its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews estimates, including those related to fair value measurements associated with acquisitions and financial derivatives, the recoverability and impairment of long-lived assets, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

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 SEC. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2018.

During the three months ended March 31, 2019, we repaid $5.1 million of outstanding debt and entered into the 2019 Term Loan with DenizBank, A.S. (“DenizBank”) for $20.0 million (see Note 7 “Loans Payable”).

~~As of March 31, 2019, we had $15.7 million of long-term debt, $21.2 million of short-term debt, $19.7 million in cash and a $10.8 million work capital surplus.~~

Based on current forecasted oil prices for 2019 and beyond, we believe that our cash flows from operations and existing cash on hand are sufficient to conduct our planned operations and meet our contractual requirements, including license obligations through June 30, 2020.

In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which establishes a new lease accounting model for leases. The most significant changes include the clarification of the definition of a lease, the requirement for lessees to recognize for all leases a right-of-use asset and a lease liability in the consolidated balance sheet, and additional quantitative and qualitative disclosures which are designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. Expenses are recognized in the consolidated statement of income in a manner similar to current accounting guidance. Lessor accounting under the new standard is substantially unchanged. The new standard became effective for us beginning with the first quarter of 2019. We adopted the accounting standard using a prospective transition approach, which applied the provisions of the new guidance at the effective date without adjusting the comparative periods presented. We elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed us to carry forward the historical accounting relating to lease identification and classification for existing leases upon adoption. We also made an accounting policy election to keep leases with an initial term of

twelve months or less off of the consolidated balance sheet. On January 1, 2019, we ~~also~~ recognized $2.7 million of additional right-of-use assets and liabilities on our consolidated balance ~~sheet.~~sheets.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s 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.

~~Scope of Modification Accounting, which clarifies Topic 718,~~ ~~Compensation – Stock Compensation~~ (“ASU 2017-09”), such that an entity must apply modification accounting to changes in the terms or conditions of a share-based payment award unless all of the following criteria are met: (1) the fair value of the modified award is the same as the fair value of the original award immediately before the modification and the ASU indicates that if the modification does not affect any of the inputs to the valuation technique used to value the award, the entity is not required to estimate the value immediately before and after the modification; (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the modification; and (3) the classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the modification. The ASU is effective for fiscal years beginning after December 15, 2017. We adopted ASU 2017-09 effective January 1, 2018. The adoption of this update had no impact our consolidated financial statements and results of operations.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in Accounting Standards Codification (“ASC”) Topic 815. The new standard provides partial relief on the timing of certain aspects of hedge documentation and eliminates the requirement to recognize hedge ineffectiveness separately in income. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018 and for interim periods therein. The Company adopted this standard effective January 1, 2019. The adoption of this update had no impact our consolidated financial statements and results of operations.

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

In November 2018, the FASB issued 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. The Company does not believe the adoption of this standard will have an impact on its consolidated financial statements.

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

As of ~~March 31,~~September 30, 2019 and 2018, we had 921,000 outstanding shares of our 12.0% Series A Convertible Redeemable Preferred Shares (“Series A Preferred 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. GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of ~~March 31,~~September 30, 2019, there were $21.3 million of Series A Preferred Shares and $24.8 million of Series A Preferred Shares – related party outstanding (See Note 13. “Related party transactions”).

Pursuant to the Certificate of Designations for the Series A Preferred Shares (the “Certificate of Designations”), each Series A Preferred Share may be converted at any time, at the option of the holder, into 45.754 common shares (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).

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 dates below are:

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

Dividends on the Series A Preferred Shares are payable quarterly at our election in cash, common shares, or a combination of cash and common shares at an annual dividend rate of 12.0% of the liquidation preference if paid all in cash or 16.0% of the liquidation preference if paid in common shares. If paid partially in cash and partially in common shares, the dividend rate on the cash portion is

12.0%, and the dividend rate on the common share portion is 16.0%. Dividends are payable quarterly on March 31, June 30, September 30, and December 31 of each year. The holders of the Series A Preferred Shares also are entitled to participate pro-rata in any dividends paid on the common shares on an as-converted-to-common shares basis. For the three and nine months ended ~~March 31,~~September 30, 2019, we accrued $1.8 million and ~~2018, we paid $1.3~~$5.1 million, respectively, in ~~cash~~ dividends on the Series A Preferred Shares, which is recorded in our consolidated statements of operations and comprehensive (loss) income under the caption “Interest and other expense”. Such amounts were paid in cash and in common shares. On July 2, 2019, we issued an aggregate of 2,321,568 common shares to holders of the Series A Preferred Shares as payment of the June 30, 2019 quarterly dividend on the Series A Preferred Shares, and on September 30, 2019, we issued an aggregate of 2,664,164 common shares to holders of the Series A Preferred Shares as payment of the September 30, 2019 quarterly dividend on the Series A Preferred Shares.

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:

	March 31, 2019			December 31, 2018			September 30, 2019			December 31, 2018
	(in thousands)						(in thousands)
Oil and natural gas properties, proved:
Turkey	$	155,306		$	162,494		$	169,758		$	162,494
Bulgaria		502			512			479			512
Total oil and natural gas properties, proved		155,808			163,006			170,237			163,006
Oil and natural gas properties, unproved:
Turkey		15,195			14,965			14,911			14,965
Bulgaria		–			730			–			730
Total oil and natural gas properties, unproved		15,195			15,695			14,911			15,695
Gross oil and natural gas properties		171,003			178,701			185,148			178,701
Accumulated depletion		(97,449	)		(100,582	)		(103,235	)		(100,582	)
Net oil and natural gas properties	$	73,554		$	78,119		$	81,913		$	78,119

The decline in oil and natural gas properties during the three months ended March 31, 2019 was primarily driven by the devaluation of the New Turkish Lira (“TRY”) versus the USD. From December 31, 2018 to March 31, 2019, the TRY to the USD declined 7.0%. At March 31, 2019, the exchange rate was 5.6284 as compared to 5.2609 at December 31, 2018. For the three months ended March 31, 2019, foreign currency translations reduced oil and natural gas properties and increased accumulated other comprehensive loss within shareholders’ equity on our consolidated balance sheet.

At ~~March 31,~~September 30, 2019 there were no amounts excluded from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production. At December 31, 2018, we excluded ~~$0.3 million and~~ $0.5 million, ~~respectively,~~ from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At ~~March 31,~~September 30, 2019, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included ~~$6.9~~$5.5 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and ~~$51.2~~$63.8 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, 2018, the capitalized costs of our oil and natural gas properties included $6.5 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and ~~$58.7~~$53.4 million relating to well costs and additional development costs, which are being 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 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 three months ended ~~March 31,~~September 30, 2019 and 2018, we recorded ~~$5.1~~$0.5 million of exploratory dry-hole costs and ~~$0.1~~$0.2 million of impairment of proved properties and exploratory well costs, respectively, which are primarily measured using Level 3 inputs.

During the nine months ended September 30, 2019 and 2018, we recorded $6.3 million of exploratory dry-hole costs and $0.4 million of impairment of proved properties and exploratory well costs, respectively, which are primarily measured using Level 3 inputs.

As of ~~March~~September 30, 2019, and December 31, ~~2019,~~2018 there were no exploratory well costs greater than one year.

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

	March 31, 2019			December 31, 2018			September 30, 2019			December 31, 2018
	(in thousands)						(in thousands)
Other equipment	$	1,159		$	1,240		$	1,176		$	1,240
Land		140			149			139			149
Inventory		6,323			6,791			5,858			6,791
Gas gathering system and facilities		182			194			181			194
Vehicles		317			336			316			336
Leasehold improvements, office equipment and software		5,438			5,698			5,421			5,698
Gross equipment and other property		13,559			14,408			13,091			14,408
Accumulated depreciation		(5,158	)		(5,268	)		(5,411	)		(5,268	)
Net equipment and other property	$	8,401		$	9,140		$	7,680		$	9,140

At ~~March~~September 30, 2019, and December 31, ~~2019,~~2018, in addition to the above, we have classified $4.8 million and $5.2 million, respectively, of inventory as a current asset, which represents our expected inventory consumption during the next twelve months. We classify our remaining materials and supply inventory as a long-term asset because such materials will ultimately be classified as a long-term asset when the material is used in the drilling of a well.

At ~~March 31,~~September 30, 2019 and December 31, 2018, we excluded ~~$11.2~~$11.7 million and $12.0 million of inventory, respectively, from depreciation as the inventory had not been placed into service.

The following table summarizes the changes in our asset retirement obligations (“ARO”) for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 and for the year ended December 31, 2018:

	March 31, 2019			December 31, 2018			September 30, 2019			December 31, 2018
	(in thousands)						(in thousands)
Asset retirement obligations at beginning of period	$	4,667		$	4,727		$	4,667		$	4,727
Liabilities settled		-			–
Foreign exchange change effect		(288	)		(1,270	)		(320	)		(1,270	)
Additions		59			1,036			332			1,036
Accretion expense		52			174			157			174
Asset retirement obligations at end of period	$	4,490		$	4,667		$	4,836		$	4,667

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.

~~During the three months ended March 31, 2019 and 2018, we recorded accretion expense of $0.1 million and $0.1 million, respectively.~~

We use derivative instruments to 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 leveraged or complex features. We have not designated the derivative contracts as hedges for accounting purposes, and accordingly, we record the derivative contracts at fair value and recognize changes in fair value in earnings as they occur.

To the extent that a legal right of offset exists, we net the value of our derivative contracts with the same counterparty in our consolidated balance sheets. All of our oil derivative contracts are settled based upon Brent crude oil pricing. We recognize gains and losses related to these contracts on a fair value basis in our consolidated statements of operations and comprehensive (loss) income under the caption “Gain (loss) on derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on derivative contracts.”

At September 30, 2019, we had outstanding derivative contracts with respect to our future crude oil production as set forth in the table below:

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

To the extent that a legal right of offset exists, we net the value of our derivative contracts with the same counterparty in our consolidated balance sheets. All of our foreign exchange derivative contracts are settled based upon the contract rate. We recognize gains and losses related to these contracts on a fair value basis in our consolidated statements of operations and comprehensive (loss) income under the caption ~~“(Loss) gain~~“Gain (loss) on derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on derivative contracts.”

At ~~March 31,~~September 30, 2019, we had outstanding foreign exchange derivative contracts as set forth in the ~~tables~~table below:

Fair Value of Foreign Exchange Derivative Instruments as of March 31, 2019

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

Buy

Sell

Estimated Fair

Buy

Sell

Estimated Fair

Type

Buy/Sell

Rate

Settlement Date

Buy Currency

Currency Amount

Sell Currency

Currency Amount

Value of Asset (Liability)

Buy/Sell

Rate

Settlement Date

Buy Currency

Currency Amount

Sell Currency

Currency Amount

Value of Asset (Liability)

(in thousands)

FXOPT

Buy

5.750

04/29/19

TRY

8,625,000

USD

1,500,000

Buy

6.090

10/28/19

USD

1,400,000

TRY

8,526,000

(414

)

FXOPT

Sell

5.750

04/29/19

USD

2,250,000

TRY

12,937,500

(59

)

FXOPT

Buy

5.750

06/03/19

TRY

8,625,000

USD

1,500,000

FXOPT

Sell

5.750

06/03/19

USD

2,250,000

TRY

12,937,500

(41

)

FXOPT

Buy

5.750

07/01/19

TRY

8,625,000

USD

1,500,000

FXOPT

Sell

5.750

07/01/19

USD

2,250,000

TRY

12,937,500

(33

)

Total Estimated Fair Value of Liability

(110

)

Total estimated fair value of liability

(414

)

During the three months ended ~~March 31,~~September 30, 2019 and 2018, we recorded a net gain on derivative contracts of $0.4 million and a net loss of $1.3 million, respectively. During the nine months ended September 30, 2019 and 2018, we recorded a net loss on derivative contracts of ~~$0.1~~$0.03 million and ~~$0.7~~$5.2 million, respectively.

The following table summarizes both: (i) the gross fair value of our derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at ~~March 31,~~September 30, 2019, and (ii) the net recorded fair value as reflected on our consolidated balance sheet at ~~March 31,~~September 30, 2019.

As of March 31, 2019

As of September 30, 2019

Gross

Amount

Net Amount of

Amount

Net Amount of

Gross

Offset in the

Liabilities

Gross

Offset in the

Assets (Liabilities)

Amount of

Consolidated

Presented in the

Amount of

Consolidated

Presented in the

Location on Consolidated

Recognized

Balance

Consolidated

Location on Consolidated

Recognized

Balance

Consolidated

Type of Derivative Contract

Balance Sheets

Liabilities

Sheets

Balance Sheets

Assets (Liabilities)

Sheets

Balance Sheets

(in thousands)

Foreign exchange

Current liabilities

133

(23

)

110

Current liabilities

(414

)

(414

)

Foreign exchange

Long-term liabilities

Commodity - crude oil

Current assets

384

As of December 31, 2018, we had no outstanding derivative contracts with respect to foreign exchange.

	March 31,		December 31,		September 30,		December 31,
	2019		2018		2019		2018
Fixed and floating rate loans	(in thousands)
Fixed and Floating Rate Loans					(in thousands)
Term Loans (1)	$	36,900	$	22,000	$	25,450	$	22,000
Unsecured line of credit						605		-
Less: current portion		21,186		22,000		18,912		22,000
Long-term portion	$	15,714	$	–	$	7,143	$	–

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

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

The 2016 Term Loan bore interest at a fixed rate of 5.25% (plus 0.2625% for Banking and Insurance Transactions Tax per the Turkish government) per annum and was payable in six monthly installments of $1.25 million each through February 2017 and thereafter in twelve monthly installments of $1.88 million each through February 2018. On April 27, 2017, TEMI and DenizBank approved a revised amortization schedule for the 2016 Term Loan. Pursuant to the revised amortization schedule, the maturity date of the 2016 Term Loan was extended from February 2018 to June 2018, and the monthly principal payments were reduced from $1.88 million to $1.38 million. The other terms of the 2016 Term Loan remained unchanged. Amounts repaid under the 2016 Term Loan could not be re-borrowed and early repayments under the 2016 Term Loan were subject to early repayment fees.

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

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

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

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

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

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

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

The 2017 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2017 Term Loan.

At ~~March 31,~~September 30, 2019, we had ~~$9.4~~$3.2 million outstanding under the 2017 Term Loan and no availability, and we were in compliance with the covenants in the 2017 Term Loan.

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

transferring revenues, dissolving, liquidating, merging, or consolidating, incurring additional debt, paying dividends, making certain investments, undergoing a change of control, and other similar matters. In addition, the 2018 Term Loan prohibits Amity, Talon Exploration, DMLP, and TransAtlantic Turkey from incurring additional debt. An event of default under the 2018 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties, and obligations, bankruptcy or insolvency, and the occurrence of a material adverse effect.

The 2018 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2018 Term Loan.

At ~~March 31,~~September 30, 2019, we had ~~$7.5~~$2.3 million outstanding under the 2018 Term Loan and no availability, and we were in compliance with the covenants in the 2018 Term Loan.

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

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

The 2019 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on encumbering or creating restrictions or limitations on all or a part of its assets, revenues, or properties, giving guaranties or sureties, selling assets or transferring revenues, dissolving, liquidating, merging, or consolidating, incurring additional debt, paying dividends, making certain investments, undergoing a change of control, and other similar matters. In addition, the 2019 Term Loan prohibits Amity, Talon Exploration, DMLP, and TransAtlantic Turkey from incurring additional debt. An event of default under the 2019 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties, and obligations, bankruptcy or insolvency, and the occurrence of a material adverse effect.

The 2019 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2019 Term Loan.

At ~~March 31,~~September 30, 2019, we had $20.0 million outstanding under the 2019 Term Loan and no availability, and we were in compliance with the covenants in the 2019 Term Loan.

~~For the three months ended March 31, 2019 and 2018, we recorded interest expense related to the 2016, 2017 and 2018 Term Loans of $0.3 million and $0.1 million, respectively.~~

Our wholly-owned subsidiaries operating in Turkey are party to unsecured, non-interest bearing lines of credit with a Turkish bank. At ~~March 31,~~September 30, 2019, we had no$0.6 million outstanding borrowings under these lines of credit.

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

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

operations yards in Turkey is recognized in our consolidated statements of operations and comprehensive (loss) income under the caption “Production”.

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

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

	March 31, 2019		September 30, 2019
	(in thousands)		(in thousands)
Operations yards	$	146	$	439
Office rent		58		176
Vehicles		36		103
Other		23		62
Total lease costs	$	263	$	780

Future non-cancelable minimum lease payments under our operating lease commitments as of ~~March 31,~~September 30, 2019 ~~are~~were as follows for each of the next ~~fives~~five years and thereafter:

	March 31, 2019		September 30, 2019
	(in thousands)		(in thousands)
Remainder of 2019	$	756	$	276
2020		731		731
2021		658		658
2022		648		648
2023		327		327
2024		-		-
Thereafter		-		-
Total	$	3,120	$	2,640
Less: Imputed interest		567		348
Present value of lease liabilities	$	2,553	$	2,292

As of ~~March 31,~~September 30, 2019, the weighted average remaining lease term in years is ~~4.25~~3.8 years and the weighted average discount rate used was ~~7.55%~~7.6%.

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

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

During 2012, we were notified that the 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 Minister of Energy filed a suit in the Sofia City Court against Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”), claiming $200,000 in liquidated damages for Direct Bulgaria’s alleged failure to fulfill its obligations under the Aglen exploration 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, imposed by the Bulgarian 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 ordered the Bulgarian Minister of Energy to pay Direct Bulgaria’s attorney’s fees and

legal costs for court experts. In June 2018, the Bulgarian Minister of Energy filed an appeal in the Sofia Court of Appeal. In November 2018, the Sofia Court of Appeal concluded that the judgement of the Sofia City Court was correct and, therefore, dismissed the Bulgarian Minister of Energy’s appeal. In January 2019, the Bulgarian Minister of Energy filed an appeal in the Supreme Court of Cassation. We continue to vigorously defend against this claim.

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

We recorded share-based compensation expense of $0.1 million ~~and $0.1 million~~ for awards of restricted stock units (“RSUs”) for each of the three months ended ~~March 31,~~September 30, 2019 and ~~2018, respectively.~~2018. We recorded share-based compensation expense of $0.3 million for awards of RSUs for each of the nine months ended September 30, 2019 and 2018.

As of ~~March 31,~~September 30, 2019, we had approximately ~~$0.2~~$0.6 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of ~~0.8~~1.4 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 months ended ~~March 31,~~September 30, 2019 and 2018 equals net loss divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding unvested RSUs. Diluted earnings per common share for the three and nine months ended ~~March 31,~~September 30, 2019 and 2018 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes RSUs and preferred shares, whether exercisable or not. For the three and nine months ended ~~March 31,~~September 30, 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						Three Months Ended					Nine Months Ended
	March 31,						September 30,					September 30,
(in thousands, except per share amounts)	2019			2018			2019		2018			2019			2018
Net loss	$	(3,902	)	$	(1,775	)
Basic net loss earnings per common share:
Net income (loss)							$	1,070	$	(1,720	)	$	(2,841	)	$	(4,501	)
Basic net income (loss) earnings per common share:
Shares:
Weighted average common shares outstanding		52,483			50,374			57,680		50,597			54,249			50,465
Basic net loss per common share:	$	(0.07	)	$	(0.04	)
Diluted net loss per common share:
Basic net income (loss) per common share:							$	0.02	$	(0.03	)	$	(0.05	)	$	(0.09	)
Diluted net income (loss) per common share:
Shares:
Weighted average common shares outstanding		52,483			50,374			57,680		50,597			54,249			50,465
Diluted net loss per common share:	$	(0.07	)	$	(0.04	)
Diluted net income (loss) per common share:							$	0.02	$	(0.03	)	$	(0.05	)	$	(0.09	)

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

	Corporate			Turkey		Bulgaria			Total			Corporate			Turkey		Bulgaria			Total
	(in thousands)											(in thousands)
For the three months ended March 31, 2019
For the three months ended September 30, 2019
Total revenues	$	-		$	19,041	$	-		$	19,041		$	-		$	14,653	$	-		$	14,653
(Loss) income from operations before income taxes		(2,873	)		7,616		(5,222	)		(479	)		(3,984	)		5,932		(628	)		1,320
Capital expenditures	$	-		$	9,857	$	-		$	9,857		$	-		$	9,696	$	487		$	10,183
For the three months ended March 31, 2018
For the three months ended September 30, 2018
Total revenues												$	-		$	20,140	$	-		$	20,140
(Loss) income from operations before income taxes													(2,995	)		7,184		(52	)		4,137
Capital expenditures												$	-		$	6,087	$	-		$	6,087
For the nine months ended September 30, 2019
Total revenues												$	-		$	50,909	$	-		$	50,909
(Loss) income from operations before income taxes													(9,524	)		20,304		(6,582	)		4,198
Capital expenditures												$	-		$	20,424	$	5,537		$	25,961
For the nine months ended September 30, 2018
Total revenues	$	-		$	16,926	$	-		$	16,926		$	-		$	55,264	$	-		$	55,264
(Loss) income from operations before income taxes		(3,806	)		3,364		(46	)		(488	)		(11,230	)		15,160		(173	)		3,757
Capital expenditures	$	-		$	5,246	$	-		$	5,246		$	-		$	17,708	$	-		$	17,708
Segment assets
March 31, 2019	$	11,244		$	134,831	$	1,548		$	147,623
September 30, 2019												$	8,842		$	133,806	$	625		$	143,273
December 31, 2018	$	8,358		$	122,325	$	1,917		$	132,600		$	8,358		$	122,325	$	1,917		$	132,600

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

We have underlying foreign currency exchange rate exposure. Our currency exposures primarily relate to transactions denominated in the Bulgarian Lev, the European Union Euro, and the TRY. We are also subject to foreign currency exposures resulting from translating the functional currency of our subsidiary financial statements into the USD reporting currency. At ~~March 31,~~September 30, 2019, we had ~~1.2~~38.0 million TRY (approximately ~~$0.2~~$6.7 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY. At ~~March 31,~~September 30, 2019, we were a party to foreign exchange derivative contracts (See Note 6. “Derivative instruments”).

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including, but not limited to, supply and demand. At ~~March 31,~~September 30, 2019, ~~and~~we were a party to commodity derivative contracts (See Note 6. “Derivative instruments”). At December 31, 2018, we were not party to any commodity derivative contracts.

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

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities and our loans payable were each estimated to have a fair value approximating the carrying amount at ~~March 31,~~September 30, 2019 and December 31, 2018, due to the short maturity of those instruments.

The following table summarizes the valuation of our financial assets and liabilities as of ~~March 31,~~September 30, 2019:

	Fair Value Measurement Classification											Fair Value Measurement Classification
	Quoted Prices in											Quoted Prices in
	Active Markets for											Active Markets for
	Identical Assets or		Significant Other			Significant						Identical Assets or		Significant Other			Significant
	Liabilities		Observable Inputs			Unobservable Inputs						Liabilities		Observable Inputs			Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)			Total			(Level 1)		(Level 2)			(Level 3)			Total
	(in thousands)											(in thousands)
Measured on a recurring basis
Assets:
Commodity derivative contracts												$	-	$	384		$	-		$	384
Liabilities:
Foreign exchange derivative contracts	$	-	$	(110	)	$	-		$	(110	)	$	-	$	(414	)	$	-		$	(414	)
Disclosed but not carried at fair value
Liabilities:
2019 Term Loan		-		-			(15,981	)		(15,981	)		-		-			(17,349	)		(17,349	)
2018 Term Loan		-		-			(7,014	)		(7,014	)		-		-			(2,189	)		(2,189	)
2017 Term Loan		-		-			(8,789	)		(8,789	)		-		-			(3,116	)		(3,116	)
Total	$	-	$	-		$	(31,784	)	$	(31,784	)	$	-	$	-		$	(22,654	)	$	(22,654	)

The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2018:

We remeasure our derivative contracts on a recurring basis, with changes flowing through earnings. At ~~March 31,~~September 30, 2019 and December 31, 2018, the fair values of the 2019 Term Loan, the 2018 Term Loan, and the 2017 Term Loan were estimated using a discounted cash flow analysis based on unobservable Level 3 inputs, including our own credit risk associated with the loans payable.

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

	March 31,		December 31,		September 30,		December 31,
	2019		2018		2019		2018
	(in thousands)				(in thousands)
Related party accounts receivable:
Service Agreement	$	412	$	526	$	381	$	526
PSI MSA		486	352			472	352
Total related party accounts receivable	$	898	$	878	$	853	$	878
Related party accounts payable:
Service Agreement	$	309	$	372	$	127	$	372
PSI MSA		1,677		2,439		3,425		2,439
Interest payable on Series A Preferred		681		-
Other - board of directors fees		-		111		-		111
Total related party accounts payable	$	2,667	$	2,922	$	3,552	$	2,922

We are a party to a Service Agreement (as amended, the “Service Agreement”) with Longfellow Energy, LP (“Longfellow”), Viking Drilling, LLC (“Viking Drilling”), Riata Management, LLC (“Riata”), LFN Holdco LLC (“LFN”), Red Rock Minerals, LP (“RRM”), Red Rock Minerals II, LP (“RRM II”), Red Rock Advisors, LLC (“RRA”), Production Solutions International Limited (“PSIL”), and NexLube Operating, LLC (“NexLube”) and their subsidiaries (collectively, the “Riata Entities”), under which we and the Riata Entities agreed to provide technical and administrative services to each other from time to time on an as-needed basis. Under the terms of the 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 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 ~~March 31,~~September 30, 2019, we had $0.4 million of outstanding receivables and $~~0.3~~0.1 million of outstanding payables pursuant to 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, which equipment is owned and operated by Production Solutions International Petrol Arama Hizmetleri Anonim Sirketi (“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 “PSI MSA”) with PSI on substantially similar terms to our then current master services agreements with Viking International, VOS, and Viking Geophysical. Pursuant to the PSI MSA, PSI performs the 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 agreement with each of Viking International, VOS, and Viking Geophysical currently remain in effect.

As of ~~March 31,~~September 30, 2019, we had ~~$0.5~~$0.5 million of outstanding receivables and ~~$1.7~~$3.4 million of outstanding payables pursuant to the PSI MSA.

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

TransAtlantic USA subleases approximately 10,000 square feet of corporate office space in Addison, Texas. The initial lease term under the Sublease commenced on June 14, 2018 (the “Commencement Date”) and expires on June 30, 2020, unless earlier terminated in accordance with the Sublease. From the Commencement Date until June 30, 2019, TransAtlantic USA iswas 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~~increased 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.

During the nine months ended September 30, 2019, we issued an aggregate of 4,985,732 common shares to holders of the Series A Preferred Shares as payment of the June 30, 2019 and September 30, 2019 quarterly dividends on the Series A Preferred Shares. Of the 4,985,732 common shares, 2,224,903 common shares were issued to Dalea Partners, LP (“Dalea”), Longfellow, and the trusts of Mr. Mitchell’s four adult children.

On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries, Viking International and Viking Geophysical, to a joint venture owned by Dalea ~~Partners, LP (“Dalea”)~~ and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $168.5 million, consisting of approximately $157.0 million in cash and a $11.5 million promissory note from Dalea (the “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, 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 ~~$7,964,053,~~$8.0 million, 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 ~~$7,964,053~~$8.0 million in exchange for the cancellation of an account payable of approximately $3.5 million (the “Account Payable”) owed by TransAtlantic Albania Ltd. (“TransAtlantic Albania”), our former subsidiary, to Viking International. ~~We have indemnified a third party for any liability relating to the payment of the Account Payable.~~

Pursuant to the Note Amendment Agreement, on April 19, 2016, we entered into the Amended Note, which amended and restated the Original Note that was issued in connection with our sale of 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, 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 PSI to less than 50%; (ii) the sale or transfer by Dalea or PSI of all or substantially all of its assets to any person (a “Transferee”) that does not own a controlling interest in Dalea or 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 PSI; (iv) termination of the PSI MSA other than as a result of an uncured default thereunder by TEMI; (v) default by PSI under the PSI MSA, which default is not remedied within a period of 30 days after notice thereof to PSI; and (vi) insolvency or bankruptcy of 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. On February 28, 2019, we and Dalea entered into an amendment (the “Note Amendment”) to the Amended Note (as amended by the Note Amendment, the “Note”), pursuant to which we and Dalea agreed to extend the maturity date of the Note to February 26, 2021 (unless otherwise accelerated in accordance with the terms of the Note).

In addition, pursuant to the Note Amendment Agreement, on April 19, 2016, we entered into a pledge agreement (the “Pledge Agreement”) with Dalea, whereby Dalea pledged the $2.0 million principal amount of the Company’s 13.0% Senior Convertible Notes due 2017 ~~Notes~~(“Convertible Notes”) owned by Dalea (the “Dalea Convertible Notes”), including any future securities for which the Dalea Convertible Notes are converted or exchanged, as security for the performance of Dalea’s obligations under the Amended Note. The Pledge Agreement provides 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~~Convertible Notes for 40,000 Series A Preferred Shares.

On ~~February~~June 28, 2019, we and Dalea entered into an amendment ~~(the “Note Amendment”)~~ to the ~~Amended Note (as amended by the Note Amendment, the “Note”),~~Pledge Agreement, pursuant to which we and Dalea agreed that any interest payable on the Series A Preferred Shares held by Dalea and ~~we agreed to extend~~pledged under the ~~maturity date~~Pledge Agreement (i) if paid in cash, will be credited first against the outstanding principal balance of the Note ~~to February 26, 2021 (unless otherwise accelerated in accordance with the terms~~and, upon full repayment of the ~~Note).~~outstanding principal balance of the Note, any accrued and unpaid interest on the Note, and (ii) if paid other than in cash, will be paid to Dalea and, within five business days of such payment to Dalea, Dalea will pay $61,500 toward the principal and, upon full repayment of the outstanding principal balance of the Note, any accrued and unpaid interest on the Note.

During the ~~three~~nine months ended ~~March 31,~~September 30, 2019, we reduced the principal amount of the Note by $1.0 million for amounts prepaid by Dalea on February 28, 2019 in conjunction with the Note Amendment and by ~~$0.1~~$0.2 million ~~for cash~~as a result of dividends paid on the Series A Preferred Shares.

As of ~~March 31,~~September 30, 2019, the amount receivable under the Note was ~~$4.6~~$4.2 million.

In connection with the pledge of certain Gundem real estate and Muratli real estate to DenizBank as collateral, ~~for the 2016 Term Loan,~~ on August 31, 2016, we entered into a pledge fee agreement (the “Gundem Fee Agreement”) with Gundem Turizm Yatirim ve Isletme A.S., predecessor-in-interest to Gundem Yatirim with respect to the Gundem real estate and Muratli real estate pledged as collateral for the Term Loans (“Gundem”). Pursuant to the Gundem Fee Agreement, we pay Gundem Yatirim a fee equal to 5% per annum of the collateral value of the Gundem real estate and Muratli real estate pledged as collateral for the Term Loans. Pursuant to the Gundem Fee Agreement, the Gundem real estate has a deemed collateral value of $10.0 million and the Muratli real estate has a deemed collateral value of $5.0 million.

In connection with the pledge of the Diyarbakir real estate to DenizBank as collateral, ~~for the 2016 Term Loan,~~ on August 31, 2016, we entered into a pledge fee agreement with Messrs. Mitchell and Uras (the “Diyarbakir Fee Agreement”) pursuant to which we pay Mr. Mitchell and Mr. Uras a fee of 5% per annum of the collateral value of the Diyarbakir real estate. 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~~nine months ended ~~March 31,~~September 30, 2019, we reduced the principal amount of the ~~Amended~~ Note by ~~$0.1~~$0.5 million for amounts paid under the pledge fee agreements.

On ~~April 1 and April 24,~~October 17, 2019, we entered into foreign exchange option and forward contracts to hedge against currency fluctuations between the TRY and USD. The forward contract settlement date was October 31, 2019, and we had an unrealized a loss of $0.1 million. The option contract settlement dates are ~~between April~~December 3 and ~~July~~December 30, 2019 for $1.0 million at a strike price of ~~5.60 TRY to $1.00 USD. The forward contracts settlement dates are between June and September for $1.5 million at a strike price of 5.87~~5.935 TRY to $1.00 USD.

~~On April 16, 2019, we entered into a t~~hree-way costless collar with DenizBank to hedge 1,000 Bbl/day of our oil production in Turkey. The three-way collar term begins on May 1, 2019 and extends through April 30, 2020, with a weighted average minimum price of $55.00 per barrel, a weighted average maximum price of $72.90 per barrel, and an additional call ceiling of $80.00 per barrel.

On April 17, 2019 and effective as of August 1, 2017, we and our subsidiaries and the Riata Entities entered into the Third Amendment (the “Third Amendment”) to the Service Agreement, dated August 6, 2008 and effective as of May 1, 2008, as previously amended by the Amendment, dated February 9, 2009 and effective as of October 1, 2008, and the Second Amendment, dated and effective as of March 20, 2017. The Third Amendment added and removed certain of the Riata Entities. Each of the Riata Entities is an affiliate of Mr. Mitchell.

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 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 ~~March 31,~~September 30, 2019, we held interests in ~~372,050~~373,948 and 162,500 net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria, respectively. As of ~~May 3,~~November 8, 2019, approximately ~~48%~~46% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

We are a holding company with two operating segments – Turkey and Bulgaria. Our assets consist of our ownership interests in subsidiaries that primarily own assets in Turkey and Bulgaria.

The following summarizes our financial and operational performance for the ~~first~~third quarter of 2019:

During the ~~first~~third quarter of 2019, we spud two wells and continued workover and recompletion production optimizations in southeastern Turkey. ~~Additionally, we re-drilled and tested one well in Bulgaria.~~

Yeniev Field. ~~Both~~In the ~~Yeniev-1 and West Yeniev-1 wells continue flowing naturally with little water. In November 2018, we spud~~third quarter of 2019,completion operations continued on the ~~East Yeniev-1 appraisal~~Yeniev-4 well, ~~to further delineate the structure. The well was~~which had been drilled to a total measured depth of ~~9,900~~9,520 feet targeting the Bedinan, Hazro, and ~~encountered hydrocarbon shows~~Mardin formations. We successfully recovered 84 feet of core from the Bedinan sandstone, which is currently undergoing analysis to assist in infill development planning and secondary recovery evaluation. The well was completed naturally in the lower Bedinan sandstone with an unstimulated initial production rate of 167 barrels of oil per day (“Bopd”).

In the third quarter of 2019, we drilled the Yeniev-5 well to a total measured depth of 7,060 feet targeting the Mardin formation. We successfully recovered 159 feet of core from two intervals within the Mardin, both of which showed live streaming oil on the cores. Completion operations are ongoing.

In October 2019, we drilled the Yeniev-6 well to a total measured depth of 9,650 feet, targeting the Mardin and Bedinan formations. Completion operations ~~began in January 2019 and resulted in a discovery~~are ongoing.

The West Yeniev-1 well underwent production optimization with the installation of artificial lift in the ~~Mardin formation.~~third quarter of 2019. Production increased to 173 Bopd from 104 Bopd when the well was flowing naturally. Further production optimization is planned in the fourth quarter of 2019 with the goal of further increasing production.

Bahar Field. We drilled the Bahar-12 well in the third quarter of 2019, targeting the Bedinan and Hazro formations. A three-stage Bedinan stimulation was executed. The well had an initial production rate of 382 Bopd flowing naturally. We successfully recovered a total of 274 feet of core from intervals within the Bedinan and Hazro formations. We intend to analyze the cores to assist in optimizing reservoir development.

Bati-Yasince Field. In the third quarter of 2019, we reentered the Bati-Yasince-1 well, targeting the Hazro formation. We ~~spud~~drilled the ~~Southeast Bahar-1~~ well ~~in March 2019. The well was drilled~~ to a total measured depth of ~~11,000 feet~~8,628 feet. Completion operations are ongoing.

Arpatepe Field. In the third quarter of 2019, we engaged in technical design and ~~encountered oil shows in~~planning of a water-flood of the ~~Mardin, Hazro,~~Arpatepe field. Following completion of the design and ~~Bedinan formations. We expect~~planning, we plan to ~~begin completion~~recomplete the Arpatepe-2 well as a water injection well and execute the first phase of the water-flood.

During the third quarter of 2019, we continued recompletion, workover, and production optimization operations in the ~~second quarter of 2019.~~

~~Other.~~ We spud the Blackeye-1 well in January 2019. The well was drilled to a total measured depth of 11,105 feet and encountered oil shows in the Hazro, Mardin, and Bedinan formations. The well was completed in the Hazro formation and put on production in the first quarter of 2019.

~~We have applied for conversion of the New Molla exploration license into a production lease and expect a final determination with respect to our application in the second quarter of 2019.~~

We have completed the initial phase of operations in the Selmo-1 well to re-enter and test the Permian formation, establishing the productivity of the Permian formation. During a short-term flow test of a previously untested interval, the Selmo-1 well tested 45.6 API condensate along with natural gas containing a high carbon dioxide percentage component. field.

We continue to evaluate our prospects in the Thrace Basin’s Basin Center Gas Accumulation (“Thrace Basin BCGA”) in light of the recent ~~production test results at the Yamalik-1~~ exploration ~~well operated~~activity by Valeura Energy Inc. ~~(“Valeura”)~~ with ~~their~~its partner Equinor ASA (formerly Statoil ASA) ~~(“Equinor”). The Yamalik-1 exploration well is located~~ on a license directly adjacent to our 120,000 net acres in the Thrace Basin of which we believe approximately 50,000 net acres (100% working interest, 87.5% net revenue interest) is in the Thrace Basin ~~BCGA and analogous to the Valeura and Equinor acreage.~~BCGA.

Subsequent to drilling and testing of the Yamalik-1 well, the joint venture between Valeura and Equinor announced a three-well program. In the first quarter of 2019, Valeura and Equinor announced that they drilled and cased a second well in the Thrace Basin BCGA, the Inanli-1 well. According to Valeura and Equinor, the well was drilled to a total depth of 4,885 meters and encountered 1,615 meters of high net-to-gross sandstone, which they interpreted to contain over-pressured gas. In the first quarter of 2019, Valeura and Equinor announced that they commenced completion operations for the Inanli-1 well. In the second quarter of 2019, ~~Valeura and Equinor announced that they~~we drilled the ~~Devepinar-1 appraisal~~Karli-1 well to a total measured depth of ~~4,796 meters~~1,289 feet and encountered ~~1,066 meters of high-pressure~~several shallow gas ~~saturated rock.~~

~~We expect~~sand intervals. While the shallow gas horizon proved non-productive, the well is strategically positioned to ~~spud a shallow exploration well on~~test our ~~license in the~~ Thrace Basin ~~in the second quarter of 2019.~~BCGA acreage.

We commenced the side-track and re-drilling of the Deventci R-1 well in December 2018, targeting the Ozirovu and Dolmi Dabnik formations. The well was drilled to a total depth of 16,450 feet. Although we encountered the targeted formations, tests did not indicate commercial quantities of reservoir quality rock. The well was plugged and abandoned at a cost of $5.1 million as of March 31, 2019. We are currently evaluating future activity in Bulgaria.

We expect that cash on hand and cash flow from operations will be sufficient to fund the remainder of our 2019 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected remaining 2019 capital expenditure budget is subject to change.

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 U.S. GAAP. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in ~~“Note~~Note 3. ~~Significant~~“Significant accounting policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2018 and are of particular importance to the portrayal of our financial position and results of operations and require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

Results of Operations—Three Months Ended ~~March 31,~~September 30, 2019 Compared to Three Months Ended ~~March 31,~~September 30, 2018

Our results of operations for the three months ended ~~March 31,~~September 30, 2019 and 2018 were as follows:

	Three Months Ended March 31,						Change			Three Months Ended September 30,						Change
	2019			2018			2019-2018			2019			2018			2019-2018
	(in thousands of U.S. Dollars, except per unit amounts and production volumes)									(in thousands of U.S. Dollars, except per unit amounts and production volumes)
Sales volumes:
Oil (Mbbl)		269			248			21			237			261			(24	)
Natural gas (Mmcf)		50			67			(17	)		47			45			2
Total production (Mboe)		277			260			17			245			268			(23	)
Average daily sales volumes (Boepd)		3,082			2,885			197			2,662			2,917			(255	)
Average prices:
Oil (per Bbl)	$	69.00		$	65.71		$	3.29		$	60.12		$	76.32		$	(16.20	)
Natural gas (per Mcf)	$	5.94		$	5.00		$	0.94		$	6.18		$	4.23		$	1.95
Oil equivalent (per Boe)	$	68.00		$	64.17		$	3.83		$	59.37		$	74.89		$	(15.52	)
Revenues:
Oil and natural gas sales	$	18,861		$	16,661		$	2,200		$	14,543		$	20,098		$	(5,555	)
Other		180			265			(85	)		110			42			68
Total revenues		19,041			16,926			2,115			14,653			20,140			(5,487	)
Costs and expenses (income):
Production		2,502			2,869			(367	)		3,162			2,307			855
Transportation and processing		1,319			1,193			126			1,262			1,054			208
Exploration, abandonment and impairment		5,113			40			5,073			488			162			326
Seismic and other geological and geophysical		77			159			(82	)		48			122			(74	)
General and administrative		3,054			3,337			(283	)		2,503			2,539			(36	)
Depletion		3,579			4,197			(618	)		2,885			2,800			85
Depreciation and amortization		137			262			(125	)		136			138			(2	)
Interest and other expense		2,478			2,782			(304	)		2,780			2,776			4
Interest and other income		(174	)		(254	)		80			(381	)		(211	)		(170	)
Foreign exchange loss		1,273			2,058			(785	)		797			2,991			(2,194	)
Gain (loss) on derivative contracts:
Cash settlements on derivative contracts		-			(1,339	)		1,339			-			(510	)		510
Change in fair value on derivative contracts		(110	)		614			(724	)		403			(780	)		1,183
Total loss on derivative contracts		(110	)		(725	)		615
Total gain (loss) on derivative contracts											403			(1,290	)		1,693
Oil and natural gas costs per Boe:
Production	$	7.90		$	10.28		$	(2.38	)	$	11.30		$	7.52		$	3.78
Depletion	$	11.29		$	14.53		$	(3.24	)	$	10.31		$	9.13		$	1.18

Oil and Natural Gas Sales. Total oil and natural gas sales revenues ~~increased~~decreased to ~~$18.9~~$14.5 million for the three months ended ~~March 31,~~September 30, 2019 from ~~$16.7~~$20.1 million for the same period in 2018. The ~~increase~~decrease was primarily due to ~~an increase~~a decrease in the average realized price per ~~Boe.~~Boe and a decrease in the average daily sales volumes. Our average price received ~~increased $3.83~~decreased $15.52 per Boe to ~~$68.00~~$59.37 per Boe for the three months ended ~~March 31, 2018~~September 30, 2019 from ~~$64.17~~$74.89 per Boe for the same period in 2018. ~~The increase was also due to an increase in our~~Our average daily sales volumes ~~of 197~~decreased 255 Boe per day (“Boepd”) for the three months ended ~~March 31,~~September 30, 2019 as compared to the same period in 2018.

Production. Production expenses ~~decreased~~increased to ~~$2.5~~$3.2 million, or ~~$7.90~~$11.30 per Boe, for the three months ended ~~March 31,~~September 30, 2019 from ~~$2.9~~$2.3 million, or ~~$10.28~~$7.52 per Boe for the same period in 2018. The ~~decrease~~increase was primarily due to aincreased costs for electricity, rental equipment, and diesel fuel consumption associated with new wells on production and the devaluation of the TRY as compared to the ~~USD, as most of our production expenses are denominated~~same period in ~~TRY.~~2018.

Transportation and Processing. Transportation and processing expense increased to $1.3 million for the three months ended ~~March 31,~~September 30, 2019 from ~~$1.2~~$1.1 million for the same period in 2018. The increase in transportation expenses was primarily due to an increase in the service cost per barrel as compared to the same period in 2018.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment cost increased to $0.5 million for the three months ended September 30, 2019 from $0.2 million for the same period in 2018. The increase was due to the exploratory dry hole write-off of the Deventci R-1 well.

General and Administrative. General and administrative expense was flat at $2.5 million for each of the three months ended September 30, 2019 and 2018.

Depletion. Depletion expense increased to $2.9 million, or $10.31 per Boe, for the three months ended September 30, 2019 from $2.8 million, or $9.13 per Boe, for the same period of 2018. The increase was primarily due to an increase to our proved properties during the three months ended September 30, 2019.

Interest and Other Expense. Interest and other expense was flat at $2.8 million for each of the three months ended September 30, 2019 and 2018.

Foreign Exchange Loss. We recorded a foreign exchange loss $0.8 million for the three months ended September 30, 2019 as compared to $3.0 million for the same period in 2018. Foreign exchange gains and losses are primarily unrealized (non-cash) in nature and result from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a 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.

Gain (Loss) on Derivative Contracts. We recorded a net gain on derivative contracts of $0.4 million for the three months ended September 30, 2019 as compared to a net loss of $1.3 million for the same period in 2018. During the three months ended September 30, 2019, we recorded a $0.4 million gain to mark our commodity and currency derivative contracts to their fair value. During the same period in 2018, we recorded a $0.8 million loss to mark our commodity derivative contracts to their fair value and a $0.5 million loss on settled contracts.

Results of Operations—Nine Months Ended September 30, 2019 Compared to Nine Months Ended September 30, 2018

Our results of operations for the nine months ended September 30, 2019 and 2018 were as follows:

	Nine Months Ended September 30,						Change
	2019			2018			2019-2018
	(in thousands of U.S. Dollars, except per unit amounts and production volumes)
Sales volumes:
Oil (Mbbl)		760			750			10
Natural gas (Mmcf)		145			168			(23	)
Total production (Mboe)		784			778			6
Average daily sales volumes (Boepd)		2,871			2,839			32
Average prices:
Oil (per Bbl)	$	65.42		$	72.09		$	(6.67	)
Natural gas (per Mcf)	$	5.84		$	4.74		$	1.10
Oil equivalent (per Boe)	$	64.48		$	70.52		$	(6.04	)
Revenues:
Oil and natural gas sales	$	50,537		$	54,859		$	(4,322	)
Other		372			405			(33	)
Total revenues		50,909			55,264			(4,355	)
Costs and expenses (income):
Production		8,376			7,980			396
Transportation and processing		3,802			3,385			417
Exploration, abandonment and impairment		6,267			393			5,874
Seismic and other geological and geophysical		233			340			(107	)
General and administrative		8,247			9,662			(1,415	)
Depletion		9,779			10,142			(363	)
Depreciation and amortization		400			531			(131	)
Interest and other expense		8,011			7,649			362
Interest and other income		(776	)		(842	)		66
Foreign exchange loss		2,185			6,987			(4,802	)
Loss on derivative contracts:
Cash settlements on derivative contracts		-			(3,710	)		3,710
Change in fair value on derivative contracts		(30	)		(1,446	)		1,416
Total loss on derivative contracts		(30	)		(5,156	)		5,126
Oil and natural gas costs per Boe:
Production	$	9.35		$	8.97		$	0.38
Depletion	$	10.92		$	11.42		$	(0.50	)

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased to $50.5 million for the nine months ended September 30, 2019 from $54.9 million for the same period in 2018. The decrease was primarily due to a decrease in the average realized price per Boe. Our average price received decreased $6.04 per Boe to $64.48 per Boe for the nine months ended September 30, 2019 from $70.52 per Boe for the same period in 2018. This was partially offset by an increase in our average daily sales volumes of 32 Boepd for the nine months ended September 30, 2019 as compared to the same period in 2018.

Production. Production expenses increased to $8.4 million, or $9.35 per Boe, for the nine months ended September 30, 2019 from $8.0 million, or $8.97 per Boe, for the same period in 2018. The increase was primarily due to increased costs for electricity, rental equipment and diesel fuel consumption associated with new wells on production.

Transportation and Processing. Transportation and processing expense increased to $3.8 million for the nine months ended September 30, 2019 from $3.4 million for the same period in 2018. The increase in transportation expenses was primarily due to the increase in our average daily sales volumes ~~197 Boepd.~~of 32 Boepd and an increase in the service cost per barrel as compared to the same period in 2018.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment cost increased to ~~$5.1 million~~$6.3million for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 from ~~$0.1~~$0.4 million for the same period in 2018. The increase was due to the exploratory dry hole write-off of the Deventci R-1 well.

General and Administrative. General and administrative expense decreased to ~~$3.1~~$8.2 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 from ~~$3.3~~$9.7 million for the same period in 2018. The decrease was primarily due to a decrease in professional and accounting fees associated with the evaluation of strategic ~~transaction~~alternatives in 2018.

Depletion. Depletion expense decreased to ~~$3.6~~$9.8 million, or ~~$11.29~~$10.92 per Boe, for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 from ~~$4.2~~$10.1 million, or ~~$14.53~~$11.42 per Boe, for the same period of 2018. The decrease was primarily due to the devaluation of the TRY to the USD.

Interest and Other Expense. Interest and other expense ~~decreased~~increased to ~~$2.5~~$8.0 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 from ~~$2.8~~$7.6 million for the same period in 2018. The ~~decrease~~increase was due to paying our ~~lower~~Series A Preferred dividend in common shares and our higher average debt balances outstanding during the ~~three~~nine months ended ~~March 31,~~September 30, 2019 versus the same period in 2018.

Foreign Exchange Loss. We recorded a foreign exchange loss of ~~$1.3~~$1.9 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 as compared to ~~$2.1~~$7.0 million for the same period in 2018. Foreign exchange gains and losses are primarily unrealized (non-cash) in nature and result from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a 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 ~~three~~nine months ended ~~March 31,~~September 30, 2019 was due to a decrease in the value of the TRY compared to the USD. From December 31, 2018 to ~~March 31,~~September 30, 2019, the TRY to the USD declined ~~7.0%~~7.6%. At ~~March 31,~~September 30, 2019, the exchange rate was ~~5.6284~~5.6591 as compared to 5.2609 at December 31, 2018.

~~Gain (Loss)~~Loss on Derivative Contracts. We recorded a net loss on derivative contracts of ~~$0.1~~$0.03 million for the ~~three~~nine months ended ~~March 31,~~September 30, 2019 as compared to ~~$0.7~~$5.2 million for the same period in 2018. During the ~~three~~nine months ended ~~March 31,~~September 30, 2019, we recorded a ~~$0.1~~$0.03 million loss to mark our commodity and currency derivative contracts to their fair value. During the same period in 2018, we recorded a ~~$0.6~~$1.4 million ~~gain~~loss to mark our commodity derivative contracts to their fair value and a ~~$1.3~~$3.7 million loss on settled contracts.

For the three months ended ~~March 31,~~September 30, 2019, we incurred ~~$9.9~~$10.2 million in capital expenditures, including seismic and corporate expenditures, as compared to ~~$5.2~~$6.1 million for the same period in 2018.

We expect our net field capital expenditures for the remainder of 2019 to range between ~~$15.0~~$2.5 million and ~~$20.0 million. We expect net field capital expenditures during the remainder of 2019 to include between $14.5~~$5.0 million ~~and $19.5 million in~~for drilling and completion ~~expense and approximately $0.5 million in recompletion expense.~~expenses. We expect that cash on hand and cash flow from operations will be sufficient to fund the remainder of our 2019 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected remaining 2019 capital expenditure budget is subject to change.

Net cash provided by operating activities during the ~~three~~nine months ended ~~March 31,~~September 30, 2019 was ~~$4.5~~$25.7 million, ~~a decrease~~an increase from net cash provided by operating activities of ~~$7.8~~$25.2 million for the same period in 2018. The ~~decrease~~increase was primarily due to an increase in our ~~accounts receivable which was partially offset by an increase~~operating assets and liabilities and a decrease in our ~~revenues.~~net loss.

Net cash used in investing activities during the ~~three~~nine months ended ~~March 31,~~September 30, 2019 was ~~$9.3~~$25.2 million, an increase from net cash used in investing activities of ~~$7.0~~$21.0 million for the same period in 2018. The increase was primarily due to an increase in our capital expenditures as compared to the same period in ~~2017.~~2018.

Net cash provided by financing activities during the ~~three~~nine months ended ~~March 31,~~September 30, 2019 was ~~$15.8~~$5.0 million, an increase from net cash used in financing activities of ~~$4.1~~$2.4 million for the same period in 2018. The change was primarily due to an increase in our outstanding loans.

As of ~~March 31,~~September 30, 2019, we had ~~$36.9~~$26.1 million of indebtedness, not including ~~$8.7~~$9.6 million of trade payables, as further described below. We believe that our cash flow from operations will be sufficient to meet our normal operating requirements and to fund planned capital expenditures during the next 12 months. As of ~~March 31,~~September 30, 2019, we had a working capital surplus of ~~$10.8~~$3.5 million.

~~2016 Term Loan.~~ On August 23, 2016, the Turkish branch of TEMI entered into the Credit Agreement with DenizBank. The Credit Agreement is a master agreement pursuant to which DenizBank may make loans to TEMI from time to time pursuant to additional loan agreements.

On August 31, 2016, DenizBank entered the 2016 Term Loan under the Credit Agreement. In addition, we and DenizBank entered into additional agreements with respect to up to $20.0 million of non-cash facilities, including guarantee letters and treasury instruments for future hedging transactions. The 2016 Term Loan bore interest at a fixed rate of 5.25% (plus 0.2625% for Banking and Insurance Transactions Tax per the Turkish government) per annum and was payable in monthly installments of $1.38 million through June 2018. Amounts repaid under the 2016 Term Loan could not be re-borrowed and early repayments under the 2016 Term Loan were subject to early repayment fees. The 2016 Term Loan was guaranteed by DMLP, TransAtlantic Turkey, Talon Exploration, and TransAtlantic Worldwide.

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

The 2016 Term Loan was secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, and (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2016 Term Loan.

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

2017 Term Loan. On November 17, 2017, DenizBank entered into the 2017 Term Loan under the Credit Agreement. The 2017 Term Loan bears interest at a fixed rate of 6.0% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2017 Term Loan had a grace period which bore no interest or payments due until July 2018. Thereafter, the 2017 Term Loan is payable in one monthly installment of $1.38 million, nine monthly installments of $1.2 million each through April 2019 and thereafter in eight monthly installments of $1.0 million each through December 2019, with the exception of one monthly installment of $1.2 million occurring in October 2019. The 2017 Term Loan matures in December 2019. Amounts repaid under the 2017 Term Loan may not be re-borrowed, and early repayments under the 2017 Term Loan are subject to early repayment fees. The 2017 Term Loan is guaranteed by Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.

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

At ~~March 31,~~September 30, 2019, we had ~~$9.4~~$3.2 million outstanding under the 2017 Term Loan and no availability, and we were in compliance with the covenants in the 2017 Term Loan.

2018 Term Loan. On May 28, 2018, DenizBank entered into the 2018 Term Loan under the Credit Agreement. The 2018 Term Loan bears interest at a fixed rate of 7.25% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2018 Term Loan had a grace period through July 2018 during which no payments were due. Thereafter, accrued interest on the 2018 Term Loan is payable monthly and the principal on the 2018 Term Loan is payable in five monthly installments of $0.2 million each through December 2018, four monthly installments of $0.5 million each through April 2019, four monthly installments of $1.0 million each through August 2019, and four monthly installments of $0.75 million each through December 2019. The 2018 Term Loan matures in December 2019. Amounts repaid under the 2018 Term Loan may not be reborrowed, and early repayments under the

2018 Term Loan are subject to early repayment fees. The 2018 Term Loan is guaranteed by Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.

The 2018 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on encumbering or creating restrictions or limitations on all or a part of its assets, revenues, or properties, giving guaranties or sureties, selling assets or transferring revenues, dissolving, liquidating, merging, or consolidating, incurring additional debt, paying dividends, making certain investments, undergoing a change of control, and other similar matters. In addition, the 2018 Term Loan prohibits Amity, Talon Exploration, DMLP, and Transatlantic Turkey from incurring additional debt. An event of default under the 2018 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties, and obligations, bankruptcy or insolvency, and the occurrence of a material adverse effect.

The 2018 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI will assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2018 Term Loan.

At ~~March 31,~~September 30, 2019, we had ~~$7.5~~$2.3 million outstanding under the 2018 Term Loan and no availability, and we were in compliance with the covenants in the 2018 Term Loan.

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

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

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

The 2019 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on encumbering or creating restrictions or limitations on all or a part of its assets, revenues, or properties, giving guaranties or sureties, selling assets or transferring revenues, dissolving, liquidating, merging, or consolidating, incurring additional debt, paying dividends, making certain investments, undergoing a change of control, and other similar matters. In addition, the 2019 Term Loan prohibits Amity, Talon Exploration, DMLP, and Transatlantic Turkey from incurring additional debt. An event of default under the 2019 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties, and obligations, bankruptcy or insolvency, and the occurrence of a material adverse effect.

The 2019 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI will assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2019 Term Loan.

At ~~March 31,~~September 30, 2019, we had $20.0 million outstanding under the 2019 Term Loan and no availability, and we were in compliance with the covenants in the 2019 Term Loan.

Unsecured lines of credit. At September 30, 2019, we had $0.6 million outstanding borrowings under these lines of credit.

Series A Preferred Shares. As of ~~March 31,~~September 30, 2019, we had 921,000 Series A Preferred Shares outstanding. The Series A Preferred Shares contain a substantive conversion option, are mandatorily redeemable, and convert into a fixed number of common shares. As a result, under U.S. GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of ~~March 31,~~September 30, 2019, we had $21.3 million of Series A Preferred Shares and $24.8 million of Series A Preferred Shares – related party outstanding (See Note 3. “Series A Preferred Shares”).

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 ~~March 31,~~September 30, 2019, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and principal accounting and financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon the evaluation, our chief executive officer and principal accounting and financial officer concluded that, as of ~~March 31,~~September 30, 2019, our disclosure controls and procedures were effective at the reasonable assurance level.

There are inherent limitations to the effectiveness of any system of disclosure controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurances of achieving their control objectives.

There were no changes in our internal control over financial reporting that occurred during the quarter ended ~~March 31,~~September 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

During the ~~first~~third quarter of 2019, there were no material developments to the Legal Proceedings disclosed in “Part I, Item 3. Legal Proceedings” in our Annual Report on Form 10-K for the year ended December 31, 2018.

~~During~~Except as set forth below, during the ~~first~~third quarter of 2019, there were no material changes to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, ~~2018.~~2018:

Acts of violence, terrorist attacks, or civil unrest in Turkey and nearby countries, or sanctions on Turkey, could adversely affect our business.

During 2019, we derived all of our revenue from our operations in Turkey and substantially all of our oil production was derived from southeastern Turkey. Historically, the southeastern area of Turkey and nearby countries such as Iran, Iraq, and Syria have occasionally experienced political, social, security, and economic problems, terrorist attacks, insurgencies, war, and civil unrest. Since December 2010, political instability has increased in a number of countries in the Middle East and North Africa. As a result of the civil war in Syria, large numbers of Syrian refugees have fled to Turkey. In addition, tensions continue between Turkey and Syria. In October 2019, President Trump announced a decision to withdraw U.S. military forces from certain areas of northeastern Syria, and Turkey announced the establishment of a safe zone along the border with Syria, contiguous to the region where our southeast Turkey licenses are located. Separately, Turkey has experienced occasional terrorist incidents. In July 2016, there was a failed attempt to overthrow the government of President Recep Tayyip Erdoğan.

On October 14, 2019, U.S. President Trump issued an executive order authorizing certain sanctions against Turkey, including specifically parties specially designated under this order in connection with Turkey’s military actions in Northern Syria. The U.S. Department of Treasury’s Office of Foreign Assets Control (“OFAC”) specifically designated and placed sanctions on two Turkish ministries and three government officials, including the Turkish Ministry of Energy and Natural Resources (“MENR”) and the Turkish Minister of Energy and Natural Resources, and issued a 30-day wind down license for affected operations and businesses. Our licenses in Turkey are issued by the MENR. Subsequently, on October 23, 2019, OFAC lifted these sanctions designations, while leaving the executive order in place. While the executive order does not impose any specific sanctions affecting Turkey at this time, additional sanctions could be imposed by OFAC under the authority established by this order against ministries, entities, or persons in Turkey, including in connection with or unrelated to draft bills that have been proposed in the U.S. House of Representatives and the U.S. Senate that call for a range of potential new sanctions on Turkey, including sanctions against the Turkish energy industry, that could have a materially adverse effect on our business.

The recent conflict with the terrorist group Islamic State in Iraq and Syria (“ISIS”), the tension in and involving the Kurdish regions of northern Iraq and northern Syria, which are contiguous to the region where our southeast Turkey licenses are located, the aftermath of the attempted coup d’etat, and the threat of sanctions on Turkey may have political, social, or security implications in Turkey or otherwise may impact the Turkish economy.

Turkey has also experienced problems with domestic terrorist and ethnic separatist groups. For example, Turkey has been in conflict for many years with the People’s Congress of Kurdistan (formerly known as the PKK), an organization that is listed as a terrorist organization by states and organizations, including Turkey, the European Union, and the United States.

The potential impact on our business from such events, conditions, and conflicts in these countries is uncertain. We may be unable to access the locations where we conduct operations or transport oil to our offtakers in a reliable manner. In those locations where we have employees or operations, we may incur substantial costs to maintain the safety of our personnel and our operations.

~~None~~On July 2, 2019, we issued an aggregate of 2,321,568 common shares to holders of the Series A Preferred Shares as payment of the June 30, 2019 quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of $0.7934 per common share, which was equal to the 15-day volume weighted average price through the close of trading of the common shares on the NYSE American on June 14, 2019.

On September 30, 2019, we issued an aggregate of 2,664,164 common shares to holders of the Series A Preferred Shares as payment of the September 30, 2019 quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of

$0.6914 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, 2019.

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

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

16803 Dallas Parkway, Suite 200 Addison, Texas	75001
(Address of Principal Executive Offices)	(Zip Code)

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of ~~March 31,~~September 30, 2019 (Unaudited) and December 31, 2018	4

Unaudited Consolidated Statements of Operations and Comprehensive (Loss) Income for the Three and Nine Months Ended ~~March 31,~~September 30, 2019 and 2018	5

Unaudited Consolidated Statement of ~~Shareholders’~~ Equity for the Three and Nine Months Ended ~~March 31,~~September 30, 2019 and 2018	6

Unaudited Consolidated Statements of Cash Flows for the ~~Three~~Nine Months Ended ~~March 31,~~September 30, 2019 and 2018	7

Notes to Unaudited Consolidated Financial Statements	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2423

Item 3. Quantitative and Qualitative Disclosures About Market Risk	2930

Item 4. Controls and Procedures	2930

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	31

Item 1A. Risk Factors	31

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	31

Item 3. Defaults Upon Senior Securities	3132

Item 4. Mine Safety Disclosures	3132

Item 5. Other Information	3132

Item 6. Exhibits	3233


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%

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

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

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

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

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

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

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

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.

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/ MICHAEL P. HILL
		Michael P. Hill Chief Accounting Officer

Date: ~~May 8,~~November 12, 2019

Large accelerated filer	☐	☐	Accelerated filer	☐

Non-accelerated filer	☒		Smaller reporting company	☒

			Emerging growth company	☐