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

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

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

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

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

As of May ~~7, 2018,~~3, 2019, the registrant had ~~50,384,698~~52,496,666 common shares outstanding.

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

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

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

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

March 31, 2018

December 31, 2017

ASSETS
(unaudited)

Current assets:

Cash and cash equivalents
$
16,251

$
18,926

Accounts receivable, net

Oil and natural gas sales

15,554

15,808

Joint interest and other

1,569

1,576

Related party

1,269

1,023

Prepaid and other current assets

4,957

3,866

Inventory

7,158

7,494

Total current assets

46,758

48,693

Property and equipment:

Oil and natural gas properties (successful efforts method)

Proved

194,577

193,647

Unproved

19,359

24,445

Equipment and other property

14,223

14,075

228,159

232,167

Less accumulated depreciation, depletion and amortization

(127,894
)

(129,183
)
Property and equipment, net

100,265

102,984

Other long-term assets:

Other assets

571

2,247

Note receivable - related party

6,507

6,726

Total other assets

7,078

8,973

Total assets
$
154,101

$
160,650

LIABILITIES, SERIES A PREFERRED SHARES AND SHAREHOLDERS' EQUITY

Current liabilities:

Accounts payable
$
5,082

$
4,853

Accounts payable - related party

4,554

3,141

Accrued liabilities (1)

11,131

10,014

Derivative liability

1,633

2,215

Asset retirement obligations - current

2

-

Loans payable

15,100

15,625

Total current liabilities

37,502

35,848

Long-term liabilities:

Asset retirement obligations less current portion

4,680

4,727

Accrued liabilities

8,721

8,810

Deferred income taxes

19,161

19,611

Loans payable

9,400

13,000

Total long-term liabilities

41,962

46,148

Total liabilities

79,464

81,996

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, 2018 and December 31, 2017, respectively

21,300

21,300

Series A preferred shares-related party, $0.01 par value, 495,000 shares authorized; 495,000 shares issued and outstanding with a liquidation preference of $50 per share as of March 31, 2018 and December 31, 2017, respectively

24,750

24,750

Shareholders' equity:

Common shares, $0.10 par value, 100,000,000 shares authorized; 50,383,870 shares and 50,319,156 shares issued and outstanding as of March 31, 2018 and December 31, 2017, respectively

5,038

5,032

Treasury stock

(970
)

(970
)
Additional paid-in-capital

575,506

575,411

Accumulated other comprehensive loss

(127,109
)

(124,766
)
Accumulated deficit

(423,878
)

(422,103
)
Total shareholders' equity

28,587

32,604

Total liabilities, Series A preferred shares and shareholders' equity
$
154,101

$
160,650

~~(1)~~

~~Includes income tax payable of $6.7 million and $6.2 million at March 31, 2018 and December 31, 2017, respectively.~~

	March 31, 2019			December 31, 2018
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	19,734		$	9,892
Accounts receivable, net
Oil and natural gas sales		21,852			12,912
Joint interest and other		1,061			982
Related party		898			878
Prepaid and other current assets		9,304			8,696
Note receivable - related party		–			5,828
Inventory		4,830			5,167
Total current assets		57,679			44,355
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		155,808			163,006
Unproved		15,195			15,695
Equipment and other property		13,559			14,408
		184,562			193,109
Less accumulated depreciation, depletion and amortization		(102,607	)		(105,850	)
Property and equipment, net		81,955			87,259
Other long-term assets:
Other assets		3,380			986
Note receivable - related party		4,609			–
Total other assets		7,989			986
Total assets	$	147,623		$	132,600
LIABILITIES, SERIES A PREFERRED SHARES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	6,074		$	3,896
Accounts payable - related party		2,667			2,922
Accrued liabilities		16,877			13,073
Derivative liability		110			–
Loans payable		21,186			22,000
Total current liabilities		46,914			41,891
Long-term liabilities:
Asset retirement obligations		4,490			4,667
Accrued liabilities		9,620			7,259
Deferred income taxes		20,531			20,314
Loans payable		15,714			–
Total long-term liabilities		50,355			32,240
Total liabilities		97,269			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
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
Treasury stock		(970	)		(970	)
Additional paid-in-capital		577,493			577,488
Accumulated other comprehensive loss		(146,247	)		(142,021	)
Accumulated deficit		(431,221	)		(427,319	)
Total shareholders' equity		4,304			12,419
Total liabilities, Series A preferred shares and shareholders' equity	$	147,623		$	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
	March 31,						March 31,
	2018			2017			2019			2018
Revenues:
Oil and natural gas sales	$	16,661		$	15,768		$	18,861		$	16,661
Sales of purchased natural gas		-			654
Other		265			14			180			265
Total revenues		16,926			16,436			19,041			16,926
Costs and expenses:
Production		2,869			3,087			2,502			2,869
Transportation and processing		1,193			-			1,319			1,193
Exploration, abandonment and impairment		40			106			5,113			40
Cost of purchased natural gas		-			568
Seismic and other exploration		159			15			77			159
General and administrative		3,337			3,590			3,054			3,337
Depreciation, depletion and amortization		4,459			4,497			3,716			4,459
Accretion of asset retirement obligations		46			48			52			46
Total costs and expenses		12,103			11,911			15,833			12,103
Operating income (loss)		4,823			4,525			3,208			4,823
Other income (expense):
Loss on sale of TBNG		-			(15,226	)
Interest and other expense		(2,782	)		(2,371	)		(2,478	)		(2,782	)
Interest and other income		254			293			174			254
(Loss) gain on commodity derivative contracts		(725	)		988
Foreign exchange (loss)		(2,058	)		(2,123	)
Loss on derivative contracts								(110	)		(725	)
Foreign exchange loss								(1,273	)		(2,058	)
Total other expense		(5,311	)		(18,439	)		(3,687	)		(5,311	)
Loss from continuing operations before income taxes		(488	)		(13,914	)
Loss from operations before income taxes								(479	)		(488	)
Income tax expense		(1,287	)		(2,135	)		(3,423	)		(1,287	)
Net loss		(1,775	)		(16,049	)		(3,902	)		(1,775	)
Other comprehensive income (loss):
Foreign currency translation adjustment		(2,343	)		20,919			(4,226	)		(2,343	)
Comprehensive income (loss)	$	(4,118	)	$	4,870
Comprehensive loss							$	(8,128	)	$	(4,118	)

Net loss per common share
Basic net loss per common share							$	(0.07	)	$	(0.04	)
Continuing operations	$	(0.04	)	$	(0.34	)
Weighted average common shares outstanding		50,374			47,298			52,483			50,374
Diluted net loss per common share							$	(0.07	)	$	(0.04	)
Continuing operations	$	(0.04	)	$	(0.34	)
Weighted average common and common equivalent shares outstanding		50,374			47,298			52,483			50,374

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

Consolidated Statement of Equity for the Three Months Ended March 31, 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			Shares		Shares		Warrants			Shares		Stock			Capital			Loss			Deficit			Equity
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	)		-			-			-			64		-		-			6		-			(6	)		-			-			-
Share-based compensation		-		-		-			-		-			101			-			-			101			-		-		-			-		-			101			-			-			101
Tax effect of restricted stock																										-		-		-			-		-			-			-			-			-
Foreign currency translation adjustment		-		-		-			-		-			-			(2,343	)		-			(2,343	)		-		-		-			-		-			-			(2,343	)		-			(2,343	)
Net loss		-		-		-			-		-			-			-			(1,775	)		(1,775	)		-		-		-			-		-			-			-			(1,775	)		(1,775	)
Balance at March 31, 2018		50,383		333		0		$	5,038	$	(970	)	$	575,506		$	(127,109	)	$	(423,878	)	$	28,587			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

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

	For the Three Months Ended						For the Three Months Ended
	March 31,						March 31,
	2018			2017			2019			2018
Operating activities:
Net loss	$	(1,775	)	$	(16,049	)	$	(3,902	)	$	(1,775	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-based compensation		101			136			102			101
Foreign currency loss (gain)		2,634			1,039
Loss (gain) on commodity derivative contracts		725			(988	)
Cash settlement on commodity derivative contracts		(1,339	)		-
Loss on sale of TBNG		-			15,226
Foreign currency loss								1,637			2,634
Loss on derivative contracts								110			725
Cash settlement on derivative contracts								–			(1,339	)
Amortization on loan financing costs		10			37			10			10
Deferred income tax expense		767			1,251			1,769			767
Exploration, abandonment and impairment		40			106			5,113			40
Depreciation, depletion and amortization		4,459			4,497			3,716			4,459
Accretion of asset retirement obligations		46			48			52			46
Changes in operating assets and liabilities:
Accounts receivable		(548	)		(1,665	)		(10,216	)		(548	)
Prepaid expenses and other assets		(1,091	)		(1,151	)		(3,757	)		(1,091	)
Accounts payable and accrued liabilities		3,781			(628	)		9,880			3,781
Net cash provided by operating activities		7,810			1,859			4,514			7,810
Investing activities:
Additions to oil and natural gas properties		(6,337	)		(6,383	)		(9,326	)		(6,337	)
Additions to equipment and other properties		(677	)		(155	)		–			(677	)
Proceeds from the sale of TBNG		-			17,779
Net cash provided by (used in) investing activities		(7,014	)		11,241
Net used in provided by investing activities								(9,326	)		(7,014	)
Financing activities:
Tax withholding on restricted share units		-			(35	)		(88	)		–
Note receivable - related party								1,000			–
Loan proceeds								20,000			–
Loan repayment		(4,125	)		(8,650	)		(5,100	)		(4,125	)
Loan repayment - related party		-			(2,694	)
Net cash used in financing activities		(4,125	)		(11,379	)
Net cash provided by (used in) financing activities								15,812			(4,125	)
Effect of exchange rate on cash flows, cash equivalents, and restricted cash		(716	)		(369	)		(1,018	)		(716	)
Net increase (decrease) in cash, cash equivalents and restricted cash		(4,045	)		1,352			9,982			(4,045	)
Cash, cash equivalents and restricted cash, beginning of period (1)		20,431			15,071			9,892			20,431
Cash, cash equivalents and restricted cash, end of period (2)	$	16,386		$	16,423		$	19,874		$	16,386
Supplemental disclosures:
Cash paid for interest	$	3,104		$	2,713		$	526		$	3,104
Cash paid for taxes	$	657		$	989		$	1,178		$	657

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

TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the ~~“Company”~~“Company,” or “TransAtlantic”) is an international oil and natural gas company engaged in acquisition, exploration, development, and production. We have focused our operations in countries that have established, yet underexplored petroleum systems, are net importers of petroleum, have an existing petroleum transportation infrastructure, and provide favorable commodity pricing, royalty rates, and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of May ~~7, 2018,~~3, 2019, approximately ~~47%~~48% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

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

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

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with U.S. GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the ~~Securities and Exchange Commission (“SEC”).~~SEC. These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, ~~2017.~~2018.

~~On February 24, 2017,~~During the three months ended March 31, 2019, we ~~closed~~repaid $5.1 million of outstanding debt and entered into the ~~sale of our ownership interests in our subsidiary Thrace Basin Natural Gas (Turkiye) Corporation~~2019 Term Loan with DenizBank, A.S. (“~~TBNG”~~DenizBank”) for ~~gross proceeds of $20.7~~$20.0 million ~~and approximate net cash proceeds of $16.1 million, which amounts reflect a $0.2 million post-closing purchase price adjustment.~~

We classified the assets and liabilities of TBNG within the captions “Assets held for sale” and “Liabilities held for sale” on our consolidated balance sheets as of December 31, 2016. Although the sale of TBNG met the threshold to classify its assets and liabilities as held for sale, it didn’t meet the requirements to classify its operations as discontinued as the sale wasn’t considered a strategic shift in our operations. As such, TBNG’s results of operations are classified as continuing operations for all periods presented (See(see Note ~~13, “Assets and liabilities held for sale and discontinued operations”~~7 “Loans Payable”).

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

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

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

~~In May 2014, the FASB issued ASU 2014-09,~~ ~~Revenue from Contracts with Customers~~, its final standard on revenue from contracts with customers. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In applying the revenue model to contracts within its scope, an entity identifies the contract(s) with a customer, identifies the performance obligations in the contract, determines the transaction price, allocates the transaction price to the performance obligations in the contract and recognizes revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 applies to all contracts with customers and requires significantly expanded disclosures about revenue recognition. ASU 2014-09 has been amended several times with subsequent ASUs including ASU 2015-14 ~~Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.~~

We have adopted the standard on January 1, 2018 using the modified retrospective approach. We have a small number of contracts with customers and have identified transactions within the scope of the standard. As a result of adoption of ASU 2014-09, we have determined that it will change our method of recording certain transportation and processing charges that were previously recorded as a reduction of revenues to record such charges as an expense under the new standard. The result of this change was an increase to both revenue and expenses of $1.2 million for the three months ended March 31, 2018. The application of the new standard has no impact on our retained earnings and no impact to our net income on an ongoing basis. As of the three months ended December 31, 2017, this change would have been an increase to both revenue and expenses of $1.1 million.

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

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

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

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

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

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

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

~~In February 2016, the FASB issued ASU~~ 2016-02, Leases (Topic 842), ~~(“ASU 2016-02”)~~,which ~~requires companies~~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 for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Oil and natural gas leases are excluded from the provisions of ASU 2016-02. As of March 31, 2018, we currently have 19 operating leases within the scope of this standard, the last lease expiring in 2022. The effect of ASU 2016-02 is expected to require additional disclosures, and we are currently evaluating the impact that ASU 2016-02 would have on our consolidated ~~financial statements and results of operations.~~balance sheet.

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

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

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

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

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

In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, which clarifies Topic 718, Compensation – Stock Compensation(“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 ~~expect the~~adopted ASU 2017-09 effective January 1, 2018. The adoption of this ~~ASU will only~~update had no impact our consolidated financial statements ~~if there is a modification to our share-based award agreements in the future.~~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. ~~Early~~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 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 ~~date~~beginning of ~~issuance~~the first reporting period in which the guidance is ~~permitted.~~effective. The ~~new standard~~Company does not believe the adoption of this standard will have an impact ~~accounting for derivatives that are not designated as accounting hedges. We do not currently account for any of our derivative position as accounting hedges.~~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, ~~2018~~2019 and ~~2017,~~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~~U.S. GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of March 31, ~~2018,~~2019, there were $21.3 million of Series A Preferred Shares and $24.8 million of Series A Preferred Shares – related party outstanding ~~(see~~(See Note 1213. “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 months ended March 31, 2019 and 2018, we paid $1.3 million in cash dividends on the Series A Preferred Shares, which is recorded in our consolidated statements of comprehensive (loss) income under the caption “Interest and other expense”.

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, 2018			December 31, 2017			March 31, 2019			December 31, 2018
	(in thousands)						(in thousands)
Oil and natural gas properties, proved:
Turkey	$	194,026		$	193,111		$	155,306		$	162,494
Bulgaria		551			536			502			512
Total oil and natural gas properties, proved		194,577			193,647			155,808			163,006
Oil and natural gas properties, unproved:
Turkey		19,359			24,445			15,195			14,965
Bulgaria								–			730
Total oil and natural gas properties, unproved		19,359			24,445			15,195			15,695
Gross oil and natural gas properties		213,936			218,092			171,003			178,701
Accumulated depletion		(121,995	)		(123,225	)		(97,449	)		(100,582	)
Net oil and natural gas properties	$	91,941		$	94,867		$	73,554		$	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, ~~2018, we recorded~~2019, foreign currency ~~translation adjustments, which decreased proved~~translations reduced oil and natural gas properties and increased accumulated other comprehensive loss within shareholders’ equity on our consolidated balance ~~sheets.~~sheet.

At March 31, ~~2018~~2019 and December 31, ~~2017,~~2018, we excluded ~~$3.0~~$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, ~~2018,~~2019, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included ~~$10.1~~$6.9 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and ~~$58.8~~$51.2 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, ~~2017,~~2018, the capitalized costs of our oil and natural gas properties included ~~$11.2~~$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 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, ~~2018~~2019 and ~~2017,~~2018, we recorded ~~$0.04~~$5.1 million of exploratory dry-hole costs and $0.1 million ~~respectively,~~ of impairment of proved properties, ~~and exploratory well costs~~respectively, which are primarily measured using Level 3 inputs.

As of March 31, ~~2018, we had $2.3 million of~~2019, there were no exploratory well costs ~~capitalized for the Pinar-1ST well in Turkey, which we spud in March 2014. The Pinar-1ST well started producing in the first quarter of 2018.~~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, 2018			December 31, 2017			March 31, 2019			December 31, 2018
	(in thousands)						(in thousands)
Other equipment							$	1,159		$	1,240
Land								140			149
Inventory	$	4,924		$	4,619			6,323			6,791
Leasehold improvements, office equipment and software		7,062			7,214
Gas gathering system and facilities		259			135			182			194
Vehicles		331			343			317			336
Other equipment		1,647			1,764
Leasehold improvements, office equipment and software								5,438			5,698
Gross equipment and other property		14,223			14,075			13,559			14,408
Accumulated depreciation		(5,899	)		(5,958	)		(5,158	)		(5,268	)
Net equipment and other property	$	8,324		$	8,118		$	8,401		$	9,140

At March 31, ~~2018,~~2019, in addition to the above, we have classified ~~$7.2~~$4.8 million of inventory as a current asset, which represents our expected inventory consumption induring the next twelve months. We classify our remaining materials and supply inventory as a long-term 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, ~~2018~~2019 and December 31, ~~2017,~~2018, we excluded ~~$12.1~~$11.2 million and ~~$12.1~~$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 months ended March 31, ~~2018~~2019 and for the year ended December 31, ~~2017:~~2018:

	March 31, 2018			December 31, 2017			March 31, 2019			December 31, 2018
	(in thousands)						(in thousands)
Asset retirement obligations at beginning of period	$	4,727		$	4,833		$	4,667		$	4,727
Liabilities settled		-			(37	)		-			–
Foreign exchange change effect		(182	)		(259	)		(288	)		(1,270	)
Additions		91			-			59			1,036
Accretion expense		46			190			52			174
Asset retirement obligations at end of period	$	4,682		$	4,727		$	4,490		$	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 ~~collar~~derivative instruments to manage certain risks related to commodity prices and ~~put~~foreign currency exchange rates. The use of derivative ~~contracts to economically hedge against the variability in cash flows associated~~instruments for risk management is covered by operating policies and is closely monitored by our senior management. We do not hold any derivatives for speculative purposes and do not use derivatives with ~~the forecasted sale of a portion of our future oil production.~~leveraged or complex features. We have not designated the derivative contracts as hedges for accounting purposes, and accordingly, we record the derivative contracts at fair value and recognize changes in fair value in earnings as they occur.

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

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

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



						Buy			Sell		Estimated Fair
Type	Buy/Sell	Rate		Settlement Date	Buy Currency	Currency Amount		Sell Currency	Currency Amount		Value of Asset (Liability)
											(in thousands)
FXOPT	Buy		5.750	04/29/19	TRY		8,625,000	USD		1,500,000		8
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		8
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		7
FXOPT	Sell		5.750	07/01/19	USD		2,250,000	TRY		12,937,500		(33	)
Total Estimated Fair Value of Liability											$	(110	)

During the three months ended March 31, ~~2018~~2019 and ~~2017,~~2018, we recorded a net loss on ~~commodity~~ derivative contracts of $0.1 million and $0.7 million, ~~and a net gain of $1.0 million,~~ respectively.

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

Weighted

Weighted

Average

Average

Quantity

Minimum

Maximum Price

Additional Call

Estimated Fair

Type

Period

(Bbl/day)

Price (per Bbl)

(per Bbl)

Ceiling

Value of Liability

(in thousands)

Collar

April 1, 2018 -
May 31, 2018

295

$
47.50

$
61.00

$
-

$
(200
)
Collar

April 1, 2018 -
June 30, 2018

742

$
47.50

$
57.10

$
-

(1,016
)
Collar

April 1, 2018 -
December 31, 2018

442

$
55.00

$
70.00

$
-

(229
)
Collar

April 1, 2018 -
December 31, 2018

491

$
56.00

$
70.00

$
84.00

(189
)
Total Estimated Fair Value of Liability

$
(1,633
)

Fair Value of Derivative Instruments as of December 31, 2017

Weighted

Weighted

Average

Average

Quantity

Minimum

Maximum Price

Estimated Fair

Type

Period

(Bbl/day)

Price (per Bbl)

(per Bbl)

Value of Liability

(in thousands)

Collar

January 1, 2018 —
February 28, 2018

458

$
50.00

$
61.50

$
(178
)

Collar

January 1, 2018 —
March 31, 2018

500

$
47.00

$
59.65

(376
)

Collar

January 1, 2018 —
May 31, 2018

298

$
47.50

$
61.00

(286
)

Collar

January 1, 2018 —
June 30, 2018

746

$
47.50

$
57.10

(1,375
)

Total Estimated Fair Value of Liability

$
(2,215
)

The following table summarizes both: (i) the gross fair value of our ~~commodity~~ derivative instruments by the appropriate balance sheet classification even when the ~~commodity~~ derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at March 31, ~~2018 and December 31, 2017,~~2019, and (ii) the net recorded fair value as reflected on our consolidated balance ~~sheets~~sheet at March 31, ~~2018 and December 31, 2017.~~2019.

As of December 31, 2017

Gross

Amount

Net Amount of

Gross

Offset in the

Liabilities

Amount of

Consolidated

Presented in the

Location on Consolidated

Recognized

Balance

Consolidated

Underlying Commodity

Balance Sheets

Liabilities

Sheets

Balance Sheets

(in thousands)

Crude oil

Current liabilities

$
2,215

$
-

$
2,215

Crude oil

Long-term liabilities

$
-

$
-

$
-

As of March 31, 2019

Gross

Amount

Net Amount of

Gross

Offset in the

Liabilities

Amount of

Consolidated

Presented in the

Location on Consolidated

Recognized

Balance

Consolidated

Type of Derivative Contract

Balance Sheets

Liabilities

Sheets

Balance Sheets

(in thousands)

Foreign exchange

Current liabilities

133

(23

)

110

Foreign exchange

Long-term liabilities

	March 31,		December 31,		March 31,		December 31,
	2018		2017		2019		2018
Fixed and floating rate loans	(in thousands)				(in thousands)
Term Loan (1)	$	24,500	$	28,625
Term Loans (1)					$	36,900	$	22,000
Less: current portion		15,100		15,625		21,186		22,000
Long-term portion	$	9,400	$	13,000	$	15,714	$	–

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

On August 31, 2016, DenizBank entered into a $30.0 million term loan ~~with TEMI~~ (the “2016 Term Loan”) 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 ~~bears~~bore interest at a fixed rate of 5.25% (plus 0.2625% for Banking and Insurance Transactions Tax per the Turkish government) per annum and was payable in six monthly installments of $1.25 million each through February 2017 and thereafter in twelve ~~monthly~~monthly installments of $1.88 million each through February 2018. On April 27, 2017, TEMI and DenizBank approved a revised amortization schedule for the 2016 Term Loan. Pursuant to the revised amortization schedule, the maturity date of the 2016 Term Loan was extended from February 2018 to June 2018, and the monthly principal payments were reduced from $1.88 million to $1.38 million. The other terms of the 2016 Term Loan ~~remain~~remained unchanged. Amounts repaid under the 2016 Term Loan ~~may~~could not be re-borrowed and early repayments under the 2016 Term Loan ~~are~~were subject to early repayment fees.

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

The 2016 Term Loan ~~contains~~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 ~~prohibits~~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 ~~includes,~~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 iswas secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) ~~the~~certain Gundem real estate and Muratli real estate owned by Gundem ~~Turizm~~ Yatirim ve ~~Isletmeleri~~Ticaret A.S. (“~~Gundem”~~Gundem Yatirim”), and (v) certain Diyarbakir real estate owned 80% by ~~N. Malone~~Mr. Mitchell 3^rd and 20% by Selami Erdem Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2016 Term Loan. Gundem 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.

~~At March 31,~~On June 28, 2018, we ~~had $4.1 million outstanding under~~repaid the 2016 Term Loan ~~and no availability and were~~ in ~~compliance~~full in accordance with ~~the covenants in the 2016 Term Loan~~.its terms.

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

The 2017 Term Loan bears interest at a fixed rate of 6.0% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2017 Term Loan ~~has~~had a grace period which ~~bears~~bore no interest or payments due until July ~~2018 and then~~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 ~~the Guarantors.~~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 be secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) ~~the~~certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by ~~N. Malone~~Mr. Mitchell ~~3rd~~ and 20% ~~Selami Erdem~~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. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.

At March 31, ~~2018,~~2019, we had ~~$20.4~~$9.4 million outstanding under the 2017 Term Loan and no availability, and we were in compliance with the covenants in the 2017 Term Loan.

The 2017 Notes were issued pursuant to an indenture, dated as of February 20, 2015 (the “Indenture”), between us and U.S. Bank National Association, as trustee (the “Trustee”). The 2017 Notes bore interest at an annual rate of 13.0%, payable semi-annually, in arrears, on January 1 and July 1 of each year. The 2017 Notes matured on July 1, 2017, and on July 3, 2017, we paid off and retired all remaining outstanding 2017 Notes.

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

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

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

The 2018 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by ~~the adult children of our chairman~~Petrogas, (iv) certain Gundem real estate and ~~chief executive officer, N. Malone Mitchell 3rd, and controlled~~Muratli real estate owned by ~~an entity managed~~Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and his wife. The ANBE Note bore interest at a rate of 13.0% per annum. On December 30, 2015, we borrowed $3.6 million under the ANBE Note for general corporate purposes. On June 30, 2016, we issued 355,826 common shares in a private placement to ANBE in lieu of paying cash interest on the ANBE Note.

On October 31, 2016, TransAtlantic USA entered into an amendment of the ANBE Note with ANBE (the “ANBE Amendment”). The ANBE Amendment extended the maturity date of the Note from October 31, 2016 to September 30, 2017, provided for the ANBE Note to be repaid in four quarterly installments of $0.9 million each in December 201620% by Mr. Uras, and ~~March, June~~(vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI assigned its Turkish collection accounts and ~~September 2017, and provided for monthly payments of interest.~~

~~On February 27, 2017, we repaid the ANBE Note in full with proceeds~~its receivables from the sale of ~~TBNG~~oil to DenizBank as additional security for the 2018 Term Loan.

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

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

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

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

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

At March 31, 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, ~~2018,~~2019, we had no outstanding borrowings under these lines of credit.

We lease office space in Dallas, Texas, Bulgaria and Turkey. We also lease apartments, vehicles and operations yards in Turkey. The terms of our lease agreements generally range from one to five years, some containing options to renew or cancel. We determine if an arrangement meets the definition of a lease at inception, at which time we also perform an analysis to determine whether the lease qualifies as an operating or financing lease. 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 comprehensive (loss) income under the caption “General and administrative”. Lease expense for our operating leases for our operations yards in Turkey is recognized in our consolidated statements of comprehensive (loss) income under the caption “Production”.

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

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

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

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

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

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

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

In October 2015, the Bulgarian ~~Ministry~~Minister of Energy ~~and Economy~~ filed a suit in the Sofia City Court against ~~our subsidiary,~~ Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”), claiming a $200,000 ~~penalty~~in liquidated damages for Direct Bulgaria’s alleged failure to fulfill ~~the work program associated with~~its obligations under the Aglen exploration ~~permit.~~permit work program. In May 2018, the Sofia City Court concluded that Direct Bulgaria did not fail to fulfill its obligations under the Aglen exploration permit work program as Direct Bulgaria received a force majeure event recognition as a result of a fracture stimulation ban in 2012, ~~from~~imposed by the Bulgarian ~~Ministry~~Parliament, which force majeure event had not been terminated before the expiry of Direct Bulgaria’s obligations under the Aglen exploration permit work program. Additionally, the Sofia City Court concluded that, even if Direct Bulgaria had failed to fulfill its obligations under the Aglen exploration permit work program, the Bulgarian Minister of Energy failed to file suit within the three-year limitation period. Therefore, the Sofia City Court dismissed all claims of the Bulgarian Minister of Energy and ~~Economy,~~ordered the Bulgarian Minister of Energy to pay Direct Bulgaria’s attorney’s fees and

legal costs for court experts. In June 2018, the ~~force majeure event has not been rectified. While we believe~~Bulgarian Minister of Energy filed an appeal in the Sofia Court of Appeal. In November 2018, the Sofia Court of Appeal concluded that ~~Direct Bulgaria is not under any obligation to fulfill~~ the ~~work program until~~judgement of the ~~force majeure event is rectified~~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,~~claim.

As a result of the judgement of the Sofia Court of Appeal, we ~~continue~~are currently evaluating an adjustment to ~~engage in discussions with the Ministry of Energy~~our contingencies relating to production leases and ~~Economy regarding settlement possibilities.~~exploration permits.

We recorded share-based compensation expense of $0.1 million and $0.1 million for awards of restricted stock units (“RSUs”) for the three months ended March 31, ~~2018~~2019 and ~~2017,~~2018, respectively.

As of March 31, ~~2018,~~2019, we had approximately $0.2 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of ~~0.5~~0.8 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 months ended March 31, ~~2018~~2019 and ~~2017~~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 months ended March 31, ~~2018~~2019 and ~~2017~~2018 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes RSUs and preferred shares, ~~and warrants (prior to January 6, 2018),~~ whether exercisable or not. For the three months ended March 31, ~~2018,~~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
	March 31,						March 31,
(in thousands, except per share amounts)	2018			2017			2019			2018
Net loss from continuing operations	$	(1,775	)	$	(16,049	)
Basic net loss per common share:
Net loss							$	(3,902	)	$	(1,775	)
Basic net loss earnings per common share:
Shares:
Weighted average common shares outstanding		50,374			47,298			52,483			50,374
Basic net loss per common share:							$	(0.07	)	$	(0.04	)
Continuing operations	$	(0.04	)	$	(0.34	)
Diluted net loss per common share:
Shares:
Weighted average common shares outstanding		50,374			47,298			52,483			50,374
Diluted net loss per common share:							$	(0.07	)	$	(0.04	)
Continuing operations	$	(0.04	)	$	(0.34	)

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

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

	Corporate			Turkey		Bulgaria			Total			Corporate			Turkey		Bulgaria			Total
	(in thousands)											(in thousands)
For the three months ended March 31, 2019
Total revenues												$	-		$	19,041	$	-		$	19,041
(Loss) income from operations before income taxes													(2,873	)		7,616		(5,222	)		(479	)
Capital expenditures												$	-		$	9,857	$	-		$	9,857
For the three months ended March 31, 2018
Total revenues	$	-		$	16,926	$	-		$	16,926		$	-		$	16,926	$	-		$	16,926
(Loss) income from continuing operations before income taxes		(3,806	)		3,364		(46	)		(488	)
Capital expenditures				$	5,246				$	5,246
For the three months ended March 31, 2017
Total revenues	$	-		$	16,436	$	-		$	16,436
(Loss) income from continuing operations before income taxes		(18,921	)		5,077		(70	)		(13,914	)
(Loss) income from operations before income taxes													(3,806	)		3,364		(46	)		(488	)
Capital expenditures	$	-		$	6,538	$	-		$	6,538		$	-		$	5,246	$	-		$	5,246
Segment assets
March 31, 2018	$	9,643		$	143,727	$	731		$	154,101
December 31, 2017	$	10,966		$	149,185	$	499		$	160,650
March 31, 2019												$	11,244		$	134,831	$	1,548		$	147,623
December 31, 2018												$	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 ~~New Turkish Lira (“TRY”).~~TRY. We are also subject to foreign currency exposures resulting from translating the functional currency of our subsidiary financial statements into the ~~U.S. Dollar~~USD reporting currency. ~~We have not used foreign currency forward contracts to manage exchange rate fluctuations.~~ At March 31, ~~2018,~~2019, we had ~~15.8~~1.2 million TRY (approximately ~~$4.0~~$0.2 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY. At March 31, 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, ~~2018~~2019 and December 31, ~~2017,~~2018, we were anot party to any commodity derivative ~~contracts (See Note 6 “Commodity derivative instruments”).~~contracts.

The majority of our receivables are within the oil and natural gas industry, primarily from our industry partners and from government agencies. Included in receivables are amounts due from Turkiye Petrolleri Anonim Ortakligi (“TPAO”), the national oil company of Turkey, 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 ~~three~~four financial institutions in the United States and Turkey.

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities and our loans payable were each estimated to have a fair value approximating the carrying amount at March 31, ~~2018~~2019 and December 31, ~~2017,~~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, ~~2018:~~2019:

	Fair Value Measurement Classification											Fair Value Measurement Classification
	Quoted Prices in											Quoted Prices in
	Active Markets for											Active Markets for
	Identical Assets or		Significant Other			Significant						Identical Assets or		Significant Other			Significant
	Liabilities		Observable Inputs			Unobservable Inputs						Liabilities		Observable Inputs			Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)			Total			(Level 1)		(Level 2)			(Level 3)			Total
	(in thousands)											(in thousands)
Measured on a recurring basis
Liabilities:
Commodity derivative contracts	$	-	$	(1,633	)	$	-		$	(1,633	)
Foreign exchange derivative contracts												$	-	$	(110	)	$	-		$	(110	)
Disclosed but not carried at fair value
Liabilities:
2019 Term Loan													-		-			(15,981	)		(15,981	)
2018 Term Loan													-		-			(7,014	)		(7,014	)
2017 Term Loan		-		-			(17,309	)		(17,309	)		-		-			(8,789	)		(8,789	)
2016 Term Loan		-		-			(4,014	)		(4,014	)
Total	$	-	$	(1,633	)	$	(21,323	)	$	(22,956	)	$	-	$	-		$	(31,784	)	$	(31,784	)

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

	Fair Value Measurement Classification											Fair Value Measurement Classification
	Quoted Prices in											Quoted Prices in
	Active Markets for											Active Markets for
	Identical Assets or		Significant Other			Significant						Identical Assets or		Significant Other		Significant
	Liabilities		Observable Inputs			Unobservable Inputs						Liabilities		Observable Inputs		Unobservable Inputs
	(Level 1)		(Level 2)			(Level 3)			Total			(Level 1)		(Level 2)		(Level 3)			Total
	(in thousands)											(in thousands)
Measured on a recurring basis
Liabilities:
Commodity derivative contracts	$	-	$	(2,215	)	$	-		$	(2,215	)
Disclosed but not carried at fair value
Liabilities:
2018 Term Loan													-		-		(8,192	)		(8,192	)
2017 Term Loan		-		-			(16,613	)		(16,613	)		-		-		(11,938	)		(11,938	)
2016 Term Loan		-		-			(7,866	)		(7,866	)
Total	$	-	$	(2,215	)	$	(24,479	)	$	(26,694	)	$	-	$	-	$	(20,130	)	$	(20,130	)

We remeasure our derivative contracts on a recurring basis, with changes flowing through earnings. At March 31, ~~2018~~2019 and December 31, ~~2017, both of~~2018, the fair values of the ~~2017~~2019 Term Loan, the 2018 Term Loan, and the ~~2016~~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,		March 31,		December 31,
	2018		2017		2019		2018
	(in thousands)				(in thousands)
Related party accounts receivable:
Riata Management Service Agreement	$	527	$	576
PSIL MSA		742	447
Service Agreement					$	412	$	526
PSI MSA						486	352
Total related party accounts receivable	$	1,269	$	1,023	$	898	$	878
Related party accounts payable:
Riata Management Service Agreement	$	352	$	341
PSIL MSA		4,202		2,119
Service Agreement					$	309	$	372
PSI MSA						1,677		2,439
Interest payable on Series A Preferred		-		681		681		-
Other - board of directors fees						-		111
Total related party accounts payable	$	4,554	$	3,141	$	2,667	$	2,922

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

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

As of March 31, ~~2018,~~2019, we had ~~$0.5~~$0.4 million of outstanding receivables and ~~$0.4~~$0.3 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 ~~will be~~is owned and operated by ~~a new entity,~~ Production Solutions International Petrol Arama Hizmetleri Anonim Sirketi (“~~PSIL”~~PSI”). PSI is beneficially owned by PSIL, which is beneficially owned by Dalea Investment Group, LLC, which is controlled by Mr. Mitchell. Consequently, on March 3, 2016, TEMI entered into a master services agreement (the ~~“PSIL~~“PSI MSA”) with ~~PSIL~~PSI on substantially similar terms to our then current master services agreements with Viking International, VOS, and Viking Geophysical. Pursuant to the ~~PSIL~~PSI MSA, ~~PSIL will perform~~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, ~~2018,~~2019, we had ~~$0.7~~$0.5 million of outstanding receivables and ~~$4.2~~$1.7 million of outstanding payables pursuant to the ~~PSIL~~PSI MSA.

On ~~June 26, 2017,~~August 7, 2018 and effective as of ~~January 1, 2017, our wholly owned subsidiary,~~June 14, 2018, TransAtlantic USA entered into ~~an Amended and Restated Office Lease~~a sublease agreement (the ~~“Office Lease”~~“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 ~~Office Lease~~Sublease commenced on ~~January 1, 2017~~June 14, 2018 (the “Commencement Date”), and expires ~~five years after the Commencement Date,~~on June 30, 2020, unless earlier terminated in accordance with the ~~Office Lease. TransAtlantic USA has~~Sublease. From the option to extend the lease term for two additional periods of five years each. If TransAtlantic USA exercises its option to extend the lease term, the monthly rent payable during such extended term shall be at a mutually agreed upon amount for monthly rent during the renewal term. During the first five months of the initial lease term,Commencement Date until June 30, 2019, TransAtlantic USA is required to pay monthly

rent of ~~$14,745.16~~$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). ~~Monthly~~The monthly rent increases by ~~$2,754.84~~$416.67 for the ~~sixth month~~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 ~~initial lease term,~~Amended and Restated Office Lease, dated June 26, 2017, by ~~$833.33 the second year of the initial lease term~~ and ~~by approximately $417 each year thereafter during the initial lease term.~~

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, ~~Partners, LP (“Dalea”),~~ pursuant to which Dalea agreed to deliver an amended and restated promissory note (the “Amended Note”) in favor of us, in the principal sum of $7,964,053, which Amended Note would amend and restate that certain Promissory Note, dated June 13, 2012, made by Dalea in favor of us in the principal amount of $11.5 million (the “Original Note”). The Note Amendment Agreement reduced the principal amount of the Original Note to $7,964,053 in exchange for the cancellation of an account payable of approximately $3.5 million (the “Account Payable”) owed by TransAtlantic Albania Ltd. (“TransAtlantic Albania”), aour former subsidiary, ~~of TransAtlantic,~~ to Viking ~~International Limited.~~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, ~~MSA. PSIL~~which is beneficially owned by Dalea Investment Group, LLC, which is controlled by Mr. Mitchell. As a result, the Amended Note revised the events triggering acceleration of the repayment of the Original Note to the following: (i) a reduction of ownership by Dalea (and other controlled affiliates of Mr. Mitchell) of equity interest in ~~PSIL~~PSI to less than 50%; (ii) the sale or transfer by Dalea or ~~PSIL~~PSI of all or substantially all of its assets to any person (a “Transferee”) that does not own a controlling interest in Dalea or ~~PSIL~~PSI and is not controlled by Mr. Mitchell (an “Unrelated Person”), or the subsequent transfer by any Transferee that is not an Unrelated Person of all or substantially all of its assets to an Unrelated Person; (iii) the acquisition by an Unrelated Person of more than 50% of the voting interests of Dalea or ~~PSIL;~~PSI; (iv) termination of the ~~PSIL~~PSI MSA other than as a result of an uncured default thereunder by TEMI; (v) default by ~~PSIL~~PSI under the ~~PSIL~~PSI MSA, which default is not remedied within a period of 30 days after notice thereof to ~~PSIL;~~PSI; and (vi) insolvency or bankruptcy of ~~PSIL.~~PSI. The maturity date of the Amended Note was extended to June 13, 2019. The interest rate on the Amended Note remains at 3.0% per annum and continues to be guaranteed by Mr. Mitchell. The Amended Note contains customary events of default.

In addition, pursuant to the Note Amendment Agreement, on April 19, 2016, we entered into a pledge agreement (the “Pledge Agreement”) with Dalea, whereby Dalea pledged the $2.0 million principal amount of the 2017 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 Notes for 40,000 Series A Preferred Shares.

On ~~June 30, 2016,~~February 28, 2019, we and Dalea entered into ~~a waiver with~~an amendment (the “Note Amendment”) to the Amended Note (as amended by the Note Amendment, the “Note”), pursuant to which Dalea ~~whereby~~and we ~~waived our right under~~agreed to extend the ~~Pledge Agreement~~maturity date of the Note to ~~receive the interest payment due July 1, 2016 under the Dalea Convertible Notes~~February 26, 2021 (unless otherwise accelerated in ~~connection~~accordance with the ~~payment~~terms of ~~201,459 common shares to Dalea with respect to~~ the ~~2017 Note interest payment paid on June 30, 2016.~~ Note).

During the three months ended March 31, ~~2018,~~2019, we reduced the principal amount of the ~~Amended~~ Note by $1.0 million for amounts prepaid by Dalea on February 28, 2019 in conjunction with the Note Amendment and by $0.1 million for cash dividends paid on the Series A Preferred Shares.

As of March 31, ~~2018,~~2019, the amount receivable under the ~~Amended~~ Note was ~~$6.5~~$4.6 million.

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

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

Amounts payable to Mr. Mitchell under the Gundem Fee Agreement and the Diyarbakir Fee Agreement are used to reduce the outstanding principal amount of the Amended Note. During the three months ended March 31, ~~2018,~~2019, we reduced the principal amount of the Amended Note by ~~$0.2~~$0.1 million for amounts ~~payable~~paid under the pledge fee agreements.

On April 1 and ~~liabilities held~~April 24, 2019, we entered into foreign exchange option and forward contracts to hedge against currency fluctuations between the TRY and USD. The option contract settlement dates are between April and July for ~~sale~~$1.0 million at a strike price of 5.60 TRY to $1.00 USD. The forward contracts settlement dates are between June and ~~discontinued operations~~September for $1.5 million at a strike price of 5.87 TRY to $1.00 USD.

On ~~October 13, 2016,~~April 16, 2019, we entered into a ~~share purchase agreement~~three-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 ~~“Purchase Agreement”~~“Third Amendment”) ~~with Valeura Energy Netherlands B.V. (“Valeura Netherlands”) for~~to the ~~sale~~Service Agreement, dated August 6, 2008 and effective as of ~~all~~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 ~~equity interests in TBNG, our wholly-owned subsidiary. TBNG owned a portion of our interests in the Thrace Basin area in Turkey.~~

On February 24, 2017, we closed on the sale of TBNG for gross proceeds of $20.7 million, and approximate net cash proceeds of $16.1 million, which amounts reflect a $0.2 million post-closing purchase price adjustment.

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

~~As a result of the TBNG sale, there were no remaining assets or liabilities held for sale as of December 31, 2017. As of March 31, 2018, there were no assets or liabilities held for sale.~~ ~~For the three months ended March 31, 2018 and March 31, 2017, we had no significant operating results from discontinued operations.~~

Exploration License 5046 in West Molla expires in June 2018. Based on the successful discovery on the Pinar-1ST exploration well, we applied to convert the exploration license to a production license in the first quarter of 2018. In March 2018, we spud the Yeniev-1 exploration well on Exploration License 5046. If a successful discovery is made on the Yeniev-1 exploration well, the southern portion of Exploration License 5046 may also convert to a production license.

In this Quarterly Report on Form 10-Q, references to “we,” “our,” “us” or the “Company,” refer to TransAtlantic Petroleum Ltd. and its subsidiaries on a consolidated basis unless the context requires otherwise. Unless stated otherwise, all sums of money stated in this Quarterly Report on Form 10-Q are expressed in ~~U.S. Dollars.~~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, ~~2018,~~2019, we held interests in ~~approximately 367,000~~372,050 and ~~163,000~~162,500 net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria, respectively. As of May ~~7, 2018,~~3, 2019, approximately ~~47%~~48% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

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

The following summarizes our financial and operational performance for the first quarter of ~~2018:~~2019:

During the first quarter of ~~2018,~~2019, we spud two wells and continued workover and recompletion production optimizations in ~~Southeastern~~southeastern Turkey. ~~The following summarizes our operations by location during the first quarter of 2018:~~Additionally, we re-drilled and tested one well in Bulgaria.

Yeniev Field. Both the Yeniev-1 and West Yeniev-1 wells continue flowing naturally with little water. In ~~January~~November 2018, we spud the ~~Selmo-81H2~~East Yeniev-1 appraisal well ~~which is~~to further delineate the ~~first~~structure. The well was drilled to a total measured depth of 9,900 feet and encountered hydrocarbon shows in the Mardin and Bedinan formations. Completion operations began in January 2019 and resulted in a ~~six-well Selmo development program. Completion is ongoing,~~discovery in the Mardin formation.

Bahar Field. We spud the Southeast Bahar-1 well in March 2019. The well was drilled to a total measured depth of 11,000 feet and weencountered oil shows in the Mardin, Hazro, and Bedinan formations. We expect to ~~commence production~~begin completion operations in the second quarter of ~~2018.~~ 2019.

Other. We ~~expect~~spud the Blackeye-1 well in January 2019. The well was drilled to ~~resume drilling~~a total measured depth of 11,105 feet and encountered oil shows in the ~~Selmo field~~Hazro, Mardin, and Bedinan formations. The well was completed in the ~~third~~Hazro formation and put on production in the first quarter of ~~2018.~~

We have applied for conversion of the New Molla exploration license into a production lease and expect a final determination with respect to ~~drill one development well in the Bahar field in 2018. We may drill an additional Bahar development well in the fourth quarter of 2018,~~ ~~contingent on financing~~.

~~In March 2018, we spud the Yeniev-1 exploration well, targeting the Bedinan, Hazro and Mardin formations. We expect to complete drilling~~our application in the second quarter of ~~2018.~~ 2019.

We have completed ~~3-D on~~ the ~~eastern Molla Block extension. We expect to complete processing~~initial phase of ~~this data~~operations in the ~~second quarter~~Selmo-1 well to re-enter and test the Permian formation, establishing the productivity of ~~2018. We expect to complete interpretation and analysis in~~ the ~~third quarter~~Permian formation. During a short-term flow test of ~~2018.~~a previously untested interval, the Selmo-1 well tested 45.6 API condensate along with natural gas containing a high carbon dioxide percentage component.

We continue to evaluate our prospects in the Thrace Basin’s Basin Center Gas Accumulation (“Thrace Basin BCGA”) in light of the recent ~~positive~~ production test results at the Yamalik-1 exploration well operated by Valeura Energy Inc. (“Valeura”) with their partner Equinor ASA (formerly Statoil ~~Banarli Turkey B.V.~~ASA) (“~~Statoil”~~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 ~~Statoil~~Equinor acreage.

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 drilled the Devepinar-1 appraisal well to a total depth of 4,796 meters and encountered 1,066 meters of high-pressure gas saturated rock.

We expect to ~~resume production operations~~spud a shallow exploration well on our ~~Yildurm-1 well on the Temrez~~ license in ~~2018. Contingent on financing, we may commence a three-well drilling program on our Temrez license starting~~the Thrace Basin in the ~~fourth~~second quarter of ~~2018.~~2019.

We ~~have prepared plans to side track~~commenced the side-track and ~~re-drill~~re-drilling of the ~~Devinci~~Deventci R-1 well ~~which~~in December 2018, targeting the Ozirovu and Dolmi Dabnik formations. The well was drilled to a total depth of 16,450 feet. Although we ~~plan to commence during 2018, contingent on financing.~~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 ~~2018~~2019 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected remaining ~~2018~~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 3. Significant accounting policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, ~~2017~~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.

Effective January 1, 2018, the Company adopted new accounting standards for revenue, statement of cash flows and restricted cash disclosures in statement of cash flows. (See Note 2. “Recent accounting pronouncements”)

Results of ~~Continuing~~ Operations—Three Months Ended March 31, ~~2018~~2019 Compared to Three Months Ended March 31, ~~2017~~2018

Our results of ~~continuing~~ operations for the three months ended March 31, ~~2018~~2019 and ~~2017~~2018 were as follows:

	Three Months Ended March 31,						Change			Three Months Ended March 31,						Change
	2018			2017			2018-2017			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)		248			314			(66	)		269			248			21
Natural gas (Mmcf)		67			184			(117	)		50			67			(17	)
Total production (Mboe)		260			345			(85	)		277			260			17
Average daily sales volumes (Boepd)		2,885			3,833			(948	)		3,082			2,885			197
Average prices:
Oil (per Bbl)	$	65.71		$	47.26		$	18.45		$	69.00		$	65.71		$	3.29
Natural gas (per Mcf)	$	5.00		$	4.96		$	0.04		$	5.94		$	5.00		$	0.94
Oil equivalent (per Boe)	$	64.17		$	45.70		$	18.47		$	68.00		$	64.17		$	3.83
Revenues:
Oil and natural gas sales	$	16,661		$	15,768		$	893		$	18,861		$	16,661		$	2,200
Sales of purchased natural gas		-			654			(654	)
Other		265			14			251			180			265			(85	)
Total revenues		16,926			16,436			490			19,041			16,926			2,115
Costs and expenses (income):
Production		2,869			3,087			(218	)		2,502			2,869			(367	)
Transportation and processing		1,193			-			1,193			1,319			1,193			126
Exploration, abandonment and impairment		40			106			(66	)		5,113			40			5,073
Cost of purchased natural gas		-			568			(568	)
Seismic and other geological and geophysical		159			15			144			77			159			(82	)
General and administrative		3,337			3,590			(253	)		3,054			3,337			(283	)
Depletion		4,197			4,310			(113	)		3,579			4,197			(618	)
Depreciation and amortization		262			187			75			137			262			(125	)
Interest and other expense		2,782			2,371			411			2,478			2,782			(304	)
Interest and other income		(254	)		(293	)		39			(174	)		(254	)		80
Foreign exchange loss		2,058			2,123			(65	)		1,273			2,058			(785	)
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts		(1,339	)		-			(1,339	)
Change in fair value on commodity derivative contracts		614			988			(374	)
Total (loss) gain on commodity derivative contracts		(725	)		988			(1,713	)
Gain (loss) on derivative contracts:
Cash settlements on derivative contracts											-			(1,339	)		1,339
Change in fair value on derivative contracts											(110	)		614			(724	)
Total loss on derivative contracts											(110	)		(725	)		615
Oil and natural gas costs per Boe:
Production	$	10.28		$	7.74		$	2.54		$	7.90		$	10.28		$	(2.38	)
Depletion	$	14.53		$	10.93		$	3.60		$	11.29		$	14.53		$	(3.24	)

Oil and Natural Gas Sales. Total oil and natural gas sales revenues increased ~~$0.9 million~~ to ~~$16.7~~$18.9 million for the three months ended March 31, ~~2018,~~2019 from ~~$15.8~~$16.7 million ~~realized in~~for the same period in ~~2017.~~2018. The increase was primarily due to an increase in the average realized price per Boe. Our average price received increased ~~$18.47~~$3.83 per Boe to ~~$64.17~~$68.00 per Boe for the three months ended March 31, 2018 from ~~$45.70~~$64.17 per Boe for the same period in ~~2017. This~~2018. The increase was ~~partially offset by a decrease~~also due to an increase in our average daily sales volumes of ~~948 Boepd~~197 Boe per day (“Boepd”) for the three months ended March 31, ~~2018 compared to the same period in 2017.~~

~~Production.~~ Production expenses for the three months ended March 31, 2018 decreased to $2.9 million, or $10.28 per Boe, from $3.1 million, or $7.74 per Boe, for the same period in 2017. The decrease was primarily due to less workovers during the three months ended March 31, 2018,2019 as compared to the same period in ~~2017.~~

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

Production. ~~Exploration, Abandonment and Impairment.~~ ~~Exploration, abandonment and impairment costs for the three months ended March 31, 2018 did not significantly change from the same period in 2017.~~

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

~~Depletion.~~ ~~Depletion decreased to $4.2~~$2.5 million, or ~~$14.53~~$7.90 per Boe, for the three months ended March 31, ~~2018, compared to $4.3~~2019 from $2.9 million, or ~~$10.93~~$10.28 per Boe, for the same period in 2018. The decrease was primarily due to a devaluation of the TRY to the USD, as most of our production expenses are denominated in TRY.

Transportation and Processing. Transportation and processing expense increased to $1.3 million for the three months ended March 31, 2019 from $1.2 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.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment cost increased to $5.1 million for the three months ended March 31, 2019 from $0.1 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 million for the three months ended March 31, 2019 from $3.3 million for the same period in 2018. The decrease was primarily due to a decrease in professional and accounting fees associated with the strategic transaction in 2018.

Depletion. Depletion expense decreased to $3.6 million, or $11.29 per Boe, for the three months ended March 31, 2019 from $4.2 million, or $14.53 per Boe, for the same period of ~~2017.~~2018. The decrease was primarily due to ~~a reduction in production volumes.~~ the devaluation of the TRY to the USD.

Interest and Other Expense. Interest and other expense ~~increased~~decreased to ~~$2.8~~$2.5 million for the three months ended March 31, ~~2018, compared to $2.4~~2019 from $2.8 million for the same period in ~~2017.~~2018. The ~~increase~~decrease was ~~primarily~~ due to our ~~higher~~lower average debt balances outstanding during the three months ended March 31, ~~2018~~2019 versus the same period in ~~2017.~~

~~Interest and Other Income.~~ ~~Interest and other income did not significantly change during the three months ended March 31, 2018 from the same period in 2017.~~2018.

Foreign Exchange Loss. We recorded a foreign exchange loss of ~~$2.1~~$1.3 million ~~during each of~~for the three months ended March 31, ~~2018 and 2017.~~2019 as compared to $2.1 million for the same period in 2018. Foreign exchange gains and losses are primarily unrealized (non-cash) in nature and ~~results~~result from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a ~~U.S. Dollar~~USD transaction which occurs in Turkey is re-measured at the period-end to the TRY amount if it has not been settled previously. Generally, a strengthening of the USD relative to the TRY increases our foreign exchange loss. The foreign exchange loss for the three months ended March 31, 2019 was due to a decrease in the value of the TRY compared to 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.

Gain (Loss) on ~~Commodity~~ Derivative Contracts. We recorded a net loss on derivative contracts of $0.1 million for the three months ended March 31, 2019 as compared to $0.7 million for the same period in 2018. During the three months ended March 31, ~~2018,~~2019, we recorded a ~~net~~$0.1 million loss ~~on commodity~~to mark our currency derivative contracts ~~of $0.7 million, as compared~~ to ~~a net gain of $1.0 million for~~their fair value. During the same period in ~~2017. During the three months ended March 31,~~ 2018, we recorded a $0.6 million gain to mark our commodity derivative contracts to their fair value and a $1.3 million loss on settled contracts. ~~During the same period in 2017, we recorded a $1.0 million gain to mark our commodity derivative contracts to their fair value.~~

For the ~~quarter~~three months ended March 31, ~~2018,~~2019, we incurred ~~$5.2~~$9.9 million in capital expenditures, including seismic and corporate expenditures, as compared to ~~$6.5~~$5.2 million for the ~~quarter ended March 31, 2017.~~ same period in 2018.

We expect our net field capital expenditures for the remainder of ~~2018~~2019 to range between ~~$18.0~~$15.0 million and ~~$21.0 million~~. $20.0 million. We expect net field capital expenditures during the remainder of ~~2018~~2019 to include between ~~$14.0~~$14.5 million and ~~$17.0~~$19.5 million in drilling and completion expense ~~for eight wells~~ and approximately ~~$4.0~~$0.5 million in ~~recompletions. We expect that any additional 2018 expenditures would be invested in the Selmo, Bahar and Molla fields in southeastern Turkey and the Koynare license in Bulgaria.~~recompletion expense. We expect that cash on hand and cash flow from operations will be sufficient to fund the remainder of our ~~2018~~2019 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected remaining ~~2018~~2019 capital expenditure budget is subject to change.

Net cash provided by operating activities during the three months ended March 31, ~~2018~~2019 was ~~$7.8~~$4.5 million, ~~an increase~~a decrease from net cash provided by operating activities of ~~$1.9~~$7.8 million for the same period in ~~2017.~~2018. The ~~increase~~decrease was primarily due to ~~the timing of collecting our receivables and paying~~an increase in our accounts ~~payable.~~receivable which was partially offset by an increase in our revenues.

Net cash used in investing activities during the three months ended March 31, ~~2018~~2019 was ~~$7.0~~$9.3 million, ~~as compared to~~an increase from net cash ~~provided by~~used in investing activities of ~~$11.2~~$7.0 million for the same period in ~~2017.~~2018. The ~~change in net cash~~increase was primarily due to an increase in our capital expenditures as compared to the ~~proceeds received from the sale of TBNG of $17.8 million during the quarter ended March 31,~~same period in 2017.

Net cash ~~used in~~provided by financing activities during the three months ended March 31, ~~2018~~2019 was ~~$4.1~~$15.8 million, ~~a decrease~~an increase from net cash used in financing activities of ~~$11.4~~$4.1 million for the same period in ~~2017.~~2018. The change ~~in net cash~~ was primarily due to ~~a decrease~~an increase in ~~debt principal repayments.~~our outstanding loans.

As of March 31, ~~2018,~~2019, we had ~~$24.5~~$36.9 million of indebtedness, not including ~~$9.6~~$8.7 million of trade payables, as further described below. We believe that our cash flow from operations will be sufficient to meet our normal operating requirements and to fund planned capital expenditures during the next 12 months. As of March 31, ~~2018,~~2019, we had a working capital surplus of ~~$9.3~~$10.8 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 ~~bears~~bore interest at a fixed rate of 5.25% (plus 0.2625% for Banking and Insurance Transactions Tax per the Turkish government) per annum and iswas payable in monthly installments of $1.38 million through June 2018. Amounts repaid under the 2016 Term Loan ~~may~~could not be re-borrowed and early repayments under the 2016 Term Loan ~~are~~were subject to early repayment fees. The 2016 Term Loan iswas guaranteed by ~~the Guarantors.~~DMLP, TransAtlantic Turkey, Talon Exploration, and TransAtlantic Worldwide.

The 2016 Term Loan ~~contains~~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 ~~prohibits~~prohibited Amity and Petrogas from incurring additional debt. An event of default under the 2016 Term Loan ~~includes,~~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 iswas secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) ~~the~~certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, and (v) certain Diyarbakir real estate owned 80% by ~~N. Malone~~Mr. Mitchell 3^rd and 20% by ~~Selami Erdem~~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. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.

~~At March 31,~~On June 28, 2018 we ~~had $4.1 million outstanding under~~repaid the 2016 Term Loan ~~and no availability and were~~ in ~~compliance~~full in accordance with ~~the covenants in the 2016 Term Loan~~.its terms.

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

The 2017 Term Loan bears interest at a fixed rate of 6.0% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2017 Term Loan ~~has~~had a grace period which ~~bears~~bore no interest or payments due until July ~~2018 and then~~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 ~~the Guarantors.~~ 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) ~~the~~certain Gundem real estate and Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by ~~N. Malone~~Mr. Mitchell ~~3rd~~ and 20% ~~Selami Erdem~~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. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.

At March 31, ~~2018,~~2019, we had ~~$20.4~~$9.4 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. ~~2017 Notes.~~The 2017 Notes were issued pursuant to the Indenture. The 2017 Notes bore interest at an annual rate of 13.0%, payable semi-annually, in arrears, on January 1 and July 1 of each year. The 2017 Notes matured on July 1, 2017, and on July 3, 2017, we paid off and retired all remaining outstanding 2017 Notes.

~~ANBE Note~~. On ~~December 30, 2015, TransAtlantic USA~~May 28, 2018, DenizBank entered into the ~~ANBE Note.~~2018 Term Loan under the Credit Agreement. The ~~ANBE Note bore~~2018 Term Loan bears interest at a fixed rate of ~~13.0%~~7.25% (plus 0.3% for Banking and Insurance Transactions Tax per ~~annum.On December 30, 2015, we borrowed $3.6 million under~~ the ~~ANBE Note for general corporate purposes.On June 30, 2016, we issued 355,826 common shares in~~Turkish government) per annum. The 2018 Term Loan had a ~~private placement to ANBE in lieu of paying cash~~grace period through July 2018 during which no payments were due. Thereafter, accrued interest on the ~~ANBE Note.~~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 ~~USA entered into~~Turkey.

The 2018 Term Loan contains standard prohibitions on the ~~ANBE Amendment, which extended~~activities of TEMI as the ~~maturity date~~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 ~~Note from October 31, 2016 to September 30, 2017, provided for the ANBE Note to be repaid in four quarterly installments~~assets of ~~$0.9 million each in December 2016~~TEMI, (iii) certain real estate owned by Petrogas, (iv) certain Gundem real estate and ~~March, June~~Muratli real estate owned by Gundem Yatirim, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and ~~September 2017,~~20% by Mr. Uras, and ~~provided for monthly payments of interest.~~

~~On February 27, 2017, we repaid the ANBE Note in full with proceeds~~(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 ~~TBNG~~oil to DenizBank as additional security for the 2018 Term Loan.

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

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, 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.

Series A Preferred Shares. As of March 31, ~~2018,~~2019, we ~~have~~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~~U.S. GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of March 31, ~~2018, there were~~2019, we had $21.3 million of Series A Preferred Shares and $24.8 million of Series A Preferred Shares – related party ~~outstanding.~~outstanding (See Note 3. “Series A Preferred Shares”).

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

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

Fair Value of Derivative Instruments as of March 31, 2018

Weighted

Weighted

Average

Average

Quantity

Minimum

Maximum Price

Additional Call

Estimated Fair

Type

Period

(Bbl/day)

Price (per Bbl)

(per Bbl)

Ceiling

Value of Liability

(in thousands)

Collar

April 1, 2018 -
May 31, 2018

295

$
47.50

$
61.00

$
-

$
(200
)
Collar

April 1, 2018 -
June 30, 2018

742

$
47.50

$
57.10

$
-

(1,016
)
Collar

April 1, 2018 -
December 31, 2018

442

$
55.00

$
70.00

$
-

(229
)
Collar

April 1, 2018 -
December 31, 2018

491

$
56.00

$
70.00

$
84.00

(189
)
Total Estimated Fair Value of Liability

$
(1,633
)

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, ~~2018,~~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, ~~2018,~~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, ~~2018~~2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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

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

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

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

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

Large accelerated filer		☐	Accelerated filer	☐

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

			Emerging growth company	☐

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of March 31, ~~2018~~2019 (Unaudited) and December 31, ~~2017~~	3

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

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

Unaudited Consolidated ~~Statements~~Statement of ~~Cash Flows~~Shareholders’ Equity for the Three Months Ended March 31, ~~2018~~2019 and ~~2017~~2018	6

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

Notes to Unaudited Consolidated Financial Statements	78

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	2324

Item 3. Quantitative and Qualitative Disclosures About Market Risk	2829

Item 4. Controls and Procedures	2829

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	3031

Item 1A. Risk Factors	3031

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	3031

Item 3. Defaults Upon Senior Securities	3031

Item 4. Mine Safety Disclosures	3031

Item 5. Other Information	3031

Item 6. Exhibits	3132


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%

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

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

Fair Value of Derivative Instruments as of December 31, 2017

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

	March 31, 2019
	(in thousands)
Operations yards	$	146
Office rent		58
Vehicles		36
Other		23
Total lease costs	$	263

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

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

Date: May ~~9, 2018~~8, 2019