TransAtlantic Petroleum (TAT) 10-Q 2017 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: September 30, 2017

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-34574

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

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)

Registrant’s Telephone Number, Including Area Code: (214) 220-4323

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):

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐  (Do not check if a smaller reporting company)	Smaller reporting company	☒
		Emerging growth company	☐

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

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

As of November 6, 2017, the registrant had 50,319,156 common shares outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2017 and December 31, 2016	3
Consolidated Statements of Comprehensive (Loss) Income for the Three and Nine Months Ended September 30, 2017 and 2016	4
Consolidated Statement of Equity for the Nine Months Ended September 30, 2017	5
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2017 and 2016	6
Notes to Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3. Quantitative and Qualitative Disclosures About Market Risk	30
Item 4. Controls and Procedures	31
PART II. OTHER INFORMATION
Item 1. Legal Proceedings	32
Item 1A. Risk Factors	32
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 3. Defaults Upon Senior Securities	32
Item 4. Mine Safety Disclosures	32
Item 5. Other Information	32
Item 6. Exhibits	33

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

(in thousands of U.S. Dollars, except share data)

	September 30, 2017			December 31, 2016
ASSETS	(unaudited)
Current assets:
Cash and cash equivalents	$	2,757		$	10,034
Restricted cash		–			2,555
Accounts receivable, net
Oil and natural gas sales		12,891			17,885
Joint interest and other		1,914			3,230
Related party		1,063			762
Prepaid and other current assets		2,557			4,756
Inventory		3,613			3,647
Assets held for sale		–			25,217
Total current assets		24,795			68,086
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		204,895			197,214
Unproved		25,730			21,109
Equipment and other property		19,399			20,273
		250,024			238,596
Less accumulated depreciation, depletion and amortization		(132,899	)		(120,638	)
Property and equipment, net		117,125			117,958
Other long-term assets:
Other assets		2,104			2,725
Note receivable - related party		7,027			7,624
Total other assets		9,131			10,349
Total assets	$	151,051		$	196,393
LIABILITIES, SERIES A PREFERRED SHARES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	3,518		$	7,036
Accounts payable - related party		4,363			1,844
Accrued liabilities		8,660			12,492
Derivative liability		571			596
Loans payable		12,375			34,750
Loan payable - related party		–			3,444
Liabilities held for sale		–			15,938
Total current liabilities		29,487			76,100
Long-term liabilities:
Asset retirement obligations		4,940			4,833
Accrued liabilities		9,138			8,126
Deferred income taxes		20,494			18,806
Loans payable		–			3,750
Derivative liability		–			242
Total long-term liabilities		34,572			35,757
Total liabilities		64,059			111,857
Commitments and contingencies
Series A preferred shares - third-parties, $0.01 par value, 950,000 shares authorized (third-parties and related parties), 426,000 shares issued to third-parties and outstanding with a liquidation preference of $50 per share as of September 30, 2017 and December 31, 2016, respectively		21,300			21,300
Series A preferred shares - related parties, $0.01 par value, 495,000 shares issued to related parties and outstanding with a liquidation preference of $50 per share as of September 30, 2017 and December 31, 2016, respectively		24,750			24,750
Shareholders' equity:
Common shares, $0.10 par value, 200,000,000 shares authorized; 47,727,772 shares and 47,220,525 shares issued and outstanding as of September 30, 2017 and December 31, 2016, respectively		4,773			4,722
Treasury stock		(970	)		(970	)
Additional paid-in-capital		573,691			573,278
Accumulated other comprehensive loss		(118,488	)		(140,316	)
Accumulated deficit		(418,064	)		(398,228	)
Total shareholders' equity		40,942			38,486
Total liabilities, Series A preferred shares and shareholders' equity	$	151,051		$	196,393

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

3

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Comprehensive (Loss) Income

(Unaudited)

(U.S. Dollars and shares in thousands, except per share amounts)

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2017			2016			2017			2016
Revenues:
Oil and natural gas sales	$	12,424		$	15,483		$	40,475		$	46,171
Sales of purchased natural gas		-			1,171			654			3,717
Other		251			5			323			35
Total revenues		12,675			16,659			41,452			49,923
Costs and expenses:
Production		2,997			3,070			8,798			9,025
Exploration, abandonment and impairment		141			1,531			249			2,964
Cost of purchased natural gas		-			1,027			568			3,264
Seismic and other exploration		2,966			3			3,046			84
General and administrative		2,532			2,659			9,303			11,401
Depreciation, depletion and amortization		4,272			7,280			13,024			23,053
Accretion of asset retirement obligations		49			97			144			285
Total costs and expenses		12,957			15,667			35,132			50,076
Operating (loss) income		(282	)		992			6,320			(153	)
Other income (expense):
Loss on sale of TBNG		-			-			(15,226	)		-
Interest and other expense		(2,322	)		(3,836	)		(6,981	)		(9,106	)
Interest and other income		182			1,009			663			1,411
(Loss) gain on commodity derivative contracts		(1,365	)		(187	)		299			(2,419	)
Foreign exchange loss		(48	)		(390	)		(1,055	)		(659	)
Total other expense		(3,553	)		(3,404	)		(22,300	)		(10,773	)
Loss from continuing operations before income taxes		(3,835	)		(2,412	)		(15,980	)		(10,926	)
Income tax expense		(518	)		(2,224	)		(3,856	)		(5,820	)
Net loss from continuing operations		(4,353	)		(4,636	)		(19,836	)		(16,746	)
Income from discontinued operations before income taxes		-			6,886			-			5,830
Gain on disposal of discontinued operations		-			9,419			-			10,168
Income tax benefit		-			-			-			204
Net income from discontinued operations		-			16,305			-			16,202
Net (loss) income	$	(4,353	)	$	11,669		$	(19,836	)	$	(544	)
Other comprehensive (loss) income:
Foreign currency translation adjustment		(1,223	)		(3,986	)		21,828			(3,277	)
Comprehensive (loss) income	$	(5,576	)	$	7,683		$	1,992		$	(3,821	)
Net (loss) income per common share
Basic net (loss) income per common share
Continuing operations	$	(0.09	)	$	(0.10	)	$	(0.42	)	$	(0.39	)
Discontinued operations	$	(0.00	)	$	0.35		$	(0.00	)	$	0.38
Weighted average common shares outstanding		47,725			46,854			47,480			42,879
Diluted net (loss) income per common share
Continuing operations	$	(0.09	)	$	(0.10	)	$	(0.42	)	$	(0.39	)
Discontinued operations	$	(0.00	)	$	0.35		$	(0.00	)	$	0.38
Weighted average common and common equivalent shares outstanding		47,725			46,854			47,480			42,879

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

4

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statement of Equity

(Unaudited)

(U.S. Dollars and shares in thousands)

															Accumulated
												Additional			Other						Total
	Common		Treasury				Common		Treasury			Paid-in			Comprehensive			Accumulated			Shareholders'
	Shares		Shares		Warrants		Shares		Stock			Capital			Loss			Deficit			Equity
Balance at December 31, 2016		47,220		333		699	$	4,722	$	(970	)	$	573,278		$	(140,316	)	$	(398,228	)	$	38,486
Issuance of restricted stock units		508		-		-		51		-			(51	)		-			-			-
Tax withholding on restricted stock units		-		-		-		-		-			(92	)		-			-			(92	)
Share-based compensation		-		-		-		-		-			556			-			-			556
Foreign currency translation adjustment		-		-		-		-		-			-			21,828			-			21,828
Net loss		-		-		-		-		-			-			-			(19,836	)		(19,836	)
Balance at September 30, 2017		47,728		333		699	$	4,773	$	(970	)	$	573,691		$	(118,488	)	$	(418,064	)	$	40,942

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

5

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands of U.S. Dollars)

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

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

6

Transatlantic Petroleum Ltd.

Notes to Consolidated Financial Statements

(Unaudited)

1. General

Nature of operations

TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the “Company” or “TransAtlantic”) is an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored petroleum systems, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey and Bulgaria.  As of November 6, 2017, approximately 47.3% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

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

Basis of presentation

Our consolidated financial statements are expressed in U.S. Dollars and have been prepared by management in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). All amounts in the notes to the consolidated financial statements are in U.S. Dollars unless otherwise indicated. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews estimates, including those related to fair value measurements associated with financial derivatives, the recoverability and impairment of long-lived assets, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.  During the nine months ended September 30, 2017, we reclassified certain balance sheet amounts previously reported on our consolidated balance sheet at December 31, 2016 to conform to current year presentation.  

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with U.S. GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2016.

On February 24, 2017, we closed the sale of our ownership interests in our subsidiary Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) for gross proceeds of $20.7 million, and net cash proceeds of $16.1 million, effective as of March 31, 2016.

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

7

2. Recent accounting pronouncements

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

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

In June 2016, the FASB issued ASU 2016-13, 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 are currently assessing the potential impact of ASU 2016-15 on our consolidated financial statements and results of operations.

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

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

3. Series A Preferred Shares

On November 4, 2016, we issued 921,000 shares of our 12.0% Series A Convertible Redeemable Preferred Shares (“Series A Preferred Shares”). Of the 921,000 Series A Preferred Shares, (i) 815,000 shares were issued in exchange for $40.75 million of our 13.0% Convertible Notes due 2017 (“2017 Notes”), at an exchange rate of 20 Series A Preferred Shares for each $1,000 principal amount of 2017 Notes, and (ii) 106,000 shares were issued and sold for $5.3 million of cash to certain holders of the 2017 Notes. All of the Series A Preferred Shares were issued at a value of $50.00 per share. We used $4.3 million of the gross proceeds to redeem a portion of the remaining 2017 Notes on January 1, 2017. The remaining proceeds were used for general corporate purposes. The Series A Preferred Shares contain a substantive conversion option, are mandatorily redeemable and convert into a fixed number of common shares. As a result, under U.S GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of September 30, 2017, there were $21.3 million of Series A Preferred Shares and $24.8 million of Series A Preferred Shares – related party outstanding.

8

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

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

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%

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

Dividends on the Series A Preferred Shares are payable quarterly at our election in cash, common shares or a combination of cash and common shares at an annual dividend rate of 12.0% of the liquidation preference if paid all in cash or 16.0% of the liquidation preference if paid in common shares. If paid partially in cash and partially in common shares, the dividend rate on the cash portion is 12.0%, and the dividend rate on the common share portion is 16.0%. Dividends are payable quarterly, on March 31, June 30, September 30, and December 31 of each year. The holders of the Series A Preferred Shares also are entitled to participate pro-rata in any dividends paid on the common shares on an as-converted-to-common shares basis. For the three and nine months ended September 30, 2017, we accrued $1.8 million and $4.6 million, respectively, in dividends on the Series A Preferred Shares, which is recorded in our consolidated statements of comprehensive (loss) income under the caption “Interest and other expense.”  On October 2, 2017, we issued an aggregate of 2,591,384 common shares to holders of the Series A Preferred Shares as payment of the September 30, 2017 quarterly dividend on the Series A Preferred Shares (see Note 14. “Subsequent Events”).

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.  

9

4. Property and equipment

Oil and natural gas properties

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

	September 30, 2017			December 31, 2016
	(in thousands)
Oil and natural gas properties, proved:
Turkey	$	204,367		$	196,743
Bulgaria		528			471
Total oil and natural gas properties, proved		204,895			197,214
Oil and natural gas properties, unproved:
Turkey		25,730			21,109
Total oil and natural gas properties, unproved		25,730			21,109
Gross oil and natural gas properties		230,625			218,323
Accumulated depletion		(126,923	)		(115,401	)
Net oil and natural gas properties	$	103,702		$	102,922

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

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

At September 30, 2017, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $12.3 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $65.3 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

At December 31, 2016, the capitalized costs of our oil and natural gas properties included $13.2 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $66.7 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

Impairments of proved properties and impairment of exploratory well costs

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

During the nine months ended September 30, 2017, we recorded $0.2 million of impairment of proved properties and exploratory well costs which are primarily measured using Level 3 inputs.  

Capitalized cost greater than one year

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

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Equipment and other property

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

	September 30, 2017			December 31, 2016
	(in thousands)
Inventory	$	9,488		$	10,704
Leasehold improvements, office equipment and software		7,543			7,280
Vehicles		361			364
Other equipment		2,007			1,925
Gross equipment and other property		19,399			20,273
Accumulated depreciation		(5,976	)		(5,237	)
Net equipment and other property	$	13,423		$	15,036

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

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

5. Asset retirement obligations

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

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

Our ARO is measured using primarily Level 3 inputs. The significant unobservable inputs to this fair value measurement include estimates of plugging costs, remediation costs, inflation rate and well life. The inputs are calculated based on historical data as well as current estimated costs.

6. Commodity derivative instruments

We use collar derivative contracts to economically hedge against the variability in cash flows associated with the forecasted sale of a portion of our future oil production. We have not designated the derivative contracts as hedges for accounting purposes, and accordingly, we record the derivative contracts at fair value and recognize changes in fair value in earnings as they occur.

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

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

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

Fair Value of Derivative Instruments as of September 30, 2017
				Weighted		Weighted
				Average		Average
		Quantity		Minimum		Maximum Price		Estimated Fair
Type	Period	(Bbl/day)		Price (per Bbl)		(per Bbl)		Value of Liability
								(in thousands)
Collar	October 1, 2017 — December 31, 2017		293	$	47.50	$	61.00	$	(14	)
Collar	October 1, 2017 — December 31, 2017		440	$	50.00	$	61.50		(6	)
Collar	October 1, 2017 — December 31, 2017		489	$	47.00	$	59.65		(40	)
Collar	October 1, 2017 — December 31, 2017		734	$	47.50	$	57.10		(130	)
Collar	January 1, 2018 — February 28, 2018		458	$	50.00	$	61.50		(4	)
Collar	January 1, 2018 — March 31, 2018		500	$	47.00	$	59.65		(50	)
Collar	January 1, 2018 — May 31, 2018		298	$	47.50	$	61.00		(32	)
Collar	January 1, 2018 — June 30, 2018		746	$	47.50	$	57.10		(295	)
Total estimated fair value of liability								$	(571	)

Fair Value of Derivative Instruments as of December 31, 2016
				Weighted		Weighted
				Average		Average
		Quantity		Minimum		Maximum Price		Estimated Fair
Type	Period	(Bbl/day)		Price (per Bbl)		(per Bbl)		Value of Liability
								(in thousands)
Collar	January 1, 2017 — December 31, 2017		296	$	47.50	$	61.00	$	(289	)
Collar	January 2, 2017 — December 31, 2017		445	$	50.00	$	61.50		(307	)
Collar	January 1, 2018 — February 28, 2018		458	$	50.00	$	61.50		(74	)
Collar	January 1, 2018 — May 31, 2018		298	$	47.50	$	61.00		(168	)
Total estimated fair value of liability								$	(838	)

Balance sheet presentation

The following table summarizes both: (i) the gross fair value of our commodity derivative instruments by the appropriate balance sheet classification even when the commodity derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at September 30, 2017 and December 31, 2016, and (ii) the net recorded fair value as reflected on our consolidated balance sheets at September 30, 2017 and December 31, 2016.

		As of September 30, 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	$	571	$	-	$	571

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		As of December 31, 2016
				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	$	596	$	-	$	596
Crude oil	Long-term liabilities	$	242	$	-	$	242

7. Loans payable

As of the dates indicated, our third-party debt consisted of the following:

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

Term Loan

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

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

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

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

On April 27, 2017, TEMI and DenizBank approved a revised amortization schedule for the Term Loan.  Pursuant to the revised amortization schedule, the maturity date of the Term Loan was extended from February 2018 to June 2018, and the monthly principal payments were reduced from $1.88 million to $1.38 million.  The other terms of the Term Loan remain unchanged.

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

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2017 Notes

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.        

ANBE Note

On December 30, 2015, TransAtlantic Petroleum (USA) Corp (“TransAtlantic USA”) entered into a $5.0 million draw down convertible promissory note (the “Note”) with ANBE Holdings, L.P. (“ANBE”), an entity owned by the adult children of the Company’s chairman and chief executive officer, N. Malone Mitchell 3rd, and controlled by an entity managed by Mr. Mitchell and his wife. The ANBE Note bore interest at a rate of 13.0% per annum.  On December 30, 2015, the Company borrowed $3.6 million under the ANBE Note (the “Initial Advance”). The Initial Advance was used for general corporate purposes.  On February 27, 2017, we repaid the ANBE Note in full with proceeds from the sale of TBNG and terminated it.

Unsecured lines of credit

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

8. Contingencies relating to production leases and exploration permits

Selmo

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.

Morocco

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

Bulgaria

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

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

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9. Shareholders’ equity

Restricted stock units

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

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

Earnings per share

We account for earnings per share in accordance with ASC Subtopic 260-10, Earnings Per Share (“ASC 260-10”). ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted. Basic earnings per common share for the three and nine months ended September 30, 2017 and 2016 equals net income (loss) divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding unvested RSUs. Diluted earnings per common share for the three and nine months ended September 30, 2017 and 2016 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes RSUs, preferred shares and warrants, whether exercisable or not.  For the nine months ended September 30, 2017, there were no dilutive securities included in the calculation of diluted earnings per share.  

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

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

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10. Segment information

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

	Corporate			Turkey			Bulgaria			Total
	(in thousands)
For the three months ended September 30, 2017
Total revenues	$	-		$	12,675		$	-		$	12,675
Loss from continuing operations before income taxes		(3,262	)		(529	)		(44	)		(3,835	)
Capital expenditures	$	-		$	2,986		$	-		$	2,986
For the three months ended September 30, 2016
Total revenues	$	-		$	16,659		$	-		$	16,659
(Loss) income from continuing operations before income taxes		(3,102	)		734			(44	)		(2,412	)
Capital expenditures	$	-		$	1,484		$	-		$	1,484
For the nine months ended September 30, 2017
Total revenues	$	-		$	41,452		$	-		$	41,452
(Loss) income from continuing operations before income taxes		(26,460	)		10,673			(193	)		(15,980	)
Capital expenditures	$	-		$	14,317		$	-		$	14,317
For the nine months ended September 30, 2016
Total revenues	$	-		$	49,923		$	-		$	49,923
(Loss) income from continuing operations before income taxes		(12,092	)		1,413			(247	)		(10,926	)
Capital expenditures	$	-		$	4,675		$	-		$	4,675
Segment assets
September 30, 2017	$	9,905		$	140,509		$	637		$	151,051
December 31, 2016 (1)	$	17,007		$	153,560		$	609		$	171,176

(1) Excludes assets of TBNG of $25.2 million at December 31, 2016.

11. Financial instruments

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities and our loans payable were each estimated to have a fair value approximating the carrying amount at September 30, 2017 and December 31, 2016, due to the short maturity of those instruments.

Interest rate risk

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

Foreign currency risk

We have underlying foreign currency exchange rate exposure. Our currency exposures relate to transactions denominated in the Bulgarian Lev, European Union Euro and Turkish Lira (“TRY”). We are also subject to foreign currency exposures resulting from translating the functional currency of our foreign subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At September 30, 2017, we had 5.4 million TRY (approximately $1.5 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY.

Commodity price risk

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including, but not limited to, supply and demand. At September 30, 2017 and December 31, 2016, we were a party to commodity derivative contracts (See Note 6. “Commodity derivative instruments”).

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Concentration of credit risk

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, the national oil company of Turkey, and Turkiye Petrol Rafinerileri A.Ş., a privately owned oil refinery in Turkey, which purchases all of our oil production. The receivables are not collateralized. To date, we have experienced minimal bad debts from customers in Turkey. The majority of our cash and cash equivalents are held by three financial institutions in the United States and Turkey.

Fair value measurements

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

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

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

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

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

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12. Related party transactions

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

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

Services transactions

On March 20, 2017, the Company entered into a second amendment to the Service Agreement among the Company and Longfellow Energy, LP, a Texas limited partnership (“Longfellow”), Viking Drilling, LLC, a Nevada limited liability company, RIATA Management LLC, an Oklahoma limited liability company, Longfellow Nemaha, LLC, a Texas limited liability company, Red Rock Minerals, LP, a Delaware limited partnership, Red Rock Advisors, LLC, a Texas limited liability company, Production Solutions International Limited, a Bermuda exempted company, and Nexlube Operating, LLC, a Delaware limited liability company, and their subsidiaries (collectively, the “Riata Entities”), adding and removing certain of the Riata Entities and expanding the scope of services. Because this agreement is a related party transaction, the independent members of the Board of Directors reviewed and approved this amendment.  As of September 30, 2017, the Company had $0.7 million of outstanding receivables and $0.3 million of outstanding payables pursuant to this Service Agreement.

On March 3, 2016, Mr. Mitchell sold his interests in Viking Services B.V. (“Viking Services”), the beneficial owner of Viking International Limited (“Viking International”), Viking Petrol Sahasi Hizmetleri A.S. (“VOS”) and Viking Geophysical Services Ltd. (“Viking Geophysical”), to a third party.  As part of the transaction, Mr. Mitchell acquired certain equipment used in the performance of stimulation, wireline, workover and similar services (the “Services”), which equipment is owned and operated by Production Solutions International Petrol Arama Hizmetleri Anonim Sirketi (“PSIL”).  PSIL is beneficially owned by Dalea Investment Group, LLC, which is controlled by Mr. Mitchell. Consequently, on March 3, 2016, TEMI entered into a master services agreement (the “PSIL MSA”) with PSIL on substantially similar terms to our then current master services agreements with Viking International, VOS and Viking Geophysical.  Pursuant to the PSIL MSA, PSIL performs the Services on behalf of TEMI and its affiliates.  The master services agreements with each of Viking International, VOS and Viking Geophysical remain in effect in accordance with the terms of the agreements.  As of September 30, 2017, the Company had $0.3 million of outstanding receivables and $3.0 million of outstanding payables pursuant to the PSIL MSA.

Debt transactions

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

Dalea Amended Note and Pledge Agreement

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

Pursuant to the Note Amendment Agreement, on April 19, 2016, we entered into the Amended Note, which amended and restated the Original Note that was issued in connection with our sale of its 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

18

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

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

On November 4, 2016, Dalea exchanged $2.0 million of 2017 Notes for 40,000 Series A Preferred Shares, which were pledged as security for the performance of Dalea’s obligations under the Amended Note pursuant to the terms of the Pledge Agreement.  During nine months ended September 30, 2017, we reduced the principal amount of the Amended Note by $0.1 million, for dividends on the Series A Preferred Shares.

Pledge fee agreements

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

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

Amounts payable to Mr. Mitchell under the Gundem Fee Agreement and the Diyarbakir Fee Agreement are used to reduce the outstanding principal amount of the Amended Note. During the three and nine months ended September 30, 2017, we reduced the principal amount of the Amended Note by $0.2 million and $0.5 million, respectively, for amounts payable under the pledge fee agreements.

Office lease

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

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Series A Dividends

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

13. Assets and liabilities held for sale and discontinued operations

TBNG assets and liabilities held for sale

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

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

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

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

	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	)

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

	Held for Sale
	(in thousands)
For the year ended December 31, 2016
Assets
Cash	$	1,551
Other current assets		7,511
Property and equipment, net		16,155
Total current assets held for sale	$	25,217
Liabilities
Accounts payable and other accrued liabilities	$	11,240
Deferred tax liability		4,698
Total current liabilities held for sale	$	15,938

We had no assets or liabilities held for sale at September 30, 2017.

Discontinued operations in Albania

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

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

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

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

	Discontinued Operations
	(in thousands)
For the three months ended September, 2016
Total revenues	$	-
Production and transportation expense		-
Total other costs and expenses		(6,886	)
Income before income taxes	$	6,886
Gain on disposal of discontinued operations		9,419
Income tax benefit		-
Income from discontinued operations	$	16,305
For the nine months ended September, 2016
Total revenues	$	626
Production and transportation expense		1,155
Total other costs and expenses		(6,359	)
Income before income taxes	$	5,830
Gain on disposal of discontinued operations		10,168
Income tax benefit		204
Income from discontinued operations	$	16,202

14. Subsequent Events

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

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

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.

Executive Overview

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored petroleum systems, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of September 30, 2017, we held interests in approximately 0.5 million net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of November 6, 2017, approximately 47.3% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

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

Financial and Operational Performance Summary

A summary of our financial and operational performance for the third quarter of 2017 include:

• We reported a $4.4 million net loss from continuing operations for the three months ended September 30, 2017, of which $1.4 million was due to a loss on commodity derivative contracts.

• We derived 96% of our oil and natural gas revenues from the production of oil and 4% from the production of natural gas during the three months ended September 30, 2017.

• Total oil and natural gas sales revenues decreased 19.8% to $12.4 million for the quarter ended September 30, 2017 from $15.5 million in the same period in 2016. The decrease was primarily the result of a decrease in sales volumes of 123 Mboe, of which 33 Mboe was attributable to the divestiture of TBNG in February 2017.  The decrease was partially offset by an increase of $7.03 in the average price received per barrel of oil equivalent (“Boe”).

• For the quarter ended September 30, 2017, we incurred $6.0 million in capital expenditures, including seismic and corporate expenditures, as compared to $1.5 million for the quarter ended September 30, 2016.

• As of September 30, 2017, we had no long-term debt and $12.4 million in short-term debt, as compared to $3.8 million in long-term debt and $38.2 million in short-term debt as of December 31, 2016.  During the quarter ended September 30, 2017, we repaid $14.1 million in debt as we continue to focus on deleveraging our balance sheet.    

Third Quarter 2017 Operational Update

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

Southeastern Turkey

Testing continued on the Bahar-11 well throughout the third quarter of 2017 in the Bedinan, Dadas, and Hazro formations. Commercial oil was discovered in all three formations with a combined test rate of 280 barrels of oil per day (“Bopd”). The well was brought on production at a commingled rate of 140 Bopd.

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

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

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Bulgaria

We continue to evaluate our position in Bulgaria with updated geologic models and continue to market a joint venture exploration program for our assets in Bulgaria.

Planned Operations

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

Turkey. We expect our net field capital expenditures for the remainder of 2017 to range between $3.0 million and $4.5 million.  We expect net field capital expenditures during the remainder 2017 to include between $0.5 million and $1.0 million in completion expense for two gross wells, between $1.0 million and $2.0 million in capital recompletions and approximately $1.5 million for 3D seismic. Additionally, expenses for the remainder of 2017 associated with the 2018 drilling program are anticipated to be $1.0 million.

Bulgaria.  We intend to drill on our Koynare license during 2018 and plan to continue working on our geologic model for additional prospects. In addition, we continue to market a joint venture exploration program for our assets in Bulgaria.

Discontinued Operations in Albania

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

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

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

Significant Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses and related disclosures. Our significant accounting policies are described in “Note 3. Significant accounting policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2016 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 various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

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

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

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

	Three Months Ended September 30,						Change
	2017			2016			2017-2016
	(in thousands of U.S. Dollars, except per unit amounts and production volumes)
Sales volumes:
Oil (Mbbl)		254			338			(84	)
Natural gas (Mmcf)		58			283			(225	)
Total production (Mboe)		263			386			(123	)
Average daily sales volumes (Boepd)		2,862			4,191			(1,329	)
Average prices:
Oil (per Bbl)	$	47.88		$	39.99		$	7.89
Natural gas (per Mcf)	$	4.82		$	6.89		$	(2.07	)
Oil equivalent (per Boe)	$	47.18		$	40.15		$	7.03
Revenues:
Oil and natural gas sales	$	12,424		$	15,483		$	(3,059	)
Sales of purchased natural gas		-			1,171			(1,171	)
Other		251			5			246
Total revenues	$	12,675		$	16,659		$	(3,984	)
Costs and expenses (income):
Production	$	2,997		$	3,070		$	(73	)
Exploration, abandonment and impairment		141			1,531			(1,390	)
Cost of purchased natural gas		-			1,027			(1,027	)
Seismic and other exploration		2,966			3			2,963
General and administrative		2,532			2,659			(127	)
Depletion		4,015			6,918			(2,903	)
Depreciation and amortization		257			362			(105	)
Interest and other expense		2,322			3,836			(1,514	)
Interest and other income		(182	)		(1,009	)		827
Foreign exchange loss	$	48		$	390		$	(342	)
Gain (loss) on commodity derivative contracts:
Cash settlements on commodity derivative contracts	$	-		$	2,729		$	(2,729	)
Change in fair value on commodity derivative contracts		(1,365	)		(2,916	)		1,551
Total loss on commodity derivative contracts	$	(1,365	)	$	(187	)	$	(1,178	)
Oil and natural gas costs per Boe:
Production	$	9.84		$	6.96		$	2.88
Depletion	$	13.34		$	15.70		$	(2.36	)

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

Sales of Purchased Natural Gas. Sales of purchased natural gas for the three months ended September 30, 2017 decreased to zero from $1.2 million for the same period in 2016.  The decrease was due to the divestiture of TBNG in February 2017.

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

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

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

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

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

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

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

Interest and Other Income. Interest and other income decreased to $0.2 million for the three months ended September 30, 2017, as compared to $1.0 million for the same period in 2016, primarily due to a $0.7 million gain on the sale of our Edirne gas gathering system and facilities during the three months ended September 30, 2016.

Foreign Exchange Loss. We recorded a foreign exchange loss of $48,000 during the three months ended September 30, 2017, as compared to a loss of $0.4 million in the same period in 2016. Foreign exchange gains and losses are primarily unrealized (non-cash) in nature and result from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the New TRY amount if it has not been settled previously. The foreign exchange loss for the three months ended September 30, 2017 was due to a decrease in the value of the TRY compared to the U.S. Dollar.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Capital Expenditures

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

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

Cash flows

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

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

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

Liquidity and Capital Resources

As of September 30, 2017, we had $12.4 million of indebtedness, not including $7.9 million of trade payables, as further described below.  We believe that 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.  

Outstanding Debt and Series A Preferred Shares

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

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

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

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

On April 27, 2017, TEMI and DenizBank approved a revised amortization schedule for the Term Loan.  Pursuant to the revised amortization schedule, the maturity date of the Term Loan was extended from February 2018 to June 2018, and the monthly principal payments were reduced from $1.88 million to $1.38 million.  The other terms of the Term Loan remain unchanged.

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

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

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

Forward-Looking Statements

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

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, but are not limited to, the following: our ability to access sufficient capital to fund our operations; fluctuations in and volatility of the market prices for oil and natural gas products; the ability to produce and transport oil and natural gas; the results of exploration and development drilling and related activities; global economic conditions, particularly in the countries in which we carry on business, especially economic slowdowns; actions by governmental authorities including increases in taxes, legislative and regulatory initiatives related to fracture stimulation activities, changes in environmental and other regulations and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflicts; the negotiation and closing of material contracts or sale of assets; future capital requirements and the availability of financing; estimates and economic assumptions used in connection with our acquisitions; risks associated with drilling, operating and decommissioning wells; actions of third-party co-owners of interests in properties in which we also own an interest; our ability to effectively integrate companies and properties that we acquire; and the other factors discussed in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”) and Canadian securities regulatory authorities. The impact of any one factor on a particular forward-looking

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statement is not determinable with certainty as such factors are interdependent upon other factors and our course of action would depend upon our assessment of the future, considering all information then available. In that regard, any statements as to: future oil or natural gas production levels; capital expenditures; asset sales; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital expenditure programs or operations; drilling of new wells; marketing of joint venture transactions; demand for oil and natural gas products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves, including the ability to convert probable and possible reserves to proved reserves; dates by which transactions are expected to close; future cash flows, uses of cash flows, collectability of receivables and availability of trade credit; expected operating costs; changes in any of the foregoing; and other statements using forward-looking terminology are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized.

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

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

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

Fair Value of Derivative Instruments as of September 30, 2017
				Weighted		Weighted
				Average		Average
		Quantity		Minimum		Maximum Price		Estimated Fair
Type	Period	(Bbl/day)		Price (per Bbl)		(per Bbl)		Value of Liability
								(in thousands)
Collar	October 1, 2017 — December 31, 2017		293	$	47.50	$	61.00	$	(14	)
Collar	October 1, 2017 — December 31, 2017		440	$	50.00	$	61.50		(6	)
Collar	October 1, 2017 — December 31, 2017		489	$	47.00	$	59.65		(40	)
Collar	October 1, 2017 — December 31, 2017		734	$	47.50	$	57.10		(130	)
Collar	January 1, 2018 — February 28, 2018		458	$	50.00	$	61.50		(4	)
Collar	January 1, 2018 — March 31, 2018		500	$	47.00	$	59.65		(50	)
Collar	January 1, 2018 — May 31, 2018		298	$	47.50	$	61.00		(32	)
Collar	January 1, 2018 — June 30, 2018		746	$	47.50	$	57.10		(295	)
Total estimated fair value of liability								$	(571	)

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our chief executive officer and principal accounting and financial officer, as appropriate to allow timely decisions regarding required disclosure.

As of September 30, 2017, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and principal accounting and financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon the evaluation, our chief executive officer and principal accounting and financial officer concluded that, as of September 30, 2017, 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.

Changes in Internal Control over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

During the third quarter of 2017, there were no material developments to the Legal Proceedings disclosed in “Part I, Item 3. Legal Proceedings” in our Annual Report on Form 10-K for the year ended December 31, 2016.

Item 1A. Risk Factors

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

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

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

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

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Item 6. Exhibits

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).
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.

* Filed herewith.

** Furnished herewith.

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Signatures

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.

By:	/s/ N. MALONE MITCHELL 3rd
	N. Malone Mitchell 3rd Chief Executive Officer
By:	/s/ G. FABIAN ANDA
	G. Fabian Anda Principal Accounting and Financial Officer
Date: November 8, 2017

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