Quarterly Report (10-q)

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, 2016

☐	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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting 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	☒

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 8, 2016, the registrant had 47,206,998 common shares outstanding.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015	2

Consolidated Statements of Comprehensive Income (Loss) for the Three and Nine Months Ended September 30, 2016 and 2015	3

Consolidated Statement of Equity for the Nine Months Ended September 30, 2016	4

Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2016 and 2015	5

Notes to Consolidated Financial Statements	6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

Item 3. Quantitative and Qualitative Disclosures About Market Risk	34

Item 4. Controls and Procedures	34

PART II. OTHER INFORMATION

Item 1. Legal Proceedings	36

Item 1A. Risk Factors	36

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	36

Item 3. Defaults Upon Senior Securities	36

Item 4. Mine Safety Disclosures	36

Item 5. Other Information	36

Item 6. Exhibits	38

PART I. FINANCIAL INFORMATION

Item 1.

Financial Statements

T RANS A TLANTIC P ETROLEUM L TD .

Consolidated Balance Sheets

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

	September 30,			December 31,
	2016			2015
ASSETS	(unaudited)
Current assets:
Cash and cash equivalents	$	20,605		$	7,480
Restricted cash		–			3,758
Accounts receivable, net
Oil and natural gas sales		18,452			14,169
Joint interest and other		5,625			5,885
Related party		468			414
Prepaid and other current assets		5,177			2,807
Inventory		4,926			–
Derivative asset		–			3,235
Assets held for sale		–			51,511
Total current assets		55,253			89,259
Property and equipment:
Oil and natural gas properties (successful efforts methods)
Proved		265,145			271,080
Unproved		29,883			31,135
Equipment and other property		25,575			36,708
		320,603			338,923
Less accumulated depreciation, depletion and amortization		(162,351	)		(148,218	)
Property and equipment, net		158,252			190,705
Other long-term assets:
Other assets		5,133			3,355
Note receivable - related party		7,911			11,500
Derivative asset		–			3,370
Total other assets		13,044			18,225
Total assets	$	226,549		$	298,189

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	11,695		$	12,675
Accounts payable - related party		2,764			2,684
Accrued liabilities		16,878			10,583
Loans payable		53,903			37,006
Loans payable - related party		24,143			3,593
Liabilities held for sale - related party		–			3,540
Liabilities held for sale		–			65,649
Total current liabilities		109,383			135,730
Long-term liabilities:
Asset retirement obligations		9,270			9,237
Accrued liabilities		12,203			11,940
Deferred income taxes		26,810			27,360
Loans payable		9,375			34,400
Loans payable - related party		–			20,600
Total long-term liabilities		57,658			103,537
Total liabilities		167,041			239,267
Commitments and contingencies
Shareholders' equity:
Common shares, $0.10 par value, 100,000,000 shares authorized; 47,205,034 shares and 41,017,777 shares issued and outstanding as of September 30, 2016 and December 31, 2015, respectively		4,721			4,102
Treasury stock		(970	)		(970	)
Additional paid-in-capital		573,153			569,365
Accumulated other comprehensive loss		(124,867	)		(121,590	)
Accumulated deficit		(392,529	)		(391,985	)
Total shareholders' equity		59,508			58,922
Total liabilities and shareholders' equity	$	226,549		$	298,189

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

T RANS A TLANTIC P ETROLEUM L TD .

Conso lidated Statements of Comprehensive Income (Loss)

(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,
	2016			2015			2016			2015
Revenues:
Oil and natural gas sales	$	15,483		$	17,543		$	46,171		$	67,464
Sales of purchased natural gas		1,171			756			3,717			1,544
Other		5			38			35			139
Total revenues		16,659			18,337			49,923			69,147
Costs and expenses:
Production		3,070			3,104			9,025			10,059
Exploration, abandonment and impairment		1,531			3,762			2,964			8,202
Cost of purchased natural gas		1,027			668			3,264			1,403
Seismic and other exploration		3			177			84			328
General and administrative		2,659			4,849			11,401			18,664
Depreciation, depletion and amortization		7,280			8,173			23,053			28,183
Accretion of asset retirement obligations		97			88			285			277
Total costs and expenses		15,667			20,821			50,076			67,116
Operating income (loss)		992			(2,484	)		(153	)		2,031
Other (expense) income:
Interest and other expense		(3,836	)		(3,159	)		(9,106	)		(9,610	)
Interest and other income		1,009			332			1,411			683
(Loss) gain on commodity derivative contracts		(187	)		24,892			(2,419	)		25,430
Foreign exchange loss		(390	)		(1,221	)		(659	)		(6,867	)
Total other (expense) income		(3,404	)		20,844			(10,773	)		9,636
(Loss) income from continuing operations before income taxes		(2,412	)		18,360			(10,926	)		11,667
Income tax expense		(2,224	)		(2,727	)		(5,820	)		(5,746	)
Net (loss) income from continuing operations		(4,636	)		15,633			(16,746	)		5,921
Income (loss) from discontinued operations before income taxes		6,886			(16,912	)		5,830			(20,627	)
Gain on disposal of discontinued operations		9,419			-			10,168			-
Income tax benefit		-			6,181			204			6,864
Net income (loss) from discontinued operations		16,305			(10,731	)		16,202			(13,763	)
Net income (loss)	$	11,669		$	4,902		$	(544	)	$	(7,842	)
Other comprehensive income (loss):
Foreign currency translation adjustment		(3,986	)		(21,743	)		(3,277	)		(50,279	)
Comprehensive income (loss)	$	7,683		$	(16,841	)	$	(3,821	)	$	(58,121	)

Net income (loss) per common share
Basic net income (loss) per common share
Continuing operations	$	(0.10	)	$	0.38		$	(0.39	)	$	0.14
Discontinued operations	$	0.35		$	(0.26	)	$	0.38		$	(0.34	)
Weighted average common shares outstanding		46,854			40,943			42,879			40,895
Diluted net income (loss) per common share
Continuing operations	$	(0.10	)	$	0.38		$	(0.39	)	$	0.14
Discontinued operations	$	0.35		$	(0.26	)	$	0.38		$	(0.34	)
Weighted average common and common equivalent shares outstanding		46,854			40,956			42,879			40,895

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

T RANS A TLANTIC P ETROLEUM L TD .

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, 2015		41,018		333		699	$	4,102	$	(970	)	$	569,365		$	(121,590	)	$	(391,985	)	$	58,922
Issuance of common shares		5,998		-		-		600		-			3,370			-			-			3,970
Issuance of restricted stock units		189		-		-		19		-			(19	)		-			-			-
Tax withholding on restricted stock units		-		-		-		-		-			(59	)		-			-			(59	)
Share-based compensation		-		-		-		-		-			496			-			-			496
Foreign currency translation adjustment		-		-		-		-		-			-			(3,277	)		-			(3,277	)
Net loss		-		-		-		-		-			-			-			(544	)		(544	)
Balance at September 30, 2016		47,205		333		699	$	4,721	$	(970	)	$	573,153		$	(124,867	)	$	(392,529	)	$	59,508

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

T RANS A TLANTIC P ETROLEUM L TD .

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands of U.S. Dollars)

	For the Nine Months Ended
	September 30,
	2016			2015
Operating activities:
Net loss	$	(544	)	$	(7,842	)
Adjustment for net (income) loss from discontinued operations		(16,202	)		13,763
Net (loss) income from continuing operations		(16,746	)		5,921
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Share-based compensation		496			1,334
Foreign currency loss		593			7,026
Loss (gain) on commodity derivative contracts		2,419			(25,430	)
Cash settlement on commodity derivative contracts		4,188			27,560
Amortization on loan financing costs		1,015			684
Bad debt expense		–			320
Deferred income tax expense		1,239			2,635
Exploration, abandonment and impairment		2,964			8,202
Depreciation, depletion and amortization		23,053			28,183
Accretion of asset retirement obligations		285			277
Gain on sale of gas gathering facility		(620	)		–
Derivative put costs		–			(1,580	)
Vendor settlements		–			(236	)
Changes in operating assets and liabilities:
Accounts receivable		(4,643	)		13,596
Prepaid expenses and other assets		(1,528	)		1,226
Accounts payable and accrued liabilities		6,892			(16,838	)
Net cash provided by operating activities from continuing operations		19,607			52,880
Net cash used in operating activities from discontinued operations		(822	)		(14,718	)
Net cash provided by operating activities		18,785			38,162
Investing activities:
Additions to oil and natural gas properties		(4,664	)		(18,734	)
Restricted cash		6,398			(198	)
Proceeds from asset sale		1,104			–
Additions to equipment and other properties		(139	)		(4,664	)
Net cash provided by (used in) investing activities from continuing operations		2,699			(23,596	)
Net cash used in investing activities from discontinued operations		-			(9,715	)
Net cash provided by (used in) investing activities		2,699			(33,311	)
Financing activities:
Issuance of common shares		1,658			-
Tax withholding on restricted share units		(59	)		(383	)
Treasury stock repurchases		-			(943	)
Loan proceeds		30,076			12,348
Loan repayment		(39,517	)		(24,878	)
Loan financing costs		-			(30	)
Net cash used in financing activities from continuing operations		(7,842	)		(13,886	)
Net cash used in financing activities from discontinued operations		-			(13,709	)
Net cash used in financing activities		(7,842	)		(27,595	)
Effect of exchange rate on cash flows and cash equivalents		(517	)		(1,812	)
Net increase (decrease) in cash and cash equivalents		13,125			(24,556	)
Cash and cash equivalents, beginning of period		7,480			35,132
Cash and cash equivalents, end of period	$	20,605		$	10,576
Supplemental disclosures:
Cash paid for interest	$	4,057		$	7,318
Cash paid for taxes	$	3,423		$	2,481
Supplemental non-cash financing activities:
Issuance of common shares	$	2,312		$	-
Contingent payment event	$	-		$	(4,188	)
Repayment of the prepayment agreement	$	-		$	2,739

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

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 8, 2016, approximately 39% 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, and an operated interest in a joint venture in Albania.

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 acquisitions and financial derivatives, the recoverability and impairment of long-lived assets, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. During the nine months ended September 30, 2016, we reclassified certain balance sheet amounts previously reported on our consolidated balance sheet at December 31, 2015 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, 2015.

2. Going concern

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

We had net a loss of $0.5 million for the nine months ended September 30, 2016, which included net income from discontinued operations of $16.2 million. At September 30, 2016, the outstanding principal amount of our debt was $87.4 million and we had a working capital deficit of $54.1 million.

On August 23, 2016, the Turkish branch of TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), entered into a general credit agreement (the “Credit Agreement”) with DenizBank, A.S. (“DenizBank”). On August 31, 2016, DenizBank entered into a $30.0 million term loan (the “Term Loan”) with TEMI under the Credit Agreement. TEMI is a wholly-owned subsidiary of TransAtlantic.

On September 7, 2016, TEMI used approximately $22.9 million of the proceeds from the Term Loan to repay in full (including accrued interest) the Company’s senior credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP”) and the International Finance Corporation (“IFC”), which was terminated upon repayment. In connection with the repayment of the Senior Credit Facility, the Company unwound its oil hedges with BNP, receiving proceeds of $2.6 million.

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 and is payable in six monthly installments of $1.25 m illion each through February 2017 and thereafter in twelve monthly installments of $1.88 million each through February 2018. The Term Loan matures in February 2018. Of the $28.8 million outstanding under the Term Loan at September 30, 2016, $19.4 million is classified as short-term debt. In addition, the Company’s $55.0 million of outstanding 13.0% convertible notes due 2017 (the “2017 Notes”) are due in full on July 1, 2017 .

Consequently, we will need some form of debt restructuring, capital raising effort or asset sale in order to fund our operations and meet our substantial debt service obligations of approximately $7.3 million during the fourth quarter of 2016 and $76.3 million in 2017. As a result, there is substantial doubt regarding our ability to continue as a going concern. The Company continues to focus on the sale of assets to raise cash, capital raising and restructuring, and repaying or refinancing its debt obligations. See Note 14. “Subsequent Events.”

Management believes the going concern assumption to be appropriate for these consolidated financial statements. If the going concern assumption was not appropriate, adjustments would be necessary to the carrying values of assets and liabilities, reported revenues and expenses, and in the balance sheet classifications used in these consolidated financial statements.

3. Recent accounting pronouncements

In July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-11, Simplifying the Measurement of Inventory (“ASU 2015-11”), an amendment to Accounting Standards Codification (“ASC”) Subtopic 330-10. The amendment states that entities should measure inventory at the lower of cost and net realizable value. The amendment does not apply to inventory that is measured using last-in, first-out (LIFO) or the retail inventory method. The amendment applies to all other inventory, which includes inventory that is measured using first-in, first-out (FIFO) or average cost. ASU 2015-11 is effective for fiscal years beginning after December 31, 2016, including interim periods within those fiscal years. We are currently assessing the potential impact of ASU 2015-11 on our consolidated financial statements and results of operations.

In March 2016, the FASB issued 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 the 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 March 2016, the FASB issued ASU 2016-09, Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). ASU 2016-09 simplifies several aspects of the accounting for employee share-based payment transactions, including the accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU 2016-09 is effective for annual and interim periods beginning after December 15, 2016 and early adoption is permitted. We are currently assessing the potential impact of ASU 2016-09 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 Certai n 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 de bt 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 payment s 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.

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.

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, 2016			December 31, 2015
	(in thousands)
Oil and natural gas properties, proved:
Turkey	$	264,646		$	270,591
Bulgaria		499			489
Total oil and natural gas properties, proved		265,145			271,080
Oil and natural gas properties, unproved:
Turkey		29,883			31,135
Total oil and natural gas properties, unproved		29,883			31,135
Gross oil and natural gas properties		295,028			302,215
Accumulated depletion		(156,210	)		(139,002	)
Net oil and natural gas properties	$	138,818		$	163,213

At September 30, 2016 and December 31, 2015, we excluded $0.1 million and $0.7 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, 2016, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $17.7 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $91.2 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

At December 31, 2015, the capitalized costs of our oil and natural gas properties included $20.0 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $111.4 million relating to well costs and additional development costs, which are being amortized 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 three and nine months ended September 30, 2016, we recorded $1.5 million and $3.0 million, respectively, of impairment of proved properties and exploratory well costs, which are primarily measured using Level 3 inputs. We recorded $0.7 million of exploratory well costs related to the Guney Residere well during the three and nine months ended September 30, 2016.

Capitalized cost greater than one year

As of September 30, 2016, we had $1.2 million and $2.1 million of exploratory well costs capitalized for the Hayrabolu-10 and Pinar-1 wells, respectively, in Turkey, which we spud in February 2013 and March 2014, respectively. The Hayrabolu-10 and Pinar-1 wells continue to be held for completion.

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, 2016			December 31, 2015
	(in thousands)
Inventory	$	15,067		$	21,338
Leasehold improvements, office equipment and software		7,632			7,794
Gas gathering system and facilities		-			4,798
Other equipment		2,487			2,378
Vehicles		389			400
Gross equipment and other property		25,575			36,708
Accumulated depreciation		(6,141	)		(9,216	)
Net equipment and other property	$	19,434		$	27,492

As of September 30, 2016, we have classified $4.9 million of inventory as a current asset, which represents our expected consumption in the next twelve months. We classify the remainder of our materials and supply inventory as a long-term asset because such materials will ultimately be classified as a long-term asset when the material is used in the drilling of a well.

At September 30, 2016 and December 31, 2015, we excluded $20.0 million and $21.3 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, 2016 and for the year ended December 31, 2015:

	September 30, 2016			December 31, 2015
	(in thousands)
Asset retirement obligations at beginning of period	$	9,237		$	10,543
Change in estimates		-			385
Foreign exchange change effect		(252	)		(2,137	)
Additions		-			78
Accretion expense		285			368
Asset retirement obligations at end of period		9,270			9,237
Less: current portion		-			-
Long-term portion	$	9,270		$	9,237

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

Historically, we have used derivative contracts to 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 have recorded 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 counterp arty in our consolidated balance sheets. All of our oil derivative contracts were 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 inc ome (loss) under the caption “(Loss) gain on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on commodity derivative c ontracts.”

During the three months ended September 30, 2016 and 2015, we recorded a net loss on commodity derivative contracts of $0.2 million and a net gain of $24.9 million, respectively. During the nine months ended September 30, 2016 and 2015, we recorded a net loss on commodity derivative contracts of $2.4 million and a net gain of $25.4 million, respectively.

On September 7, 2016 and September 9, 2016, we unwound all of our existing crude oil hedges for the periods September 10, 2016 through March 31, 2019. The unwinding of these hedging transactions resulted in proceeds of $2.6 million and was used for general corporate purposes. See Note 14. “Subsequent Events” for more information.

At December 31, 2015, we had outstanding hedging contracts with respect to our future crude oil production as set forth in the table below:

Fair Value of Derivative Instruments as of December 31, 2015

		Puts
				Weighted
				Average		Estimated Fair
		Quantity		Price		Value of
Type	Period	(Bbl/day)		(per Bbl)		Asset
						(in thousands)
Put	January 1, 2016— December 31, 2016		808	$	50.00	$	3,235
Put	January 1, 2017— December 31, 2017		610	$	50.00		1,798
Put	January 1, 2018— December 31, 2018		494	$	50.00		1,292
Put	January 1, 2019— March 31, 2019		443	$	50.00		280
Total estimated fair value of asset						$	6,605

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 December 31, 2015, and (ii) the net recorded fair value as reflected on our consolidated balance sheets at December 31, 2015.

As of December 31, 2015

Gross

Amount

Net Amount of

Gross

Offset in the

Assets

Amount of

Consolidated

Presented in the

Recognized

Balance

Consolidated

Underlying Commodity

Location on Balance Sheet

Assets

Sheets

Balance Sheets

(in thousands)

Crude oil

Current assets

3,235

Crude oil

Long-term assets

3,370

7. Loans payable

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

	September 30,		December 31,
	2016		2015
Fixed and floating rate loans	(in thousands)
Term Loan	$	28,750	$	-
2017 Notes		34,450		34,400
2017 Notes - Related Party		20,550		20,600
Senior Credit Facility		-		32,075
Unamortized deferred financing cost - Senior Credit Facility and 2017 Notes		-		(1,260	)
TBNG credit facility		-		5,192
ANBE Note		3,593		3,592
Short-term lines of credit		78		-
West Promissory Notes		-		1,000
Loans payable		87,421		95,599
Less: current portion		78,046		40,599
Long-term portion	$	9,375	$	55,000

Senior Credit Facility

On May 6, 2014, certain of our wholly-owned subsidiaries entered into the Senior Credit Facility with BNP Paribas and IFC. The Senior Credit Facility was guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. (“TransAtlantic USA”) and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”). On August 31, 2016, TEMI entered into the Term Loan and, on September 7, 2016, we repaid the Senior Credit Facility in full and terminated it.

TEMI Term Loan

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

On August 31, 2016, DenizBank entered into the $30.0 million Term Loan with TEMI under the Credit Agreement. In addition, the Company 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 in full the Senior Credit Facility.

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 and is payable in six monthly installments of $1.25 million each through February 2017 and thereafter in twelve monthly installments of $1.88 million each through February 2018. The Term Loan matures in February 2018. Amounts repaid under the Term Loan may not be re-borrowed, and early repayments under the Term Loan are subject to early repayment fees.

The Term Loan is guaranteed by DMLP, Ltd. (“DMLP”), TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”), Talon Exploration, Ltd. (“Talon Exploration”) and TransAtlantic Worldwide (collectively, the “Guarantors”). Each of the Guarantors is a wholly-owned subsidiary of the Company.

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

The Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Mura tli real estate owned by Gundem Turizm Yatirim ve Isletmeleri A.S. (“Gundem”) and (v) the Diyarbakir real estate owned 80% by N. Malone Mitchell 3 ^rd and 20% by Selami Erdem Uras. In addition, TEMI assigned its Turkish collection accounts and its receivabl es from the sale of oil to DenizBank as additional security for the Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our c hief e xecutive o fficer and c hairman of our b oard of directors . Mr. Uras i s our v ice p resident, Turkey.

At September 30, 2016, we had $28.8 million outstanding under the Term Loan and no availability, and were in compliance with the covenants in the Term Loan.

2017 Notes

As of September 30, 2016, we had $55.0 million aggregate principal amount of outstanding 2017 Notes. The 2017 Notes bear interest at a rate of 13.0% per annum and mature on July 1, 2017. The 2017 Notes are convertible at any time, at the election of a holder, into our common shares at a conversion price of $6.80 per share.

On June 30, 2016, we issued 2,905,737 common shares in a private placement to certain holders of the 2017 Notes, at the election of such holders to receive common shares in lieu of cash interest on the 2017 Notes. See Note 14. “Subsequent Events” for more information.

TBNG credit facility

Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) had a fully-drawn credit facility with a Turkish bank. On August 9, 2016, TBNG repaid the credit facility in full and terminated it.

West Promissory Notes

In August 2015, TransAtlantic USA entered into promissory notes (the “Promissory Notes”) with each of Mary West CRT 2 LLC and Gary West CRT 2 LLC, shareholders of the Company (collectively, the “Holders”), whereby TransAtlantic USA could borrow up to $1.5 million under each Promissory Note to fund our share repurchase program. The Holders are managed by Randy Rochman, an observer of our board of directors. On September 9, 2016, the Promissory Notes were repaid in full with proceeds from the Term Loan and were terminated.

ANBE Note

On December 30, 2015, 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 Mr. Mitchell and controlled by an entity managed by Mr. Mitchell and his wife. The Note bears interest at a rate of 13.0% per annum. On December 30, 2015, the Company borrowed $3.6 million under the Note (the “Initial Advance”) for general corporate purposes. On June 30, 2016, the Company issued 355,826 common shares in a private placement to ANBE in lieu of paying cash interest on the Note. As of September 30, 2016, the Company had borrowed $3.6 million under the Note and had no availability.

Advances under the Note may be converted, at the election of ANBE, any time prior to the maturity of the Note into common shares of the Company. The conversion price per common share for each advance is equal to 105% of the closing price of the Company’s common shares on the NYSE MKT on the trading date immediately prior to such advance. The conversion price of the Initial Advance is $1.3755 per share. See Note 14. “Subsequent Events” for more information.

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, and 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 Aglen work program. We believe that Direct Bulgaria is not under any obligation to fulfill the work program until the 2012 force majeure event is rectified and intend to vigorously defend this claim.

9. Shareholders’ equity

June 2016 share issuance

On June 30, 2016, we issued an aggregate of 5,773,305 common shares in private placements under the Securities Act of 1933, as amended (the “Securities Act”). Of the 5,773,305 common shares, (i) 2,905,737 common shares were issued to holders of the 2017 Notes at the election of such holders to receive common shares in lieu of cash interest on the 2017 Notes; (ii) 355,826 common shares were issued to ANBE in lieu of cash interest on the Note; and (iii) 2,511,742 common shares were issued for cash, which was used to pay cash interest to certain holders of the 2017 Notes. All of the shares were issued at a value of $0.6599 per share, which was equal to 75% of the 10-day volume weighted average price through the close of trading of the common shares on the NYSE MKT on June 29, 2016.

Restricted stock units

We recorded non-cash share-based compensation expense of $0.1 million and $0.3 million for awards of restricted stock units (“RSUs”) for the three months ended September 30, 2016 and 2015, respectively. We recorded non-cash share-based compensation expense of $0.5 million and $0.8 million for awards of RSUs for the nine months ended September 30, 2016 and 2015, respectively.

As of September 30, 2016, we had approximately $0.8 million of unrecognized non-cash compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.5 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, 2016 and 2015 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, 2016 and 2015 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. For the three and nine months ended September 30, 2016, 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)	2016			2015			2016			2015
Net (loss) income from continuing operations	$	(4,636	)	$	15,633		$	(16,746	)	$	5,921
Net income (loss) from discontinued operations	$	16,305		$	(10,731	)	$	16,202		$	(13,763	)
Basic net (loss) income per common share:
Shares:
Weighted average common shares outstanding		46,854			40,943			42,879			40,895
Basic net (loss) income per common share:
Continuing operations	$	(0.10	)	$	0.38		$	(0.39	)	$	0.14
Discontinued operations	$	0.35		$	(0.26	)	$	0.38		$	(0.34	)
Diluted net (loss) income per common share:
Shares:
Weighted average common shares outstanding		46,854			40,943			42,879			40,895
Dilutive effect of:
Warrants		-			13			-			-
Restricted stock units		-			-			-			-
		46,854			40,956			42,879			40,895
Diluted net (loss) income per common share:
Continuing operations	$	(0.10	)	$	0.38		$	(0.39	)	$	0.14
Discontinued operations	$	0.35		$	(0.26	)	$	0.38		$	(0.34	)

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, 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 three months ended September 30, 2015
Total revenues	$	-		$	18,337				$	18,337
(Loss) income from continuing operations before income taxes		(3,884	)		22,390		(146	)		18,360
Capital expenditures	$	-		$	7,679	$	-		$	7,679
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
For the nine months ended September 30, 2015
Total revenues	$	-		$	69,147	$	-		$	69,147
(Loss) income from continuing operations before income taxes		(15,787	)		31,567		(4,113	)		11,667
Capital expenditures	$	163		$	18,411	$	41		$	18,615
Segment assets
September 30, 2016	$	14,378		$	211,555	$	616		$	226,549
December 31, 2015 ₍₁₎	$	14,689		$	231,388	$	601		$	246,678

(1)	Excludes assets from our discontinued Albanian and Moroccan operations of $51.5 million December 31, 2015.

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, 2016 and December 31, 2015, 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 Canadian Dollar, Bulgarian Lev, European Union Euro, Romanian New Leu 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, 2016, we had 47.6 million TRY (approximately $15.9 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 December 31, 2015, we were a party to commodity derivative contracts (see Note 6, “Commodity derivative instruments”).

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, 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)
Disclosed but not carried at fair value
Liabilities:
Term Loan	$	-	$	-	$	(25,244	)	$	(25,244	)
2017 Notes		-		-		(49,438	)		(49,438	)
Total	$	-	$	-	$	(74,682	)	$	(74,682	)

At September 30, 2016, the fair values of the Term Loan and 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.

The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2015:

	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
Assets:
Commodity derivative contracts	$	-	$	6,605	$	-		$	6,605
Disclosed but not carried at fair value
Liabilities:
Senior Credit Facility		-		-		(30,050	)		(30,050	)
2017 Notes		-		-		(44,489	)		(44,489	)
Total	$	-	$	6,605	$	(74,539	)	$	(67,934	)

We remeasure our derivative contracts on a recurring basis, with changes flowing through earnings. At December 31, 2015, the fair values of the Senior Credit Facility and 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.

12. Related party transactions

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

	September 30,		December 31,
	2016		2015
	(in thousands)
Related party accounts receivable:
Riata Management service agreement	$	408	$	194
PSIL MSA		60		-
Viking International master services agreement		-		220
Total related party accounts receivable	$	468	$	414
Related party accounts payable:
PSIL MSA	$	1,768	$	-
Interest Payable on 2017 Notes and ANBE Note		768		-
Riata Management service agreement		228		384
Viking International master services agreement		-		2,300
Total related party accounts payable	$	2,764	$	2,684

Services transactions

On March 3, 2016, Mr. Mitchell closed a transaction whereby he sold his interests in Viking Services B.V. (“Viking Services”), the beneficial owner of Viking International Limited (“Viking International”), Viking Petrol Sahasi Hizmetleri A.S. (“VOS”) and Viking Geophysical Services Ltd. (“Viking Geophysical”), to a third party. As part of the transaction, Mr. Mitchell acquired certain equipment used in the performance of stimulation, wireline, workover and similar services, which equipment is owned and operated by Production Solutions International Petrol Arama Hizmetleri Anonim Sirketi (“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 the 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 service agreements with each of Viking International, VOS and Viking Geophysical will remain in effect through the remainder of the five-year term of the agreements ending on June 13, 2017.

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 $7,964,053, which Amended Note would amend and restate that certain promissory note, dated June 13, 2012, made by Dalea in favor of us in the principal amount of $11.5 million (the “Original Note”). The Note Amendment Agreement reduced the principal amount of the Original Note to $8.0 million 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. We have indemnified a third party for any liability relating to the payment of the Account Payable.

Pursuant to the Note Amendment Agreement, on April 19, 2016, we entered into the Amended Note, which amended and restated the Original Note that was issued in connection with our sale of our subsidiaries, Viking International and Viking Geophysical Services, to a joint venture owned by Dalea and Abraaj Investment Management Limited in June 2012. In the Amended Note, we and Dalea acknowledged that (i) while the sale of Dalea’s interest in Viking Services enabled us to take the position that the Original Note was accelerated in accordance with its terms, the principal purpose of including the acceleration events in the Original Note was to ensure that certain oilfield services provided by Viking Services to us would continue to be available to us, and (ii) such services will now be provided pursuant to the 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 $2.0 million principal amount of the 2017 Notes owned by Dalea (the “Dalea Convertible Notes”), including any future securities for which the Dalea Convertible Notes are converted or exchanged, as security for the performance of Dalea’s obligations under the Amended Note. The Pledge Agreement provides that interest payable to Dalea under the Dalea Convertible Notes (or any future securities for which the Dalea Convertible Notes are converted or exchanged) will be credited first against the outstanding principal balance of the Amended Note and, upon full repayment of the outstanding principal balance of the Amended Note, any accrued and unpaid interest on the Amended Note. The Pledge Agreement contains customary events of default.

On June 30, 2016, we entered into a waiver with Dalea, whereby we waived our right under the Pledge Agreement to receive the interest payment due July 1, 2016 under the Dalea Convertible Notes in connection with the payment of 201,459 common shares to Dalea with respect to the 2017 Note interest payment paid on June 30, 2016.

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 will pay 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 Messrs. Mitchell and Uras (the “Diyarbakir Fee Agreement”) pursuant to which the Company will pay Messrs. Mitchell and Uras a fee of 5% per annum of the collateral value of the Diyarbakir real estate. Pursuant to the Diyarbakir Fee Agreement, the Diyarbakir real estate has a deemed collateral value of $5.0 million.

Amounts payable to Mr. Mitchell under the Gundem Fee Agreement and the Diyarbakir Fee Agreement will be used to reduce the outstanding principal amount of the Amended Note.

Private placements

On June 30, 2016, we issued an aggregate of 5,773,305 common shares in private placements under the Securities Act. Of the 5,773,305 common shares, (i) 1,974,452 common shares were issued to Dalea, the trusts of Mr. Mitchell’s four adult children and Pinon Foundation, a nonprofit entity controlled by Mrs. Mitchell, at their election to receive common shares in lieu of cash interest on the 2017 Notes; (ii) 355,826 common shares were issued to ANBE in lieu of cash interest on the Note and (iii) 814,627 common shares were issued to Dalea and the trusts of Mr. Mitchell’s four adult children for cash, which was used to pay cash interest to certain holders of the 2017 Notes (see Note 9, “Shareholders’ equity”).

Indemnity agreement

On May 9, 2016, Mr. Mitchell guaranteed the payment of director and officer liability premiums in the amount of $0.4 million (the “Guaranteed Payments”) payable to US Premium Finance solely in the event of a change of control of the Company. On May 9, 2016, we entered into an Indemnity Agreement with Mr. Mitchell pursuant to which we agreed to indemnify him for any damages he incurs related to the Guaranteed Payments.

13. Discontinued operations

Discontinued operations in Albania

As of December 31, 2015, we classified our former Albania segment as assets and liabilities held for sale. We have presented the operating results of our former Albanian segment within discontinued operations for all periods presented.

In February 2016, we sold all of the outstanding equity in Stream Oil & Gas Ltd. (“Stream”) to GBC Oil Company Ltd. (“GBC Oil”) in exchange for (i) the future payment of $2.3 million to Raiffeisen Bank Sh.A. (“Raiffeisen”) to pay down the term loan facility dated as of September 17, 2014 (the “Term Loan Facility”) between Stream’s wholly-owned subsidiary, TransAtlantic Albania Ltd. (“TransAtlantic Albania”) and Raiffeisen, and (ii) the assumption of $29.2 million of liabilities owed by Stream, consisting of $23.1 million of accounts payable and accrued liabilities and $6.1 million of debt. TransAtlantic Albania owns all of our former Albanian oil assets and operations. In addition, GBC Oil issued us a warrant pursuant to which we have the option to acquire up to 25% of the fully diluted equity interests in TransAtlantic Albania for nominal consideration at any time on or before March 1, 2019.

On September 1, 2016, the Company completed a joint venture transaction with respect to the assets in the Delvina gas field in Albania (the “Delvina Assets”). The Company 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 will be used primarily to repay debt and for general corporate purposes with respect to the Delvina Assets. These payments will be made each quarter over an 18-month period, with the first payment of $1.0 million to be completed by November 2016. As a result of this transaction, we have recorded a gain on disposal of discontinued operations of $9.4 million during three and nine months ended September 2016.

After the Transfer, the Company retained a 25% equity interest in DelvinaCo and has agreed to pay 25% of the operating costs of DelvinaCo, subject to a three-year deferral of capital expenditures. For the next three years, Ionian will be responsible for all agreed upon capital expenditures with respect to the Delvina Assets. At the end of the three-year period, the Company will be required to either reimburse Ionian for its 25% share of such capital expenditures or face dilution in its ownership of DelvinaCo. As of September 30, 2016, we no longer hold our 25% interest in DelvinaCo as assets held for sale, and have consolidated our interest using proportionate consolidation.

At December 31, 2015, TransAtlantic Albania’s third-party debt consisted of the following:

	December 31,
	2015
Fixed and floating rate loans
Term Loan Facility	$	6,123
Loans payable	$	6,123

TransAtlantic Albania was a party to the Term Loan Facility with Raiffeisen. The loan was scheduled to mature on December 31, 2016 and bore interest at the rate of LIBOR plus 5.5%, with a minimum interest rate of 7.0%. TransAtlantic Albania was required to pay 1/16th of the total commitment each quarter on the last business day of each of March, June, September and December each year. The loan was guaranteed by TransAtlantic Albania’s parent company, Stream. TransAtlantic Albania could prepay the loan at its option in whole or in part, subject to a 3.0% penalty plus breakage costs. The Term Loan Facility was secured by substantially all of the assets of TransAtlantic Albania.

As of December 31, 2015, TransAtlantic Albania had $6.1 million outstanding under the Term Loan Facility and no availability. As of December 31, 2015, TransAtlantic Albania was in default under the Term Loan Facility for failure to repay $1.1 million due on December 31, 2015. On February 29, 2016, we sold all the equity interest in Stream, the parent company of TransAtlantic Albania, to GBC Oil, who assumed the Term Loan Facility.

Discontinued operations in Morocco

On June 27, 2011, we decided to discontinue our operations in Morocco. We have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for all periods presented.

Assets and liabilities held for sale

The assets and liabilities held for sale at December 31, 2015 were as shown below. As a result of the joint venture transaction related to the Delvina Assets and the reassessment of the Moroccan contingent liabilities, there were no remaining assets or liabilities held for sale at September 30, 2016.

	Albania		Morocco		Total Held for Sale
	(in thousands)
As of December 31, 2015
Assets
Cash	$	1,201	$	16	$	1,217
Other current assets		1,853		11		1,864
Property and equipment, net		48,430		-		48,430
Total current assets held for sale	$	51,484	$	27	$	51,511

Liabilities
Accounts payable and other accrued liabilities	$	37,888	$	6,352	$	44,240
Accounts payable - related party		3,540		-		3,540
Loans payable		6,123		-		6,123
Deferred tax liability		15,286		-		15,286
Total current liabilities held for sale	$	62,837	$	6,352	$	69,189

Results of discontinued operations

Our operating results from discontinued operations for the three and nine months ended September 30, 2016 and 2015 are summarized as follows:

	Albania			Morocco			Total
	(in thousands)
For the three months ended September, 2016
Total revenues	$	-		$	-		$	-
Production and transportation expense		-			-			-
Total other expenses (income)		17			(6,903	)		(6,886	)
(Loss) income before income taxes	$	(17	)	$	6,903		$	6,886
Gain on disposal of discontinued operations		9,419			-			9,419
Income tax benefit		-			-			-
Income from discontinued operations	$	9,402		$	6,903		$	16,305

For the three months ended September, 2015
Total revenues	$	1,878		$	-		$	1,878
Production and transportation expense		2,612			-			2,612
Total other costs and expenses		15,963			-			15,963
Total other income		(215	)		-			(215	)
Loss before income taxes	$	(16,912	)	$	-		$	(16,912	)
Income tax benefit		6,181			-			6,181
Loss from discontinued operations	$	(10,731	)	$	-		$	(10,731	)

For the nine months ended September, 2016
Total revenues	$	626		$	-		$	626
Production and transportation expense		1,155			-			1,155
Total other expenses (income)		544			(6,903	)		(6,359	)
(Loss) income before income taxes	$	(1,073	)	$	6,903		$	5,830
Gain on disposal of discontinued operations		10,168			-			10,168
Income tax benefit		204			-			204
Income from discontinued operations	$	9,299		$	6,903		$	16,202

For the nine months ended September, 2015
Total revenues	$	6,554		$	-		$	6,554
Production and transportation expense		8,759			-			8,759
Total other costs and expenses		20,794			-			20,794
Total other income		2,372			-			2,372
Loss before income taxes	$	(20,627	)	$	-		$	(20,627	)
Income tax benefit		6,864			-			6,864
Loss from discontinued operations	$	(13,763	)	$	-		$	(13,763	)

During the fourth quarter of 2015, we identified an error related to our deferred tax liability and deferred tax benefit that originated in prior periods and concluded that the error was not material to any of the previously reported periods or to the period in which the error was corrected. The impact of the error resulted in a decrease to our net loss from discontinued operations of $4.7 million for each of the three and nine months ended September 30, 2015. This immaterial error was corrected in our third quarter of 2015 results of operations for discontinued operations.

14. Subsequent Events

Sale of TBNG

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 owns a portion of the Company’s interests in the Thrace Basin area in Turkey.

Pursuant to the Purchase Agreement, Valeura will pay $22.0 million to TransAtlantic Worldwide, subject to purchase price adjustments for the period from March 31, 2016 (the effective date of the sale) through the closing date, in exchange for the transfer of all of the equity interests in TBNG.

The Purchase Agreement contains customary representations, warranties, covenants, indemnification and termination rights of the parties. The closing of the sale is subject to the satisfaction of certain closing conditions, including the receipt of required regulatory approvals and the sale by Valeura of certain assets to a third party. The Company expects the transaction to close during the fourth quarter of 2016 or the first quarter of 2017. However, there is no guarantee that the Company will be able to close the sale of TBNG.

Extension of ANBE Note

On October 31, 2016, TransAtlantic USA entered into an amendment of the Note with ANBE (the “ANBE Amendment”). The ANBE Amendment extends the maturity date of the Note from October 31, 2016 to September 30, 2017, provides for the Note to be repaid in four quarterly installments of $0.9 million each in December 2016 and March, June and September 2017, and provides for monthly payments of interest. In addition, pursuant to the ANBE Amendment, if the sale of TBNG is completed prior to the extended maturity date of the Note, then the Company will repay the Note in full with proceeds from the sale of TBNG within five business days from the closing of the sale.

Offering of Series A Preferred Shares

On November 4, 2016, the Company issued 921,000 shares of its newly designated 12.0% Series A Convertible Redeemable Preferred Shares, par value $0.01 per share and liquidation preference of $50 per share (the “Series A Preferred Shares”), in private placements under the Securities Act. Of the 921,000 Series A Preferred Shares, (i) 815,000 shares were issued in a private placement exchange offer (the “Exchange Offer”) to certain holders of the 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 in a private placement (the “Private Offering”) to certain holders of the 2017 Notes. All of the Series A Preferred Shares were issued at a value of $50.00 per share. Gross proceeds from the Private Offering were $5.3 million, which will be used by the Company to redeem $4.3 million of 2017 Notes and for general corporate purposes. The Series A Convertible Redeemable Preferred Shares contain a substantive conversion option and convert into a fixed number of common shares. As a result, we will classify the Series A Preferred Shares within mezzanine equity in our consolidated balance sheet. After completion of the Exchange Offer, $14.3 million aggregate principal amount of the 2017 Notes remain outstanding.

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 (after approval of the listing of the common shares issuable upon conversion of the Series A Preferred Shares by the NYSE MKT and Toronto Stock Exchange) (the “Listing Condition”), at the option of the holder, into 45.754 common shares, par value $0.10 per share (“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 adjustment 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 shall exclude (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 will result in a contingent beneficial conversion feature.

If not converted sooner, on November 4, 2024, the Company is 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, the Company 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 the Company issues 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, the Company is 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 the election of the Company 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 shall be 12.0%, and the dividend rate on the Common Share portion shall be 16.0%. Dividends are payable quarterly, on June 30, September 30, December 31, and March 31 of each year, beginning on December 31, 2016, with the dividend payable on December 31, 2016 being pro-rated for the period from November 4, 2016. The holders of the Series A Preferred Shares also shall be entitled to participate pro-rata in any dividends paid on the Common Shares on an as-converted-to-Common Shares basis.

Except as required by Bermuda law the holders of Series A Preferred Shares will 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 shall have the right to elect two directors to the Company’s 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 shall have the right to elect one director to the Company’s 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 the Company’s 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, the Company 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 Company’s PV-10 of proved reserves as disclosed in its most recent independent reserve report filed or furnished by the Company on EDGAR. In addition, until the Company’s 2017 Notes are repaid in full, the Company will not issue indebtedness for money borrowed (other than ordinary trade indebtedness and up to $30.0 million borrowed from DenizBank) unless the net proceeds thereof are used (i) to redeem, retire or repay the 2017 Notes, (ii) spud, drill or complete two designated wells, or (iii) used in connection with collateralization or guarantees with respect to the Company’s hedging efforts.

The Company has agreed to use commercially reasonable efforts to file a shelf registration statement for the resale of the Series A Preferred Shares and the Common Shares issuable upon conversion of the Series A Preferred Shares prior to November 5, 2017 and have such shelf registration statement declared effective by the Securities and Exchange Commission as soon as practicable after filing.

Hedging Transactions

On October 6, 2016, we entered into costless collars with DenizBank to hedge a portion of our oil production in Turkey. The following table sets forth information about these hedges.

		Collars
				Weighted		Weighted
				Average		Average
		Quantity		Minimum		Maximum
Type	Period	(Bbl/day)		Price (per Bbl)		Price (per Bbl)
Collar	December 1, 2016 — December 31, 2016		290	$	47.50	$	61.00
Collar	January 1, 2017 — December 31, 2017		296	$	47.50	$	61.00
Collar	January 1, 2018 — May 31, 2018		298	$	47.50	$	61.00

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, 2016, we held interests in approximately 1.2 million net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of November 8, 2016, approximately 39% 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 interest in subsidiaries that primarily own assets in Turkey and Bulgaria, and an operated interest in a joint venture in Albania.

Recent Developments

TEMI Term Loan . On August 23, 2016, the Turkish branch of TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”) entered into a general credit agreement (the “Credit Agreement”) with DenizBank, A.S. (“DenizBank”). On August 31, 2016, DenizBank entered into a $30.0 million term loan (the “Term Loan”) with TEMI under the Credit Agreement. TEMI is one of our wholly-owned subsidiaries.

On September 7, 2016, TEMI used approximately $22.9 million of the proceeds from the Term Loan to repay in full (including accrued interest) our senior credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP”) and the International Finance Corporation, which was terminated upon repayment. In connection with repaying the Senior Credit Facility, we unwound our oil hedges with BNP, receiving proceeds of $2.6 million.

Sale of TBNG . 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 Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”), our wholly-owned subsidiary. TBNG owns a portion of our interests in the Thrace Basin area in Turkey.

Pursuant to the Purchase Agreement, Valeura will pay $22.0 million to TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”), one of our wholly-owned subsidiaries, subject to purchase price adjustments for the period from March 31, 2016 (the effective date of the sale) through the closing date, in exchange for the transfer of all of the equity interests in TBNG.

The Purchase Agreement contains customary representations, warranties, covenants, indemnification and termination rights of the parties. The closing of the sale is subject to the satisfaction of certain closing conditions, including the receipt of required regulatory approvals and the sale by Valeura of certain assets to a third party. We expect the transaction to close during the fourth quarter of 2016 or the first quarter of 2017. However, there is no guarantee that we will be able to close the sale of TBNG.

Extension of ANBE Note . On October 31, 2016, TransAtlantic Petroleum (USA) Corp. (“TransAtlantic USA”), one of our wholly-owned subsidiaries, entered into an amendment of a convertible promissory note (the “Note”) with ANBE Holdings, L.P. (the “ANBE Amendment”). The ANBE Amendment extends the maturity date of the Note from October 31, 2016 to September 30, 2017, provides for the Note to be repaid in four quarterly installments of $0.9 million each in December 2016 and March, June and September 2017, and provides for monthly payments of interest. In addition, pursuant to the ANBE Amendment, if the sale of TBNG is completed prior to the extended maturity date of the Note, then the Company will repay the Note in full with proceeds from the sale of TBNG within five business days from the closing of the sale.

Offering of Series A Preferred Shares . On Nov ember 4, 2016, we issued 921,000 shares of our newly designated 12.0% Series A Convertible Redeemable Preferred Shares, par value $0.01 per share and liquidation preference of $50 per share (the “Series A Preferred Shares”), in private placements under the Securities Act of 1933. Of the 921,000 Series A Preferred Shares, (i) 815,000 shares were issued in a private placement exchange offer (the “Exchange Offer”) to certain holders of our 13.0% convertible notes due 2017 (the “2017 Notes”), at an exchange ra te of 20 Series A Preferred Shares for each $1,000 principal amount of 2017 Notes, and (ii) 106,000 shares were issued and sold in a private placement (the “Private Offering”) to certain h olders of 2017 Notes . All of the Series A Preferred Shares were iss ued at a value of $50 .00 per share. Gross proceeds from the Private Offering were approximately $ 5.3 million , which will be used by us to redeem $4.3 million of 2017 Notes and for general corporate purposes. After completion of the Exchange Offer, $14.3 mi llion aggregate principal amount of the 2017 Notes remain outstanding. The Series A Preferred Shares will be classified as mezzanine equity on our balance sheet. For more information on the terms of the Series A Preferred Shares, see “Note 14. Subsequent Events” to our consolidated financial statements included elsewhere in this quarterly report on Form 10-Q.

Going Concern

At September 30, 2016, we had (i) $78.0 million of short-term debt, consisting of $19.4 million due under the Term Loan, $3.6 million due under the Note and $55.0 million of 2017 Notes due on July 1, 2017, (ii) $20.6 million of cash and cash equivalents, and (iii) a working capital deficit of $54.1 million. After the extension of the ANBE Note and the closing of the offering of Series A Preferred Shares, we have $37.3 million of short-term debt, consisting of $19.4 million due under the Term Loan, $3.6 million due under the Note and $14.3 million of 2017 Notes due on July 1, 2017, and we raised an additional $5.3 million of cash to redeem $4.3 million of 2017 Notes and for general corporate purposes. In addition, we have entered into the Purchase Agreement to sell TBNG for $22.0 million, which we expect to close in the fourth quarter of 2016 or the first quarter of 2017, subject to the satisfaction of closing conditions.

Given the current market price for Brent crude, our working capital deficit and the amount of our short-term debt, we are focused on the following near-term business strategies: (i) consummating the sale of TBNG to raise cash to repay outstanding short-term indebtedness and for general corporate purposes, (ii) a development plan focused on maintaining our acreage position by drilling obligation wells and performing low cost, high return well optimizations, (iii) continued cost reduction measures to reduce our operating costs and general and administrative expenses, and (iv) raising additional cash for general corporate purposes, including our 2017 development plan.

These factors raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements included in this report do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts of liabilities that might result from the outcome of this uncertainty.

Financial and Operational Performance Summary

The following is a summary of our financial and operational performance for the third quarter of 2016:

•

We reported a $4.6 million net loss from continuing operations for the three months ended September 30, 2016.

•

We derived 87.4% of our oil and natural gas revenues from the production of oil and 12.6% from the production of natural gas during the three months ended September 30, 2016.

•

Total oil sales decreased $0.2 million to $13.5 million for the quarter ended September 30, 2016, from $13.7 million in the same period in 2015. The decrease was primarily the result of a $2.09 decrease in the average price received per barrel of oil (“Bbl”) which resulted in lower revenues of $0.7 million. This was partially offset by an increase in oil sales volumes of 13 thousand barrels of oil (“Mbbl”) which resulted in higher revenues of $0.5 million.

•

Total natural gas sales decreased $1.9 million to $2.0 million for the quarter ended September 30, 2016, from $3.9 million in the same period in 2015. The decrease was primarily the result of a decrease in sales volumes of 256 million cubic feet of natural gas (“Mmcf”) which resulted in lower revenues of $1.8 million. Additionally, the average price received decreased $0.27 per Mmcf of natural gas which resulted in lower revenues of $0.1 million.

•

For the quarter ended September 30, 2016, we incurred $1.5 million in capital expenditures, including seismic and corporate expenditures, as compared to $7.7 million for the quarter ended September 30, 2015.

•

As of September 30, 2016, we had $9.4 million in long-term debt and $78.0 million in short-term debt, as compared to $55.0 million in long-term debt and $41.9 million in short-term debt as of December 31, 2015.

Third Quarter 2016 Operational Update

During the third quarter of 2016, we drilled one well and continued workover and production optimizations in Southeast Turkey. The following summarizes our operations by location during the third quarter of 2016:

Turkey-Southeast

In the Selmo and Bahar fields, we continued low cost well optimizations. In Bahar, we ran electric submersible pumps in the Bahar-3 and Bahar-4 wells, which resulted in incremental production of 500 gross barrels of oil per day (“Bopd”). We also completed facility upgrades and modifications in the Bahar field, and we are currently waiting for the arrival of power generation equipment, which will complete our electrification and gas utilization project. In Selmo, we completed pipeline and facility upgrades, which allowed further optimization work to be undertaken. As a result of this work, we added approximately 100 gross Bopd to our Selmo production.

Turkey-Northwest

In the Thrace Basin, we drilled one gross well, the Guney Reisdere-1 (50% working interest). The well was spud on August 2, 2016 as part of our drilling obligations on licenses in our Turkiye Petrolleri Anonim Ortakligi (“TPAO”) joint venture. The well reached a total depth of 9,243 feet. Although various gas shows were seen while drilling, open-hole logs did not indicate commercial quantities of reservoir quality rock and we subsequently plugged and abandoned the well.

Bulgaria

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

Albania

On September 1, 2016, we completed a joint venture transaction with respect to the assets in the Delvina gas field in Albania. We are the operator of the joint venture. We have begun engineering and geologic work in order to restart production in the most efficient and cost effective manner possible.

Planned Operations for the fourth quarter 2016

We currently plan to execute the following activities under our reduced development plan during the remainder of 2016:

Turkey. As a result of improved seismic interpretation and further engineering and geologic evaluation, we plan to drill or commence drilling between one and two wells during the remainder of 2016. These wells will be located in our Selmo and Bahar fields in Southeast Turkey. We are increasing the pumping capacity of the Bahar-1, Bahar-3 and Bahar-7 wells and the capacity to process and store oil. We will also complete an initial gas-to-electricity facility to provide power to operate our field operations.

Bulgaria. We plan to continue working on our geologic model for additional prospects and continue to market a joint venture exploration program for our assets in Bulgaria.

Albania. We plan to complete our engineering evaluation required to restart production and then hold a meeting with our JV partner in the fourth quarter of 2016 to agree upon future operations and budgets, with the goal of expeditiously restoring production and further developing the Delvina gas field.

Discontinued Operations in Albania

In February 2016, we sold all of the outstanding equity in our wholly-owned subsidiary, Stream Oil & Gas Ltd. (“Stream”), to GBC Oil Company Ltd. (“GBC Oil”) in exchange for (i) the future payment of $2.3 million to Raiffeisen Bank Sh.A. (“Raiffeisen”) to pay down a term loan facility, and (ii) the assumption of $29.2 million of liabilities owed by Stream, consisting of $23.1 million of accounts payable and accrued liabilities and $6.1 million of debt. TransAtlantic Albania Ltd. (“TransAtlantic Albania”), Stream’s wholly-owned subsidiary, owns all of our former Albanian oil assets and operations. In addition, GBC Oil issued us a warrant pursuant to which we have the option to acquire up to 25% of the fully diluted equity interests in TransAtlantic Albania for nominal consideration at any time on or before March 1, 2019.

On September 1, 2016, we completed a joint venture transaction with respect to the assets in the Delvina gas fie ld 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 $1 2.0 million, which will be used primarily to repay debt and for general corporate purposes with respect to the Delvina Assets. These payments will be made each quarter over an 18-month period, with the first payment of $1.0 million to be completed by Novem ber 2016. As a result of this transaction , we have recorded a gain on disposal of discontinued operations of $9.4 million during three and nine months ended September 2016.

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. For the next three years, Ionian will be responsible for all agreed upon capital expenditures with respect to the Delvina Assets. At the end of the three-year period, we will be required to either reimburse Ionian for our 25% share of such capital expenditures or face dilution in our ownership of DelvinaCo. As of September 30, 2016, we no longer hold our 25% interest in DelvinaCo as assets held for sale, and have consolidated our interest using proportionate consolidation.

Discontinued Operations in Morocco

In June 2011, we decided to discontinue our Moroccan operations. We have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for the three and nine months ended September 30, 2016 and September 30, 2015. During the three and nine months ended September 30, 2016, we reversed a contingent liability of $6.3 million as it was deemed to no longer be probable of payment.

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, 2015 and are of particular importance to the portrayal of our financial position and results of operations and require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

There have been no changes to the significant accounting policies disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.

Results of Continuing Operations—Three Months Ended September 30, 2016 Compared to Three Months Ended September 30, 2015

Our results of continuing operations for the three months ended September 30, 2016 and 2015 were as follows:

	Three Months Ended September 30,						Change
	2016			2015			2016-2015
	(in thousands of U.S. Dollars, except per unit amounts and production volumes)
Sales volumes:
Oil (Mbbl)		338			325			13
Natural gas (Mmcf)		283			539			(256	)
Total production (Mboe)		386			415			(29	)
Average daily sales volumes (Boepd)		4,191			4,511			(320	)
Average prices:
Oil (per Bbl)	$	39.99		$	42.08		$	(2.09	)
Natural gas (per Mcf)	$	6.89		$	7.16		$	(0.27	)
Oil equivalent (per Boe)	$	40.15		$	42.28		$	(2.13	)
Revenues:
Oil and natural gas sales	$	15,483		$	17,543		$	(2,060	)
Sales of purchased natural gas		1,171			756			415
Other		5			38			(33	)
Total revenues		16,659			18,337			(1,678	)
Costs and expenses (income):
Production		3,070			3,104			(34	)
Exploration, abandonment and impairment		1,531			3,762			(2,231	)
Cost of purchased natural gas		1,027			668			359
General and administrative		2,659			4,849			(2,190	)
Depletion		6,918			7,540			(622	)
Depreciation and amortization		362			633			(271	)
Interest and other expense		3,836			3,159			677
Interest and other income		(1,009	)		(332	)		(677	)
Foreign exchange loss		390			1,221			(831	)
(Loss) gain on commodity derivative contracts:
Cash settlements on commodity derivative contracts		2,729			20,312			(17,583	)
Change in fair value on commodity derivative contracts		(2,916	)		4,580			(7,496	)
Total (loss) gain on commodity derivative contracts		(187	)		24,892			(25,079	)
Oil and natural gas costs per Boe:
Production	$	6.96		$	6.54		$	0.42
Depletion	$	15.70		$	15.90		$	(0.20	)

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $2.1 million to $15.5 million for the three months ended September 30, 2016, from $17.5 million realized in the same period in 2015. The decrease was primarily due to a decrease in the average realized price per barrel of oil equivalent (“Boe”) and reduced production. Our average price received decreased $2.13 per Boe to $40.15 per Boe for the three months ended September 30, 2016, from $42.28 per Boe for the same period in 2015. Additionally, our average daily sales volumes decreased by 320 barrels of oil equivalent per day (“Boepd”) for the three months ended September 30, 2016, as compared to the same period in 2015.

Production. Production expenses for the three months ended September 30, 2016 of $3.1 million remained flat from the same period in 2015.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended September 30, 2016 decreased $2.2 million to $1.5 million, from $3.8 million for the same period in 2015. During the three months ended September 30, 2016, we recorded $0.7 million of exploratory well costs related to the Guney Residere well.

General and Administrative. General and admi nistrative expense was $2.7 million for the three months ended September 30, 2016, compared to $4.8 million for the same period in 2015. Our general and administrative expenses decreased $2.2 million due to a $1.6 million decrease in personnel expenses, a $0.3 million decrease in legal, accounting and other services and a decrease in office and travel expenses of $0.3 million.

Depletion. Depletion decreased to $6.9 million, or $15.70 per Boe, for the three months ended September 30, 2016, compared to $7.5 million, or $15.90 per Boe, for the same period of 2015. The decrease was primarily due to a decrease in our production during the three months ended September 30, 2016, compared to the same period in 2015.

Interest and Other Expense. Interest and other expense increased to $3.8 million for the three months ended September 30, 2016, compared to $3.2 million for the same period in 2015. The increase was primarily due to the write-off of $0.5 million of deferred financing costs associated with our former Senior Credit Facility, which we repaid during the quarter.

Interest and Other Income. Interest and other income increased to $1.0 million for the three months ended September 30, 2016, as compared to $0.3 million for the same period in 2015. This was primarily due to the sale of our Edirne gas gathering system and facilities, resulting in a gain of $0.7 million.

Foreign Exchange Loss. We recorded a foreign exchange loss of $0.4 million during the three months ended September 30, 2016, as compared to a loss of $1.2 million in the same period in 2015. The foreign exchange loss is primarily unrealized (non-cash) in nature and results from re-measuring 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 Turkish Lira (“TRY”) amount if it has not been settled previously. The foreign exchange loss for the three months ended September 30, 2016 was due to a 3.5% decrease in the value of the TRY compared to the U.S. Dollar, versus an 11.0% decrease in the value of the TRY for the three months ended September 30, 2015.

(Loss) Gain on Commodity Derivative Contracts. During the three months ended September 30, 2016, we recorded a net loss on commodity derivative contracts of $0.2 million, as compared to a net gain of $24.9 million for the same period in 2015. During the three months ended September 30, 2016, we recorded a $2.9 million loss to mark our commodity derivative contracts to their fair value and a $2.7 million gain on settled contracts. During the same period in 2015, we recorded a $4.6 million gain to mark our derivative contracts to their fair value and a $20.3 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, 2016 decreased to a loss of $4.0 million from a loss of $21.7 million for the same period in 2015. The decrease in foreign currency translation loss in the three months ended September 30, 2016 was due to a 3.5% decrease in the value of the TRY as compared to the U.S. Dollar, versus an 11.0% decrease in the value of the TRY for the three months ended September 30, 2015.

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

	Albania			Morocco			Total
	(in thousands)
For the three months ended September, 2016
Total revenues	$	-		$	-		$	-
Production and transportation expense		-			-			-
Total other costs and expenses		17			(6,903	)		(6,886	)
(Loss) income before income taxes	$	(17	)	$	6,903		$	6,886
Gain on disposal of discontinued operations		9,419			-			9,419
Income tax benefit		-			-			-
Income from discontinued operations	$	9,402		$	6,903		$	16,305

For the three months ended September, 2015
Total revenues	$	1,878		$	-		$	1,878
Production and transportation expense		2,612			-			2,612
Total other costs and expenses		15,963			-			15,963
Total other income		(215	)		-			(215	)
Loss before income taxes	$	(16,912	)	$	-		$	(16,912	)
Income tax benefit		6,181			-			6,181
Loss from discontinued operations	$	(10,731	)	$	-		$	(10,731	)

R esults of Continuing Operations—Nine Months Ended September 30, 2016 Compared to Nine Months Ended September 30, 2015

Our results of continuing operations for the nine months ended September 30, 2016 and 2015 were as follows:

	Nine Months Ended September 30,						Change
	2016			2015			2016-2015
	(in thousands of U.S. Dollars, except per unit amounts and volumes)
Sales volumes:
Oil (Mbbl)		1,024			1,049			(25	)
Natural gas (Mmcf)		1,152			1,949			(797	)
Total production (Mboe)		1,216			1,374			(158	)
Average daily sales volumes (Boepd)		4,437			5,031			(594	)
Average prices:
Oil (per Bbl)	$	37.20		$	49.79		$	(12.59	)
Natural gas (per Mcf)	$	7.02		$	7.83		$	(0.81	)
Oil equivalent (per Boe)	$	37.98		$	49.12		$	(11.14	)
Revenues:
Oil and natural gas sales	$	46,171		$	67,464		$	(21,293	)
Sales of purchased natural gas		3,717			1,544			2,173
Other		35			139			(104	)
Total revenues		49,923			69,147			(19,224	)
Costs and expenses (income):
Production		9,025			10,059			(1,034	)
Exploration, abandonment and impairment		2,964			8,202			(5,238	)
Cost of purchased natural gas		3,264			1,403			1,861
General and administrative		11,401			18,664			(7,263	)
Depletion		21,745			26,227			(4,482	)
Depreciation and amortization		1,308			1,956			(648	)
Interest and other expense		9,106			9,610			(504	)
Interest and other income		(1,411	)		(683	)		(728	)
Foreign exchange loss		659			6,867			(6,208	)
(Loss) gain on commodity derivative contracts:
Cash settlements on commodity derivative contracts		4,188			27,560			(23,372	)
Change in fair value on commodity derivative contracts		(6,607	)		(2,130	)		(4,477	)
Total (loss) gain on commodity derivative contracts		(2,419	)		25,430			(27,849	)
Oil and natural gas costs per Boe:
Production	$	6.50		$	6.41		$	0.09
Depletion	$	16.65		$	16.71		$	(0.06	)

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $21.3 million to $46.2 million for the nine months ended September 30, 2016, from $67.5 million realized in the same period in 2015. The decrease was primarily due to a decrease in the average realized price per Boe and reduced production. Our average price received decreased $11.14 per Boe to $37.98 per Boe for the nine months ended September 30, 2016, from $49.12 per Boe for the same period in 2015. Additionally, our average daily sales volumes decreased 594 Boepd for the nine months ended September 30, 2016, as compared to the same period in 2015.

Production. Production expenses for the nine months ended September 30, 2016 decreased to $9.0 million, or $6.50 per Boe, from $10.1 million, or $6.41 per Boe, for the same period in 2015. The decrease in Turkey was primarily due to fewer workovers, reduced headcount and successful cost-cutting measures in our field operations during the nine months ended September 30, 2016, as compared to the same period in 2015.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the nine months ended September 30, 2016 decreased $5.2 million to $3.0 million, from $8.2 million for the same period in 2015. During the nine months ended September 30, 2016, we incurred proved property impairment of $1.4 million and exploratory well costs associated with the Guney Residere well of $0.7 million.

General and Administrative. General and administrative expense was $11.4 million for the nine months ended September 30, 2016, compared to $18.7 million for the same peri od in 2015. Our general and administrative expenses decreased $7.3 million due to a $6.4 million decrease in personnel expenses, a $0.6 million decrease in office expenses and a $0.3 million decrease in travel expenses.

Depletion. Depletion decreased to $21.7 million, or $16.65 per Boe, for the nine months ended September 30, 2016, compared to $26.2 million, or $16.71 per Boe, for the same period of 2015. The decrease was primarily due to a reduction in the net book value of our Goksu field to zero during 2015, which resulted in lower depletion expense during the nine months ended September 30, 2016.

Interest and Other Expense. Interest and other expense decreased to $9.1 million for the nine months ended September 30, 2016, compared to $9.6 million for the same period in 2015. The decrease was primarily due to our lower average debt balances during the nine months ended September 30, 2016 versus the same period in 2015.

Interest and Other Income. Interest and other income increased to $1.4 million for the nine months ended September 30, 2016, as compared to $0.7 million for the same period in 2015. This was primarily due to the sale of our Edirne gas gathering system and facilities, resulting in a gain of $0.7 million.

Foreign Exchange Loss. We recorded a foreign exchange loss of $0.7 million during the nine months ended September 30, 2016, as compared to a loss of $6.9 million in the same period in 2015. The foreign exchange loss is primarily unrealized (non-cash) in nature and results from re-measuring 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, 2016 was due to a 3.0% decrease in the value of the TRY compared to the U.S. Dollar, versus a 31.2% decrease in the value of the TRY for the nine months ended September 30, 2015.

(Loss) Gain on Commodity Derivative Contracts. During the nine months ended September 30, 2016, we recorded a net loss on commodity derivative contracts of $2.4 million, as compared to a net gain of $25.4 million for the same period in 2015. During the nine months ended September 30, 2016, we recorded a $6.6 million loss to mark our commodity derivative contracts to their fair value and a $4.2 million gain on settled contracts. During the same period in 2015, we recorded a $2.1 million loss to mark our derivative contracts to their fair value and a $27.6 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, 2016 decreased to a loss of $3.3 million from a loss of $50.3 million for the same period in 2015. The change in foreign currency translation adjustments in the nine months ended September 30, 2016 was due to a 3.0% decrease in the value of the TRY as compared to the U.S. Dollar, versus a 31.2% decrease in the value of the TRY for the nine months ended September 30, 2015.

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

	Albania			Morocco			Total
	(in thousands)
For the nine months ended September, 2016
Total revenues	$	626		$	-		$	626
Production and transportation expense		1,155			-			1,155
Total other costs and expenses		544			(6,903	)		(6,359	)
(Loss) income before income taxes	$	(1,073	)	$	6,903		$	5,830
Gain on disposal of discontinued operations		10,168			-			10,168
Income tax benefit		204			-			204
Income from discontinued operations	$	9,299		$	6,903		$	16,202

For the nine months ended September, 2015
Total revenues	$	6,554		$	-		$	6,554
Production and transportation expense		8,759			-			8,759
Total other costs and expenses		20,794			-			20,794
Total other income		2,372			-			2,372
Loss before income taxes	$	(20,627	)	$	-		$	(20,627	)
Income tax benefit		6,864			-			6,864
Loss from discontinued operations	$	(13,763	)	$	-		$	(13,763	)

Capital Expenditures

For the three months ended September 30, 2016, we incurred $1.5 million in capital expenditures, including seismic and corporate expenditures, as compared to $7.7 million for the quarter ended September 30, 2015. The decrease was due to our planned reduction in capital expenditures during the three months ended September 30, 2016.

For the nine months ended September 30, 2016, we incurred $4.7 million in capital expenditures, including seismic and corporate expenditures, as compared to $18.6 million for the nine months ended September 30, 2015. The decrease was due to our planned reduction in capital expenditures during the nine months ended September 30, 2016.

We expect our net field capital expenditures for the remainder of 2016 to range between $2.5 million and $4.5 million in Turkey for new wells and low cost, high return well optimizations. We do not anticipate material capital expenditures in Bulgaria during the remainder of 2016. We expect cash on hand and cash flow from operations will be sufficient to fund our remaining 2016 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2016 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, 2016 was $19.6 million, a decrease from net cash provided by operating activities from continuing operations of $52.9 million during the same period in 2015, due primarily to a decrease in our oil and natural gas sales and a decrease in cash settlements on our commodity derivative contracts. Net cash provided by investing activities from continuing operations for the nine months ended September 30, 2016 increased to $2.7 million, compared to net cash used in investing activities from continuing operations of $23.6 million for the same period in 2015, due primarily to a decrease in drilling operations in light of the low oil price environment. Additionally, net cash used in financing activities from continuing operations for the nine months ended September 30, 2016 was $7.8 million, a decrease from net cash used in financing activities from continuing operations of $13.9 million for the same period in 2015, due primarily to a decrease in our net borrowings and higher loan repayments in 2016.

Liquidity and Capital Resources

On a consolidated basis, as of September 30, 2016, we had $87.4 million of indebtedness, not including $14.5 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 twelve months.

Outstanding Debt

At September 30, 2016, we had the Term Loan, the Note and 2017 Notes outstanding, all of which are discussed below.

Term Loan. On August 31, 2016, DenizBank entered into the $30.0 million Term Loan with TEMI. In addition, the Company 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 in full the Senior Credit Facility.

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 and is payable in six monthly installments of $1.25 million each through February 2017 and thereafter in twelve monthly installments of $1.88 million each through February 2018. The Term Loan matures in February 2018. Amounts repaid under the Term Loan may not be re-borrowed, and early repayments under the Term Loan are subject to early repayment fees.

The Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate owned by Gundem Turizm Yatirim ve Isletmeleri A.S. (“Gundem”) and (v) the Diyarbakir real estate owned 80% by N. Malone Mitchell 3 ^rd and 20% by Selami Erdem Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to the Lender as additional security for the Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.

At September 30, 2016, we had $28.8 million outstanding under the Term Loan and no availability, and we were in compliance with the covenants in the Term Loan.

2017 Notes. At September 30, 2016, we had $ 55.0 million aggregate principal amount of 2017 Notes. The 2017 Notes bear interest at an annual rate of 13.0% per annum. Interest is payable semi-annually, in arrears, on January 1 and July 1 of each year. The 2017 Notes mature on July 1, 2017. The 2017 Notes are convertible at any time, at the election of a holder, into our common shares at a conversion price of $6.80 per share.

On November 4, 2016, we exchanged $40.8 million of 2017 Notes for 815,000 of our Series A Preferred Shares. After the consummation of the Exchange Offer, we had $14.3 million aggregate principal amount of 2017 Notes outstanding. In addition, we expect to redeem $4.3 million of 2017 Notes with the proceeds of our offering of Series A Preferred Shares.

ANBE Note . On December 30, 2015, TransAtlantic USA entered into the Note with ANBE Holdings, L.P. (“ANBE”), an entity owned by the adult children of Mr. Mitchell and controlled by an entity managed by Mr. Mitchell and his wife. The Note bears interest at a rate of 13.0% per annum. On December 30, 2015, the Company borrowed $3.6 million under the Note (the “Initial Advance”) for general corporate purposes. As of September 30, 2016, we had borrowed $3.6 million under the Note and had no availability.

Advances under the Note may be converted, at the election of ANBE, into common shares any time prior to the maturity of the Note. The conversion price per common share for each advance is equal to 105% of the closing price of the Company’s common shares on the NYSE MKT on the trading date immediately prior to such advance. The conversion price of the Initial Advance is $1.3755 per share.

On October 31, 2016, TransAtlantic USA entered into the ANBE Amendment. The ANBE Amendment extends the maturity date of the Note from October 31, 2016 to September 30, 2017, provides for the Note to be repaid in four quarterly installments of $0.9 million each in December 2016 and March, June and September 2017 and provides for monthly payments of interest. In addition, pursuant to the ANBE Amendment, if the sale of TBNG is completed prior to the extended maturity date of the Note, then the Company will repay the Note in full with proceed s from the sale of TBNG within five business days from the closing of the sale.

Contractual Obligations

The following table presents a summary of our contractual obligations at September 30, 2016 and have been adjusted to reflect our subsequent events described in “Note 14. Subsequent Events”.

	Payments Due By Year
	Total		2016		2017		2018		2019		2020		Thereafter
Debt	$	46,592	$	4,648	$	38,194	$	3,750	$	-	$	-	$	-
Series A Preferred Shares		46,050		-		-		-		-		-		46,050	(1)
Series A Preferred Shares dividends ₍₂₎		44,208		860		5,526		5,526		5,526		5,526		21,244
Interest		4,068		709		3,271		88		-		-		-
Leases		1,056		92		518		446		-		-		-
Total	$	141,974	$	6,309	$	47,509	$	9,810	$	5,526	$	5,526	$	67,294

(1)

Represents the redemption amount of the Series A Preferred Shares payable on November 4, 2024 and assumes no conversion of the Series A Preferred Shares into Common Shares or redemption of the Series A Preferred Shares, in each case, prior to November 4, 2024.

(2)

Dividends on the Series A Preferred Shares may be paid by the Company, in its sole discretion, in cash at a rate of 12% per annum or in common shares at a rate of 16% per annum or in a combination of cash and common shares. The amounts in the table assume that the Company pays all future dividend payments solely in cash.

Ite m 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. 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 2016, other than the unwind of our hedges with BNP upon repayment of the Senior Credit Facility, 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, 2015. The following tables set forth our derivatives contracts which were entered into with DenizBank on October 6, 2016, and are settled based on Brent crude oil pricing:

		Collars
				Weighted		Weighted
				Average		Average
		Quantity		Minimum		Maximum
Type	Period	(Bbl/day)		Price (per Bbl)		Price (per Bbl)
Collar	December 1, 2016 — December 31, 2016		290	$	47.50	$	61.00
Collar	January 1, 2017 — December 31, 2017		296	$	47.50	$	61.00
Collar	January 1, 2018 — May 31, 2018		298	$	47.50	$	61.00

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 chief financial officer, as appropriate to allow timely decisions regarding required disclosure.

As of Septembe r 30, 2016, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief 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 chief financial officer concluded that, as of September 30, 2016, 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, 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1.

Legal Proceedings

During the third quarter of 2016, 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, 2015.

Item 1A.

Risk Factors

During the third quarter of 2016, there were no material changes to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3.

Defaults Upon Senior Securities

None.

Item 4.

Mine Safety Disclosures

Not applicable.

Item 5.

Other Information

RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges for the nine months ended September 30, 2016. You should read this ratio in connection with our consolidated financial statements and the related notes included in this Quarterly Report on Form 10-Q. Because we did not have preferred stock outstanding during this period, our ratio of earnings to combined fixed charges and preferred dividends for any given period is equivalent to our ratio of earnings to fixed charges.

	Nine
	Months
	Ended
	September 30,
	2016
Ratio of earnings to fixed charges	$	-
Deficiency of earnings to fixed charges (in thousands)		20,033

For purposes of calculating the ratio of earnings to fixed charges, “earnings” represents income (loss) from continuing operations before income taxes plus fixed charges. “Fixed charges” includes interest expense, capitalized interest, amortization of discount and capitalized expenses related to indebtedness and the portion of rental expense that management believes is representative of the interest component of rental expense. The ratio of earnings to fixed charges presented in this Form 10-Q may not be comparable to similarly titled measures presented by other companies, and may not be comparable to corresponding measures used in our various agreements, including the Senior Credit Facility.

PRICE RANGE OF OUR COMMON SHARES

Canada

Our common shares are traded in Canada on the Toronto Stock Exchange (the “TSX”) under the trading symbol “TNP”. The following table sets forth the quarterly high and low sales prices per common share in Canadian dollars on the TSX for the period indicated.

	High		Low
2016:	$	1.96	$	0.93
Third Quarter

United States

Our common shares are traded in the United States on the NYSE MKT under the trading symbol “TAT”. The following table sets forth the high and low sales price per common share in U.S. Dollars on the NYSE MKT for the period indicated.

	High		Low
2016:	$	1.52	$	0.71
Third Quarter

Item 6.

E xhibits

2.1		Share Purchase Agreement, dated February 29, 2016, among TransAtlantic Holdings B.C. Ltd. and Continental Oil & Gas (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K dated February 29, 2016, filed with the SEC on March 4, 2016).

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).

10.1*		Form of General Credit Agreement between DenizBank A.S. and each of TransAtlantic Exploration Mediterranean International Pty Ltd, TransAtlantic Turkey, Ltd., DMLP, Ltd. and Talon Exploration, Ltd, dated August 23, 2016.

10.2*		Current Account Loan Agreement between TransAtlantic Exploration Mediterranean International Pty Ltd and DenizBank A.S., dated August 31, 2016.

10.3		Amendment of Convertible Promissory Note, dated October 31, 2016, by and between ANBE Holdings, L.P. and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated October 31, 2016, filed with the SEC on November 4, 2016).

12.1*		Ratio of Earnings to Fixed Charges

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.

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/ Christopher R. Elmore
		Christopher R. Elmore Principal Accounting and Financial Officer

Date: November 9, 2016

INDEX TO EXHIBITS

2.1		Share Purchase Agreement, dated February 29, 2016, among TransAtlantic Holdings B.C. Ltd. and Continental Oil & Gas (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K dated February 29, 2016, filed with the SEC on March 4, 2016).

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).

10.1*		Form of General Credit Agreement between DenizBank A.S. and each of TransAtlantic Exploration Mediterranean International Pty Ltd, TransAtlantic Turkey, Ltd., DMLP, Ltd. and Talon Exploration, Ltd, dated August 23, 2016.

10.2*		Current Account Loan Agreement between TransAtlantic Exploration Mediterranean International Pty Ltd and DenizBank A.S., dated August 31, 2016.

10.3		Amendment of Convertible Promissory Note, dated October 31, 2016, by and between ANBE Holdings, L.P. and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated October 31, 2016, filed with the SEC on November 4, 2016).

12.1*		Ratio of Earnings to Fixed Charges

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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