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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

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

For the quarterly period ended: March 31, 2012

OR

 

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

For the transition period from                 to                

Commission file number: 001-34574

 

 

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

 

 

 

Bermuda		None
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
Akmerkez B Blok Kat 6 Nispetiye Caddesi 34330 Etiler, Istanbul, Turkey		None
(Address of principal executive offices)		(Zip Code)

Registrant’s Telephone Number, Including Area Code: +90 212 317 25 00

 

 

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  x    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  x    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		x
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  x

As of May 8, 2012, the registrant had 366,534,449 common shares outstanding.

 

 

 

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TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION
Item 1.		Financial Statements
				Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011			1
				Consolidated Statements of Operations and Comprehensive Income (Loss) for the Three Months Ended March 31, 2012 and 2011			2
				Consolidated Statements of Shareholders’ Equity for the Three Months Ended March 31, 2012			3
				Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011			4
				Notes to Consolidated Financial Statements			5
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations					17
Item 3.		Quantitative and Qualitative Disclosures About Market Risk					29
Item 4.		Controls and Procedures					29
PART II. OTHER INFORMATION
Item 1.		Legal Proceedings					31
Item 1A.		Risk Factors					31
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds					32
Item 3.		Defaults Upon Senior Securities					32
Item 4.		Mine Safety Disclosures					32
Item 5.		Other Information					32
Item 6.		Exhibits					33

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PART I. FINANCIAL INFORMATION

 

Item 1.

Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

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

 

		March 31, 2012				December 31, 2011
		(unaudited)
ASSETS
Current assets:
Cash and cash equivalents		$	15,087			$	15,116
Accounts receivable
Oil and natural gas sales, net			37,507				35,702
Other			6,233				6,992
Prepaid and other current assets			10,750				8,810
Deferred income taxes			3,179				2,124
Assets held for sale			134,972				128,117
Total current assets			207,728				196,861
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved			194,736				174,577
Unproved			77,370				70,180
Equipment and other property			45,484				40,403
			317,590				285,160
Less accumulated depreciation, depletion and amortization			(62,434	)			(49,436	)
Property and equipment, net			255,156				235,724
Other long-term assets:
Other assets			3,886				4,673
Goodwill			9,071				8,514
Total other assets			12,957				13,187
Total assets		$	475,841			$	445,772
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	23,985			$	25,733
Accounts payable — related party			—				323
Accrued liabilities			18,560				16,450
Loans payable			4,542				7,732
Loan payable — related party			84,000				73,000
Derivative liabilities			8,256				3,716
Asset retirement obligations			3,605				3,031
Liabilities held for sale — related party			1,863				3,677
Liabilities held for sale			24,076				23,037
Total current liabilities			168,887				156,699
Long-term liabilities:
Asset retirement obligations			11,111				10,503
Accrued liabilities			5,631				5,503
Deferred income taxes			15,562				15,508
Loan payable			78,000				78,000
Derivative liabilities			9,775				3,355
Total long-term liabilities			120,079				112,869
Total liabilities			288,966				269,568
Commitments and contingencies
Shareholders’ equity:
Common shares, $0.01 par value, 1,000,000,000 shares authorized; issued and outstanding 366,534,449 as of March 31, 2012 and 365,790,492 as of December 31, 2011			3,665				3,658
Additional paid-in capital			535,203				534,117
Accumulated other comprehensive loss			(36,241	)			(50,615	)
Accumulated deficit			(315,752	)			(310,956	)
Total shareholders’ equity			186,875				176,204
Total liabilities and shareholders’ equity		$	475,841			$	445,772

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

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Operations and Comprehensive Income (Loss)

(Unaudited)

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

 

		For the Three Months Ended March 31,
		2012				2011
Revenues:
Oil and natural gas sales		$	34,661			$	28,676
Other			274				403
Total revenues			34,935				29,079
Costs and expenses:
Production			3,635				4,102
Exploration, abandonment and impairment			2,796				7,232
Seismic and other exploration			664				2,252
General and administrative			9,748				9,085
Depreciation, depletion and amortization			9,169				4,630
Accretion of asset retirement obligations			252				214
Total costs and expenses			26,264				27,515
Operating income			8,671				1,564
Other (expense) income:
Interest and other expense			(3,259	)			(3,597	)
Interest and other income			273				157
Loss on commodity derivative contracts			(12,435	)			(9,311	)
Foreign exchange gain			4,272				4
Total other (expense) income			(11,149	)			(12,747	)
Loss from continuing operations before income taxes			(2,478	)			(11,183	)
Current income tax expense			(2,020	)			(2,538	)
Deferred income tax benefit			1,859				1,874
Loss from continuing operations			(2,639	)			(11,847	)
Loss from discontinued operations, net of taxes			(2,157	)			(9,308	)
Net loss		$	(4,796	)		$	(21,155	)
Other comprehensive income:
Foreign currency translation adjustment			14,374				2,299
Comprehensive income (loss)		$	9,578			$	(18,856	)
Net loss per common share:
Basic and diluted net loss attributable to common shareholders, per common share
From continuing operations		$	(0.01	)		$	(0.03	)
From discontinued operations		$	(0.01	)		$	(0.03	)
Basic and diluted weighted average number of shares outstanding			366,436				341,142

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

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Equity

(Unaudited)

(U.S. dollars and shares in thousands)

 

		Common Shares				Common Shares ($)				Additional Paid-in Capital				Accumulated Other Comprehensive Loss				Accumulated Deficit				Total Shareholders’ Equity
Balance at December 31, 2011			365,790			$	3,658			$	534,117			$	(50,615	)		$	(310,956	)		$	176,204
Exercise of stock options			600				6				594				—				—				600
Issuance of restricted stock units			144				1				(1	)			—				—				—
Share-based compensation			—				—				493				—				—				493
Foreign currency translation adjustments			—				—				—				14,374				—				14,374
Net loss attributable to common shareholders			—				—				—				—				(4,796	)			(4,796	)
Balance at March 31, 2012			366,534			$	3,665			$	535,203			$	(36,241	)		$	(315,752	)		$	186,875

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

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

(Unaudited)

(in thousands of U.S. dollars)

 

		For the Three Months Ended March 31,
		2012				2011
Operating activities:
Net loss		$	(4,796	)		$	(21,155	)
Adjustment for net loss from discontinued operations			2,157				9,308
Net loss from continuing operations			(2,639	)			(11,847	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-based compensation			493				557
Foreign currency gain			(6,653	)			(1,425	)
Unrealized loss on commodity derivative contracts			10,960				8,607
Amortization of loan financing costs			225				730
Deferred income tax benefit			(1,859	)			(1,874	)
Amortization of warrants — related party			—				1,224
Exploration, abandonment and impairment			1,493				6,437
Depreciation, depletion and amortization			9,169				4,630
Accretion of asset retirement obligations			252				214
Changes in operating assets and liabilities, net of effect of acquisitions:
Accounts receivable			(1,658	)			(2,945	)
Prepaid expenses and other assets			1,290				2,842
Accounts payable and accrued liabilities			223				(3,466	)
Net cash provided by operating activities from continuing operations			11,296				3,684
Net cash (used in) provided by operating activities from discontinued operations			(4,322	)			527
Net cash provided by operating activities			6,974				4,211
Investing activities:
Acquisitions, net of cash			—				(2,088	)
Additions to oil and natural gas properties			(13,355	)			(14,485	)
Additions to equipment and other properties			(824	)			(1,457	)
Restricted cash			1,062				—
Net cash used in investing activities from continuing operations			(13,117	)			(18,030	)
Net cash used in investing activities from discontinued operations			(1,208	)			(8,056	)
Net cash used in investing activities			(14,325	)			(26,086	)
Financing activities:
Exercise of stock options and warrants			600				173
Loan proceeds			4,284				8,110
Loan proceeds — related party			11,000				—
Loan repayment			(7,497	)			(2	)
Loan financing costs			(250	)			—
Net cash provided by financing activities from continuing operations			8,137				8,281
Net cash used in financing activities from discontinued operations			(1,519	)			(1,044	)
Net cash provided by financing activities			6,618				7,237
Effect of exchange rate changes on cash			704				162
Net decrease in cash and cash equivalents			(29	)			(14,476	)
Cash and cash equivalents, beginning of year			15,116				34,676
Cash and cash equivalents, end of period		$	15,087			$	20,200
Supplemental disclosures:
Cash paid for interest		$	2,747			$	1,272
Cash paid for income taxes		$	2,007			$	881

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

 

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TRANSATLANTIC PETROLEUM LTD.

Notes to Consolidated Financial Statements

 

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 are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey, Bulgaria and Romania. As of March 31, 2012, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell, 3rd, the chairman of our board of directors and chief executive officer.

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 U.S. (“U.S. GAAP”). All amounts in these notes to the consolidated financial statements are in U.S. Dollars unless otherwise indicated. We have prepared the accompanying unaudited interim financial statements pursuant to the rules and regulations of the Securities and Exchange Commission, or the SEC, and in the opinion of management, such financial statements reflect all adjustments necessary to present fairly the consolidated financial position of TransAtlantic at March 31, 2012 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP pursuant to those rules and regulations, although we believe that the disclosures we have made are adequate to make the information presented not misleading. These unaudited interim financial statements should be read in conjunction with our audited consolidated financial statements and related footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2011. Certain prior year amounts have been reclassified to conform to current year presentation.

In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the financial statements and disclosures. The results of operations for the interim periods are not necessarily indicative of the results we expect for the full year.

 

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 incurred a net loss of $4.8 million for the three months ended March 31, 2012, which includes a net loss from discontinued operations of $2.2 million. At March 31, 2012, the outstanding principal amount of our debt was $170.2 million, of which $3.7 million was classified as held for sale. Excluding assets held for sale of $135.0 million and total liabilities held for sale of $25.9 million, we had a working capital deficit from continuing operations of $70.2 million. Of our outstanding debt, $73.0 million under our credit agreement (the “Dalea Credit Agreement”) with Dalea Partners, LP (“Dalea”) is due upon the earlier of (i) June 30, 2012 or (ii) the later of (x) two business days after demand by Dalea or (y) the closing of the sale of our oilfield services business, which is substantially comprised of our wholly owned subsidiaries Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”). Dalea is 100% owned by Mr. Mitchell and his wife. On March 15, 2012, we entered into a stock purchase agreement to sell Viking International and Viking Geophysical. We also entered into a $15.0 million credit facility with Dalea (the “Dalea Credit Facility”), of which $11.0 million was outstanding at March 31, 2012, to provide us with additional liquidity for general corporate purposes. Should we be unable to consummate the sale, raise additional financing or extend the maturity date of the Dalea Credit Agreement, we will not have sufficient funds to continue operations beyond June 30, 2012. As a result of the recurring losses from operations and a working capital deficiency, there is substantial doubt regarding our ability to continue as a going concern. The continuing application of the going concern assumption is dependent upon our continuing ability to obtain the necessary financing to discharge our existing obligations, fund ongoing exploration, development and operations and ultimately achieve profitable operations.

Management believes the going concern assumption to be appropriate for these 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 policies

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-

 

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04”). ASU 2011-04 amends Accounting Standards Codification (“ASC”) 820 Fair Value Measurements and Disclosures (“ASC 820”), providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurement and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. We adopted ASU 2011-04 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In June 2011, FASB issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. In December 2011, FASB issued ASU 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU 2011-05 (“ASU 2011-12”). ASU 2011-12 deferred the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. The amendments will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted ASU 2011-05 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In September 2011, FASB issued ASU 2011-08, Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”). ASU 2011-08 allows both public and nonpublic entities an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity would no longer be required to calculate the fair value of a reporting unit unless the entity determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. ASU 2011-08 allows early adoption and will be effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted ASU 2011-08 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In December 2011, FASB issued ASU No. 2011-11, Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of ASU 2011-11 is required for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We are currently evaluating the effects of adopting ASU 2011-11.

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.	Pro forma results of operations

The following table presents the unaudited pro forma results of operations as though the acquisitions of Direct Petroleum Morocco, Inc. (“Direct Morocco”), Anschutz Morocco Corporation (“Anschutz”), Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”) and Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) had occurred as of January 1, 2011 (see our Annual Report on Form 10-K for the year ended December 31, 2011 for a discussion of these acquisitions):

 

		For the Three Months Ended March 31, 2011
		(in thousands, except per share data)
Total revenues		$	36,415
Loss from continuing operations before income taxes			(9,249	)
Loss from continuing operations			(10,300	)
Loss from discontinued operations			(9,926	)
Net loss			(20,226	)
Net loss per common share from continuing operations
Basic		$	(0.03	)
Diluted		$	(0.03	)
Net loss per common share from discontinued operations
Basic		$	(0.03	)
Diluted		$	(0.03	)

 

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5.	Discontinued operations

Discontinued operations in Morocco

On June 27, 2011, we decided to discontinue our operations in Morocco. We have transferred our oilfield services equipment from Morocco to Turkey and are in the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for all periods presented.

Discontinued operations of oilfield services business

On September 30, 2011, we engaged a financial advisor to assist with the sale, transfer or other disposition of our oilfield services business. On March 15, 2012, we entered into a stock purchase agreement with Dalea to sell Viking International and Viking Geophysical for an aggregate purchase price of $164.0 million, subject to adjustments in certain circumstances. The sale of Viking International and Viking Geophysical is subject to the approval of regulatory authorities, the receipt of equity financing by Dalea and other customary closing conditions. We have presented the oilfield services segment operating results as discontinued operations for all periods presented.

The assets and liabilities held for sale of the Moroccan and oilfield services segments at March 31, 2012 were as follows (in thousands):

 

		Morocco				Oilfield Services				Total Held for Sale
Cash		$	196			$	2,335			$	2,531
Receivables, net			—				7,575				7,575
Property and equipment, net			1,029				116,200				117,229
Other assets			1,526				6,111				7,637
Total assets held for sale		$	2,751			$	132,221			$	134,972
Accrued expenses and other liabilities		$	5,569			$	18,507			$	24,076
Liabilities held for sale related party			—				1,863				1,863
Total liabilities held for sale		$	5,569			$	20,370			$	25,939

The assets and liabilities held for sale of the Moroccan and oilfield services segments at December 31, 2011 are as follows (in thousands):

 

		Morocco				Oilfield Services				Total Held for Sale
Cash		$	95			$	1,090			$	1,185
Receivables, net			—				8,098				8,098
Property and equipment, net			1,026				113,497				114,523
Other assets			1,652				2,659				4,311
Total assets held for sale		$	2,773			$	125,344			$	128,117
Accrued expenses and other liabilities		$	6,154			$	16,883			$	23,037
Liabilities held for sale related party			—				3,677				3,677
Total liabilities held for sale		$	6,154			$	20,560			$	26,714

Operating results of discontinued operations are summarized as follows for the three months ended (in thousands):

 

		Morocco				Oilfield Services				Total				Morocco				Oilfield Services				Total
		March 31, 2012												March 31, 2011
Total revenues		$	—			$	10,284			$	10,284			$	48			$	3,117			$	3,165
Total costs and expenses			470				9,056				9,526				4,347				7,198				11,545
Total other (expense) income			2				(937	)			(935	)			(73	)			(631	)			(704	)
Income (loss) before income taxes		$	(468	)		$	291			$	(177	)		$	(4,372	)		$	(4,712	)		$	(9,084	)
Income tax			—				(1,980	)			(1,980	)			—				(224	)			(224	)
Loss from discontinued operations		$	(468	)		$	(1,689	)		$	(2,157	)		$	(4,372	)		$	(4,936	)		$	(9,308	)

 

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6.

Goodwill

Goodwill represents the excess of the purchase price of a business over the estimated fair value of the assets acquired and liabilities assumed. We have goodwill on acquisitions where we anticipated access to potential exploration and production opportunities. All of our goodwill is attributable to our Turkey operating segment. Goodwill was as follows at March 31, 2012 and December 31, 2011:

 

		March 31, 2012				December 31, 2011
		(in thousands)
Goodwill at beginning of period,		$	8,514			$	10,341
Foreign exchange change effect			557				(1,827	)
Goodwill at end of period		$	9,071			$	8,514

 

7.	Property and equipment

 

(a)

Oil and natural gas properties. The following table sets forth the capitalized costs under the successful efforts method for oil and gas properties:

 

		March 31, 2012				December 31, 2011
		(in thousands)
Oil and natural gas properties, proved:
Turkey		$	192,332			$	172,886
Bulgaria			2,404				1,691
Total oil and natural gas properties, proved			194,736				174,577
Oil and natural gas properties, unproved:
Turkey			77,370				70,180
Total oil and natural gas properties, unproved			77,370				70,180
Gross oil and natural gas properties			272,106				244,757
Accumulated depletion			(55,406	)			(45,327	)
Net oil and natural gas properties		$	216,700			$	199,430

At March 31, 2012 and December 31, 2011, we excluded $10.4 million and $7.1 million, respectively, from the depletion calculation for proved development wells currently in progress and for fields currently not in production.

At March 31, 2012, our oil and gas properties were comprised of $58.1 million relating to acquisition costs of proved properties which are being amortized by the unit-of-production method using total proved reserves and $70.8 million relating to exploratory well costs and additional development costs which are being amortized by the unit-of-production method using proved developed reserves.

At December 31, 2011, our oil and gas properties were comprised of $61.8 million relating to acquisition costs of proved properties which are being amortized by the unit-of-production method using total proved reserves and $60.4 million relating to exploratory well costs and additional development costs which are being amortized by the unit-of-production method using proved developed reserves.

During the three months ended March 31, 2012, we incurred approximately $6.1 million in exploratory drilling costs, of which $1.3 million was charged to earnings (included in exploration, abandonment and impairment expense) and $4.8 million remained capitalized at March 31, 2012. No exploratory well costs were reclassified to proved properties in the first quarter of 2012. As of March 31, 2012, we had $7.0 million of exploratory well costs capitalized for the Pancarkoy-1 well, which we began drilling in the fourth quarter of 2010. The following table summarizes the costs related to this well:

 

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										Three Months Ended March 31,
		2010				2011				2012				Total
		(in thousands)
Pancarkoy-1 well initial re-entry and fracture stimulation (Ceylan and Mezardere formations)		$	803			$	4,958			$	1,208			$	6,969
Total capitalized costs		$	803			$	4,958			$	1,208			$	6,969

After the second fracture stimulation, commercial natural gas production could not be sustained due to the high amount of water production when the well was placed on production. A third fracture stimulation was performed in April 2012, but commercial production could not be sustained due to high water production. We have identified at least two more sands within the Mezardere formation that we expect to test initially by conventional means. These sands possess different, more favorable reservoir properties than the previous targets and have strong indicators of natural gas. We expect testing to commence late in the second quarter of 2012, and further fracture stimulation will depend on the outcome of the conventional test results.

Uncertainties affect the recoverability of these costs, as the recovery of the costs are dependent upon us obtaining government approvals, obtaining and maintaining licenses in good standing and achieving commercial production or sale.

 

(b)

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

 

		March 31, 2012				December 31, 2011
		(in thousands)
Other equipment		$	7,204			$	6,351
Inventory			23,335				20,471
Gas gathering system and facilities			7,268				6,822
Vehicles			1,128				1,001
Office equipment and furniture			6,549				5,758
Gross equipment and other property			45,484				40,403
Accumulated depreciation			(7,028	)			(4,109	)
Net equipment and other property		$	38,456			$	36,294

We classify our materials and supply inventory, including steel tubing and casing, as a long-term assets because such materials will ultimately be classified as long-term assets when the material is used in the drilling of a well.

At March 31, 2012, we excluded $0.5 million of other equipment and $23.3 million of inventory from depreciation, as the equipment and inventory had not been placed into service.

At December 31, 2011, we excluded $0.5 million of other equipment, $20.5 million of inventory and $1.8 million of gas gathering system and facilities from depreciation as the equipment and inventory had not been placed into service.

 

8.	Commodity derivative instruments

We use collar derivative contracts to economically hedge against the variability in cash flows associated with the forecasted sale of our future oil production. We have not designated the derivative financial instruments as hedges for accounting purposes and, accordingly, we record the 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 instruments with the same counterparty in our consolidated balance sheets. All of our oil derivative contracts are settled based upon Brent oil pricing. We recognize unrealized and realized gains and losses related to these contracts on a fair value basis in our consolidated statements of operations and comprehensive income (loss) under the caption “Loss on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows.

For the three months ended March 31, 2012, we recorded a net loss on commodity derivative contracts of $12.4 million, consisting of a $11.0 million unrealized loss related to changes in fair value and a $1.4 million realized loss for settled contracts. For the three months ended March 31, 2011, we recorded a net loss on commodity derivative contracts of $9.3 million, consisting of a $8.6 million unrealized loss related to changes in fair value and a $0.7 million realized loss for settled contracts.

 

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At March 31, 2012 and December 31, 2011, we had outstanding contracts with respect to our future crude oil production as set forth in the tables below:

Fair Value of Derivative Instruments as of March 31, 2012

 

Type		Period				Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of  Liability
																		(in thousands)
Collar			April 1, 2012—December 31, 2012				960			$	64.69			$	106.98			$	(4,186	)
Collar			January 1, 2013—December 31, 2013				400			$	75.00			$	125.50				(772	)
Collar			January 1, 2014—December 31, 2014				380			$	75.00			$	124.25				(430	)
																		$	(5,388	)

 

						Collars												Additional Call
Type		Period				Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Liability
																						(in thousands)
Three-way collar contract			April 1, 2012—December 31, 2012				240			$	70.00			$	100.00			$	129.50			$	(1,229	)
Three-way collar contract			April 1, 2012— June 30, 2012				350			$	85.00			$	116.25			$	137.38				(226	)
Three-way collar contract			July 1, 2012—December 31, 2012				205			$	85.00			$	97.13			$	162.13				(841	)
Three-way collar contract			January 1, 2013—December 31, 2013				831			$	85.00			$	97.13			$	162.13				(4,997	)
Three-way collar contract			January 1, 2014—December 31, 2014				726			$	85.00			$	97.13			$	162.13				(2,472	)
Three-way collar contract			January 1, 2015—December 31, 2015				1,016			$	85.00			$	91.88			$	151.88				(2,878	)
																						$	(12,643	)

Fair Value of Derivative Instruments as of December 31, 2011

 

Type		Period				Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Asset (Liability)
																		(in thousands)
Collar			January 1, 2012—December 31, 2012				960			$	64.69			$	106.98			$	(2,529	)
Collar			January 1, 2013—December 31, 2013				400			$	75.00			$	125.50				(116	)
Collar			January 1, 2014—December 31, 2014				380			$	75.00			$	124.25				12
																		$	(2,633	)

 

						Collars												Additional Call
Type		Period				Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Liability
																						(in thousands)
Three-way collar contract			January 1, 2012—December 31, 2012				240			$	70.00			$	100.00			$	129.50			$	(764	)
Three-way collar contract			January 1, 2012— March 31, 2012				350			$	85.00			$	118.88			$	138.13				(7	)
Three-way collar contract			April 1, 2012— June 30, 2012				350			$	85.00			$	116.25			$	137.38				(35	)
Three-way collar contract			July 1, 2012—December 31, 2012				205			$	85.00			$	97.13			$	162.13				(381	)

 

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						Collars												Additional Call
Type		Period				Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Liability
																						(in thousands)
Three-way collar contract			January 1, 2013—December 31, 2013				831			$	85.00			$	97.13			$	162.13				(1,985	)
Three-way collar contract			January 1, 2014—December 31, 2014				726			$	85.00			$	97.13			$	162.13				(626	)
Three-way collar contract			January 1, 2015—December 31, 2015				1,016			$	85.00			$	91.88			$	151.88				(640	)
																						$	(4,438	)

 

9.	Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations for the three months ended March 31, 2012 and for the year ended December 31, 2011:

 

			xxxxxxxx				xxxxxxxx
		Three Months Ended March  31, 2012				Year Ended December 31, 2011
		(in thousands)
Asset retirement obligations at beginning of period		$	13,534			$	6,943
Acquisitions			—				6,480
Change in estimates			(96	)			512
Liabilities settled			—				(195	)
Foreign exchange change effect			873				(2,524	)
Additions			153				1,176
Accretion expense			252				1,142
Asset retirement obligations at end of period			14,716				13,534
Less: current portion			3,605				3,031
Long-term portion		$	11,111			$	10,503

 

10.	Third party loans payable

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

 

			xxxxxxxx				xxxxxxxx
		March 31,          2012				December 31, 2011
		(in thousands)
Third-Party Floating Rate Debt
Amended and Restated Credit Facility		$	78,000			$	78,000
Third-Party Fixed Rate Debt
TBNG credit agreement			4,542				7,732
Viking International equipment loan			—				—	(1)
Total third-party debt			82,542				85,732
Less: short-term third-party debt			4,542				7,732
Long-term third-party debt		$	78,000			$	78,000
(1)    $2.0 million and $2.1 million outstanding at March 31, 2012 and December 31, 2011, respectively, was classified as “Liabilities held for sale”.

Amended and Restated Senior Secured Credit Facility

On May 18, 2011, DMLP, Ltd. (“DMLP”), TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Ltd. (“TAT”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayive Ticaret A.Ş. (“Petrogas”) (collectively, and together with Amity Oil International Pty Ltd (“Amity”), the “Borrowers”) entered into the amended and restated senior secured credit facility with Standard Bank Plc and BNP Paribas

 

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(Suisse) SA (the “Amended and Restated Credit Facility”). Each of the Borrowers is our wholly owned subsidiary. In July 2011, Amity executed a joinder agreement and became a borrower under the Amended and Restated Credit Facility. The Amended and Restated Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”).

The borrowing base is re-determined semi-annually on April 1st and October 1st of each year prior to September 30, 2012 and quarterly on January 1st, April 1st, July 1st and October 1st of each year after September 30, 2012. We expect to complete the semi-annual borrowing base redetermination in the second quarter of 2012. Our borrowing base is currently $81.4 million.

At March 31, 2012, the Borrowers had borrowed $78.0 million and were in compliance with all material covenants under the Amended and Restated Credit Facility.

TBNG credit agreement

At March 31, 2012, we had outstanding borrowings of approximately 8.0 million New Turkish Lira (approximately $4.5 million) under an unsecured credit agreement between TBNG and a Turkish bank. Borrowings under the credit agreement bear interest at a rate of 14% per annum, and interest is payable quarterly. The credit agreement matures on September 13, 2012 and may be renewed for an additional period on the same terms.

Viking International equipment loan

As of March 31, 2012, we had an outstanding balance of $2.0 million under a secured credit agreement between Viking International and a Turkish bank. This secured credit agreement is included in “Liabilities held for sale” in our consolidated balance sheets.

 

11.	Related party loans payable

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

 

Related Party Floating Rate Debt		March 31, 2012				December 31, 2011
		(in thousands)
Dalea Credit Agreement		$	73,000			$	73,000
Dalea Credit Facility			11,000				—
			84,000				73,000
Viking Drilling note			—	(1)			—	(1)
Total related party debt			84,000				73,000
Less: short-term related party debt			84,000				73,000
Long-term related party debt		$	—			$	—
(1)    $1.7 million and $2.9 million outstanding at March 31, 2012 and December 31, 2011, respectively, was classified as “Liabilities held for sale – related party”.

Dalea Credit Agreement

On June 28, 2010, we entered into the Dalea Credit Agreement. The purpose of the Dalea Credit Agreement was (i) to fund the acquisition of all of the shares of Amity and Petrogas, and (ii) for general corporate purposes. On May 18, 2011, we entered into a first amendment to the Dalea Credit Agreement to extend the maturity date and increase the interest rate to match the interest rate payable under our Amended and Restated Credit Facility. On November 7, 2011, we entered into a second amendment to the Dalea Credit Agreement to extend the maturity date to the earlier of (i) March 31, 2012 or (ii) the sale of Viking International and Viking Geophysical. On March 15, 2012, we entered into a third amendment to the Dalea Credit Agreement to extend the maturity date until the earlier of (i) June 30, 2012 or (ii) the later of (x) the closing of the sale of our oilfield services business or (y) two business days after demand by Dalea.

As of March 31, 2012, we had borrowed $73.0 million under the Dalea Credit Agreement. No further borrowings are permitted under the Dalea Credit Agreement.

Dalea Credit Facility

On March 15, 2012, TransAtlantic Worldwide, TBNG and the Company (collectively, the “Credit Facility Borrowers”) entered into a $15.0 million credit facility with Dalea to provide us with additional liquidity for general corporate purposes until we

 

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complete the sale of Viking International and Viking Geophysical. Loans under the Dalea Credit Facility accrue interest at a rate of three-month London Interbank Offered Rate (“LIBOR”) plus 5.5% per annum, to be adjusted monthly on the first day of each month. We will be required to pay all accrued interest in arrears on the last day of each month, and we may prepay outstanding amounts at any time before maturity without penalty. Outstanding borrowings must be repaid upon the earlier of (i) July 1, 2012 or (ii) the sale of Viking.

For the initial advance, we were required to pay Dalea an arrangement fee of $250,000. Under the Dalea Credit Facility, we are also required to pay Dalea a commitment fee equal to 2.75% per annum of the difference between the $15.0 million committed amount and the outstanding balance measured and payable on the last day of each fiscal quarter.

Any proceeds received by us or any subsidiary from any debt financings (subject to certain specified exceptions) or from the sale of Viking International and Viking Geophysical, net of reasonable transaction and financing costs, must be used to repay amounts outstanding under the credit facility. In addition, the Dalea Credit Facility is subject to customary covenants, including covenants that limit the ability of the Credit Facility Borrowers to, among other things, (i) make, give, create or permit or attempt to make, give or create any mortgage, charge, lien or encumbrance over any assets of any Credit Facility Borrower or any subsidiary (subject to certain specific exceptions), (ii) change the name of any of the Credit Facility Borrowers or the jurisdictions of organization, (iii) declare or provide for any dividends or other payments or distributions (whether in cash, assets or indebtedness) based on share capital, (iv) redeem or purchase any of their shares, (v) make or permit any sale of or disposition of any substantial or material part of their business, assets or undertaking, or that of any subsidiary, (vi) save and (except for certain specified exceptions) borrow or cause or permit any subsidiary to borrow money from any other person, without first obtaining and delivering a duly signed assignment and postponement of claim by such person in form and terms satisfactory to Dalea, (vii) pay out or permit the payment out of any shareholders loans or other indebtedness to non-arm’s length parties, or (viii) guarantee or permit the guarantee of the obligations of any other person, directly or indirectly, except in the ordinary course of business.

The Dalea Credit Facility is also subject to customary events of default, including payment defaults, defaults in observing or performing any term, covenant or condition of the Dalea Credit Facility or collateral documents, material misrepresentations by a Credit Facility Borrower or any subsidiary, a Credit Facility Borrower or any subsidiary ceases or threatens to cease to carry on business, the prohibition in trading in shares of any of the Credit Facility Borrowers or suspension or delisting from any stock exchange, a material adverse change in the financial condition of any of the Credit Facility Borrowers and any of their subsidiaries taken as a whole, Dalea believes in good faith and on commercially reasonable grounds that the ability of the Credit Facility Borrowers to pay or perform any of the covenants contained in the Dalea Credit Facility is materially impaired, insolvency of any of the Credit Facility Borrowers or any change of control of any of the Credit Facility Borrowers. Control is defined in the Dalea Credit Facility as ownership of or control or direction over, directly or indirectly, 20% or more of the outstanding voting securities of the Credit Facility Borrowers. If an event of default occurs and is continuing, Dalea may demand immediate payment of all monies owing under the Dalea Credit Facility; provided that with respect to certain specified events of default, all monies due under the Dalea Credit Facility shall automatically become due and payable without any demand or any other action by Dalea or any other person.

At March 31, 2012, we had borrowed $11.0 million under the Dalea Credit Facility and had availability of $4.0 million.

Viking Drilling note

As of March 31, 2012, we had an outstanding balance of $1.7 million under a note payable with Viking Drilling, LLC. The note is included in “Liabilities held for sale — related party” in our consolidated balance sheets. Dalea owns 85% of Viking Drilling, LLC.

 

12.	Shareholders’ equity

June 2011 share issuance

On June 7, 2011, we issued 18.5 million common shares at the acquisition date closing price of $2.05 per share in a private placement to an accredited investor in connection with the acquisition of TBNG.

February 2011 share issuance

On February 18, 2011, we issued 8,924,478 common shares at the acquisition date closing price of $3.15 per share in a private placement to an accredited investor in connection with the acquisition of Direct Morocco, Anschutz and Direct Bulgaria.

Restricted stock units

Share-based compensation expense of approximately $0.5 million and $0.6 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three months ended March 31, 2012 and 2011, respectively.

 

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As of March 31, 2012, we had approximately $2.2 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.79 years.

Stock option plan

Our Amended and Restated Stock Option Plan (2006) (the “Option Plan”) terminated on June 16, 2009. All outstanding awards issued under the Option Plan remained in full force and effect. All options presently outstanding under the Option Plan have a five-year term. We did not grant any stock options during the three months ended March 31, 2011. At March 31, 2012, all stock options have been fully amortized.

Earnings per share

Because we reported a net loss for the three months ended March 31, 2012 and March 31, 2011, we excluded the following share based awards from the computation of earnings per share, as their effect would have been anti-dilutive:

 

		For the Three Months Ended
		March 31, 2012				March 31,2011
Unvested RSUs			1,524,080				2,083,817
Stock options			430,055				2,065,111
Warrants			7,318,720				17,365,831

Additionally, we had a contingent liability at March 31, 2012 of approximately $10.0 million that is payable in our common shares. At the March 31, 2012 closing price of our common shares, this liability represents 7,692,308 common shares that could be potentially dilutive to future earnings per share calculations.

 

13.	Segment information

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

 

 

14.	Financial instruments

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount at March 31, 2012 and December 31, 2011, due to the short maturity of those instruments.

 

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Interest rate risk

We are exposed to interest rate risk as a result of our variable rate short-term cash holdings and borrowings under the Amended and Restated Credit Facility, the Dalea Credit Agreement, the Dalea Credit Facility and note payable with Viking Drilling, LLC.

Foreign currency risk

We have underlying foreign currency exchange rate exposure. Our currency exposures relate to transactions denominated in the Canadian Dollar, British Pound, Bulgarian Lev, European Union Euro, Romanian New Leu, Moroccan Dirham and New Turkish Lira. 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 March 31, 2012, we had 12.1 million New Turkish Lira (approximately $6.8 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the New Turkish Lira.

Commodity price risk

We are exposed to fluctuations in commodity prices for crude oil and natural gas. Commodity prices are affected by many factors including but not limited to supply and demand. At March 31, 2012 and December 31, 2011, we were a party to commodity derivative contracts.

Concentration of credit risk

The majority of our receivables are within the oil and 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, Zorlu Dogal Daz Ithalat Ihracat ve Toptan Ticaret A.S., a privately owned natural gas distributor in Turkey, and Turkiye Petrol Refinerileri A.Ş., a privately owned oil refinery in Turkey, which purchase the majority of our oil and natural gas production. The receivables are not collateralized. To date, we have experienced minimal bad debts and have no allowance for doubtful accounts. Other accounts receivable relating to value added taxes are due from various government agencies and are expected to be collected during 2012. 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 March 31, 2012:

 

		Fair Value Measurement Classification
		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
		(in thousands)
Liabilities:
Related party floating rate debt		$	—			$	(84,000	)		$	—			$	(84,000	)
Amended and Restated Credit Facility			—				(78,000	)			—				(78,000	)
TBNG credit agreement			—				(4,542	)			—				(4,542	)
Derivative financial instruments			—				(18,031	)			—				(18,031	)
Total		$	—			$	(184,573	)		$	—			$	(184,573	)

 

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The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2011:

 

		Fair Value Measurement Classification
		Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)				Significant Other Observable Inputs (Level 2)				Significant Unobservable Inputs (Level 3)				Total
		(in thousands)
Liabilities:
Related party floating rate debt		$	—			$	(73,000	)		$	—			$	(73,000	)
Amended and Restated Credit Facility			—				(78,000	)			—				(78,000	)
TBNG credit agreement			—				(7,732	)			—				(7,732	)
Derivative financial instruments			—				(7,071	)			—				(7,071	)
Total		$	—			$	(165,803	)		$	—			$	(165,803	)

 

15.	Related party transactions

The following table summarizes related party accounts receivable and accounts payable as of March 31, 2012 and December 31, 2011:

 

		March 31, 2012				December 31, 2011
		(in thousands)
Related party accounts payable:
Riata Management service agreement		$	—			$	323
Total related party accounts payable		$	—			$	323

The following table summarizes related party accounts receivable held for sale and related party accounts payable held for sale as of March 31, 2012 and December 31, 2011:

 

		March 31, 2012				December 31, 2011
		(in thousands)
Related party accounts receivable:
Maritas services agreement		$	1,788			$	251
Viking Oilfield Services services agreement			146				116
Total related party accounts receivable held for sale		$	1,934			$	367
Related party accounts payable:
Viking Drilling services agreement		$	—			$	92
Viking Oilfield Services services agreement			137				617
Gundem lease agreements			36				36
Total related party accounts payable held for sale		$	173			$	745

 

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Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

In this Quarterly Report on Form 10-Q, references to “we,” “our,” “us” or the “Company,” refer to TransAtlantic Petroleum Ltd. and its subsidiaries on a consolidated basis unless the context requires otherwise. Unless stated otherwise, all sums of money stated in this Quarterly Report on Form 10-Q are expressed in U.S. Dollars.

Executive Overview

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey, Bulgaria and Romania. As of March 31, 2012, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell, 3rd, the chairman of our board of directors and chief executive officer.

Financial and Operational Performance Highlights. Highlights of our financial performance and operational performance for the first quarter of 2012 include:

 

•

During the quarter ended March 31, 2012, we derived 69.5% of our revenues from the production of oil and 29.7% of our revenues from the production of natural gas.

 

•

Total oil and natural gas revenues increased 20.9% to $34.7 million for the quarter ended March 31, 2012 from $28.7 million realized in the same period in 2011. The increase was the result of an increase in production volumes, offset by a decline in our average sales price.

 

•

Production increased to approximately 224 net thousand barrels (Mbbls) of oil and approximately 1,367 net million cubic feet (Mmcf) of natural gas for the first quarter of 2012, compared to approximately 219 net Mbbls of oil and 803 net Mmcf of natural gas for the same period in 2011.

 

•

As of March 31, 2012, we produced an aggregate of approximately 2,337 net barrels (Bbls) oil per day and approximately 13.2 net Mmcf of natural gas per day.

 

•

For the quarter ended March 31, 2012, we incurred $14.2 million in capital expenditures, compared to capital expenditures of $17.8 million for the quarter ended March 31, 2011. The decrease in capital expenditures was primarily due to the acquisition of Direct Petroleum Morocco, Inc. (“Direct Morocco”), Anschutz Morocco Corporation (“Anschutz”) and Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”) in the first quarter of 2011.

 

•

As of March 31, 2012, our short-term borrowings were $88.5 million, compared to short-term borrowings of $80.7 million as of December 31, 2011.

Recent Developments

Sale of Viking International and Viking Geophysical. On March 15, 2012, we signed a stock purchase agreement to sell our oilfield services business, which is substantially comprised of our wholly owned subsidiaries Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical” and collectively, “Viking”), to Dalea Partners, LP (“Dalea”, an affiliate of Mr. Mitchell) for an aggregate purchase price of $164.0 million, consisting of $152.5 million in cash, subject to a net working capital adjustment, and a $11.5 million promissory note from Dalea. The promissory note will be payable five years from the date of issuance or earlier upon the occurrence of certain specified events, will bear interest at a rate of 3.0% per annum and will be guaranteed by Mr. Mitchell. Contractually, the effective date of the sale of Viking will be April 1, 2012, regardless of when the actual closing occurs. The closing is anticipated to occur during the second quarter of 2012. The sale of Viking is subject to the approval of regulatory authorities, the receipt of equity financing by Dalea and other customary closing conditions. For additional information concerning the stock purchase agreement, see “Part I, Item 1. Business—Divestiture of Our Oilfield Services Business” in our Annual Report on Form 10-K for the year ended December 31, 2011.

Dalea Credit Facility. On March 15, 2012, we entered into a $15.0 million credit facility with Dalea to provide us with additional liquidity for general corporate purposes until we complete the sale of Viking. Loans under the credit facility accrue interest at a rate of three-month London Interbank Offered Rate (“LIBOR”) plus 5.5% per annum. Any proceeds received by us or any subsidiary from any debt financings (subject to certain specified exceptions) or from the sale of Viking, net of reasonable transaction and financing costs, must be used to repay amounts outstanding under the credit facility. Any outstanding borrowings under the credit facility must be repaid upon the earlier of (i) July 1, 2012 or (ii) the sale of Viking. As of March 31, 2012, we had borrowed $11.0 million under the Dalea credit facility.

Ban on Fracture Stimulation in Bulgaria. On January 18, 2012, the Bulgarian Parliament enacted legislation that was intended to ban fracture stimulation in the Republic of Bulgaria. As long as this legislation remains in effect, our exploration, development and production activities in Bulgaria will be significantly constrained.

 

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Changes in Executive Management. On January 5, 2012, our board of directors appointed Mustafa Yavuz as our chief operating officer.

First Quarter 2012 Operational Update

During the first quarter of 2012, we continued to develop our Selmo and Arpatepe oil fields in southeastern Turkey and our Thrace Basin natural gas fields in northwestern Turkey, including the natural gas fields acquired in the acquisition of Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”). In addition, we continued to expand our inventory of exploration opportunities with new prospects identified on recently completed 3D seismic surveys. We achieved positive results on recent fracture stimulation (“frac”) jobs in the Thrace Basin and produced approximately 99 Mmcf of gross incremental production as a result of the frac jobs performed during the first quarter of 2012. As of March 31, 2012, the gross incremental production rate from these frac jobs was approximately 2.2 Mmcf of natural gas per day.

Production. For the quarter ended March 31, 2012, we produced an average of approximately 2,462 net Bbls of oil per day and approximately 15.0 net Mmcf of natural gas per day.

Turkey-Thrace Basin. Following the acquisition of TBNG in June 2011, we accelerated plans for exploration and development of TBNG’s acreage. Our immediate emphasis was on identifying low-cost, high-yield conventional potential in existing wellbores. In the first quarter of 2012, we recompleted six existing wellbores on our TBNG acreage, adding production of approximately 1.4 net Mmcf of natural gas per day. This program has been the primary contributor in offsetting normal field decline rates.

As of March 31, 2012, we had $7.0 million of exploratory well costs capitalized for the Pancarkoy-1 well, which we began drilling in the fourth quarter of 2010. After the second fracture stimulation, commercial natural gas production could not be sustained due to the high amount of water production when the well was placed on production. A third fracture stimulation was performed in April 2012, but commercial production could not be sustained due to high water production. We have identified at least two more sands within the Mezardere formation that we expect to test initially by conventional means. These sands possess different, more favorable reservoir properties than the previous targets and have strong indicators of natural gas. We expect to commence testing late in the second quarter of 2012, and further fracture stimulation will depend on the outcome of the conventional test results.

We continue to identify and prioritize existing TBNG wellbores for fracture stimulation. Furthermore, we have begun evaluating existing wellbores to select our first set of multi-stage fracture stimulation candidates. We will continue our fracture stimulation campaign in the Thrace Basin by stimulating both existing wellbores and newly drilled wells, which target unconventional horizons identified by integrating our geological and engineering studies with our knowledge gained through stimulating existing wellbores in our previous re-entry campaigns.

Southeastern Turkey.

 

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Selmo. We completed two wells and began drilling four additional wells during the first quarter of 2012.

 

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Arpatepe. In the first quarter of 2012, we spud one new well and continued drilling a well spud in December 2011. The Arpatepe-6 well was drilled in January 2012, and we expect to complete both the Arpatepe-5 and Arpatepe-6 wells in the second quarter of 2012.

 

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Molla. We completed the Goksu-2 appraisal well in February 2012 with an initial flow rate of approximately 400 Bbls per day. We commenced drilling the Bahar-1 well in March 2012, with plans to test both the Mardin and Bedinan formations as well as the Dadas shale. Following the drilling of the Bahar-1 well, we plan to drill the Goksu-3H well in the second quarter of 2012. We believe this well will be the first horizontal well to test the fractured Mardin carbonate formations found in this region.

Central Basins. We have substantial exploration acreage in central Turkey. In February 2012, we entered into an agreement with Shell Upstream Turkey BV (“Shell”) pursuant to which Shell agreed to co-fund the acquisition of 1,000 kilometers of 2D seismic data and approximately 8,000 kilometers of airborne gravity gradiometry and magnetic data in Turkey’s Sivas Basin, where we hold exploration licenses covering approximately 1.6 million acres. The agreement provides an option for Shell to farm-in to the exploration licenses after it assesses the data collected. Up to two initial exploration wells may be drilled in 2013 in accordance with the underlying work commitments for the Sivas Basin exploration licenses.

Bulgaria. As a result of the legislation that was intended to ban fracture stimulation in the Republic of Bulgaria, we have temporarily suspended drilling and completion operations for the Deventci-R2 and Peshtene-R11 wells. Although we expect the Bulgarian government to clarify the legislation to allow for conventional drilling and to institute a set of procedures regulating the fracture stimulation of wells, we cannot be certain when or if this will occur. In the meantime, we and our partner, LNG Energy, Ltd. (“LNG”), are evaluating core data gathered while drilling the Peshtene-R11 well and developing a conventional completion program for the well.

 

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Romania. We and the operator of the Sud Craiova license, Sterling Resources, Ltd. (“Sterling”), have committed to participate in a 200-kilometer 2D seismic survey on the Sud Craiova license, which we plan to complete by the end of 2012.

Planned Operations

We continue to actively explore and develop our existing oil and natural gas properties in Turkey and evaluate opportunities for further activities in Bulgaria and Romania. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. For the remainder of 2012, we are focused on accomplishing the following objectives:

 

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Expand Fracture Stimulation Program. In the fourth quarter of 2011, our Thrace Basin fracture simulation program brought positive results and provided important lessons regarding fracture stimulation design. We plan to expand our application of fracture stimulation techniques to additional properties in the Thrace Basin. We plan to continue our exploration of the deep, unconventional opportunities in the Thrace Basin, and we plan to drill and test the Dadas shale formation underlying several of our licenses in southeastern Turkey. We anticipate that employing fracture stimulation techniques will result in the development of production and reserves that would have not been commercial otherwise.

 

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Reduce Exploration Risk Through Partnerships. In an effort to increase the pace of exploration activity, share exploration risk, and reduce our share of the capital commitments necessary to carry forward the exploration of our extensive acreage position, we are currently seeking joint venture partners for our exploration acreage in Bulgaria, Romania and Turkey and plan to continue this effort during the remainder of 2012.

 

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Complete the Sale of Viking. We expect to complete the sale of Viking in the second quarter of 2012.

Capital expenditures for the remainder of 2012 are expected to range between $100.0 million and $110.0 million. Approximately 55% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Most of the remaining 45% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Selmo, Arpatepe, Molla and Bakuk. If cash on hand, borrowings from our amended and restated senior credit facility (the “Amended and Restated Credit Facility”) with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”), our credit facility with Dalea and cash flow from operations are not sufficient to fund our capital expenditures, then we will either curtail our discretionary capital expenditures or seek other funding sources. If we successfully complete the sale of our oilfield services business, we may use a portion of the net proceeds to pay down our Amended and Restated Credit Facility, thereby increasing our capacity to fund capital expenditures. Our projected 2012 capital expenditure budget is subject to change and could be reduced if we do not raise additional funds.

We currently plan to execute the following drilling and exploration activities in the remainder of 2012:

Turkey. We plan to drill approximately 65 gross wells during the remainder of 2012, of which 21 will be fracture stimulated. In addition, we plan to fracture stimulate another 16 existing wellbores and perform conventional uphole recompletions in 25 existing wellbores on our Thrace Basin properties. We also plan to construct the infrastructure necessary to produce and sell oil and natural gas from the productive wells we drill.

Bulgaria. We plan to complete our evaluation of the Peshtene-R11 exploration well core data and develop a conventional completion program for the well.

Romania. We plan to complete a 200-kilometer 2D seismic survey on the Sud Craiova license by the end of 2012.

Discontinued Operations in Morocco

On June 27, 2011, we decided to discontinue our Moroccan operations. We are in the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for all periods presented, and they are not included in results from continuing operations.

Discontinued Operations of Oilfield Services Business

On March 15, 2012, we signed a stock purchase agreement to sell Viking for an aggregate purchase price of $164.0 million, consisting of $152.5 million in cash, subject to a net working capital adjustment, and a $11.5 million promissory note from Dalea. We intend to use approximately $3.7 million of the cash consideration to repay (i) the outstanding balance on our amended and restated note payable from Viking International to Viking Drilling, LLC (“Viking Drilling”) and (ii) the outstanding balance of a secured credit agreement entered into by Viking International to fund the purchase of vehicles. In addition, we intend to use a portion of the remaining cash proceeds to repay our credit agreement with Dalea and our credit facility with Dalea, and we may use the remaining cash proceeds along with existing cash to repay some or all of the outstanding indebtedness under our Amended and Restated Credit Facility.

 

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Pursuant to the stock purchase agreement, the Company, Viking International and Viking Geophysical will enter into a five-year master services agreement that would provide us with continued access to Viking’s equipment and services. After the consummation of the sale of these operations, we will no longer own drilling rigs and oilfield services equipment, which will increase our costs and expenses, but will reduce our depreciation and amortization expense and our general and administrative expense. We could also be subject to greater risks related to the availability and cost of drilling rigs and third party oilfield services.

There is no assurance that we will complete the sale of Viking as contemplated or at all. The sale of Viking is subject to the approval of regulatory authorities, the receipt of equity financing by Dalea and other customary closing conditions. The closing is anticipated to occur during the second quarter of 2012. We have presented the oilfield services segment operating results as discontinued operations for all periods presented, and they are not included in results from continuing operations.

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, 2011 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, 2011.

Recent Accounting Pronouncements

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (“ASU 2011-04”). ASU 2011-04 amends Accounting Standards Codification (“ASC”) 820 Fair Value Measurements and Disclosures (“ASC 820”), providing a consistent definition and measurement of fair value, as well as similar disclosure requirements between U.S. GAAP and International Financial Reporting Standards. ASU 2011-04 changes certain fair value measurement principles, clarifies the application of existing fair value measurement and expands the ASC 820 disclosure requirements, particularly for Level 3 fair value measurements. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. We adopted ASU 2011-04 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In June 2011, FASB issued ASU 2011-05, Presentation of Comprehensive Income (“ASU 2011-05”). ASU 2011-05 requires the presentation of comprehensive income in either (1) a continuous statement of comprehensive income or (2) two separate but consecutive statements. In December 2011, FASB issued ASU 2011-12, Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in ASU 2011-05 (“ASU 2011-12”). ASU 2011-12 deferred the specific requirement to present items that are reclassified from accumulated other comprehensive income to net income separately with their respective components of net income and other comprehensive income. The amendments will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. We adopted ASU 2011-05 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In September 2011, FASB issued ASU 2011-08, Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment (“ASU 2011-08”). ASU 2011-08 allows both public and nonpublic entities an option to first assess qualitative factors to determine whether it is necessary to perform the two-step quantitative goodwill impairment test. An entity would no longer be required to calculate the fair value of a reporting unit unless the entity determines, based on that qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. ASU 2011-08 allows early adoption and will be effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We adopted ASU 2011-08 on January 1, 2012. The adoption did not have a material effect on our financial statements.

In December 2011, FASB issued ASU No. 2011-11, Balance Sheet (Topic 210), Disclosures about Offsetting Assets and Liabilities (“ASU 2011-11”). ASU 2011-11 will require entities to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. Application of ASU 2011-11 is required for annual reporting periods beginning on or after January 1, 2013 and interim periods within those annual periods. We are currently evaluating the effects of adopting ASU 2011-11.

 

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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 our current or future earnings or operations.

Results of Operations—Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

 

		Three Months Ended March 31,								Change
		2012				2011				2012-2011
		(in thousands of U.S. dollars, except per unit prices and production  volumes) (as adjusted)
Production:
Oil (Mbbl)			224				219				5
Natural gas (Mmcf)			1,367				803				564
Total production (Mboe)			452				353				99
Average prices:
Oil (per Bbl)		$	108.38			$	108.17			$	0.21
Natural gas (per Mcf)		$	7.60			$	7.29			$	0.31
Oil equivalent (per Boe)		$	76.68			$	81.23			$	(4.55	)
Revenues:
Oil and natural gas sales		$	34,661			$	28,676			$	5,985
Other			274				403				129
Total revenues			34,935				29,079				5,856
Costs and expenses:
Production			3,635				4,102				(467	)
Exploration, abandonment and impairment			2,796				7,232				(4,436	)
Seismic and other exploration			664				2,252				(1,588	)
General and administrative			9,748				9,085				663
Depreciation, depletion and amortization			9,169				4,630				4,539
Interest and other expense			3,259				3,597				(338	)
Loss on commodity derivative contracts:
Cash settlements on commodity derivative contracts			(1,474	)			(704	)			(770	)
Non-cash change in fair value on commodity derivative contracts			(10,961	)			(8,607	)			(2,354	)
Total loss on commodity derivative contracts			(12,435	)			(9,311	)			(3,124	)

Oil and Natural Gas Sales. Total oil and natural gas revenues increased $6.0 million to $34.7 million for the three months ended March 31, 2012 from $28.7 million realized in the same period in 2011. Of this increase, $8.0 million was due to an increase in our total production volumes of 99 Mboe to 452 Mboe for the three months ended March 31, 2012 compared to 353 Mboe in the same period in 2011. Production volumes increased primarily due to the acquisition of TBNG in June 2011, which contributed approximately 111 Mboe. This was partially offset by a decrease in production due to the natural decline of our reserve base. A decrease in our average sales price also partially offset the increase by approximately $2.0 million. For the three months ended March 31, 2012, our average price received was $76.68 per Boe, compared to $81.23 per Boe for the same period in 2011.

Production. Production expenses for the three months ended March 31, 2012 decreased to $3.6 million from $4.1 million for the same period in 2011. The decrease was primarily attributable to an increase in the utilization of our oilfield services business to provide these services.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended March 31, 2012 decreased approximately $4.4 million to $2.8 million for the three months ended March 31, 2012, from $7.2 million for the same period in 2011. For the three months ended March 31, 2012, we wrote off two wells, compared to three wells written off for the three months ended March 31, 2011.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $0.7 million for the three months ended March 31, 2012, compared to $2.3 million for the same period in 2011. This decrease was due primarily to a decrease in the utilization of third parties to provide our seismic services.

 

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General and Administrative. General and administrative expense was $9.7 million for the three months ended March 31, 2012, compared to $9.1 million for the same period in 2011. The increase was primarily due to our acquisition of TBNG in June 2011 and costs related to the proposed sale of our oilfield services business, partially offset by a decrease due to high expenses in the first quarter of 2011 related to acquisition costs for Direct Morocco, Anschutz, Direct Bulgaria and TBNG.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $9.2 million for the three months ended March 31, 2012, compared to $4.6 million in the same period of 2011. The increase was primarily due to an increase in our depletable asset base at March 31, 2012, which was primarily as a result of our 2011 acquisitions.

Interest and Other Expense. Interest and other expense decreased to $3.3 million for the three months ended March 31, 2012, compared to $3.6 million for the same period in 2011. The decrease was primarily due to warrant expenses for the three months ended March 31, 2011 of approximately $1.2 million associated with our Dalea credit agreement, which were fully amortized in 2011. This decrease was partially offset by an increase of approximately $0.9 million primarily due to an increase in the interest rate under this credit agreement and higher total outstanding debt at March 31, 2012, as compared to March 31, 2011. For the three months ended March 31, 2012, the interest rate on this agreement was LIBOR plus 5.50% per annum, compared to LIBOR plus 2.50% per annum for the same period in 2011. Total outstanding debt at March 31, 2012 was $170.2 million (of which $3.7 million was held for sale), compared to $145.1 million at March 31, 2011.

Loss on Commodity Derivative Contracts. During the three months ended March 31, 2012, we recorded a loss on commodity derivative contracts of approximately $12.4 million, compared to a loss of $9.3 million for the same period in 2011. We recorded a $11.0 million unrealized loss and a $1.5 million realized loss on our derivative contracts for the three months ended March 31, 2012, compared to a $8.6 million unrealized loss and a $0.7 million realized loss for the three months ended March 31, 2011. Unrealized gains and losses are attributable to changes in oil and natural gas prices and volumes hedged from one period end to another. We are required under our Amended and Restated Credit Facility to hedge a portion of our oil production in the Selmo and Arpatepe oil fields in Turkey.

Other Comprehensive Income. 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 March 31, 2012 increased to a gain of $14.4 million from a gain of $2.3 million for the same period in 2011 due to the strengthening of the New Turkish Lira (“TRY”) at March 31, 2012.

Discontinued Operations. All revenues and expenses associated with the Moroccan operations and oilfield services business for the three months ended March 31, 2012 and 2011 have been included in discontinued operations.

 

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The results of operations for our Moroccan operations and oilfield services business were as follows:

 

		Three Months Ended March 31,
		2012				2011
		(in thousands)
Revenues:
Oil and natural gas sales		$	—			$	48
Oilfield services			10,284				3,117
Total revenues			10,284				3,165
Costs and expenses:
Production			288				5
Exploration, abandonment and impairment			—				2,566
Seismic and other exploration			—				27
Oilfield services costs			7,072				4,738
General and administrative			2,166				1,276
Depreciation, depletion and amortization			—				2,933
Accretion of asset retirement obligations			—				—
Total costs and expenses			9,526				11,545
Operating income (loss)			758				(8,380	)
Other (expense) income:
Interest and other expense			(65	)			(253	)
Interest and other income			18				39
Foreign exchange loss			(888	)			(490	)
Total other (expense) income			(935	)			(704	)
Loss from discontinued operations before income taxes			(177	)			(9,084	)
Current income tax expense			(2,147	)			(173	)
Deferred income tax benefit			167				(51	)
Net loss from discontinued operations		$	(2,157	)		$	(9,308	)

Capital Expenditures

For the quarter ended March 31, 2012, we incurred $14.2 million in capital expenditures compared to capital expenditures from continuing operations of $17.8 million for the quarter ended March 31, 2011. The decrease in capital expenditures was primarily due to the acquisition of Direct Morocco, Anschutz and Direct Bulgaria during the quarter ended March 31, 2011. The remaining decrease was due to less drilling during the first quarter of 2012, as we have been interpreting seismic data shot in late 2011. In the first quarter of 2011, our capital expenditures were for drilling and exploration activities and acquiring long-term drilling inventory.

For the remainder of 2012, we expect our capital expenditures to range between approximately $100.0 million and $110.0 million. Approximately 55% of these anticipated expenditures will occur in the Thrace Basin in Turkey, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Most of the remaining 45% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Selmo, Arpatepe, Molla and Bakuk. If cash on hand, borrowings from our Amended and Restated Credit Facility and credit facility with Dalea, and cash flow from operations are not sufficient to fund our capital expenditures, then we will either curtail our discretionary capital expenditures or seek other funding sources. If we successfully complete the sale of our oilfield services business, we may use a portion of the net proceeds to pay down our Amended and Restated Credit Facility, thereby increasing our capacity to fund capital expenditures. Our projected 2012 capital expenditure budget is subject to change and could be reduced if we do not raise additional funds. See “—Liquidity and Capital Resources.”

Liquidity and Capital Resources

Our primary sources of liquidity for the first quarter of 2012 were our cash and cash equivalents, cash flow from operations and borrowings under our various debt agreements. At March 31, 2012, we had cash and cash equivalents of $15.1 million, $88.5 million in short-term debt associated with our continuing operations, $3.7 million in short-term debt associated with our discontinued operations, $78.0 million in long-term debt associated with our continuing operations and, excluding assets held for sale of $135.0 million and liabilities held for sale of $25.9 million, a working capital deficit of $70.2 million, compared to cash and cash equivalents of $15.1 million, $80.7 million in short-term debt associated with our continuing operations, $5.0 million in short-term debt associated with our discontinued operations, $78.0 million in long-term debt associated with our continuing operations, and, excluding assets

 

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held for sale of $128.1 million and liabilities held for sale of $26.7 million, a working capital deficit of $61.2 million at December 31, 2011. Cash provided by operating activities for the three months ended March 31, 2012 increased to $7.0 million, as compared to cash provided by operating activities of $4.2 million for the quarter ended March 31, 2011, primarily as a result of higher revenues due to increased production.

As of March 31, 2012, the outstanding principal amount of our debt was $170.2 million, of which $3.7 million was classified as held for sale. Of our outstanding debt, $73.0 million under the Dalea credit agreement was due upon the earlier of (i) June 30, 2012 or (ii) the later of (x) the closing of the sale of Viking or (y) two business days after demand by Dalea. We forecast that we will need to consummate the sale of Viking or raise additional debt or equity financing to fund our repayment of the Dalea credit agreement and to fund our operations, including our planned exploration and development activities. On March 15, 2012, we entered into a stock purchase agreement to sell Viking. We also entered into a $15.0 million credit facility with Dalea, of which $11.0 million was outstanding as of March 31, 2012, to provide us with additional liquidity for general corporate purposes. Should we be unable to consummate the sale of Viking, raise additional financing or extend the maturity date of the Dalea credit agreement, we will not have sufficient funds to continue operations beyond June 30, 2012. As a result of the recurring losses from operations and a working capital deficiency, there is substantial doubt regarding our ability to continue as a going concern. The continuing application of the going concern assumption is dependent upon our continuing ability to obtain the necessary financing to discharge our existing obligations, fund ongoing exploration, development and operations and ultimately achieve profitable operations. The inability to secure additional funding when and as needed could have a material adverse effect on our operations and financial condition.

In addition to cash, cash equivalents and cash flow from operations, at March 31, 2012, we had an Amended and Restated Credit Facility, a credit agreement with Dalea, a credit facility with Dalea, a term note with Viking Drilling, an equipment loan with a Turkish bank and a credit agreement with a Turkish bank, each of which is discussed below.

Amended and Restated Credit Facility. DMLP, Ltd., TransAtlantic Exploration Mediterranean International Pty Ltd, Amity Oil International Pty Ltd (“Amity”), Talon Exploration, Ltd., TransAtlantic Turkey, Ltd. and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”) (collectively, the “Borrowers”) are parties to the Amended and Restated Credit Facility. Each of the Borrowers is a wholly owned subsidiary. The Amended and Restated Credit Facility is guaranteed by TransAtlantic Petroleum Ltd. and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) (collectively, the “Guarantors”).

The amount drawn under the Amended and Restated Credit Facility may not exceed the lesser of (i) $250.0 million, (ii) the borrowing base amount at such time, (iii) the aggregate commitments of all lenders at such time, and (iv) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment. At March 31, 2012, the lenders had aggregate commitments of $120.0 million, with individual commitments of $60.0 million each. On the last day of each fiscal quarter commencing September 30, 2012 and at the maturity date, the lenders’ commitments are subject to reduction by 6.25% of their commitments existing on such commitment reduction date.

The borrowing base is re-determined semi-annually on April 1st and October 1st of each year prior to September 30, 2012, and quarterly on January 1st, April 1st, July 1st and October 1st of each year after September 30, 2012. We expect to complete the semi-annual borrowing base redetermination in the second quarter of 2012. Our borrowing base is currently $81.4 million.

The borrowing base amount equals, for any calculation date, the lowest of:

 

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the debt value which results in the field life coverage ratio for such calculation date being 1.50 to 1.00;

 

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the debt value which results in the loan life coverage ratio for such calculation date being 1.30 to 1.00; and

 

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the debt value which results in a debt service coverage ratio for any calculation period being 1.25 to 1.00.

The Amended and Restated Credit Facility matures on the earlier of (i) May 18, 2016 or (ii) the last date of the borrowing base calculation period that immediately precedes the date that the semi-annual report of Standard Bank and the Borrowers determines that the aggregate amount of hydrocarbons to be produced from the borrowing base assets in Turkey are less than 25% of the amount of hydrocarbons to be produced from the borrowing base assets shown in the initial report prepared by Standard Bank and the Borrowers. The Amended and Restated Credit Facility bears various letter of credit sub-limits, including among other things, sub-limits of up to (i) $10.0 million, (ii) the aggregate available unused and uncancelled portion of the lenders’ commitments or (iii) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment.

Loans under the Amended and Restated Credit Facility accrue interest at a rate of three-month LIBOR plus 5.50% per annum. The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.75% per annum of the unused and uncancelled portion of the aggregate commitments that is less than or equal to the maximum available

 

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amount under the Amended and Restated Credit Facility, and (b) 1.65% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available amount under the Amended and Restated Credit Facility, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to Standard Bank or (b) 5.50% for all other letters of credit.

The Amended and Restated Credit Facility is secured by a pledge of (i) the local collection accounts and offshore collection accounts of each of the Borrowers, (ii) the receivables payable to each of the Borrowers, (iii) the shares of each Borrower, and (iv) substantially all of the present and future assets of the Borrowers.

The Borrowers are required to comply with certain financial and non-financial covenants under the Amended and Restated Credit Facility, including maintaining the following financial ratios:

 

•

ratio of combined current assets to combined current liabilities of not less than 1.10 to 1.00;

 

•

ratio of EBITDAX (less non-discretionary capital expenditures) to aggregate amounts payable under the Amended and Restated Credit Facility of not less than 1.50 to 1.00;

 

•

ratio of EBITDAX (less non-discretionary capital expenditures) to interest expense of not less than 4.00 to 1.00; and

 

•

ratio of total debt to EBITDAX of less than 2.50 to 1.00.

The non-financial covenants limit the ability of the Borrowers to, among other things, incur indebtedness or create any liens, merge or consolidate, liquidate or dissolve, dispose of any property or business, pay dividends, distributions or similar payments, make certain types of investments, enter into transactions with an affiliate and engage in certain businesses or business activities.

The Amended and Restated Credit Facility is also subject to customary events of default, such as the failure to pay principal or interest when due, the breach of certain covenants and obligations, a cross default to other indebtedness, our bankruptcy or insolvency, the failure to meet the required financial covenant ratios, the occurrence of a material adverse effect and the occurrence of a change in control. If an event of default shall occur and be continuing, all loans under the Amended and Restated Credit Facility will bear an additional interest rate of 2.00% per annum. In the case of an event of default upon bankruptcy or insolvency, all amounts payable under the Amended and Restated Credit Facility become immediately due and payable. In the case of any other event of default, all amounts due under the Amended and Restated Credit Facility may be accelerated by the lenders or the administrative agent. Borrowers have certain rights to cure an event of default arising from a violation of the fixed charge coverage ratio or the interest coverage ratio by obtaining cash equity or loans from us.

At March 31, 2012, the Borrowers had borrowed $78.0 million under the Amended and Restated Credit Facility, had availability of $3.4 million under the Amended and Restated Credit Facility and were in compliance with all material covenants under the Amended and Restated Credit Facility. For additional information concerning the ratios, financial and non-financial covenants, events of default and other material terms of our Amended and Restated Credit Facility, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in our Annual Report on Form 10-K for the year ended December 31, 2011.

Dalea Credit Agreement. We also have a credit agreement with Dalea. The purpose of the Dalea credit agreement was (i) to fund the acquisition of all of the shares of Amity and Petrogas and (ii) for general corporate purposes. On May 18, 2011, we entered into a first amendment to the Dalea credit agreement to extend the maturity date and increase the interest rate. On November 7, 2011, we entered into a second amendment to the Dalea credit agreement to extend the maturity date to the earlier of (i) March 31, 2012 or (ii) the sale of Viking. On March 15, 2012, we entered into a third amendment to the Dalea credit agreement to extend the maturity date until the earlier of (i) June 30, 2012 or (ii) the later of (x) the closing of the sale of Viking or (y) two business days after demand by Dalea.

Pursuant to the Dalea credit agreement, as amended, the aggregate unpaid principal balance, together with all accrued but unpaid interest and other costs, expenses or charges payable under the Dalea credit agreement are due and payable by us upon the earlier of (i) June 30, 2012 or (ii) the later of (x) the closing of the sale of Viking or (y) two business days after demand by Dalea. The Dalea credit agreement is subject to customary events of default, such as payment defaults, defaults in any terms, covenants or conditions of the agreement, the prohibition in trading in our common shares, suspension or delisting of our common shares from any stock exchange, the occurrence of a material adverse change and the occurrence of a change in control. If an event of default occurs and is continuing, Dalea may demand immediate payment of all monies owing under the Dalea credit agreement; provided, that with respect to certain specified events of default, all monies due under the Dalea credit agreement shall automatically become due and payable without any demand or any other action by Dalea or any other person.

 

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Amounts due under the credit agreement accrue interest at a rate of three-month LIBOR plus 5.50% per annum beginning on May 1, 2011, to be adjusted monthly on the first day of each month. Prior to May 1, 2011, amounts due under the credit agreement accrued interest at a rate of three-month LIBOR plus 2.50% per annum. Interest on the Dalea credit agreement ceased to accrue on April 1, 2012 and will be suspended until the closing date of the sale of Viking. If the closing does not occur, the abated interest will be reinstated. In addition, we are required to pay all accrued interest in arrears on the last day of each month until the date of repayment and at any time that the principal balance is due and payable. We may prepay the amounts due under the credit agreement at any time before maturity without penalty.

The Dalea credit agreement is also subject to customary covenants, such as covenants that limit our ability to incur indebtedness or create any mortgage, charge, lien or encumbrance, declare or provide for any dividends, redeem or repurchase shares, make or permit the sale or disposition of any substantial or material part of our business, assets or undertakings and borrow or allow our subsidiaries to borrow money from any person.

In addition, any proceeds received by us or any subsidiary from any debt financings (subject to certain specified exceptions) must be used to repay amounts outstanding under the credit agreement, net of reasonable transaction and financing costs. We (or any subsidiary) are also required to repay amounts outstanding under the credit agreement from (i) any proceeds of any equity issuance received from Mr. Mitchell, his immediate family or any entities owned or controlled by Mr. Mitchell or his immediate family (collectively, the “Mitchell Family”), and (ii) all proceeds of any equity issuance in excess of $75.0 million (excluding any proceeds received from the Mitchell Family), net of reasonable transaction costs. Amounts repaid under the credit agreement cannot be reborrowed. We were required to pay for Dalea’s reasonable legal fees and other expenses incidental to the completion of the credit agreement.

Under the terms of the Dalea credit agreement, we were required to issue Dalea 100,000 common share purchase warrants for each $1.0 million in principal amount advanced under the credit agreement. We borrowed an aggregate of $73.0 million under the credit agreement, and on September 1, 2010, we issued 7,300,000 common share purchase warrants to Dalea. The common share purchase warrants are exercisable until September 1, 2013 and have an exercise price of $6.00 per share.

At March 31, 2012, we had borrowed $73.0 million under the Dalea credit agreement. No further borrowings are permitted under the Dalea credit agreement. For additional information concerning the covenants, events of default and other material terms of the Dalea credit agreement, see “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in our Annual Report on Form 10-K for the year ended December 31, 2011.

Viking Drilling Note. On July 27, 2009, Viking International purchased the I-13 drilling rig and associated equipment from Viking Drilling. Dalea owns 85% of Viking Drilling. On February 19, 2010, Viking International purchased the I-14 drilling rig and associated equipment from Viking Drilling and entered into an amended and restated note payable to Viking Drilling in the amount of $11.8 million, which was comprised of $5.9 million payable related to the I-14 drilling rig and $5.9 million payable related to the purchase of the I-13 drilling rig. Under the terms of the amended and restated note, interest is payable monthly at a floating rate of LIBOR plus 6.25%, and the amended and restated note is due and payable August 1, 2012. The amended and restated note is secured by the I-13 and I-14 drilling rigs and associated equipment. At March 31, 2012, the outstanding balance under this note was $1.7 million and the note is included in “Liabilities held for sale—related party” in our Consolidated Balance Sheets.

Viking International Equipment Loan. In 2010, Viking International entered into a secured credit agreement with a Turkish bank to fund the purchase of vehicles. The credit agreement matures on July 20, 2014, bears interest at an annual rate of 3.84% and is secured by the vehicles purchased with the proceeds of the loan. There is no further availability under the credit agreement. At March 31, 2012, Viking International had an outstanding balance of $2.0 million under the secured credit agreement and the credit agreement is included in “Liabilities held for sale” in our Consolidated Balance Sheets.

TBNG Credit Agreement. TBNG is a party to an unsecured credit agreement with a Turkish bank. At March 31, 2012, we had outstanding borrowings of approximately 8.0 million New Turkish Lira (approximately $4.5 million) under the credit agreement. Borrowings under the credit agreement bear interest at a rate of 14.0% per annum, and interest is payable quarterly. The credit agreement matures on September 13, 2012 and may be renewed for an additional period on the same terms.

Dalea Credit Facility. On March 15, 2012, TransAtlantic Worldwide, TBNG and TransAtlantic Petroleum Ltd. (collectively, the “Credit Facility Borrowers”) entered into a $15.0 million credit facility with Dalea to provide us with additional liquidity for general corporate purposes until we complete the sale of Viking. Loans under the credit facility accrue interest at a rate of three-month LIBOR plus 5.5% per annum, to be adjusted monthly on the first day of each month. We will be required to pay all accrued interest in arrears on the last day of each month, and we may prepay outstanding amounts at any time before maturity without penalty. Any outstanding borrowings under the credit facility must be repaid upon the earlier of (i) July 1, 2012 or (ii) the sale of Viking.

 

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For the initial advance, we were required to pay Dalea an arrangement fee of $250,000. Under the credit facility, we are also required to pay Dalea a commitment fee equal to 2.75% per annum of the difference between the $15.0 million committed amount and the outstanding balance measured and payable on the last day of each fiscal quarter.

Any proceeds received by us or any subsidiary from any debt financings (subject to certain specified exceptions) or from the sale of Viking, net of reasonable transaction and financing costs, must be used to repay amounts outstanding under the credit facility. In addition, the Dalea credit facility is subject to customary covenants, including covenants that limit the ability of the Credit Facility Borrowers to, among other things, (i) make, give, create or permit or attempt to make, give or create any mortgage, charge, lien or encumbrance over any assets of any Credit Facility Borrower or any subsidiary (subject to certain specific exceptions), (ii) change the name of any of the Credit Facility Borrowers or the jurisdictions of organization, (iii) declare or provide for any dividends or other payments or distributions (whether in cash, assets or indebtedness) based on share capital, (iv) redeem or purchase any of their shares, (v) make or permit any sale of or disposition of any substantial or material part of their business, assets or undertaking, or that of any subsidiary, (vi) save and (except for certain specified exceptions) borrow or cause or permit any subsidiary to borrow money from any other person, without first obtaining and delivering a duly signed assignment and postponement of claim by such person in form and terms satisfactory to Dalea, (vii) pay out or permit the payment out of any shareholders loans or other indebtedness to non-arm’s length parties, or (viii) guarantee or permit the guarantee of the obligations of any other person, directly or indirectly, except in the ordinary course of business.

The Dalea credit facility is also subject to customary events of default, including payment defaults, defaults in observing or performing any term, covenant or condition of the Dalea credit facility or collateral documents, material misrepresentations by a Credit Facility Borrower or any subsidiary, a Credit Facility Borrower or any subsidiary ceases or threatens to cease to carry on business, the prohibition in trading in shares of any of the Credit Facility Borrowers or suspension or delisting from any stock exchange, a material adverse change in the financial condition of any of the Credit Facility Borrowers and any of their subsidiaries taken as a whole, Dalea believes in good faith and on commercially reasonable grounds that the ability of the Credit Facility Borrowers to pay or perform any of the covenants contained in the Dalea credit facility is materially impaired, insolvency of any of the Credit Facility Borrowers or any change of control of any of the Credit Facility Borrowers. Control is defined in the Dalea credit facility as ownership of or control or direction over, directly or indirectly, 20% or more of the outstanding voting securities of the Credit Facility Borrowers. If an event of default occurs and is continuing, Dalea may demand immediate payment of all monies owing under the Dalea credit facility; provided that with respect to certain specified events of default, all monies due under the Dalea credit facility shall automatically become due and payable without any demand or any other action by Dalea or any other person.

At March 31, 2012, we had borrowed $11.0 million under the Dalea credit facility and had availability of $4.0 million under the Dalea credit facility.

Contractual Obligations

The following table presents our contractual obligations at March 31, 2012:

 

						Payments Due by Year
		Total				2012				2013				2014				2015				2016				Thereafter
		(in thousands)
Debt (1)		$	170,205			$	90,843			$	850			$	512			$	—			$	78,000			$	—
Leases and other			13,943				3,828				2,517				1,765				1,236				835				3,762
Contracts			8,815				8,815				—				—				—				—				—
Permits			13,000				13,000				—				—				—				—				—
		$	205,963			$	116,486			$	3,367			$	2,277			$	1,236			$	78,835			$	3,762

 

 

(1)	Includes $2.0 million and $1.7 million outstanding classified as “Liabilities held for sale” and “Liabilities held for sale – related party”, respectively, in our Consolidated Balance Sheets.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at March 31, 2012.

Forward-Looking Statements

Certain statements contained in this Quarterly Report on Form 10-Q are “forward-looking statements” and are prospective. Forward-looking statements are typically identified by words such as “anticipate,” “believe,” “expect,” “plan,” “intend,” “may,” “project,” “forecast,” “estimate,” “continue,” “would,” “could” or similar words suggesting future outcomes or statements regarding an outlook. Such forward-looking statements are subject to risks, uncertainties and other factors which could cause actual results to differ materially from future results expressed or implied by such forward-looking statements.

 

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The following factors, among others, could cause actual results to differ from those set forth in the forward-looking statements: market prices for natural gas, natural gas liquids and oil products; estimates of reserves and economic assumptions; the ability to produce and transport natural gas, natural gas liquids and oil; the results of exploration and development drilling and related activities; economic conditions in the countries and provinces in which we carry on business, especially economic slowdowns; actions by governmental authorities receipt of required approvals, increases in taxes, legislative and regulatory initiatives relating to fracture stimulation activities, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflict; the negotiation and closing of material contracts; the ability to consummate the sale of our oilfield services business as contemplated or at all; the effect of the sale of our oilfield services business to our costs and expenses; and the other factors discussed in other documents that we file with or furnish to the Securities and Exchange Commission (“SEC”). The impact of any one factor on a particular forward-looking statement is not determinable with certainty, as such factors are interdependent upon other factors. In that regard, any statements as to future natural gas or oil production levels; capital expenditures; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital program; drilling of new wells; demand for natural gas and oil products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves; dates by which transactions are expected to close (including the sale of our oilfield services business); cash flows; uses of cash flows; collectability of receivables; availability of trade credit; expected operating costs; changes in any of the foregoing and other statements using forward-looking terminology are forward-looking statements.

Readers are cautioned not to place undue reliance on forward-looking statements, as there can be no assurance that the plans, intentions or expectations upon which they are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the possibility that the predictions, forecasts, projections and other things contemplated by the forward-looking statements will not occur.

Forward-looking statements in this Quarterly Report on Form 10-Q are based on management’s beliefs and opinions at the time the statements are made. The forward-looking statements contained in this Quarterly Report on Form 10-Q are expressly qualified in their entirety by this cautionary statement. The forward-looking statements included in this Quarterly Report on Form 10-Q are made as of the date of this Quarterly Report on Form 10-Q and we undertake no obligation to publicly update or revise any forward-looking statements to reflect new information, future events or otherwise, except as required by applicable securities laws.

 

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Item 3.

Quantitative and Qualitative Disclosures About Market Risk

During the first quarter of 2012, there were no material changes in market risk exposures that would affect the Quantitative and Qualitative Disclosures About Market Risk disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011. The following tables set forth our outstanding derivatives contracts with respect to future crude oil production as of March 31, 2012:

 

Type		Period				Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum  Price (per Bbl)				Estimated Fair Value of Liability
																		(in thousands)
Collar			April 1, 2012 — December 31, 2012				960			$	64.69			$	106.98			$	(4,186	)
Collar			January 1, 2013 — December 31, 2013				400			$	75.00			$	125.50				(772	)
Collar			January 1, 2014 — December 31, 2014				380			$	75.00			$	124.25				(430	)
																		$	(5,388	)

 

						Collars												Additional Call
Type		Period				Quantity (Bbl/day)				Weighted Average Minimum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Weighted Average Maximum Price (per Bbl)				Estimated Fair Value of Liability
																						(in thousands)
Three-way collar contract			April 1, 2012 — December 31, 2012				240			$	70.00			$	100.00			$	129.50			$	(1,229	)
Three-way collar contract			April 1, 2012 — June 30, 2012				350			$	85.00			$	116.25			$	137.38				(226	)
Three-way collar contract			July 1, 2012 — December 31, 2012				205			$	85.00			$	97.13			$	162.13				(841	)
Three-way collar contract			January 1, 2013 — December 31, 2013				831			$	85.00			$	97.13			$	162.13				(4,997	)
Three-way collar contract			January 1, 2014 — December 31, 2014				726			$	85.00			$	97.13			$	162.13				(2,472	)
Three-way collar contract			January 1, 2015 — December 31, 2015				1,016			$	85.00			$	91.88			$	151.88				(2,878	)
																						$	(12,643	)

 

Item 4.

Controls and Procedures

Acquisition of TBNG

In June 2011, we acquired TBNG. For purposes of determining the effectiveness of our disclosure controls and procedures and internal control over financial reporting, management has excluded the internal control over financial reporting of TBNG from its evaluation of these matters. The acquired business represents approximately 14.7% of our consolidated total assets at March 31, 2012 and 0% of our consolidated net loss for the three months ended March 31, 2012.

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 March 31, 2012, 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. Based upon the evaluation, which excluded the internal control over financial reporting of TBNG, and as a result of the material weaknesses in internal control over financial reporting described in our Annual Report on Form 10-K for the year ended December 31, 2011, our chief executive officer and chief financial officer concluded that, as of March 31, 2012, our disclosure controls and procedures were not effective at the reasonable assurance level.

 

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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

The following change in our internal control over financial reporting occurred during the first quarter of 2012 and has affected, or is reasonably likely to materially affect, our internal control over financial reporting:

 

•

In January 2012, we integrated TBNG into our accounting system database, effective for all activity on or after January 1, 2012.

 

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PART II. OTHER INFORMATION

Item 1.         Legal Proceedings

During the first quarter of 2012, there were no material developments to the Legal Proceedings disclosed in “Part I, Item 3. Legal Proceedings” of our Annual Report on Form 10-K for the year ended December 31, 2011.

Item 1A.        Risk Factors

During the first quarter of 2012, there were no material changes to the Risk Factors disclosed in “Part I, Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2011, except for the following:

Our Amended and Restated Credit Facility, credit facility with Dalea and credit agreement with Dalea, as amended, contain various covenants that limit our management’s discretion in the operation of our business and can lead to an event of default that may adversely affect our business, financial condition and results of operations.

The operating and financial restrictions and covenants in our Amended and Restated Credit Facility, credit facility with Dalea or our credit agreement with Dalea may adversely affect our ability to finance future operations or capital needs or to engage in other business activities. Our Amended and Restated Credit Facility, credit facility with Dalea and credit agreement with Dalea contain various covenants that restrict our ability to, among other things:

 

•

incur additional debt;

 

•

create liens;

 

•

enter into any hedge agreement for speculative purposes;

 

•

engage in business other than as an oil and natural gas exploration and production company;

 

•

enter into sale and leaseback transactions;

 

•

enter into any merger, consolidation or amalgamation;

 

•

dispose of all or substantially all of our assets;

 

•

use the amounts borrowed for only certain specified purposes;

 

•

declare or provide for any dividends or other payments or distributions;

 

•

redeem or purchase any shares; or

 

•

guarantee or permit the guarantee of the obligations of any other person.

In addition, the Amended and Restated Credit Facility requires us to maintain specified financial ratios and tests. Various risks, uncertainties and events beyond our control could affect our ability to comply with the covenants and financial tests and ratios required by the Amended and Restated Credit Facility and could result in a default under the Amended and Restated Credit Facility.

An event of default under the Amended and Restated Credit Facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and beneficially, all of the equity of the Borrowers or any of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or Guarantor; (ii) the failure by the Borrowers to own or hold, directly or indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated in the Amended and Restated Credit Facility; or (iii) (a) Mr. Mitchell ceases for any reason to be the executive chairman of our board of directors at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner, directly or indirectly, of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis. Provided that, if Mr. Mitchell ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute an event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event.

Events of default under the credit facility with Dalea and credit agreement with Dalea include, among other events, failure to make the payment of principal or interest when due, breach of certain covenants or conditions, the occurrence of an adverse material change in our financial condition, bankruptcy or insolvency, or a change of control. In the event of a default under the credit agreement or the credit facility, the lender can demand all amounts payable under the credit agreement or the credit facility to be immediately due and payable. In the event of bankruptcy or insolvency, all amounts payable under the credit agreement and the credit facility become immediately due and payable.

 

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In the event of a default and acceleration of indebtedness under the Amended and Restated Credit Facility, credit facility with Dalea or the credit agreement with Dalea, our business, financial condition and results of operations may be materially and adversely affected.

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

None.

 

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Item 6.        Exhibits

 

2.1*		Stock Purchase Agreement, dated March 15, 2012, by and among TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Longe Energy Limited, TransAtlantic Petroleum (USA) Corp., TransAtlantic Pertroleum Cyprus Limited, Viking International Limited, Viking Geophysical Services, Ltd., Viking Oilfield Services SRL and Dalea Partners, LP.
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		Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated August 20, 2009 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.3		Bye-Laws of TransAtlantic Petroleum Ltd., dated July 14, 2009 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
4.1		Amended and Restated Registration Rights Agreement, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Riata Management, LLC (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009).
4.2		Registration Rights Agreement, dated February 18, 2011, by and between TransAtlantic Petroleum Ltd. and Direct Petroleum Exploration, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated February 18, 2011, filed with the SEC on February 24, 2011).
4.3		Common Share Purchase Warrants, dated September 1, 2010, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP (incorporated by reference to Exhibit 4.4 to the Company’s Annual Report on Form 10-K, filed with the SEC on April 21, 2011).
10.1*		Third Amendment to Credit Agreement, dated March 15, 2012, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP.
10.2*		Credit Agreement, dated March 15, 2012, by and among TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Thrace Basin Natural Gas (Turkiye) Corporation and Dalea Partners, LP.
10.3*		Management Services Agreement, dated March 15, 2012, by and between Viking Geophysical Services, Ltd. and Viking Petrol Sahasi Hizmetleri A.S.
10.4		Management Services Agreement, effective February 1, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Petrol Sahasi Hizmetleri A.S. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated April 20, 2012, filed with the SEC on April 26, 2012).
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 Chief 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 Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101†		The following materials from the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, formatted in XBRL (eXtensible Business Reporting Language), (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Income (Loss), (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements.

 

*	Filed herewith. Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

†

Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

 

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Table of Contents

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.

 

 

 

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Table of Contents

INDEX TO EXHIBITS

 

2.1*		Stock Purchase Agreement, dated March 15, 2012, by and among TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Longe Energy Limited, TransAtlantic Petroleum (USA) Corp., TransAtlantic Pertroleum Cyprus Limited, Viking International Limited, Viking Geophysical Services, Ltd., Viking Oilfield Services SRL and Dalea Partners, LP.
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		Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated August 20, 2009 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.3		Bye-Laws of TransAtlantic Petroleum Ltd., dated July 14, 2009 (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
4.1		Amended and Restated Registration Rights Agreement, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Riata Management, LLC (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009).
4.2		Registration Rights Agreement, dated February 18, 2011, by and between TransAtlantic Petroleum Ltd. and Direct Petroleum Exploration, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated February 18, 2011, filed with the SEC on February 24, 2011).
4.3		Common Share Purchase Warrants, dated September 1, 2010, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP (incorporated by reference to Exhibit 4.4 to the Company’s Annual Report on Form 10-K, filed with the SEC on April 21, 2011).
10.1*		Third Amendment to Credit Agreement, dated March 15, 2012, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP.
10.2*		Credit Agreement, dated March 15, 2012, by and among TransAtlantic Petroleum Ltd., TransAtlantic Worldwide, Ltd., Thrace Basin Natural Gas (Turkiye) Corporation and Dalea Partners, LP.
10.3*		Management Services Agreement, dated March 15, 2012, by and between Viking Geophysical Services, Ltd. and Viking Petrol Sahasi Hizmetleri A.S.
10.4		Management Services Agreement, effective February 1, 2012, by and between TransAtlantic Petroleum Ltd. and Viking Petrol Sahasi Hizmetleri A.S. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated April 20, 2012, filed with the SEC on April 26, 2012).
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 Chief 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 Chief Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101†		The following materials from the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, formatted in XBRL (eXtensible Business Reporting Language), (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Income (Loss), (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cash Flows and (v) Notes to the Consolidated Financial Statements.

 

*	Filed herewith. Pursuant to Item 601(b)(2) of Regulation S-K, the registrant agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

†

Pursuant to Rule 406T of Regulation S-T, the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Section 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

 

35