Form 10-Q
Table of Contents

 

 

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: June 30, 2013

OR

 

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

For the transition period from                      to                     

Commission file number: 001-34574

 

 

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

 

 

 

Bermuda   None

(State or Other Jurisdiction of

Incorporation or Organization)

 

(I.R.S. Employer

Identification No.)

16803 Dallas Parkway

Addison, Texas

  75001
(Address of Principal Executive Offices)   (Zip Code)

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

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  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 August 5, 2013, the registrant had 369,838,025 common shares outstanding.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION   

Item 1. Financial Statements

  

Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012

   1

Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June  30, 2013 and 2012

   2

Consolidated Statements of Equity for the Six Months Ended June 30, 2013

   3

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2013 and 2012

   4

Notes to Consolidated Financial Statements

   5

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

   16

Item 3. Quantitative and Qualitative Disclosures About Market Risk

   26

Item 4. Controls and Procedures

   26
PART II. OTHER INFORMATION   

Item 1. Legal Proceedings

   26

Item 1A. Risk Factors

   27

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

   27

Item 3. Defaults Upon Senior Securities

   27

Item 4. Mine Safety Disclosures

   27

Item 5. Other Information

   27

Item 6. Exhibits

   28


Table of Contents

PART I. FINANCIAL INFORMATION

 

Item 1. Financial Statements

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

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

 

     June 30, 2013     December 31,
2012
 
     (Unaudited)        

ASSETS

    

Current assets:

    

Cash and cash equivalents

   $ 15,920      $ 14,768   

Accounts receivable

    

Oil and natural gas sales, net

     27,742        34,158   

Joint interest and other

     10,951        18,192   

Related party

     662        419   

Prepaid and other current assets

     2,009        2,339   

Deferred income taxes

     3,680        1,895   

Assets held for sale

     534        1,619   
  

 

 

   

 

 

 

Total current assets

     61,498        73,390   
  

 

 

   

 

 

 

Property and equipment:

    

Oil and natural gas properties (successful efforts method)

    

Proved

     250,491        231,498   

Unproved

     56,169        68,938   

Equipment and other property

     39,943        35,747   
  

 

 

   

 

 

 
     346,603        336,183   

Less accumulated depreciation, depletion and amortization

     (91,754     (80,031
  

 

 

   

 

 

 

Property and equipment, net

     254,849        256,152   

Other long-term assets:

    

Other assets

     7,825        8,195   

Note receivable – related party

     11,500        11,500   

Goodwill

     8,355        9,021   
  

 

 

   

 

 

 

Total other assets

     27,680        28,716   
  

 

 

   

 

 

 

Total assets

   $ 344,027      $ 358,258   
  

 

 

   

 

 

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

    

Current liabilities:

    

Accounts payable

   $ 11,948      $ 12,864   

Accounts payable — related party

     18,922        15,634   

Accrued liabilities

     22,235        29,972   

Derivative liabilities

     1,516        3,908   

Asset retirement obligations

     968        818   

Liabilities held for sale

     7,169        8,416   
  

 

 

   

 

 

 

Total current liabilities

     62,758        71,612   
  

 

 

   

 

 

 

Long-term liabilities:

    

Asset retirement obligations

     10,750        11,140   

Accrued liabilities

     6,822        7,548   

Deferred income taxes

     17,722        16,483   

Loan payable

     39,766        32,766   

Derivative liabilities

     2,038        4,882   
  

 

 

   

 

 

 

Total long-term liabilities

     77,098        72,819   
  

 

 

   

 

 

 

Total liabilities

     139,856        144,431   

Commitments and contingencies

    

Shareholders’ equity:

    

Common shares, $0.01 par value, 1,000,000,000 shares authorized; 369,304,453 shares issued and outstanding as of June 30, 2013 and 368,748,592 shares issued and outstanding as of December 31, 2012

     3,693        3,687   

Additional paid-in capital

     538,837        537,962   

Accumulated other comprehensive loss

     (44,391     (28,012

Accumulated deficit

     (293,968     (299,810
  

 

 

   

 

 

 

Total shareholders’ equity

     204,171        213,827   
  

 

 

   

 

 

 

Total liabilities and shareholders’ equity

   $ 344,027      $ 358,258   
  

 

 

   

 

 

 

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

 

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Table of Contents

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)

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

 

     For the Three Months Ended
June 30,
    For the Six Months Ended
June 30,
 
     2013     2012     2013     2012  
           (See Note 1)           (See Note 1)  

Revenues:

        

Oil and natural gas sales

   $ 29,455      $ 31,890      $ 62,180      $ 66,557   

Sales of purchased natural gas

     1,966        2,001        4,240        3,663   

Other

     342        537        855        1,714   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     31,763        34,428        67,275        71,934   

Costs and expenses:

        

Production

     3,328        4,293        8,855        7,928   

Exploration, abandonment and impairment

     11,885        6,883        15,749        9,679   

Cost of purchased natural gas

     1,866        1,900        4,046        3,636   

Seismic and other exploration

     1,090        848        1,333        1,511   

Revaluation of contingent consideration

     (5,000     —          (5,000     —     

General and administrative

     6,893        9,280        14,416        18,557   

Depreciation, depletion and amortization

     9,581        9,382        18,557        18,551   

Accretion of asset retirement obligations

     124        164        253        415   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     29,767        32,750        58,209        60,277   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     1,996        1,678        9,066        11,657   

Other income (expense):

        

Interest and other expense

     (955     (2,018     (1,845     (5,277

Interest and other income

     307        348        682        482   

Gain on commodity derivative contracts

     4,278        14,304        3,502        1,869   

Foreign exchange (loss) gain

     (2,543     (1,073     (3,030     3,199   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other income (expense)

     1,087        11,561        (691     273   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations before income taxes

     3,083        13,239        8,375        11,930   

Current income tax expense

     (528     (422     (1,867     (2,442

Deferred income tax benefit (expense)

     348        (4,247     (573     (2,388
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income from continuing operations

     2,903        8,570        5,935        7,100   

Loss from discontinued operations before income taxes

     —          (4,485     (93     (4,662

Gain on disposal of discontinued operations

     —          27,214        —          27,214   

Income tax provision

     —          (6,193     —          (8,173
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) from discontinued operations

     —          16,536        (93     14,379   

Net income

   $ 2,903      $ 25,106      $ 5,842      $ 21,479   

Other comprehensive income (loss):

        

Foreign currency translation adjustment

     (13,543     1,141        (16,379     14,504   
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

   $ (10,640   $ 26,247      $ (10,537   $ 35,983   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income per common share:

        

Basic net income per common share:

        

Continuing operations

   $ 0.01      $ 0.02      $ 0.02      $ 0.02   

Discontinued operations

   $ 0.00      $ 0.05      $ 0.00      $ 0.04   

Weighted average common shares outstanding

     368,936        366,536        368,911        366,486   

Diluted net income per common share:

        

Continuing operations

   $ 0.01      $ 0.02      $ 0.02      $ 0.02   

Discontinued operations

   $ 0.00      $ 0.05      $ 0.00      $ 0.04   

Weighted average common and common equivalent shares outstanding

     368,936        368,855        368,911        368,288   

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, 2012

     368,749       $ 3,687       $ 537,962      $ (28,012   $ (299,810   $ 213,827   

Issuance of restricted stock units

     555         6         (6     —         —         —    

Share-based compensation

     —          —          881        —         —         881   

Foreign currency translation adjustments

     —          —          —         (16,379     —         (16,379

Net income

     —          —          —         —         5,842        5,842   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance at June 30, 2013

     369,304       $ 3,693       $ 538,837      $ (44,391   $ (293,968   $ 204,171   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

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 Six Months
Ended June 30,
 
     2013     2012  
           (See Note 1)  

Operating activities:

    

Net income

   $ 5,842      $ 21,479   

Adjustment for net loss (income) from discontinued operations

     93        (14,379
  

 

 

   

 

 

 

Net income from continuing operations

     5,935        7,100   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Share-based compensation

     881        1,103   

Foreign currency loss

     2,138        1,972   

Unrealized gain on commodity derivative contracts

     (5,238     (4,116

Amortization of loan financing costs

     256        645   

Deferred income tax expense

     573        2,388   

Exploration, abandonment and impairment

     15,749        9,679   

Depreciation, depletion and amortization

     18,557        18,551   

Accretion of asset retirement obligations

     253        415   

Revaluation of contingent consideration

     (5,000     —    

Changes in operating assets and liabilities, net of effect of acquisitions:

    

Accounts receivable

     10,432        (12,332

Prepaid expenses and other assets

     141        1,584   

Accounts payable and accrued liabilities

     11,045        21,024   
  

 

 

   

 

 

 

Net cash provided by operating activities from continuing operations

     55,722        48,013   

Net cash used in operating activities from discontinued operations

     (1,071     (33,154
  

 

 

   

 

 

 

Net cash provided by operating activities

     54,651        14,859   

Investing activities:

    

Additions to oil and natural gas properties

     (52,320     (30,685

Additions to equipment and other properties

     (7,925     (2

Restricted cash

     (206     1,059   
  

 

 

   

 

 

 

Net cash used in investing activities from continuing operations

     (60,451     (29,628

Net cash provided by investing activities from discontinued operations

     1,016        154,871   
  

 

 

   

 

 

 

Net cash (used in) provided by investing activities

     (59,435     125,243   

Financing activities:

    

Exercise of stock options and warrants

     —         600   

Tax withholding on restricted stock units

     —         52   

Loan proceeds

     22,885        9,974   

Loan proceeds—related party

     —         11,000   

Loan repayment

     (15,885     (62,923

Loan financing costs

     —         (250

Loan repayment—related party

     —         (84,000
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities from continuing operations

     7,000        (125,547

Net cash used in financing activities from discontinued operations

     —         (2,180
  

 

 

   

 

 

 

Net cash provided by (used in) financing activities

     7,000        (127,727

Effect of exchange rate changes on cash

     (1,064     388   

Net increase in cash and cash equivalents

     1,152        12,763   

Cash and cash equivalents, beginning of year

     14,768        15,116   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 15,920      $ 27,879   
  

 

 

   

 

 

 

Supplemental disclosures:

    

Cash paid for interest

   $ 1,539      $ 4,459   
  

 

 

   

 

 

 

Cash paid for taxes

   $ 1,448      $ 2,485   
  

 

 

   

 

 

 

Supplemental non-cash investing and financing activities:

    

Note receivable—related party from sale of oilfield services business

   $ —       $ 11,500   

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 have established, yet underexplored petroleum systems, have stable governments, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of June 30, 2013, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

Basis of presentation

Our consolidated financial statements are expressed in U.S. Dollars and have been prepared by management in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). All amounts in these notes to the consolidated financial statements are in U.S. Dollars unless otherwise indicated. We have prepared the accompanying unaudited interim consolidated financial statements pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”), and in the opinion of management, such consolidated financial statements reflect all adjustments necessary to present fairly the consolidated financial position of TransAtlantic at June 30, 2013 and its results of operations and cash flows for the periods presented. We have omitted certain information and disclosures normally included in annual consolidated 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 consolidated 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, 2012. Certain prior period amounts have been reclassified to conform to the current period presentation.

In preparing the accompanying consolidated financial statements, management has made certain estimates and assumptions that affect reported amounts in the consolidated 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.

Reclassification

As reported in our Annual Report on Form 10-K for the year ended December 31, 2012, during the three and six months ended June 30, 2012, we reclassified certain amounts previously reported on our consolidated statements of comprehensive income (loss) to conform to current year presentation. Specifically, we reclassified the revenue and cost related to natural gas purchased from third parties. For the three and six months ended June 30, 2012, these reclassifications increased total revenues and costs and expenses by approximately $1.9 million and $3.6 million, respectively.

Revision of prior period financial statements and out-of-period adjustments

During the three months ended September 30, 2012, we identified and corrected errors that originated in prior periods. We assessed the materiality of the errors in accordance with the SEC guidance on considering the effects of prior period misstatements based on an analysis of quantitative and qualitative factors. Based on this analysis, we determined that the errors were immaterial to each of the prior reporting periods affected and, therefore, amendments of reports previously filed with the SEC were not required. However, we also concluded that not correcting the errors in our 2012 year-end consolidated financial statements would have materially understated results for the year ended December 31, 2012. Accordingly, we have reflected the correction of these prior period errors in the periods in which they originated and revised our consolidated statements of comprehensive income (loss) for the three and six months ended June 30, 2012 and our consolidated statements of cash flows for the six months ended June 30, 2012 in this Quarterly Report on Form 10-Q.

These errors consisted mainly of accrued liabilities that should have been recorded in prior periods, inappropriate recognition of receivable balances, and other minor corrections with immaterial impact to other miscellaneous accounts.

Additionally, during the three months ended March 31, 2013, we identified and corrected errors previously reported on our consolidated statements of cash flows. As a result, we increased the “Exploration, abandonment and impairment” sub-caption, which is an adjustment to reconcile net income (loss) to net cash provided by operating activities, and increased the cash used in investing activities related to “Additions to oil and natural gas properties” by $2.2 million for the six months ended June 30, 2012, as we previously did not include the cash portion of additions to oil and natural gas properties in investing activities for dry hole expenses that were recognized in the same period as the related cash disbursed. These amounts had also been excluded from the adjustment to reconcile net income (loss) to net cash provided by operating activities.

 

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We assessed the materiality of the errors in accordance with the SEC guidance on considering the effects of prior period misstatements based on an analysis of quantitative and qualitative factors. Based on this analysis, we determined that the errors were immaterial to each of the prior reporting periods affected and, therefore, amendments of reports previously filed with the SEC were not required. Accordingly, we have reflected the correction of these prior period errors in the periods in which they originated and revised our consolidated statement of cash flows for the six months ended June 30, 2012 in this Quarterly Report on Form 10-Q.

The following shows the effect of the out-of-period adjustments and reclassifications on the Company’s consolidated statement of comprehensive income (loss) for the three months ended June 30, 2012 (in thousands):

 

     As Reported     Correction     As Revised  

For the three months ended June 30, 2012

      

Total revenues

   $ 32,528      $ 1,900      $ 34,428   

Total costs and expenses

     (31,894     (856     (32,750

Total other income

     11,290        271        11,561   
  

 

 

   

 

 

   

 

 

 

Income from continuing operations before income taxes

     11,924        1,315        13,239   

Net income from continuing operations

     7,860        710        8,570   

Net income from discontinued operations

     15,052        1,484        16,536   
  

 

 

   

 

 

   

 

 

 

Net income

     22,912        2,194        25,106   

Foreign currency translation adjustment

     345        796        1,141   
  

 

 

   

 

 

   

 

 

 

Comprehensive income

   $ 23,257      $ 2,990      $ 26,247   
  

 

 

   

 

 

   

 

 

 

The following shows the effect of the out-of-period adjustments and reclassifications on the Company’s consolidated statement of comprehensive income (loss) for the six months ended June 30, 2012 (in thousands):

 

     As Reported     Correction     As Revised  

For the six months ended June 30, 2012

      

Total revenues

   $ 67,463      $ 4,471      $ 71,934   

Total costs and expenses

     (58,158     (2,119     (60,277

Total other income

     141        132        273   
  

 

 

   

 

 

   

 

 

 

Income from continuing operations before income taxes

     9,446        2,484        11,930   

Net income from continuing operations

     5,221        1,879        7,100   

Net income from discontinued operations

     12,895        1,484        14,379   
  

 

 

   

 

 

   

 

 

 

Net income

     18,116        3,363        21,479   

Foreign currency translation adjustment

     14,719        (215     14,504   
  

 

 

   

 

 

   

 

 

 

Comprehensive income

   $ 32,835      $ 3,148      $ 35,983   
  

 

 

   

 

 

   

 

 

 

The following shows the effect of the out-of-period adjustments and reclassifications on our consolidated statement of cash flows for the six months ended June 30, 2012 (in thousands):

 

     As Reported     Correction     As Revised  

For the six months ended June 30, 2012

      

Operating activities:

      

Exploration, abandonment and impairment

   $ 7,464      $ 2,215      $ 9,679   

Other

     39,495        (1,161     38,334   

Net cash provided by operating activities from continuing operations

     46,959        1,054        48,013   

Net cash provided by operating activities

     12,321        2,538        14,859   

Investing activities:

      

Additions to oil and natural gas properties

     (27,937     (2,748     (30,685

Net cash used in investing activities from continuing operations

     (26,880     (2,748     (29,628

Net cash provided by (used in) investing activities

     127,991        (2,748     125,243   

Financing activities:

      

Tax withholding on restricted stock units

     (158     210        52   

Net cash (used in) provided by financing activities from continuing operations

     (125,757     210        (125,547

Net cash (used in) provided by financing activities

   $ (127,937   $ 210      $ (127,727

 

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2. Recent accounting policies

In February 2013, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-02, New Disclosures for Items Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 requires reclassification adjustments for items that are reclassified out of accumulated other comprehensive income to net income to be presented in the statements where the components of net income and the components of other comprehensive income are presented or in the footnotes to the financial statements. Additionally, the amendment requires cross-referencing to other disclosures currently required for other reclassification items. The amendments were effective for interim and annual reporting periods beginning after December 15, 2012. The adoption of ASU 2013-02 did not have a material impact on our consolidated financial statements.

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

3. Discontinued operations

Discontinued operations in Morocco

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

The following shows our assets and liabilities held for sale at June 30, 2013 and December 31, 2012:

 

     June 30, 2013      December 31, 2012  
     (in thousands)  

Cash

   $ 24       $ 93   

Other assets (1)

     510         1,526   
  

 

 

    

 

 

 

Total assets held for sale

   $ 534       $ 1,619   
  

 

 

    

 

 

 

Accrued expenses and other liabilities

   $ 7,169       $ 8,416   
  

 

 

    

 

 

 

Total liabilities held for sale

   $ 7,169       $ 8,416   
  

 

 

    

 

 

 

 

(1) Other assets consist primarily of $0.5 million and $1.5 million of restricted cash at June 30, 2013 and December 31, 2012, respectively.

Discontinued operations of oilfield services business

On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”), to a joint venture owned by Dalea Partners, LP (“Dalea”) and funds advised by Abraaj Investment Management Limited for an aggregate purchase price of $168.5 million, consisting of approximately $157.0 million in cash and a $11.5 million promissory note from Dalea. The promissory note bears interest at a rate of 3.0% per annum and is guaranteed by Mr. Mitchell. We have presented the oilfield services segment operating results as discontinued operations for the three and six months ended June 30, 2012.

Our operating results from discontinued operations for the three and six months ended June 30, 2013 and 2012 are summarized as follows:

 

     For the Three Months Ended
June 30,
    For the Six Months Ended
June 30,
 
     2013     2012     2013     2012  
     (in thousands)  

Total revenues

   $ —        $ 10,672      $ —        $ 20,956   

Total costs and expenses

     (52     (15,325     (138     (24,851

Total other income (expense)

     52        168        45        (767
  

 

 

   

 

 

   

 

 

   

 

 

 

Loss from discontinued operations before income taxes

     —          (4,485     (93     (4,662

Gain on disposal of discontinued operations

     —          27,214        —          27,214   

Income tax provision

     —          (6,193     —          (8,173
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) from discontinued operations

   $ —        $ 16,536      $ (93   $ 14,379   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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4. Property and equipment

Oil and natural gas properties

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

 

     June 30, 2013     December 31, 2012  
     (in thousands)  

Oil and natural gas properties, proved:

    

Turkey

   $ 248,638      $ 229,462   

Bulgaria

     1,853        2,036   
  

 

 

   

 

 

 

Total oil and natural gas properties, proved

     250,491        231,498   

Oil and natural gas properties, unproved:

    

Turkey

     56,169        68,938   
  

 

 

   

 

 

 

Gross oil and natural gas properties

     306,660        300,436   

Accumulated depletion

     (84,986     (74,099
  

 

 

   

 

 

 

Net oil and natural gas properties

   $ 221,674      $ 226,337   
  

 

 

   

 

 

 

At June 30, 2013 and December 31, 2012, we excluded $0.8 million and $1.8 million, respectively, from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At June 30, 2013, the capitalized costs of our net oil and natural gas properties included $42.0 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $122.7 million relating to well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.

At December 31, 2012, the capitalized costs of our oil and natural gas properties included $49.5 million relating to acquisition costs of proved properties before a fourth quarter 2012 impairment charge, which are being amortized by the unit-of-production method using total proved reserves, and $105.3 million relating to well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.

During the six months ended June 30, 2013, we incurred approximately $26.3 million in exploratory drilling costs, of which $4.3 million was included in exploration, abandonment and impairment expense, $17.0 million was reclassified from unproved properties to proved properties and $5.0 million remained capitalized at June 30, 2013. No exploratory well costs were reclassified to proved properties in the second quarter of 2012. Uncertainties affect the recoverability of costs of our oil and natural gas properties, as the recovery of the costs are dependent upon us maintaining licenses in good standing and achieving commercial production or sale.

Dry hole costs

As of June 30, 2013, we had $4.3 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 of the Pancarkoy-1 well, commercial natural gas production could not be sustained due to the high amount of water production. A third fracture stimulation of the Pancarkoy-1 well was performed in April 2012, but commercial production could not be sustained due to high water production. In the fourth quarter of 2012, we tested the up-hole interval of the well. A further fracture stimulation of this well was performed in the second quarter for 2013, but commercial production could not be sustained. As a result, we have classified this well as a dry hole during the three months ended June 30, 2013.

The Meneske-1 well was spud in November 2011, and we had capitalized $1.9 million of exploratory well costs for this well as of June 30, 2013. After further review, based on the results of other nearby wells and the expected high tie-in costs of the Meneske-1 well, we have classified this well as a dry hole during the three months ended June 30, 2013.

The Suleymaniye-2 well was spud in December 2011, and we had capitalized $0.9 million of exploratory well costs for this well as of June 30, 2013. After being evaluated for artificial lift and based on the results of other nearby wells, we have classified this well as a dry hole during the three months ended June 30, 2013.

Of the $7.3 million of dry hole costs expensed during the three months ended June 30, 2013, approximately $0.5 million was related to cash spent during the second quarter of 2013.

 

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Impairment and abandonment

We recorded $4.6 million in impairment and abandonment charges on our proved and unproved properties during the six months ended June 30, 2013, primarily related to our Malkara license. We recorded $1.5 million in impairment charges on our proved properties during the six months ended June 30, 2012, primarily due to downward revisions in natural gas reserves in our Alpullu field.

Equipment and other property

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

 

     June 30, 2013     December 31, 2012  
     (in thousands)  

Other equipment

   $ 2,583      $ 2,013   

Inventory

     24,361        20,517   

Gas gathering system and facilities

     4,973        5,369   

Vehicles

     234        131   

Office equipment and furniture

     7,792        7,717   
  

 

 

   

 

 

 

Gross equipment and other property

     39,943        35,747   

Accumulated depreciation

     (6,768     (5,932
  

 

 

   

 

 

 

Net equipment and other property

   $ 33,175      $ 29,815   
  

 

 

   

 

 

 

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

At June 30, 2013, we excluded $24.4 million of inventory and $0.4 million of office equipment and furniture from depreciation, as the inventory and office equipment and furniture had not been placed into service. At December 31, 2012, we excluded $20.5 million of inventory from depreciation, as the inventory had not been placed into service.

5. 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 crude oil pricing. We recognize unrealized and realized gains and losses related to these contracts on a fair value basis in our consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows. We are required under our amended and restated senior secured credit facility (as amended, the “Amended and Restated Credit Facility”) with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”) to hedge between 30% and 75% of our anticipated production volumes in Turkey.

For the three months ended June 30, 2013, we recorded a net gain on commodity derivative contracts of approximately $4.3 million, consisting of a $4.8 million unrealized gain related to changes in fair value and a $0.5 million realized loss for settled contracts. For the six months ended June 30, 2013, we recorded a net gain on commodity derivative contracts of $3.5 million, consisting of a $5.2 million unrealized gain related to changes in fair value and a $1.7 million realized loss for settled contracts.

For the three months ended June 30, 2012, we recorded a net gain on commodity derivative contracts of approximately $14.3 million consisting of a $15.1 million unrealized gain related to changes in fair value and a $0.8 million realized loss for settled contracts. For the six months ended June 30, 2012, we recorded a net gain on commodity derivative contracts of $1.9 million, consisting of a $4.1 million unrealized gain related to changes in fair value and a $2.2 million realized loss for settled contracts.

 

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At June 30, 2013 and December 31, 2012, 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 June 30, 2013

 

Type

   Period      Quantity
(Bbl/day)
     Weighted
Average
Minimum
Price (per Bbl)
     Weighted
Average
Maximum Price
(per Bbl)
     Estimated Fair
Value of Asset
 
                                 (in thousands)  

Collar

     July 1, 2013—December 31, 2013         775       $ 82.26       $ 121.36       $ 13   

Collar

     January 1, 2014—December 31, 2014         662       $ 80.83       $ 118.07         134   
              

 

 

 
               $ 147   
              

 

 

 

 

            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

     July 1, 2013—December 31, 2013         831       $ 85.00       $ 97.13       $ 162.13       $ (837

Three-way collar contract

     January 1, 2014—December 31, 2014         726       $ 85.00       $ 97.13       $ 162.13         (1,292

Three-way collar contract

     January 1, 2015—December 31, 2015         1,016       $ 85.00       $ 91.88       $ 151.88         (1,572
                 

 

 

 
                  $ (3,701
                 

 

 

 

Fair Value of Derivative Instruments as of December 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

     January 1, 2013—December 31, 2013         775       $ 82.26       $ 121.36       $ (253

Collar

     January 1, 2014—December 31, 2014         662       $ 80.83       $ 118.07         (292
              

 

 

 
               $ (545
              

 

 

 

 

 

            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       $ (3,655

Three-way collar contract

     January 1, 2014—December 31, 2014         726       $ 85.00       $ 97.13       $ 162.13         (2,150

Three-way collar contract

     January 1, 2015—December 31, 2015         1,016       $ 85.00       $ 91.88       $ 151.88         (2,440
                 

 

 

 
                  $ (8,245
                 

 

 

 

 

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6. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations (“ARO”) for the six months ended June 30, 2013 and for the year ended December 31, 2012:

 

     June 30, 2013     December 31, 2012  
     (in thousands)  

Asset retirement obligations at beginning of period

   $ 11,958      $ 13,534   

Change in estimates

     (8     (3,868

Liabilities settled

     (107     (110

Foreign exchange change effect

     (870     793   

Additions

     492        899   

Accretion expense

     253        710   
  

 

 

   

 

 

 

Asset retirement obligations at end of period

     11,718        11,958   

Less: current portion

     968        818   
  

 

 

   

 

 

 

Long-term portion

   $ 10,750      $ 11,140   
  

 

 

   

 

 

 

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

7. Loan payable

As of the indicated dates, our debt consisted of the following:

 

     June 30, 2013      December 31, 2012  
     (in thousands)  

Floating Rate Debt

     

Amended and Restated Credit Facility

   $ 39,766       $ 32,766   
  

 

 

    

 

 

 

Loan payable

   $ 39,766       $ 32,766   
  

 

 

    

 

 

 

Amended and Restated Senior Secured Credit Facility

On May 18, 2011, DMLP, Ltd., TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd., TransAtlantic Turkey, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayive Ticaret A.Ş. and Amity Oil International Pty Ltd (collectively, the “Borrowers”) entered into the Amended and Restated Credit Facility. Each of the Borrowers is our wholly owned subsidiary. The Amended and Restated Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd (“TransAtlantic Worldwide”).

Availability under the Amended and Restated Credit Facility is subject to a borrowing base. The borrowing base is re-determined quarterly on January 1st, April 1st, July 1st and October 1st of each year. As of July 4, 2013 our borrowing base was $58.2 million. Loans under the Amended and Restated Credit Facility accrue interest at a rate of three-month LIBOR plus 5.50% per annum.

At June 30, 2013, we had borrowed $39.8 million under the Amended and Restated Credit Facility.

TBNG credit facility

On June 18, 2013, our wholly owned subsidiary, Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”), entered into a 78.8 million New Turkish Lira (approximately $40.9 million at June 30, 2013) unsecured line of credit with a Turkish bank, of which 60 million New Turkish Lira is available in cash for TBNG and 18.8 million New Turkish Lira is available in the form of non-cash bank guarantees and letters of credit for TBNG and several other of our wholly owned subsidiaries operating in Turkey. The interest rate will be established at the time of each borrowing, and each borrowing is expected to have a two-year term. As of June 30, 2013, there were no borrowings under this credit facility.

8. Contingencies relating to production leases and exploration permits

Selmo

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

 

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Morocco

In the second quarter of 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew down our $1.0 million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we plan to pursue a settlement with the Moroccan government for a lesser amount, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during the second quarter of 2012 for this contractual obligation.

Aglen

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

Direct Petroleum

In July 2013, we entered into a second amendment (the “Amendment”) to our Purchase Agreement (the “Purchase Agreement”) with Direct Petroleum Exploration, LLC, formerly Direct Petroleum Exploration, Inc. (“Direct”). Pursuant to the Amendment, we agreed to issue 3,510,743 common shares to Direct as partial payment of certain liquidated damages due under the Purchase Agreement. The number of shares was calculated by dividing $2.5 million by the volume weighted average price per share of our common shares on the NYSE MKT for the ten trading days prior to July 2, 2013. This share issuance will be recorded in the three months ended September 30, 2013 in accordance with Accounting Standard Codification (“ASC”) 855, Subsequent Events (“ASC 855”) and is expected to have a dilutive effect on future earnings per share calculations.

The parties also agreed that Direct is not eligible for any liquidated damages relating to the coring of the Etropole shale formation, which resulted in the reversal of the $5.0 million contingent liability recorded in 2011, which we recognized in our consolidated statement of comprehensive income (loss) under the caption “Revaluation of contingent consideration” during the three and six months ended June 30, 2013.

The Amendment sets forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. In the event that we do not meet the drilling and testing obligations by May 1, 2014, the Amendment requires us to issue an additional $2.5 million in common shares to Direct. As such, the $2.5 million contingent liability, recorded in 2011, will remain as of June 30, 2013.

Additionally, the Amendment provides that if the Bulgarian government issues a production concession over the Stefenetz Concession Area of at least 200,000 acres, Direct will be entitled to a payment of $10.0 million in common shares, or a pro rata amount if the production concession is less than 200,000 acres.

9. Shareholders’ equity

Restricted stock units

Share-based compensation expense of approximately $0.5 million and $0.9 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three and six months ended June 30, 2013, respectively. We recorded share-based compensation expense of $0.6 million and $1.1 million for the three and six months ended June 30, 2012, respectively.

As of June 30, 2013, we had approximately $2.6 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.8 years.

Earnings per share

We account for earnings per share in accordance with ASC Subtopic 260-10, Earnings Per Share (“ASC 260-10”). ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted. Basic earnings per common share for the three and six months ended June 30, 2013 and 2012 equals net income divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding RSUs. Diluted earnings per common share for the three and six months ended June 30, 2013 and 2012 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes stock options, RSUs and warrants, whether exercisable or not. The computation of diluted earnings per common share excluded 7,300,000 and 7,455,206 antidilutive common share equivalents from the three months ended June 30, 2013 and 2012, respectively, and 7,300,000 and 7,464,463 antidilutive common share equivalents from the six months ended June 30, 2013 and 2012, respectively.

 

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

 

     Three Months Ended
June 30,
     Six Months Ended
June 30,
 

(in thousands, except per share amounts)

   2013      2012      2013     2012  

Net income from continuing operations

   $ 2,903       $ 8,570       $ 5,935      $ 7,100   

Net income (loss) from discontinued operations

   $ —         $ 16,536       $ (93   $ 14,379   

Basic net income per common share:

          

Shares:

          

Weighted average shares outstanding

     368,936         366,536         368,911        366,486   
  

 

 

    

 

 

    

 

 

   

 

 

 

Basic net income per common share:

          

Continuing operations

   $ 0.01       $ 0.02       $ 0.02      $ 0.02   
  

 

 

    

 

 

    

 

 

   

 

 

 

Discontinued operations

   $ 0.00       $ 0.05       $ 0.00      $ 0.04   
  

 

 

    

 

 

    

 

 

   

 

 

 

Diluted net income per common share:

          

Shares:

          

Weighted average number of common shares outstanding

     368,936         366,536         368,911        366,486   

Dilutive effect of:

          

Restricted stock units

     —           2,169         —          1,645   

Stock options

     —           150         —          157   
  

 

 

    

 

 

    

 

 

   

 

 

 

Weighted average common and common equivalent shares outstanding

     368,936         368,855         368,911        368,288   
  

 

 

    

 

 

    

 

 

   

 

 

 

Diluted net income per common share:

          

Continuing operations

   $ 0.01       $ 0.02       $ 0.02      $ 0.02   
  

 

 

    

 

 

    

 

 

   

 

 

 

Discontinued operations

   $ 0.00       $ 0.05       $ 0.00      $ 0.04   
  

 

 

    

 

 

    

 

 

   

 

 

 

Additionally, we had a contingent liability at June 30, 2013 of approximately $2.5 million that is payable in our common shares. At the June 28, 2012 closing price of our common shares, this liability represented 3,623,188 common shares that could be potentially dilutive to future earnings per share calculations (see Note 8).

10. 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:

 

     Corporate     Romania     Turkey      Bulgaria     Total  
     (in thousands)  

For the three months ended June 30, 2013

           

Total revenues

   $ 2     $ —       $ 31,733       $ 28      $ 31,763   

Income (loss) from continuing operations before income taxes

     (3,119     (35     1,525         4,712        3,083   

Capital expenditures

   $ —       $ —       $ 27,147       $ —       $ 27,147   

For the three months ended June 30, 2012

           

Total revenues

   $ —       $ —       $ 34,344       $ 84      $ 34,428   

Income (loss) from continuing operations before income taxes

     (1,835     (357     17,631         (2,200     13,239   

Capital expenditures

   $ —       $ —       $ 13,760       $ —       $ 13,760   

For the six months ended June 30, 2013

           

Total revenues

   $ 2     $ —       $ 67,177       $ 96      $ 67,275   

Income (loss) from continuing operations before income taxes

     (6,076     (58     9,897         4,612        8,375   

Capital expenditures

   $ —       $ —       $ 45,846       $ —       $ 45,846   

For the six months ended June 30, 2012

           

Total revenues

   $ —       $ —       $ 71,785       $ 149      $ 71,934   

Income (loss) from continuing operations before income taxes

     (7,274     (655     22,259         (2,400     11,930   

Capital expenditures

   $ —       $ —       $ 27,771       $ 168      $ 27,939   

Segment assets

           

June 30, 2013

   $ 14,675      $ 38      $ 327,042       $ 1,738      $ 343,493 (1) 

December 31, 2012

   $ 14,825      $ 105      $ 339,752       $ 1,957      $ 356,639 (1) 

Goodwill

           

June 30, 2013

   $ —       $ —       $ 8,355       $ —       $ 8,355   

December 31, 2012

   $ —       $ —       $ 9,021       $ —       $ 9,021   

 

(1) Excludes assets held for sale from our discontinued Moroccan operations of $0.5 million and $1.6 million at June 30, 2013 and December 31, 2012, respectively.

 

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11. Financial instruments

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities and our loan payable were each estimated to have a fair value approximating the carrying amount at June 30, 2013 and December 31, 2012, due to the short maturity of those instruments.

Interest rate risk

We are exposed to interest rate risk as a result of our variable rate short-term cash holdings and borrowings under the Amended and Restated Credit Facility.

Foreign currency risk

We have underlying foreign currency exchange rate exposure. Our currency exposures relate to transactions denominated in the Canadian Dollar, Bulgarian Lev, European Union Euro, Romanian New Leu, 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 June 30, 2013, we had 25.7 million New Turkish Lira (approximately $13.4 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 oil and natural gas. Commodity prices are affected by many factors, including, but not limited to, supply and demand. At June 30, 2013 and December 31, 2012, we were a party to commodity derivative contracts.

Concentration of credit risk

The majority of our receivables are within the oil and natural gas industry, primarily from our industry partners and from government agencies. Included in receivables are amounts due from Turkiye Petrolleri Anonim Ortakligi, the national oil company of Turkey, and Turkiye Petrol Rafinerileri A.Ş., a privately owned oil refinery in Turkey, which purchase the majority of our oil production. The receivables are not collateralized. To date, we have experienced minimal bad debts. 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 June 30, 2013:

 

     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:

          

Derivative financial instruments (commodity)

   $ —        $ (3,554   $ —        $ (3,554
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ —        $ (3,554   $ —        $ (3,554
  

 

 

    

 

 

   

 

 

    

 

 

 

 

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

          

Derivative financial instruments (commodity)

   $ —        $ (8,790   $ —        $ (8,790
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ —        $ (8,790   $ —        $ (8,790
  

 

 

    

 

 

   

 

 

    

 

 

 

We remeasure our derivative contracts on a recurring basis, with changes flowing through earnings. All other financial instruments are recorded at carrying value. The carrying value of these other financial instruments approximates fair value, as they are subject to short-term floating interest rates that approximate the rates available to us.

12. Related party transactions

The following table summarizes related party accounts receivable and accounts payable as of June 30, 2013 and December 31, 2012:

 

     June 30,
2013
     December 31,
2012
 
     (in thousands)  

Related party accounts receivable:

     

Viking International master services agreement

   $ 629       $ 313   

Riata Management service agreement

     33         —    

Dalea promissory note

     —          106   
  

 

 

    

 

 

 

Total related party accounts receivable

   $ 662       $ 419   
  

 

 

    

 

 

 

Related party accounts payable:

     

Viking International master services agreement

   $ 18,803       $ 15,467   

Riata Management service agreement

     119         167   
  

 

 

    

 

 

 

Total related party accounts payable

   $ 18,922       $ 15,634   
  

 

 

    

 

 

 

For the three and six months ended June 30, 2013 and 2012, we incurred expenditures of $17.5 million and $37.7 million and $13.5 million and $15.6 million, respectively, related to our various related party agreements.

13. Subsequent events

In July 2013, we entered into the Amendment to the Purchase Agreement with Direct. The Company recorded the impact of the Amendment in the second quarter of 2013 as an adjusting subsequent event in accordance with ASC 855 (see Note 8).

 

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

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

Executive Overview

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored petroleum systems, have stable governments, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of June 30, 2013, we held interests in approximately 3.9 million net onshore acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of June 30, 2013, approximately 40% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

Financial and Operational Performance Highlights. Highlights of our financial and operational performance for the second quarter of 2013 include:

 

   

We reported $2.9 million of net income from continuing operations for the three months ended June 30, 2013, as compared to $8.6 million for the same period in 2012.

 

   

We derived 68.2% of our revenues from the production of oil and 24.6% of our revenues from the production of natural gas during the three months ended June 30, 2013.

 

   

Total oil and natural gas sales revenues decreased 7.6% to $29.5 million for the quarter ended June 30, 2013 from $31.9 million in the same period in 2012. The decrease was primarily the result of lower production of 47 thousand barrels of oil equivalent (“Mboe”), which decreased revenues by $3.6 million. This decrease was partially offset by an increase in our average realized price per Boe, which increased revenues by $1.2 million.

 

   

Total net production was 230 thousand barrels (“Mbbls”) of oil and 816 million cubic feet (“Mmcf”) of natural gas, as compared to 233 Mbbls of oil and 1,081 Mmcf of natural gas for the same period in 2012.

 

   

For the quarter ended June 30, 2013, we produced an average of 4,022 net barrels of oil equivalent (“Boe”) per day, as compared to 4,538 Boe per day for the same period in 2012.

 

   

For the quarter ended June 30, 2013, we incurred $28.1 million in capital expenditures, including license acquisition and seismic expenditures from continuing operations, as compared to $14.7 million for the quarter ended June 30, 2012.

 

   

As of June 30, 2013, we had $39.8 million in outstanding debt and no short-term borrowings, as compared to $32.8 million in outstanding debt and no short-term borrowings as of June 30, 2012.

Recent Developments

Amendment of Purchase Agreement. In July 2013, our wholly owned subsidiary, TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”), entered into a second amendment (the “Amendment”) to our purchase agreement (the “Purchase Agreement”) with Direct Petroleum Exploration, LLC (formerly Direct Petroleum Exploration, Inc.) (“Direct”). Pursuant to the Amendment, we will issue 3,510,743 common shares to Direct as partial payment of certain liquidated damages due under the Purchase Agreement. The parties also agreed that Direct is not eligible for any liquidated damages relating to the coring of the Etropole shale formation, which resulted in the reversal of a $5.0 million contingent liability recorded in 2011. The Amendment sets forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. In the event that we do not meet the drilling and testing obligations by May 1, 2014, the Amendment requires us to issue an additional $2.5 million in common shares to Direct. Additionally, the Amendment provides that if the Bulgarian government issues a production concession over the Stefenetz Concession Area, Direct will be entitled to a payment of $10.0 million in common shares, or a pro rata amount if the production concession is less than 200,000 acres.

TBNG Credit Facility. On June 18, 2013, our wholly owned subsidiary, Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) entered into a 78.8 million New Turkish Lira (approximately $40.9 million at June 30, 2013) unsecured line of credit with a Turkish bank, of which 60 million New Turkish Lira is available in cash for TBNG and 18.8 million New Turkish Lira is available in the form of non-cash bank guarantees and letters of credit for TBNG and several other of our wholly owned subsidiaries operating in Turkey. The interest rate will be established at the time of each borrowing, and each borrowing is expected to have a two-year term. As of June 30, 2013, there were no borrowings under this credit facility.

 

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Acquisition of Additional Exploration Acreage in Southeastern Turkey. On May 20, 2013, we completed the acquisition of three exploration licenses from ARAR Petrol ve Gaz Arama Uretim Pazarlama A.S. The exploration licenses, which cover an aggregate of 150,000 acres, are located adjacent to our Molla exploration licenses in southeastern Turkey. We are the 100% owner and operator of the licenses.

Relinquishment of Sud Craiova Exploration License. In 2012, the Romanian government temporarily suspended unconventional exploration of hydrocarbons, including fracture stimulation, pending a government review of unconventional drilling and completion techniques. As a result, on May 10, 2013, we notified the Romanian government that we were relinquishing our Sud Craiova exploration license, covering approximately 500,000 net onshore acres in Romania.

Second Quarter 2013 Operational Update

During the second quarter of 2013, we continued to develop our oil fields in southeastern Turkey and our Thrace Basin natural gas fields in northwestern Turkey.

Turkey-Southeast.

Molla. We completed three horizontal wells during the first half of 2013, including the Bahar-2H well, our first attempt to drill a horizontal well within the targeted Bedinan H-1 sand that is one of the primary producing zones for the Bahar-1 well. We were unable to encounter and stay within the target zone, and a two-stage frac resulted in uneconomic production. We plugged back to test the Hazro section, which tested at 170 barrels (“Bbls”) of oil per day. We may re-drill the well below 8,000 feet as a vertical Bedinan H-1 well.

We completed drilling the Catak-1, a vertical well targeting the Dadas shales and Bedinan sandstones. The well encountered multiple oil shows in the Mardin, Hazro, Dadas shale and first and third Bedinan sands. We drilled the Oba-1H, a Mardin horizontal well, which we are currently completing. We are currently drilling the lateral portion of the Goksu-5H, our fifth horizontal well targeting the Mardin zone, and expect to achieve target depth by the end of August 2013.

In May 2013, we commenced an 800 square km 3D seismic program over Molla and the surrounding areas, including northwest Arpatepe, which we expect to complete by the end of 2013 and interpret in the first half of 2014.

Selmo. We completed the Selmo-13H, our first horizontal well in the Selmo oil field. The well is currently producing approximately 200 Bbls of oil per day from the LSD zone from a natural completion. This was our first completion in the LSD zone. As a result of the success of Selmo-13H well, we plan to add additional LSD horizontal wells to our drilling schedule for the second half of 2013, in addition to the four horizontal wells we plan to drill in the MSD formation of the Selmo oil field.

Gaziantep. We completed the Alibey-1H and are currently testing the well. We expect to commence production from the well during the third quarter of 2013.

Turkey-Northwest.

In the first half of 2013, we completed three new wells and fracture stimulated six wells. We also recompleted two wells, which increased our Thrace Basin gross natural gas production to 25 Mmcf per day (“Mmcf/d”) or net production of 14 Mmcf/d in July 2013. We drilled our first horizontal well in the Thrace Basin, the DTD-19HK, and we completed a seven-stage fracture stimulation on the well during the third quarter of 2013.

We drilled the Gocerler-7 well, a vertical well targeting the Osmancik formation, during the third quarter of 2013. We are currently completing the well. During the second half of 2013, we plan to drill six shallow, vertical natural gas prospects in the northern part of the Thrace Basin using efficient drilling techniques and three additional horizontal wells in the southern part of the Thrace Basin.

Planned Operations

We continue to actively explore and develop our existing oil and natural gas properties in Turkey and Bulgaria. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and bringing these discoveries into production. For the remainder of 2013, we are focused on accomplishing the following objectives:

 

   

Increase Production. We plan to increase our oil and natural gas production in Turkey through exploration and development on our Molla, Thrace Basin, Selmo and Arpatepe licenses and production leases, including the application of fracture stimulation techniques and horizontal drilling.

 

   

Continue to Expand Fracture Stimulation Program. In 2012, our Thrace Basin fracture simulation program tested and defined deeper intervals and provided important lessons regarding hydraulic fracture stimulation design. In 2013, we plan to expand our application of fracture stimulation techniques in several of our exploration licenses in southeastern Turkey.

 

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Expand the Use of Horizontal Drilling. In 2012, we had initial horizontal drilling success with the Goksu-3H well on our Molla licenses and the Alibey-1 well on our Gaziantep licenses. During the second half of 2013, we anticipate our drilling in southeastern Turkey will include extensive use of horizontal drilling techniques, including seven wells on our Molla licenses and five wells at Selmo. We also plan to drill three horizontal wells on our Thrace Basin licenses.

 

   

Accelerate 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 positions, we are currently seeking joint venture partners for our exploration acreage in Bulgaria and Turkey and plan to continue this effort during the remainder of 2013.

Capital expenditures, including seismic expenditures, for the third and fourth quarters of 2013 are expected to range between $70 million and $90 million. Approximately 75% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling developmental and exploratory oil wells and acquiring seismic data at Molla, Selmo, Arpatepe and Gaziantep. Most of the remaining 25% of these anticipated expenditures will occur in the Thrace Basin, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Our projected 2013 capital budget is subject to change, and if cash on hand, borrowings from our amended and restated senior secured credit facility (as amended, the “Amended and Restated Credit Facility”) with Standard Bank Plc (“Standard Bank”) and BNP Paribas (Suisse) SA (“BNP Paribas”) and TBNG credit facility, and cash flow from operations are not sufficient to fund our capital expenditures, we will either curtail our discretionary capital expenditures or seek other funding sources.

We currently plan to execute the following drilling and exploration activities during the third and fourth quarters of 2013:

Turkey. We plan to continue our three-part strategy in Turkey: (i) the Molla horizontal program, (ii) the Selmo field redevelopment program, and (iii) the Thrace Basin development program. We plan to drill approximately 34 gross wells, 16 of which are expected to be drilled horizontally and approximately 65% of which will be fracture stimulated. 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 resume drilling the Deventci-R2 well on our Koynare Concession Area in the second half of 2013.

Other Matters

During our review procedures associated with our mid-year reserve analysis, we discovered that the future lease operating expenses used in our reserves calculation were overstated, resulting in an immaterial understatement of the present value of estimated future net revenues (“PV-10”) and standardized measure of discounted future net cash flows (“Standardized Measure”) as of December 31, 2012. The correction resulted in a proved reserve volume increase of approximately 19 Mboe, related to one of our oil fields where the economic life exceeds our remaining lease term. For the year ended December 31, 2012, this change in volumes had a negligible impact on the consolidated financial statements. A reconciliation of the reported and corrected PV-10 and Standardized Measure are presented below:

     As Reported     Change     As Corrected  
     (in thousands  

Total PV-10

   $ 511,078      $ 52,679      $ 563,757   

Future income taxes

     (106,411     (15,395     (121,806

Discount of future income taxes at 10% per annum

     31,210        5,437        36,647   
  

 

 

   

 

 

   

 

 

 

Standardized measure

   $ 435,877      $ 42,721      $ 478,598   

Discontinued Operations in Morocco

On June 27, 2011, we decided to discontinue our Moroccan operations. We have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for the three and six months ended June 30, 2013 and June 30, 2012, and they are not included in results from continuing operations.

Discontinued Operations of Oilfield Services Business

On June 13, 2012, we closed the sale of our oilfield services business, which was substantially comprised of our wholly owned subsidiaries Viking International Limited (“Viking International”) and Viking Geophysical Services, Ltd. (“Viking Geophysical”). We have presented the oilfield services segment operating results as discontinued operations for the three and six months ended June 30, 2012, and they are not included in results from continuing operations.

 

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Table of Contents

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, 2012 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, 2012.

Recent Accounting Pronouncements

In February 2013, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2013-02, New Disclosures for Items Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). ASU 2013-02 requires reclassification adjustments for items that are reclassified out of accumulated other comprehensive income to net income to be presented in the statements where the components of net income and the components of other comprehensive income are presented or in the footnotes to the financial statements. Additionally, the amendment requires cross-referencing to other disclosures currently required for other reclassification items. The amendments were effective for interim and annual reporting periods beginning after December 15, 2012. The adoption of ASU 2013-02 did not have a material impact on our consolidated financial statements.

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

Results of Operations—Three Months Ended June 30, 2013 Compared to Three Months Ended June 30, 2012

Our results of operations for the three months ended June 30, 2013 and 2012 were as follows:

 

    Three Months Ended June 30,     Change  
    2013     2012     2013-2012  
   

(in thousands of U.S. dollars, except per unit prices and production  volumes)

(as adjusted)

 

Production:

     

Oil (Mbbl)

    230        233        (3

Natural gas (Mmcf)

    816        1,081        (265

Total production (Mboe)

    366        413        (47

Average daily production (Boe/day)

    4,022        4,538        (516

Average prices:

     

Oil (per Bbl)

  $ 94.13      $ 97.49      $ (3.36

Natural gas (per Mcf)

    9.57        8.49        1.08   

Oil equivalent (per Boe)

    80.48        77.22        3.26   

Revenues:

     

Oil and natural gas sales

  $ 29,455      $ 31,890      $ (2,435

Sales of purchased natural gas

    1,966        2,001        (35

Other

    342        537        (195

Costs and expenses:

     

Production

  $ 3,328      $ 4,293      $ (965

Exploration, abandonment and impairment

    11,885        6,883        5,002   

Cost of purchased natural gas

    1,866        1,900        (34

Seismic and other exploration

    1,090        848        242   

Revaluation of contingent consideration

    (5,000     —         (5,000

General and administrative

    6,893        9,280        (2,387

Depreciation, depletion and amortization

    9,581        9,382        199   

Interest and other expense

    955        2,018        (1,063

 

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    Three Months Ended June 30,     Change  
    2013     2012     2013-2012  
   

(in thousands of U.S. dollars, except per unit prices and production  volumes)

(as adjusted)

 

Gain on commodity derivative contracts:

     

Cash settlements on commodity derivative contracts

  $ (484   $ (773   $ 289   

Non-cash change in fair value on commodity derivative contracts

    4,762        15,077        (10,315
 

 

 

   

 

 

   

 

 

 

Total gain on commodity derivative contracts

  $ 4,278      $ 14,304      $ (10,026

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $2.4 million to $29.5 million for the three months ended June 30, 2013, from $31.9 million realized in the same period in 2012. Of this decrease, $3.6 million resulted from lower production volumes of 47 Mboe. This was partially offset by $1.2 million from higher average realized prices per Boe due to producing a higher percentage of oil and a 10% increase in the price of natural gas by Boru Hatlari ile Petrol Tasima A.S. (“BOTAŞ”), effective October 1, 2012. For the three months ended June 30, 2013, our average price was $80.48 per Boe, as compared to $77.22 per Boe for the same period in 2012.

Production. Production expenses for the three months ended June 30, 2013 decreased to $3.3 million, from $4.3 million for the same period in 2012. The decrease was primarily attributable to $1.1 million of operating expenses billed back to our TBNG joint venture partners following a redetermination of operating costs billable to our joint venture partners.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended June 30, 2013 increased approximately $5.0 million to $11.9 million, from $6.9 million for the same period in 2012. Of the $11.9 million of exploration, abandonment and impairment costs, approximately $0.5 million was cash spent during the quarter. During the three months ended June 30, 2013, there were write-offs of three wells for $4.3 million, $1.9 million and $0.9 million. During the three months ended June 30, 2012, there were write-offs of two wells for $2.1 and $1.7 million. Additionally, during the three months ended June 30, 2013, we recorded $4.6 million of impairment charges which primarily related to our Malkara license as compared to $1.5 million of impairment charges for the same period in 2012.

Seismic and Other Exploration. Seismic and other exploration costs increased to $1.1 million for the three months ended June 30, 2013, as compared to $0.9 million for the same period in 2012.

Revaluation of Contingent Consideration. As a result of the Amendment to the Purchase Agreement with Direct, we recognized the reversal of the $5.0 million contingent liability, originally recorded in 2011, during the three months ended June 30, 2013.

General and Administrative. General and administrative expense was $6.9 million for the three months ended June 30, 2013, as compared to $9.3 million for the same period in 2012. The decrease was primarily due to a decrease in employee-related costs of $0.9 million, which was partially offset by an increase of $0.6 million in accounting and consulting expenses. Employee-related costs decreased due to a reduction in headcount. Accounting and consulting expenses were higher during the three months ended June 30, 2013 due to the late filing of our Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2013. Also contributing to the decrease was the $2.0 million contingency related to the Aglen exploration permit in Bulgaria, which was recognized during the three months ended June 30, 2012. The remaining decrease of $0.1 million was attributable to our overall cost reduction efforts.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization increased to $9.6 million for the three months ended June 30, 2013, as compared to $9.4 million in the same period of 2012.

Interest and Other Expense. Interest and other expense decreased to $1.0 million for the three months ended June 30, 2013, as compared to $2.0 million for the same period in 2012. The decrease was primarily due to decreased debt levels for the three months ended June 30, 2013 compared to the same period in 2012. In June 2012, we repaid $129.2 million of debt with the proceeds from the sale of our oilfield services business.

Gain on Commodity Derivative Contracts. During the three months ended June 30, 2013, we recorded a gain on commodity derivative contracts of approximately $4.3 million, as compared to a gain of $14.3 million for the same period in 2012. We recorded a $4.8 million unrealized gain and a $0.5 million realized loss on our derivative contracts for the three months ended June 30, 2013, as compared to a $15.1 million unrealized gain and a $0.8 million realized loss for the three months ended June 30, 2012. 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 Turkey.

 

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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 June 30, 2013 decreased to a loss of $13.5 million from a gain of $1.1 million for the same period in 2012 due to the devaluation of the New Turkish Lira as compared to the U.S. Dollar.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations for the three months ended June 30, 2013 and 2012 and oilfield services business for the three months ended June 30, 2012 have been included in discontinued operations.

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

 

     Three Months Ended June 30,  
     2013     2012  
     (in thousands)  

Revenues:

    

Oilfield services

   $ —        $ 10,672   
  

 

 

   

 

 

 

Total revenues

     —          10,672   

Costs and expenses:

    

Production

     41        361   

Oilfield services costs

     —          6,664   

General and administrative

     11        8,300   
  

 

 

   

 

 

 

Total costs and expenses

     52        15,325   
  

 

 

   

 

 

 

Operating loss

     (52     (4,653

Other income (expense):

    

Interest and other expense

     (6     (111

Interest and other income

     58        154   

Foreign exchange gain

     —          125   
  

 

 

   

 

 

 

Total other income

     52        168   
  

 

 

   

 

 

 

Loss from discontinued operations before income taxes

     —          (4,485

Gain on disposal of discontinued operations

     —          27,214   

Income tax provision

     —          (6,193
  

 

 

   

 

 

 

Net income from discontinued operations

   $ —        $ 16,536   
  

 

 

   

 

 

 

Results of Operations—Six Months Ended June 30, 2013 Compared to Six Months Ended June 30, 2012

Our results of operations for the six months ended June 30, 2013 and 2012 were as follows:

 

                          
    Six Months Ended June 30,     Change  
    2013     2012     2013-2012  
   

(in thousands of U.S. dollars, except per unit prices and production  volumes)

(as adjusted)

 

Production:

     

Oil (Mbbl)

    470        457        13   

Natural gas (Mmcf)

    1,616        2,448        (832

Total production (Mboe)

    739        865        (126

Average daily production (Boe/day)

    4,083        4,753        (670

Average prices:

     

Oil (per Bbl)

  $ 98.44      $ 103.31      $ (4.87

Natural gas (per Mcf)

    9.85        7.90        1.95   

Oil equivalent (per Boe)

    84.14        76.94        7.20   

Revenues:

     

Oil and natural gas sales

  $ 62,180      $ 66,557      $ (4,377

Sales of purchased natural gas

    4,240        3,663        577   

Other

    855        1,714        (859

Costs and expenses:

     

Production

  $ 8,855      $ 7,928      $ 927   

Exploration, abandonment and impairment

    15,749        9,679        6,070   

Cost of purchased natural gas

    4,046        3,636        410   

 

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Table of Contents
                    
    Six Months Ended June 30,     Change  
    2013     2012     2013-2012  
   

(in thousands of U.S. dollars, except per unit prices and production  volumes)

(as adjusted)

 

Seismic and other exploration

    1,333        1,511        (178

Revaluation of contingent consideration

    (5,000     —         (5,000

General and administrative

    14,416        18,557        (4,141

Depreciation, depletion and amortization

    18,557        18,551        6   

Interest and other expense

    1,845        5,277        (3,432

Gain on commodity derivative contracts:

     

Cash settlements on commodity derivative contracts

  $ (1,736   $ (2,247   $ 511   

Non-cash change in fair value on commodity derivative contracts

    5,238        4,116        1,122   
 

 

 

   

 

 

   

 

 

 

Total gain on commodity derivative contracts

  $ 3,502      $ 1,869      $ 1,633   

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $4.4 million to $62.2 million for the six months ended June 30, 2013, from $66.6 million realized in the same period in 2012. Of this decrease, $9.7 million was due to a decrease in production volumes of 126 Mboe. Production volumes decreased primarily on our Thrace Basin wells due to depletion of wells recompleted in the second half of 2011. This was partially offset by an increase of $5.3 million, primarily due to higher average realized prices per Boe resulting from the production of a higher percentage of oil and realization of higher natural gas prices. Our average price received increased $7.20 to $84.14 per Boe for the six months ended June 30, 2013, from $76.94 per Boe for the same period in 2012.

Production. Production expenses for the six months ended June 30, 2013 increased to $8.9 million, from $7.9 million for the same period in 2012. The increase was primarily attributable to the sale of our oilfield services business in June 2012. Prior to the sale, certain expenses were eliminated upon consolidation as they were classified as intercompany whereas they are now classified as third-party.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the six months ended June 30, 2013 increased approximately $6.0 million to $15.7 million, from $9.7 million for the same period in 2012. During the six months ended June 30, 2013, there were write-offs of four wells for $4.3 million, $2.9 million, $1.9 million and $0.9 million. In the first half of 2012, there were write-offs of four wells at an average of approximately $1.8 million per well. Additionally, during the six months ended June 30, 2013, we recorded $4.6 million of impairment charges which primarily related to our Malkara license as compared to $1.5 million of impairment charges for the same period in 2012.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $1.3 million for the six months ended June 30, 2013, as compared to $1.5 million for the same period in 2012.

Revaluation of Contingent Consideration. As a result of the Amendment to the Purchase Agreement with Direct, we recognized the reversal of the $5.0 million contingent liability, originally recorded in 2011, during the six months ended June 30, 2013.

General and Administrative. General and administrative expense was $14.4 million for the six months ended June 30, 2013, as compared to $18.6 million for the same period in 2012. The decrease was primarily due to a decrease in employee-related costs of $1.3 million, a $0.3 million decrease in rents on offices and corporate apartments, and a decrease of $0.6 million in consulting expenses, which was partially offset by an increase of $0.4 million in accounting and legal expenses. Employee-related costs decreased due to a reduction in headcount. Accounting and legal expenses were higher during the six months ended June 30, 2013 due to the late filing of our Annual Report on Form 10-K for the year ended December 31, 2012 and our Quarterly Report on Form 10-Q for the three months ended March 31, 2013. Also contributing to the decrease was the $2.0 million accrual for a contingency related to the Aglen exploration permit in Bulgaria, which was recognized during the six months ended June 30, 2012. The remaining decrease of $0.4 million was attributable to our overall cost reduction efforts.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization was unchanged at $18.6 million for the six months ended June 30, 2013 and 2012.

Interest and Other Expense. Interest and other expense decreased to $1.8 million for the six months ended June 30, 2013, as compared to $5.3 million for the same period in 2012. The decrease is primarily due to decreased debt levels for the six months ended June 30, 2013 compared to the same period in 2012. In June 2012, we repaid $129.2 million of debt with the proceeds from the sale of our oilfield services business.

 

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Table of Contents

Gain on Commodity Derivative Contracts. During the six months ended June 30, 2013, we recorded a gain on commodity derivative contracts of approximately $3.5 million, as compared to a gain of $1.9 million for the same period in 2012. We recorded a $5.2 million unrealized gain and a $1.7 million realized loss on our derivative contracts for the six months ended June 30, 2013, as compared to a $4.1 million unrealized gain and a $2.2 million realized loss on our derivative contracts for the six months ended June 30, 2012. 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 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 six months ended June 30, 2013 decreased to a loss of $16.4 million from a gain of $14.5 million for the same period in 2012 due to the devaluation of the New Turkish Lira as compared to the U.S Dollar.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations for the six months ended June 30, 2013 and 2012 and oilfield services business for the six months ended June 30, 2012 have been included in discontinued operations.

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

 

     Six Months Ended June 30,  
     2013     2012  
     (in thousands)  

Revenues:

    

Oilfield services

   $ —        $ 20,956   
  

 

 

   

 

 

 

Total revenues

     —          20,956   

Costs and expenses:

    

Production

     110        649   

Oilfield services costs

     —          13,736   

General and administrative

     28        10,466   
  

 

 

   

 

 

 

Total costs and expenses

     138        24,851   
  

 

 

   

 

 

 

Operating loss

     (138     (3,895

Other income (expense):

    

Interest and other expense

     (8     (176

Interest and other income

     53        172   

Foreign exchange loss

     —          (763
  

 

 

   

 

 

 

Total other income (expense)

     45        (767
  

 

 

   

 

 

 

Loss from discontinued operations before income taxes

     (93     (4,662

Gain on disposal of discontinued operations

     —          27,214   

Income tax provision

     —          (8,173
  

 

 

   

 

 

 

Net (loss) income from discontinued operations

   $ (93   $ 14,379   
  

 

 

   

 

 

 

Capital Expenditures

For the quarter ended June 30, 2013, we incurred $28.1 million in capital expenditures, including license acquisition and seismic expenditures from continuing operations, as compared to $14.7 million for the quarter ended June 30, 2012.

Capital expenditures, including seismic expenditures, for the third and fourth quarters of 2013 are expected to range between $70 million and $90 million. Approximately 75% of these anticipated expenditures will occur in southeastern Turkey, devoted to drilling developmental and exploratory oil wells and acquiring seismic data at Molla, Selmo, Arpatepe and Gaziantep. Most of the remaining 25% of these anticipated expenditures will occur in the Thrace Basin, devoted to developing conventional and unconventional natural gas production, building infrastructure and acquiring seismic data. Our projected 2013 capital budget is subject to change, and if cash on hand, borrowings from our Amended and Restated Credit Facility and TBNG credit facility, and cash flow from operations are not sufficient to fund our capital expenditures, we will either curtail our discretionary capital expenditures or seek other funding sources.

Liquidity and Capital Resources

Our primary sources of liquidity for the second quarter of 2013 were our cash and cash equivalents, cash flow from operations and net borrowings under our Amended and Restated Credit Facility. At June 30, 2013, we had cash and cash equivalents of $15.9 million, no short-term debt, $39.8 million in long-term debt, and working capital of $3.2 million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities), compared to cash and cash equivalents of $14.8 million, no short-term debt,

 

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Table of Contents

$32.8 million in long-term debt, and working capital of $10.6 million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities) at December 31, 2012. Net cash provided by operating activities from continuing operations for the six months ended June 30, 2013 increased to $55.7 million, as compared to net cash provided by operating activities from continuing operations of $48.0 million for the six months ended June 30, 2012, primarily as a result of a decrease in general and administrative expenses, a decrease in interest expense and improved cash management.

As of June 30, 2013, the outstanding principal amount of our debt was $39.8 million. In addition to cash, cash equivalents and cash flow from operations, at June 30, 2013, we had an Amended and Restated Credit Facility and a credit facility with a Turkish bank, which are discussed below.

Amended and Restated Credit Facility. DMLP, Ltd., TransAtlantic Exploration Mediterranean International Pty Ltd. (“TEMI”), Amity Oil International Pty Ltd., Talon Exploration, Ltd., TransAtlantic Turkey, Ltd. and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (collectively, the “Borrowers”) are parties to the Amended and Restated Credit Facility. Each of the Borrowers is our wholly owned subsidiary. The Amended and Restated Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and 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 June 30, 2013, the lenders had aggregate commitments of $78.0 million, with individual commitments of $39.0 million each. Loans under the Amended and Restated Credit Facility accrue interest at a rate of three-month LIBOR plus 5.50% per annum.

The borrowing base is re-determined quarterly on January 1st, April 1st, July 1st and October 1st of each year. As of July 4, 2013, our borrowing base was $58.2 million.

At June 30, 2013, we had outstanding borrowings of $39.8 million and availability of $18.4 million 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, 2012.

TBNG Credit Facility. On June 18, 2013, our wholly owned subsidiary, TBNG, entered into a 78.8 million New Turkish Lira (approximately $40.9 million at June 30, 2013) unsecured line of credit with a Turkish bank, of which 60 million New Turkish Lira is available in cash for TBNG and 18.8 million New Turkish Lira is available in the form of non-cash bank guarantees and letters of credit for TBNG and several other of our wholly owned subsidiaries operating in Turkey. The interest rate will be established at the time of each borrowing, and each borrowing is expected to have a two-year term. As of June 30, 2013, there were no borrowings under this credit facility.

Contingencies Relating to Production Leases and Exploration Permits

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

Morocco. In the second quarter of 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew down our $1.0 million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we plan to pursue a settlement with the Moroccan government for a lesser amount, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during the second quarter of 2012 for this contractual obligation.

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

Direct Petroleum. In July 2013, we entered into the Amendment to our Purchase Agreement with Direct. Pursuant to the Amendment, we agreed to issue 3,510,743 common shares to Direct as partial payment of certain liquidated damages due under the Purchase Agreement. The number of shares was calculated by dividing $2.5 million by the volume weighted average price per share of our common shares on the NYSE MKT for the ten trading days prior to July 2, 2013.

 

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Table of Contents

The parties also agreed that Direct is not eligible for any liquidated damages relating to the coring of the Etropole shale formation, which resulted in the reversal of the $5.0 million contingent liability recorded in 2011, which we recognized in our consolidated statement of comprehensive income (loss) under the caption “Revaluation of contingent consideration” during the three and six months ended June 30, 2013.

The Amendment sets forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. In the event that we do not meet the drilling and testing obligations by May 1, 2014, the Amendment requires us to issue an additional $2.5 million in common shares to Direct. As such, the $2.5 million contingent liability, recorded in 2011, will remain as of June 30, 2013.

Additionally, the Amendment provides that if the Bulgarian government issues a production concession over the Stefenetz Concession Area, Direct will be entitled to a payment of $10.0 million in common shares, or a pro rata amount if the production concession is less than 200,000 acres.

Contractual Obligations

There were no material changes to our contractual obligations set forth in our Annual Report on Form 10-K for the year ended December 31, 2012.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at June 30, 2013.

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.

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; shortages of drilling rigs, equipment or oilfield services; 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; 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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Table of Contents
Item 3. Quantitative and Qualitative Disclosures About Market Risk

During the second quarter of 2013, there were no material changes in market risk exposures or their management 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, 2012. Our oil derivatives contracts are settled based upon Brent crude oil pricing. The following tables set forth our outstanding derivatives contracts with respect to future crude oil production as of June 30, 2013:

 

Type

   Period      Quantity
(Bbl/
day)
     Weighted
Average
Minimum
Price (per Bbl)
     Weighted
Average
Maximum Price
(per Bbl)
     Estimated Fair
Value of Asset
 
                                 (in thousands)  

Collar

     July 1, 2013—December 31, 2013         775       $ 82.26       $ 121.36       $ 13   

Collar

     January 1, 2014—December 31, 2014         662       $ 80.83       $ 118.07         134   
              

 

 

 
               $ 147   
              

 

 

 

 

            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

     July 1, 2013—December 31, 2013         831       $ 85.00       $ 97.13       $ 162.13       $ (837

Three-way collar contract

     January 1, 2014—December 31, 2014         726       $ 85.00       $ 97.13       $ 162.13         (1,292

Three-way collar contract

     January 1, 2015—December 31, 2015         1,016       $ 85.00       $ 91.88       $ 151.88         (1,572
                 

 

 

 
                  $ (3,701
                 

 

 

 

 

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

As of June 30, 2013, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon the evaluation, 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, 2012, our chief executive officer and chief financial officer concluded that, as of June 30, 2013, our disclosure controls and procedures were not effective at the reasonable assurance level.

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

Changes in Internal Control over Financial Reporting

There were no changes during the second quarter of 2013 that have affected, or are reasonably likely to materially affect, our internal control over financial reporting, except for the following:

In April 2013, we hired a vice president of accounting and corporate controller with 12 years of “Big 4” public accounting experience, including several years of public company oil and natural gas accounting experience, to manage the accounting function beginning in May 2013.

PART II. OTHER INFORMATION

 

Item 1. Legal Proceedings

During the second quarter of 2013, there were no material developments to the Legal Proceedings disclosed in “Part I, Item 3. Legal Proceedings” in our Annual Report on Form 10-K for the year ended December 31, 2012.

 

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Table of Contents
Item 1A. Risk Factors

During the second quarter of 2013, there were no material changes to the Risk Factors disclosed in “Part I, Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.

 

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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Table of Contents

Item 6. Exhibits

 

3.1    Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.2    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).
10.1    Office Lease dated effective April 5, 2013, by and between TransAtlantic Petroleum (USA) Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 8, 2013, filed with the SEC on May 14, 2013).
10.2*    Letter Agreement dated April 24, 2013, by and between TransAtlantic Petroleum Ltd. and Chad W. Potter.
10.3    Second Amendment to Purchase Agreement dated effective July 2, 2013 by and among Direct Petroleum Exploration, LLC, TransAtlantic Worldwide, Ltd. and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated July 3, 2013, filed with the SEC on July 10, 2013).
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.INS†    XBRL Instance Document.
101.SCH†    XBRL Taxonomy Extension Schema Document.
101.CAL†    XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF†    XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB†    XBRL Taxonomy Extension Label Linkbase Document.
101.PRE†    XBRL Taxonomy Extension Presentation Linkbase Document.

 

* Filed herewith.
Furnished herewith. 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 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.

 

By:   /s/ N. MALONE MITCHELL 3rd
 

N. Malone Mitchell 3rd

Chief Executive Officer

By:   /s/ WIL F. SAQUETON
 

Wil F. Saqueton

Chief Financial Officer

Date: August 7, 2013

 

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Table of Contents

INDEX TO EXHIBITS

 

3.1    Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.2    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).
10.1    Office Lease dated effective April 5, 2013, by and between TransAtlantic Petroleum (USA) Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 8, 2013, filed with the SEC on May 14, 2013).
10.2*    Letter Agreement dated April 24, 2013, by and between TransAtlantic Petroleum Ltd. and Chad W. Potter.
10.3    Second Amendment to Purchase Agreement dated effective July 2, 2013 by and among Direct Petroleum Exploration, LLC, TransAtlantic Worldwide, Ltd. and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated July 3, 2013, filed with the SEC on July 10, 2013).
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.INS†    XBRL Instance Document.
101.SCH†    XBRL Taxonomy Extension Schema Document.
101.CAL†    XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF†    XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB†    XBRL Taxonomy Extension Label Linkbase Document.
101.PRE†    XBRL Taxonomy Extension Presentation Linkbase Document.

 

* Filed herewith.
Furnished herewith. 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 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.

 

30

EX-10.2

Exhibit 10.2

 

LOGO

www.transatlanticpetroleum.com

 

16803 Dallas Parkway       Canon’s Court
Addison, Texas 75001       22 Victoria Street                    
Phone    214-220-4323       Hamilton HM 12
Fax    214-265-4711       Bermuda

 

April 24, 2013    Via Hand Delivery

Mr. Chad W. Potter

16803 Dallas Parkway

Dallas, Texas 75001

RE:    Severance Agreement and Release

Dear Chad,

As we have discussed, you and TransAtlantic Petroleum Ltd., a Bermuda exempted company (TransAtlantic Petroleum Ltd. and its wholly owned subsidiary, TransAtlantic Petroleum (USA) Corp., a Delaware company with offices at 16803 Dallas Parkway, Addison, Texas 75001, together with their affiliates and subsidiaries, are collectively referred to herein as the “Company”) have reached an agreement regarding your resignation from the Company. To ease your transition into new employment, the Company wishes to offer you a severance agreement in accordance with the terms of this letter. In return, the Company is asking you for certain commitments to protect its business interests.

The terms of the severance package are memorialized in this letter agreement (the “Agreement”). Upon your execution and return of this Agreement, you and the Company agree to the following:

 

1. Cash Severance. The Company will pay you a cash severance payment in the amount of Fifty Thousand USD ($50,000), to be paid in five (5) equal payments of Ten Thousand USD ($10,000 USD) (the “Cash Severance”). The Cash Severance payments will be paid on the fifteenth day of each month, beginning May 15, 2013. You acknowledge that if you (a) do not accept the terms of this Agreement, or (b) accept the terms of this Agreement but revoke the Release (as defined in Paragraph 4 below), the Company will not pay you the Cash Severance.


April 24, 2013

Page 2

 

2. Equity Severance. The Company will cause the accelerated vesting of the following restricted stock units: (a) 116,959 restricted stock units vesting one-half September 1, 2013 and one-half September 1, 2014, and (b) 11,319 restricted stock units vesting on July 15, 2013 (the “Equity Severance” and, together with the Cash Severance, the “Severance”). The Company will use its reasonable efforts to accelerate the vesting of the Equity Severance effective May 10, 2013. You acknowledge that if you (a) do not accept the terms of this Agreement, or (b) accept the terms of this Agreement but revoke the Release (as defined in Paragraph 4 below), the Company will not pay you the Equity Severance.

 

3. Acceptance. The Company will leave this offer open until 5:00 p.m. on Wednesday, April 24, 2013 (the “Deadline”). You may accept the Agreement at any time between now and the Deadline by signing a copy of this Agreement and delivering a copy of the same to Mike Kissner via e-mail at mike.kissner@tapcor.com.

 

4. Release. You agree to release, remise and discharge the Company by signing a release substantially in the form attached hereto as Exhibit A (the “Release”).

 

5. Severance Date. Your employment with the Company will end on May 10, 2013 (the “Termination Date”). You agree to continue to perform your duties as an employee of the Company, including transitioning any replacement, through the Termination Date.

 

6. Non-Solicitation. For a period of six (6) months following the date you execute this Agreement, you agree that you will not solicit, directly or indirectly, or cause or permit others to solicit, directly or indirectly, any person (i) formerly employed by the Company or any of its subsidiaries or affiliates during the six (6) month period immediately preceding the last date of your employment with the Company (a “Former Employee”) or (ii) employed by Company or its subsidiaries or affiliates (a “Current Employee”). The term “solicit” includes, but is not limited to, the following (regardless of whether done directly or indirectly): (a) requesting that a Former Employee or Current Employee change employment; (b) informing a Former Employee or Current Employee that an opening exists elsewhere; (c) assisting a Former Employee or a Current Employee in finding employment elsewhere; (d) inquiring if a Former Employee or a Current Employee knows of anyone who might be interested in a position elsewhere; (e) inquiring if a Former Employee or a Current Employee might have an interest in employment elsewhere; (f) informing others of the name or status of, or other information about, a Former Employee or a Current Employee; or (g) any other similar conduct, the intended or actual effect of which is that a Former Employee affiliates with another employer or a Current Employee leaves the employment of Employer.

 

7. Non-Competition. For a period of one (1) year following the date of your acceptance of this Agreement, you will not directly or indirectly solicit any person or company with which, on the date of your separation from the Company, the Company and/or any of its subsidiaries or affiliates has an existing contract for services, or with which the Company and/or any its subsidiaries and affiliates is in negotiations to enter into a contract for services, or induce any of these companies to terminate or reduce their business with the Company and/or any its subsidiaries and affiliates.


April 24, 2013

Page 3

 

8. Commitment to Preserve Good Name. You and the Company mutually agree to not make or publish any disparaging statements (whether written, electronic or oral) regarding, or otherwise malign the business reputation of, either you or the Company or any of the Company’s directors, officers, partners, managers, members or employees.

 

9. Confidentiality. By executing this Agreement, you agree that you will treat the existence and amount of the Severance as confidential. You agree that you will not discuss this Agreement, the Release or any of the terms of this Agreement or the Release, with anyone other than your immediate family and your financial and legal advisors, provided that you inform them of this confidentially provision and they agree to abide by it.

 

10. No Undue Hardship. You agree that none of the restraints and provisions in this Agreement are unduly burdensome or impose an undue hardship on you, are no greater than necessary, and are as narrowly drafted as possible to protect the legitimate interests of the Company and its subsidiaries and affiliates.

 

11. Other Issues. This Agreement and the Release constitute the entire agreement between you and the Company. You and the Company agree that there are no oral representations or understandings between us that are not contained within the written terms of this Agreement and the Release. Furthermore, you and the Company agree that this Agreement and the Release may not be orally modified. To change the terms of this Agreement or the Release, both you and an authorized representative of the Company must agree in writing. If any portion of this Agreement or the Release is held by a court or other entity of competent jurisdiction to be invalid or unenforceable, the remainder of the provisions shall remain in full force and effect.

 

12. Governing Law. This Agreement and the Release shall be governed by and construed and enforced, in all respects in accordance with the laws of the State of Texas, USA, without regard to principles of conflicts of law.

If you are in agreement with these terms, please sign and date below.

Very truly yours,

/s/ Jeffrey S. Mecom

Jeffrey S. Mecom

Vice President


April 24, 2013

Page 4

 

ACCEPTED AND AGREED TO BY:

                /s/ Chad W. Potter                    

Chad W. Potter

Dated:

April 24, 2013

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, N. Malone Mitchell 3rd, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of TransAtlantic Petroleum Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

August 7, 2013       /s/ N. Malone Mitchell 3rd
     

N. Malone Mitchell 3rd

Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Wil F. Saqueton, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of TransAtlantic Petroleum Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

August 7, 2013       /s/ Wil F. Saqueton
     

Wil F. Saqueton

Chief Financial Officer

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), each of the undersigned officers of TransAtlantic Petroleum Ltd. (the “Company”) does hereby certify, to such officer’s knowledge, that:

This Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 (the “Form 10-Q”) of the Company fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934 and the information contained in the Form 10-Q fairly represents, in all material respects, the financial condition and results of operation of the Company as of, and for, the periods presented in the Form 10-Q.

Date: August 7, 2013

 

/s/ N. Malone Mitchell 3rd

N. Malone Mitchell 3rd

Chief Executive Officer

 

/s/ Wil F. Saqueton

Wil F. Saqueton

Chief Financial Officer

The foregoing certification is being furnished as an exhibit to the Form 10-Q pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-Q for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.