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, 2014

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 1, 2014, the registrant had 37,479,956 common shares outstanding.

 

 

 


Table of Contents

TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION       

Item 1. Financial Statements

  

Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013

     1   

Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June  30, 2014 and 2013

     2   

Consolidated Statements of Equity for the Six Months Ended June 30, 2014

     3   

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013

     4   

Notes to Consolidated Financial Statements

     5   

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

     17   

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     28   

Item 4. Controls and Procedures

     28   
PART II. OTHER INFORMATION   

Item 1. Legal Proceedings

     29   

Item 1A. Risk Factors

     29   

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

     31   

Item 3. Defaults Upon Senior Securities

     31   

Item 4. Mine Safety Disclosures

     31   

Item 5. Other Information

     31   

Item 6. Exhibits

     32   


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, 2014     December 31,
2013
 
     (Unaudited)        

ASSETS

    

Current assets:

    

Cash and cash equivalents

   $ 5,161      $ 12,881   

Accounts receivable

    

Oil and natural gas sales, net

     38,796        30,619   

Joint interest and other

     5,974        15,348   

Related party

     192        1,004   

Prepaid and other current assets

     3,242        5,072   

Deferred income taxes

     2,666        2,239   

Assets held for sale

     29        536   
  

 

 

   

 

 

 

Total current assets

     56,060        67,699   
  

 

 

   

 

 

 

Property and equipment:

    

Oil and natural gas properties (successful efforts method)

    

Proved

     298,369        260,857   

Unproved

     61,957        54,392   

Equipment and other property

     41,285        39,916   
  

 

 

   

 

 

 
     401,611        355,165   

Less accumulated depreciation, depletion and amortization

     (127,761     (104,193
  

 

 

   

 

 

 

Property and equipment, net

     273,850        250,972   

Other long-term assets:

    

Other assets

     9,973        8,880   

Note receivable – related party

     11,500        11,500   

Goodwill

     7,574        7,535   
  

 

 

   

 

 

 

Total other assets

     29,047        27,915   
  

 

 

   

 

 

 

Total assets

   $ 358,957      $ 346,586   
  

 

 

   

 

 

 

LIABILITIES AND SHAREHOLDERS’ EQUITY

    

Current liabilities:

    

Accounts payable

   $ 13,002      $ 16,712   

Accounts payable - related party

     7,697        23,090   

Accrued liabilities

     16,477        20,658   

Derivative liabilities

     8,279        3,737   

Asset retirement obligations

     397        610   

Loan payable

     28,288        43,284   

Liabilities held for sale

     7,533        7,559   
  

 

 

   

 

 

 

Total current liabilities

     81,673        115,650   
  

 

 

   

 

 

 

Long-term liabilities:

    

Asset retirement obligations

     10,830        10,286   

Accrued liabilities

     6,785        6,487   

Deferred income taxes

     19,018        16,134   

Loan payable

     59,766        26,482   

Derivative liabilities

     5,716        4,230   
  

 

 

   

 

 

 

Total long-term liabilities

     102,115        63,619   
  

 

 

   

 

 

 

Total liabilities

     183,788        179,269   

Commitments and contingencies

    

Shareholders’ equity:

    

Common shares, $0.10 par value, 100,000,000 shares authorized; 37,447,909 shares issued and outstanding as of June 30, 2014 and 37,340,206 shares issued and outstanding as of December 31, 2013

     3,745        3,734   

Additional paid-in capital

     542,725        542,091   

Accumulated other comprehensive loss

     (63,188     (64,985

Accumulated deficit

     (308,113     (313,523
  

 

 

   

 

 

 

Total shareholders’ equity

     175,169        167,317   
  

 

 

   

 

 

 

Total liabilities and shareholders’ equity

   $ 358,957      $ 346,586   
  

 

 

   

 

 

 

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,
 
     2014     2013     2014     2013  

Revenues:

        

Oil and natural gas sales

   $ 40,441      $ 29,455      $ 73,425      $ 62,180   

Sales of purchased natural gas

     491        719        1,036        1,525   

Other

     129        342        246        855   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

     41,061        30,516        74,707        64,560   

Costs and expenses:

        

Production

     4,666        3,328        8,797        8,855   

Exploration, abandonment and impairment

     3,775        11,885        7,916        15,749   

Cost of purchased natural gas

     440        619        925        1,331   

Seismic and other exploration

     892        1,090        4,186        1,333   

Revaluation of contingent consideration

     —          (5,000     (2,500     (5,000

General and administrative

     7,460        6,893        14,012        14,416   

Depreciation, depletion and amortization

     12,588        9,581        22,678        18,557   

Accretion of asset retirement obligations

     106        124        204        253   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

     29,927        28,520        56,218        55,494   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     11,134        1,996        18,489        9,066   

Other (expense) income:

        

Interest and other expense

     (1,769     (955     (2,972     (1,845

Interest and other income

     327        307        600        682   

(Loss) gain on commodity derivative contracts

     (9,522     4,278        (8,560     3,502   

Foreign exchange gain (loss)

     2,494        (2,543     1,150        (3,030
  

 

 

   

 

 

   

 

 

   

 

 

 

Total other (expense) income

     (8,470     1,087        (9,782     (691
  

 

 

   

 

 

   

 

 

   

 

 

 

Income from continuing operations before income taxes

     2,664        3,083        8,707        8,375   

Current income tax expense

     (838     (528     (907     (1,867

Deferred income tax (expense) benefit

     (389     348        (2,370     (573
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income from continuing operations

     1,437        2,903        5,430        5,935   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss from discontinued operations

     —          —         (20     (93

Net income

   $ 1,437      $ 2,903      $ 5,410      $ 5,842   

Other comprehensive income (loss):

        

Foreign currency translation adjustment

     5,092        (13,543     1,797        (16,379
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income (loss)

   $ 6,529      $ (10,640   $ 7,207      $ (10,537
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income per common share:

        

Basic net income per common share:

        

Continuing operations

   $ 0.04      $ 0.08      $ 0.15      $ 0.16   

Discontinued operations

   $ 0.00      $ 0.00      $ 0.00      $ 0.00   

Weighted average common shares outstanding

     37,411        36,893        37,402        36,891   

Diluted net income per common share:

        

Continuing operations

   $ 0.04      $ 0.08      $ 0.15      $ 0.16   

Discontinued operations

   $ 0.00      $ 0.00      $ 0.00      $ 0.00   

Weighted average common and common equivalent shares outstanding

     37,411        36,893        37,402        36,891   

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, 2013

     37,340       $ 3,734       $ 542,091      $ (64,985   $ (313,523   $ 167,317   

Issuance of restricted stock units

     108         11         (11     —         —         —    

Share-based compensation

     —          —          713        —         —         713   

Tax withholding on restricted stock units

     —          —          (68     —         —         (68

Foreign currency translation adjustments

     —          —          —         1,797        —         1,797   

Net income

     —          —          —         —         5,410        5,410   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

Balance at June 30, 2014

     37,448       $ 3,745       $ 542,725      $ (63,188   $ (308,113   $ 175,169   
  

 

 

    

 

 

    

 

 

   

 

 

   

 

 

   

 

 

 

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,
 
     2014     2013  

Operating activities:

    

Net income

   $ 5,410      $ 5,842   

Adjustment for net loss from discontinued operations

     20        93   
  

 

 

   

 

 

 

Net income from continuing operations

     5,430        5,935   

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

    

Share-based compensation

     713        881   

Foreign currency loss

     74        2,138   

Loss (gain) on commodity derivative contracts

     8,560        (3,502

Cash settlement on commodity derivative contracts

     (2,533     (1,736

Amortization of loan financing costs

     764        256   

Deferred income tax expense

     2,370        573   

Exploration, abandonment and impairment

     7,916        15,749   

Depreciation, depletion and amortization

     22,678        18,557   

Accretion of asset retirement obligations

     204        253   

Revaluation of contingent consideration

     (2,500     (5,000

Changes in operating assets and liabilities:

    

Accounts receivable

     2,215        10,432   

Prepaid expenses and other assets

     2,056        141   

Accounts payable and accrued liabilities

     (6,487     11,045   
  

 

 

   

 

 

 

Net cash provided by operating activities from continuing operations

     41,460        55,722   

Net cash used in operating activities from discontinued operations

     (64     (1,071
  

 

 

   

 

 

 

Net cash provided by operating activities

     41,396        54,651   

Investing activities:

    

Additions to oil and natural gas properties

     (62,993     (52,320

Additions to equipment and other properties

     (2,589     (7,925

Restricted cash

     —          (206
  

 

 

   

 

 

 

Net cash used in investing activities from continuing operations

     (65,582     (60,451

Net cash provided by investing activities from discontinued operations

     500        1,016   
  

 

 

   

 

 

 

Net cash used in investing activities

     (65,082     (59,435

Financing activities:

    

Tax withholding on restricted stock units

     (68     —    

Loan proceeds

     26,092        22,885   

Loan repayment

     (7,804     (15,885

Loan financing costs

     (2,176     —    
  

 

 

   

 

 

 

Net cash provided by financing activities from continuing operations

     16,044        7,000   

Effect of exchange rate changes on cash

     (78     (1,064

Net (decrease) increase in cash and cash equivalents

     (7,720     1,152   

Cash and cash equivalents, beginning of period

     12,881        14,768   
  

 

 

   

 

 

 

Cash and cash equivalents, end of period

   $ 5,161      $ 15,920   
  

 

 

   

 

 

 

Supplemental disclosures:

    

Cash paid for interest

   $ 1,212      $ 1,539   
  

 

 

   

 

 

 

Cash paid for taxes

   $ —       $ 1,448   
  

 

 

   

 

 

 

Supplemental non-cash financing activities:

    

Repayment of amended and restated credit facility from refinancing

   $ 49,766      $ —    
  

 

 

   

 

 

 

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

 

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TRANSATLANTIC PETROLEUM LTD.

Notes to Consolidated Financial Statements

(Unaudited)

1. General

Nature of operations

TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the “Company” or “TransAtlantic”) is an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored petroleum systems, 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 August 1, 2014, 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. In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews estimates, including those related to fair value measurements associated with acquisitions and financial derivatives, the recoverability and impairment of long-lived assets and goodwill, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

Certain information and footnote disclosures normally included in the consolidated financial statements prepared in accordance with U.S. GAAP have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). These consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Form 10-K for the year ended December 31, 2013.

2. Recent accounting pronouncements

In April 2014, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Components of an Entity (“ASU 2014-08”). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. Currently, we do not expect the adoption of ASU 2014-08 to have a material impact on our consolidated financial statements or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods or services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The update is effective for periods beginning after December 15, 2016. We are currently assessing the potential impact of ASU 2014-09 on our consolidated financial statements and results of operations.

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

 

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3. 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, 2014     December 31, 2013  
     (in thousands)  

Oil and natural gas properties, proved:

    

Turkey

   $ 297,748      $ 260,232   

Bulgaria

     621        625   
  

 

 

   

 

 

 

Total oil and natural gas properties, proved

     298,369        260,857   

Oil and natural gas properties, unproved:

    

Turkey

     57,502        51,273   

Bulgaria

     4,455        3,119   
  

 

 

   

 

 

 

Total oil and natural gas properties, unproved

     61,957        54,392   
  

 

 

   

 

 

 

Gross oil and natural gas properties

     360,326        315,249   

Accumulated depletion

     (119,373     (96,958
  

 

 

   

 

 

 

Net oil and natural gas properties

   $ 240,953      $ 218,291   
  

 

 

   

 

 

 

At June 30, 2014 and December 31, 2013, we excluded $0.7 million and $1.5 million, respectively, from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At June 30, 2014, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $32.6 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $146.2 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

At December 31, 2013, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $35.5 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $126.9 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

Impairment and dry hole costs

During the three and six months ended June 30, 2014, we recorded $3.8 million and $7.9 million of impairment and exploratory dry hole costs, respectively. Of the $7.9 million of costs incurred during the six months ended June 30, 2014, $3.5 million related to impairment on one well in the first quarter of 2014 and $2.8 million related to impairment of the Kazanci-5 well in the second quarter of 2014. Of the $7.9 million of costs incurred during the six months ended June 30, 2014, $1.4 million was cash spent during the period.

Capitalized cost greater than one year

As of June 30, 2014, we had $1.7 million of exploratory well costs capitalized for the Hayrabolu-10 well, which we spud in February 2013. The Hayrabolu-10 well continues to be evaluated for completion pending more analysis and comparable well results.

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, 2014     December 31, 2013  
     (in thousands)  

Other equipment

   $ 3,944      $ 2,678   

Inventory

     24,811        24,318   

Gas gathering system and facilities

     4,508        4,485   

Vehicles

     347        321   

Leasehold improvements, office equipment and software

     7,675        8,114   
  

 

 

   

 

 

 

Gross equipment and other property

     41,285        39,916   

Accumulated depreciation

     (8,388     (7,235
  

 

 

   

 

 

 

Net equipment and other property

   $ 32,897      $ 32,681   
  

 

 

   

 

 

 

 

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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, 2014, we excluded $24.8 million of inventory and $1.2 million of software from depreciation as the inventory and software had not been placed into service. At December 31, 2013, we excluded $24.3 million of inventory and $0.7 million of software from depreciation as the inventory and software had not been placed into service.

4. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations (“ARO”) for the six months ended June 30, 2014 and for the year ended December 31, 2013:

 

     June 30, 2014     December 31, 2013  
     (in thousands)  

Asset retirement obligations at beginning of period

   $ 10,896      $ 11,958   

Change in estimates

     —          (7

Liabilities settled

     (212     (296

Foreign exchange change effect

     53        (2,258

Additions

     286        991   

Accretion expense

     204        508   
  

 

 

   

 

 

 

Asset retirement obligations at end of period

     11,227        10,896   

Less: current portion

     397        610   
  

 

 

   

 

 

 

Long-term portion

   $ 10,830      $ 10,286   
  

 

 

   

 

 

 

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.

5. Commodity derivative instruments

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

To the extent that a legal right of offset exists, we net the value of our derivative contracts with the same counterparty in our consolidated balance sheets. All of our oil derivative contracts are settled based upon Brent crude oil pricing. We recognize gains and losses related to these contracts on a fair value basis in our consolidated statements of comprehensive income (loss) under the caption “(Loss) gain on commodity derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on commodity derivative contracts.” We are required under our senior secured credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP Paribas”) and the International Finance Corporation (“IFC”) to hedge at least 30% of our anticipated oil production volumes in Turkey.

In May 2014, we novated our existing commodity derivative contracts with Standard Bank Plc (“Standard Bank”) and BNP Paribas and entered into new commodity derivative contracts with BNP Paribas. During the three months ended June 30, 2014, we recognized a $0.7 million realized loss on the unwinding of these commodity derivative contracts, which is included in our consolidated statement of comprehensive income (loss) under the caption “(Loss) gain on commodity derivative contracts”.

 

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During the three months ended June 30, 2014 and 2013, we recorded a net loss on commodity derivative contracts of $9.5 million and a net gain of $4.3 million, respectively. During the six months ended June 30, 2014 and 2013, we recorded a net loss on commodity derivative contracts of $8.6 million and a net gain of $3.5 million, respectively.

At June 30, 2014 and December 31, 2013, 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, 2014

 

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

     July 1, 2014—December 31, 2014         1,770       $ 85.00       $ 97.25       $ (4,758

Collar

     January1, 2015—December 31, 2015         1,410       $ 85.00       $ 97.25         (6,027
              

 

 

 
               $ (10,785
              

 

 

 

 

            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, 2016—December 31, 2016         1,066       $ 85.00       $ 97.25       $ 114.25       $ (2,057

Three-way collar contract

     January 1, 2017—December 31, 2017         888       $ 85.00       $ 97.25       $ 114.25         (851

Three-way collar contract

     January 1, 2018—December 31, 2018         726       $ 85.00       $ 97.25       $ 114.25         (282

Three-way collar contract

     January 1, 2019—March 31, 2019         663       $ 85.00       $ 97.25       $ 114.25         (20
                 

 

 

 
                  $ (3,210
                 

 

 

 

Fair Value of Derivative Instruments as of December 31, 2013

 

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, 2014—December 31, 2014         622       $ 80.83       $ 118.07       $ (387
              

 

 

 
               $ (387
              

 

 

 

 

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            Collars      Additional Call         

Type

   Period      Quantity
(Bbl/day)
     Weighted
Average
Minimum
Price

(per Bbl)
     Weighted
Average
Maximum
Price
(per Bbl)
     Weighted
Average
Maximum
Price
(per Bbl)
     Estimated Fair
Value of
Liability
 
                                        (in thousands)  

Three-way collar contract

     January 1, 2014—December 31, 2014         726       $ 85.00       $ 97.13       $ 162.13       $ (3,350

Three-way collar contract

     January 1, 2015—December 31, 2015         1,016       $ 85.00       $ 91.88       $ 151.88         (4,230
                 

 

 

 
                  $ (7,580
                 

 

 

 

Balance sheet presentation

The following table summarizes both: (i) the gross fair value of our commodity derivative instruments by the appropriate balance sheet classification even when the commodity derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at June 30, 2014 and December 31, 2013, and (ii) the net recorded fair value as reflected on our consolidated balance sheets at June 30, 2014 and December 31, 2013.

 

            As of June 30, 2014  

Underlying commodity

   Location on Balance Sheet      Gross
Amount of
Recognized

Liabilities
     Gross
Amount
Offset in the
Consolidated

Balance
Sheet
     Net Amount of
Liabilities

Presented in the
Consolidated

Balance Sheet
 
            (in thousands)  

Crude oil

     Current liabilities       $ 8,279       $ —        $ 8,279   

Crude oil

     Long-term liabilities       $ 5,716       $ —        $ 5,716   
            As of December 31, 2013  

Underlying commodity

   Location on Balance Sheet      Gross
Amount of
Recognized

Liabilities
     Gross
Amount
Offset in the
Consolidated
Balance
Sheet
     Net Amount of
Liabilities
Presented in the
Consolidated

Balance Sheet
 
            (in thousands)  

Crude oil

     Current liabilities       $ 3,737       $ —        $ 3,737   

Crude oil

     Long-term liabilities       $ 4,230       $ —        $ 4,230   

 

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6. Loan payable

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

 

     June 30,
2014
     December 31,
2013
 
Floating Rate Debt    (in thousands)  

Amended and Restated Credit Facility

   $ —         $ 49,766   

Senior Credit Facility

     59,766         —     

TBNG credit facility

     26,700         20,000   

Unsecured lines of credit

     1,588         —     
  

 

 

    

 

 

 

Loan payable

     88,054         69,766   

Less: current portion

     28,288         43,284   
  

 

 

    

 

 

 

Long-term portion

   $ 59,766       $ 26,482   
  

 

 

    

 

 

 

Amended and Restated Credit Facility

On May 18, 2011, DMLP, Ltd. (“DMLP”), TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”) (collectively, and together with Amity Oil International Pty Ltd (“Amity”), the “Borrowers”) entered into an amended and restated credit facility (the “Amended and Restated Credit Facility”) with Standard Bank and BNP Paribas. Each of the Borrowers is our wholly owned subsidiary. In July 2011, Amity executed a joinder agreement and became a borrower under the Amended and Restated Credit Facility. The Amended and Restated Credit Facility was guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”). On May 6, 2014, we entered into the new Senior Credit Facility and, on May 15, 2014, we repaid the Amended and Restated Credit Facility in full and it was terminated.

Senior Credit Facility

On May 6, 2014, the Borrowers entered into the Senior Credit Facility with BNP Paribas and IFC. Each of the Borrowers is our wholly owned subsidiary. The Senior Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide (each, a “Guarantor”).

The amount drawn under the Senior Credit Facility may not exceed the lesser of (i) $150.0 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. The lenders have an initial aggregate commitment of $80.0 million, with individual commitments of $40.0 million each. The Company has the ability to increase the commitments up to an aggregate of $150.0 million by March 31, 2016. On the first day of each fiscal quarter commencing April 1, 2016, the lenders’ commitments are subject to reduction in an amount equal to 7.69% of the aggregate commitments in effect on April 1, 2016.

The borrowing base amount is re-determined semi-annually on April 1st and October 1st of each year, beginning April 1, 2015. The current borrowing base is $74.6 million. The borrowing base amount equals, for any calculation date, the lowest of:

 

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

 

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

The Senior Credit Facility matures on the earlier of (i) March 31, 2019, or (ii) the last date of the borrowing base calculation period that immediately precedes the date that the semi-annual banking case of BNP Paribas and the Borrowers determines that the aggregate amount of hydrocarbons to be produced from the borrowing base assets in Turkey are less than 25% of the amount of hydrocarbons to be produced from the borrowing base assets shown in the initial banking case prepared by BNP Paribas and the Borrowers. The Senior Credit Facility bears various letter of credit sub-limits, including among other things, sub-limits of up to (i) $10.0 million, (ii) the aggregate available unused and uncancelled portion of the lenders’ commitments or (iii) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment.

 

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Loans under the Senior Credit Facility accrue interest at a rate of three-month LIBOR plus 5.00% per annum (5.23% at June 30, 2014). The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.00% per annum of the unused and uncancelled portion of the aggregate commitments that is less than or equal to the maximum available amount under the Senior Credit Facility, and (b) 1.00% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available amount under the Senior Credit Facility and is not available to be borrowed, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to BNP Paribas or (b) 5.00% for all other letters of credit.

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

The Borrowers are required to comply with certain financial and non-financial covenants under the Senior Credit Facility, including maintaining the following financial ratios during the four most recently completed fiscal quarters occurring on or after March 31, 2014:

 

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

 

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

 

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

 

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

The Senior Credit Facility defines EBITDAX as net income (excluding extraordinary items) plus, to the extent deducted in calculating such net income, (i) interest expense (excluding interest paid-in-kind, or non-cash interest expense and interest incurred on certain subordinated intercompany debt or interest on equity recapitalized into subordinated debt), (ii) income tax expense, (iii) depreciation, depletion and amortization expense, (iv) amortization of intangibles and organization costs, (v) any extraordinary, unusual or non-recurring non-cash expenses or losses, (vi) expenses incurred in connection with oil and gas exploration activities entered into in the ordinary course of business (including related drilling, completion, geological and geophysical costs), (vii) transaction costs, expenses and fees incurred in connection with the negotiation, execution and delivery of the Senior Credit Facility and the related loan documents, minus, to the extent included in calculating net income, (a) any extraordinary, unusual or non-recurring income or gains (including, gains on the sales of assets outside of the ordinary course of business) and (b) any other non-cash income or gains.

Pursuant to the terms of the Senior Credit Facility, until amounts under the Senior Credit Facility are repaid, each of the Borrowers shall not, and shall cause each of its subsidiaries not to, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to create any liens, (iii) enter into any merger, consolidation or amalgamation, liquidate or dissolve, (iv) dispose of any property or business, (v) pay any dividends, distributions or similar payments to shareholders, (vi) make certain types of investments, (vii) enter into any transactions with an affiliate, (viii) enter into a sale and leaseback arrangement, (ix) engage in any business or business activity, own any assets or assume any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and natural gas exploration and production company or operate or carry on business in any jurisdiction outside of Turkey or its jurisdiction of formation, (x) change its organizational documents, (xi) permit its fiscal year to end on a day other than December 31st or change its method of determining fiscal quarters, or alter the accounting principles it uses, (xii) modify certain hydrocarbon licenses and agreements or material contracts, (xiii) enter into any hedge agreement for speculative purposes, (xiv) open or maintain new deposit, securities or commodity accounts, (xv) use the proceeds from any loan in the territories of any country that is not a member of the World Bank, (xvi) incur any expenditure that is not covered by the projections in the most recent corporate cashflow projection, (xvii) modify its social and environmental action plans as determined in conjunction with IFC, (xviii) enter into any transaction or engage in any activity prohibited by the United Nations Security Council, or (xix) engage in any corrupt, fraudulent, coercive, collusive or obstructive practice.

An event of default under the Senior Credit Facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and beneficially, all of the equity of the Borrowers or any Guarantor or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or Guarantor; (ii) the failure by the Borrowers to own or hold, directly or indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated in the Senior Credit Facility; or (iii) (a) Mr. Mitchell ceases

 

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for any reason to be the executive chairman of our board of directors at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner, directly or indirectly, of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis; provided, that, if Mr. Mitchell ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute an event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event.

As of July 1, 2014, we had outstanding borrowings of $59.8 million under the Senior Credit Facility and availability of $14.8 million.

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 (“TRY”) (approximately $37.1 million at June 30, 2014) unsecured line of credit with a Turkish bank, of which 60 million TRY is available in cash for TBNG and 18.8 million TRY 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 is established at the time of each borrowing. We have made three borrowings under this credit facility, on October 9, 2013, November 5, 2013 and January 22, 2014, each of which has a one-year term at a fixed interest rate of 4.6% per annum. At maturity, we expect to renew the borrowings for one additional year at then current market interest rates. As of June 30, 2014, we had borrowed $26.7 million under this credit facility.

Unsecured lines of credit

Our wholly owned subsidiaries operating in Turkey are party to unsecured, non-interest bearing lines of credit with a Turkish bank. At June 30, 2014, we had outstanding borrowings of $1.6 million under these lines of credit.

7. Contingencies relating to production leases and exploration permits

Selmo

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

Morocco

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 believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during 2012 for this contingency.

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 2012 for this contractual obligation.

Direct Petroleum

In July 2013, we entered into a second amendment (the “Amendment”) to the purchase agreement (the “Purchase Agreement”) with Direct Petroleum Exploration, LLC (“Direct”). The Amendment set forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. We completed the drilling and testing requirements pursuant to the Amendment during April 2014, which resulted in the reversal of the $2.5 million contingent liability recorded in 2011. The reversal is recognized in our consolidated statements of comprehensive income (loss) under the caption “Revaluation of contingent consideration” during the six months ended June 30, 2014.

In addition, the Amendment provides that we will issue $7.5 million in common shares if the Deventci-R2 well is a commercial success (as defined in the Purchase Agreement) on or prior to May 1, 2016. We will record any provision for this contingent consideration when it is estimable and probable. As of June 30, 2014, we had not recorded a contingent liability for this contingent consideration. Any adjustment will be recorded when it becomes probable and estimable.

Additionally, the Amendment provides that if the Bulgarian government issues a production concession over the stefenetz concession area (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. We do not have enough information to estimate the potential contingent liability we would incur in the event the Bulgarian government issues a production concession over the Stefenetz Concession Area. Any adjustment will be recorded when it becomes probable and estimable.

 

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8. Shareholders’ equity

Reverse stock split

On March 4, 2014, our shareholders approved a 1-for-10 reverse stock split, which became effective March 6, 2014. Pursuant to the reverse stock split, all shareholders of record received one common share for each ten common shares owned (subject to minor adjustments as a result of fractional shares). The reverse stock split reduced the issued and outstanding common shares as of March 4, 2014 from 374,026,984 to 37,402,698. U.S. GAAP requires that the reverse stock split be applied retrospectively to all periods presented. As a result, all common share amounts and transactions herein have been adjusted to reflect the 1-for-10 reverse stock split.

Restricted stock units

Share-based compensation expense of approximately $0.3 million and $0.7 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three and six months ended June 30, 2014, respectively. We recorded share-based compensation expense of $0.5 million and $0.9 million for the three and six months ended June 30, 2013, respectively.

As of June 30, 2014, we had approximately $1.4 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.7 years.

Earnings per share

We account for earnings per share in accordance with Accounting Standards Codification (“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, 2014 and 2013 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, 2014 and 2013 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes RSUs. For the three and six months ended June 30, 2014 and 2013, there were no dilutive securities included in the calculation of diluted earnings per share.

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

 

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

(in thousands, except per share amounts)

   2014      2013      2014     2013  

Net income from continuing operations

   $ 1,437       $ 2,903       $ 5,430      $ 5,935   

Net loss from discontinued operations

   $ —        $ —        $ (20   $ (93

Basic net income per common share:

          

Shares:

          

Weighted average shares outstanding

     37,411         36,893         37,402        36,891   
  

 

 

    

 

 

    

 

 

   

 

 

 

Basic net income per common share:

          

Continuing operations

   $ 0.04       $ 0.08       $ 0.15      $ 0.16   
  

 

 

    

 

 

    

 

 

   

 

 

 

Discontinued operations

   $ 0.00       $ 0.00       $ 0.00      $ 0.00   
  

 

 

    

 

 

    

 

 

   

 

 

 

Diluted net income per common share:

          

Shares:

          

Weighted average common and common equivalent shares outstanding

     37,411         36,893         37,402        36,891   
  

 

 

    

 

 

    

 

 

   

 

 

 

Diluted net income per common share:

          

Continuing operations

   $ 0.04       $ 0.08       $ 0.15      $ 0.16   
  

 

 

    

 

 

    

 

 

   

 

 

 

Discontinued operations

   $ 0.00       $ 0.00       $ 0.00      $ 0.00   
  

 

 

    

 

 

    

 

 

   

 

 

 

 

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9. Segment information

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

 

     Corporate     Turkey      Bulgaria     Total  
     (in thousands)  

For the three months ended June 30, 2014

         

Total revenues

   $ —       $ 41,051       $ 10      $ 41,061   

Income (loss) from continuing operations before income taxes

     (3,082     5,819         (73     2,664   

Capital expenditures

   $ 64      $ 27,540       $ 334      $ 27,938   

For the three months ended June 30, 2013

         

Total revenues

   $ 2      $ 30,486       $ 28      $ 30,516   

Income (loss) from continuing operations before income taxes

     (3,154     1,525         4,712        3,083   

Capital expenditures

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

For the six months ended June 30, 2014

         

Total revenues

   $ —       $ 74,690       $ 17      $ 74,707   

Income (loss) from continuing operations before income taxes

     (6,902     13,319         2,290        8,707   

Capital expenditures

   $ 233      $ 49,321       $ 1,375      $ 50,929   

For the six months ended June 30, 2013

         

Total revenues

   $ 2      $ 64,462       $ 96      $ 64,560   

Income (loss) from continuing operations before income taxes

     (6,134     9,897         4,612        8,375   

Capital expenditures

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

Segment assets

         

June 30, 2014

   $ 13,464      $ 338,754       $ 6,710      $ 358,928 (1) 

December 31, 2013

   $ 14,070      $ 321,749       $ 10,231      $ 346,050 (1) 

Goodwill

         

June 30, 2014

   $ —       $ 7,574       $ —       $ 7,574   

December 31, 2013

   $ —       $ 7,535       $ —       $ 7,535   

 

(1) Excludes assets held for sale from our discontinued Moroccan operations of $29,000 and $536,000 at June 30, 2014 and December 31, 2013, respectively.

10. 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, 2014 and December 31, 2013, 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 Senior 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 TRY. We are also subject to foreign currency exposures resulting from translating the functional currency of our foreign subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At June 30, 2014, we had 8.2 million TRY (approximately $3.9 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY.

Commodity price risk

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including, but not limited to, supply and demand. At June 30, 2014 and December 31, 2013, 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.

 

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Fair value measurements

The following table summarizes the valuation of our financial assets and liabilities as of June 30, 2014:

 

     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)

   $ —        $ (13,995   $ —        $ (13,995
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ —        $ (13,995   $ —        $ (13,995
  

 

 

    

 

 

   

 

 

    

 

 

 

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

   $ —        $ (7,967   $ —        $ (7,967
  

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ —        $ (7,967   $ —        $ (7,967
  

 

 

    

 

 

   

 

 

    

 

 

 

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.

11. Related party transactions

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

 

     June 30,
2014
     December 31,
2013
 
     (in thousands)  

Related party accounts receivable:

     

Viking International master services agreement

   $ 171       $ 939   

Riata Management service agreement

     21         65   
  

 

 

    

 

 

 

Total related party accounts receivable

   $ 192       $ 1,004   
  

 

 

    

 

 

 

Related party accounts payable:

     

Viking International master services agreement

   $ 7,258       $ 15,956   

Viking Geophysical master services agreement

     18         6,800   

Riata Management service agreement

     421         334   
  

 

 

    

 

 

 

Total related party accounts payable

   $ 7,697       $ 23,090   
  

 

 

    

 

 

 

For the three and six months ended June 30, 2014 and 2013, we incurred expenditures of $31.6 million and $50.6 million, and $17.5 million and $37.7 million, respectively, related to our various related party agreements.

12. Discontinued operations

Discontinued operations in Morocco

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

 

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The assets and liabilities held for sale are summarized as follows:

 

     June 30, 2014      December 31, 2013  
     (in thousands)  

Cash

   $ 16       $ 23   

Other assets

     13         513   
  

 

 

    

 

 

 

Total assets held for sale

   $ 29       $ 536   
  

 

 

    

 

 

 

Accrued expenses and other liabilities

   $ 7,533       $ 7,559   
  

 

 

    

 

 

 

Total liabilities held for sale

   $ 7,533       $ 7,559   
  

 

 

    

 

 

 

Our operating results from discontinued operations for the three and six months ended June 30, 2014 and 2013 are summarized as follows:

 

     For the Three Months Ended
June 30,
    For the Six Months Ended
June 30,
 
     2014      2013     2014     2013  
     (in thousands)  

Total revenues

   $ —        $ —       $ —       $ —    

Total costs and expenses

     —          (52     (20     (138

Total other income (expense)

     —          52        —         45   
  

 

 

    

 

 

   

 

 

   

 

 

 

Loss from discontinued operations before income taxes

     —          —         (20     (93

Income tax provision

     —          —         —         —    
  

 

 

    

 

 

   

 

 

   

 

 

 

Net loss from discontinued operations

   $ —        $ —       $ (20   $ (93
  

 

 

    

 

 

   

 

 

   

 

 

 

 

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

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

Executive Overview

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored petroleum systems, are net importers of petroleum, have existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of June 30, 2014, we held interests in approximately 1.8 million net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of August 1, 2014, 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 2014 include:

 

    We reported $1.4 million of net income from continuing operations for the three months ended June 30, 2014, as compared to $2.9 million for the same period in 2013.

 

    We derived 81.0% of our revenues from the production of oil, 17.5% of our revenues from the production of natural gas and 1.5% of our revenues from other sources during the three months ended June 30, 2014.

 

    Total oil and natural gas sales revenues increased 37% to $40.4 million for the quarter ended June 30, 2014, from $29.5 million in the same period in 2013. The increase was primarily the result of an increase in sales volumes of 89 thousand barrels of oil equivalent (“Mboe”) and an increase in the average sales price of $8.40 per barrel of oil equivalent (“Boe”).

 

    Wellhead production was 319 thousand barrels (“Mbbls”) of oil and 890 million cubic feet (“Mmcf”) of natural gas for the quarter ended June 30, 2014, as compared to 231 Mbbls of oil and 926 Mmcf of natural gas for the same period in 2013.

 

    For the quarter ended June 30, 2014, we incurred $28.7 million in capital expenditures, including license acquisition and seismic expenditures from continuing operations, as compared to $28.1 million for the quarter ended June 30, 2013.

 

    As of June 30, 2014, we had $59.8 million in long-term debt and $28.3 million in short-term debt, as compared to $26.5 million in long-term debt and $43.3 million in short-term debt as of December 31, 2013.

Recent Developments

Senior Credit Facility. On May 6, 2014, DMLP, Ltd. (“DMLP”), TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey Ltd., Amity Oil International Pty Ltd (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”)(collectively, the “Borrowers”) entered into a senior secured credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP Paribas”) and the International Finance Corporation (“IFC”). Each of the Borrowers is our wholly owned subsidiary. The Senior Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) (each, a “Guarantor”). We used the proceeds from the Senior Credit Facility to pay off in full our prior senior secured credit facility on May 15, 2014, and to fund our oil and natural gas development and exploration activities in Turkey.

Changes in Management. On May 27, 2014, our board of directors appointed Todd C. Dutton as president and James R. Huling as chief operating officer of the Company. On June 16, 2014, we announced that our board of directors appointed Harold “Lee” Muncy as vice president of geosciences. In addition, our board of directors accepted the resignation of vice president, legal and corporate secretary Jeffrey S. Mecom and appointed Matthew W. McCann as general counsel and corporate secretary effective as of August 6, 2014. Mr. Mecom plans to remain at the Company in an advisory capacity through September 8, 2014.

Second Quarter 2014 Operational Update

During the second quarter of 2014, we continued to develop our oil fields in southeastern Turkey and our Thrace Basin natural gas fields in northwestern Turkey, and tested the Deventci-R2 well in Bulgaria.

Turkey-Southeast

Molla. We completed shooting our Molla 3D seismic program of approximately 800 km2 in April 2014. The final phase of processed data is projected to be delivered in the third quarter of 2014. We recently drilled the Bahar-2ST and Bahar-3 wells, both of which are being completed. We also commenced drilling the Bahar-4 and Bahar-6, vertical wells, which we expect will yield additional confirmation of the Bahar structure. For the remainder of 2014, we expect to spud at least two additional vertical Bahar wells. We also plan to drill one Mardin horizontal well based on our new Molla 3D seismic data.

 

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Selmo. We drilled three MSD horizontal wells, the Selmo-84H, Selmo-54H and Selmo-85H in the second quarter of 2014, and completed two of these wells. We are currently drilling the Selmo-68H3 well. During the first half of 2014, we spudded a total of five MSD horizontal wells, and we expect to spud four additional horizontal wells in the Selmo field during the remainder of 2014.

We initiated a waterflood pilot test program in the Selmo field in which two Selmo wells were converted to injector wells. To date, we have injected more than 250,000 barrels of water into the Selmo field. We believe secondary recovery will increase production from the field, and we intend to convert at least two additional Selmo wells to injector wells in 2014.

Based on the successful results of our five-well polymer injection program in the first quarter of 2014, which added approximately 250 barrels of oil per day (“bbl/d”), we plan to commence a second phase of polymer injections in the third quarter of 2014.

Arpatepe. We completed the Arpatepe-7, a Bedinan appraisal well in the second quarter of 2014. We plan to drill one additional appraisal well and initiate a waterflood pilot test in the Arpatepe field during the remainder of 2014.

Idil. We expect to drill a vertical exploration well on our Idil license in the second half of 2014. Our joint venture partner, Onshore Petroleum Company AS (“Onshore”), will be assigned a 50% interest in the Idil license and will fund 100% of TransAtlantic’s expected share of the cost of this well.

Turkey-Thrace Basin, Northwest

During the second quarter of 2014, we processed the remaining 25% of our Osmanli 3D seismic program. We recently spudded the TDR-5H well. During the remainder of 2014, we expect to drill five conventional shallow wells and one additional horizontal well targeting the Teslimkoy formation in the Thrace Basin.

Bulgaria

In the second quarter of 2014, we conducted a long-term pressure build-up test on the Deventci-R2 well to evaluate its connectivity to the reservoir following an initial production test of approximately 2.0 million cubic feet per day (“Mmcf/d”) of natural gas with condensates. On June 26, 2014, we submitted a request to the Bulgarian government to acidize the well. Upon receipt of approval, we plan to stimulate the well to enhance its productivity.

Planned Operations

We continue to actively explore and develop our existing oil and natural gas properties in Turkey and evaluate opportunities for further activities in Bulgaria. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and bringing these discoveries into production. For the remainder of 2014, we are focused on accomplishing the following objectives:

 

    Increase Reserves and Production. In the second quarter of 2014, we increased our average net sales volumes per day by 8% from the first quarter of 2014, and by 24% from the second quarter of 2013. We plan to continue to grow our oil and natural gas reserves and production in Turkey through exploration and development on our Selmo, Molla and Thrace Basin exploration licenses and production leases, including the application of 3D seismic, horizontal drilling and fracture stimulation techniques. During the remainder of 2014, we plan to drill, or participate in the drilling of, approximately nine new gross wells in southeastern Turkey and approximately six new gross wells in northwestern Turkey.

 

    Utilize New 3D Seismic Data to Improve Well Targeting. During the year ended December 31, 2013, we spent $12.8 million shooting 3D seismic over areas of Turkey where 3D seismic data did not previously exist. We expect this new data will improve our ability to target well locations, drill wells and ultimately delineate hydrocarbon reservoirs.

 

    Expand the Use of Horizontal Drilling. During 2013, we expanded our use of horizontal drilling, employing it on 13 of 35 wells drilled, with successful results in the Selmo, Molla and Thrace Basin areas. During the remainder of 2014, we anticipate that extensive use of horizontal drilling techniques on our wells in southeastern and northwestern Turkey will more effectively extract hydrocarbons and increase our returns on invested capital.

 

    Further Expand Fracture Stimulation Program. In 2013, we expanded our use of hydraulic fracturing technology to complete otherwise low productive formations in Turkey. The evolution of fracturing fluid and stimulation design has yielded positive results in both northwestern and southeastern Turkey. For the remainder of 2014, we plan to continue optimizing our hydraulic fracturing techniques to improve well performance and economics.

 

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    Pursue Other Growth Opportunities. In addition to growing our reserves and production through the exploration and development of our substantial acreage in Turkey and Bulgaria, we continually evaluate acquisition, joint venture and farm-in/out opportunities. We are focused on both strengthening our positions in Turkey and Bulgaria and identifying opportunities in new countries.

We expect net field capital expenditures for the remainder of 2014 to range between $45.0 million and $55.0 million for the drilling and completion of approximately 15 gross wells, the recompletion of approximately 15 existing gross wells, the processing of remaining seismic data, infrastructure improvements and other capital investments. Of these expenditures, we expect to spend approximately 75% in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Selmo, Arpatepe and Molla and processing seismic data. We expect to spend most of the remaining anticipated expenditures in northwestern Turkey, devoted to developing conventional and unconventional natural gas production and building infrastructure. We expect cash on hand, borrowings from our credit facilities and cash flow from operations will be sufficient to fund the remainder of our 2014 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2014 capital expenditure budget is subject to change. We currently plan to execute the following drilling and exploration activities during the third and fourth quarters of 2014:

Turkey. We plan to drill approximately 15 gross wells, six of which are expected to be drilled horizontally and approximately 75% of which will be fracture stimulated. We also plan to continue our waterflood pilot test and polymer injection programs.

Bulgaria. We plan to perform additional completion activities on the Deventci-R2 well pending approval from the Bulgarian government to acidize the well.

Discontinued Operations in Morocco

In June 2011, we discontinued 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, 2014 and June 30, 2013.

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 2. Significant accounting policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2013 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, 2013.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-08, Reporting Discontinued Operations and Disclosures of Components of an Entity (“ASU 2014-08”). ASU 2014-08 revises the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity’s operations and financial results, removing the lack of continuing involvement criteria and requiring discontinued operations reporting for the disposal of an equity method investment that meets the definition of discontinued operations. The update also requires expanded disclosures for discontinued operations, including disclosure of pretax profit or loss of an individually significant component of an entity that does not qualify for discontinued operations reporting. The update is effective prospectively to all periods beginning after December 15, 2014. Currently, we do not expect the adoption of ASU 2014-08 to have a material impact on our consolidated financial statements or results of operations.

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”). ASU 2014-09 amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods or services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The update is effective for periods beginning after December 15, 2016. We are currently assessing the potential impact of ASU 2014-09 on our consolidated financial statements and results of operations.

 

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

Results of Operations—Three Months Ended June 30, 2014 Compared to Three Months Ended June 30, 2013

Our results of operations for the three months ended June 30, 2014 and 2013 were as follows:

 

     Three Months Ended June 30,     Change  
     2014     2013     2014-2013  
    

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

 

Welhead Production:

      

Oil (Mbbl)

     319        231        88   

Natural gas (Mmcf)

     890        926        (36

Total production (Mboe)

     467        385        82   

Average daily wellhead production (Boepd)

     5,132        4,231        901   

Sales volumes:

      

Oil (Mbbl)

     318        230        88   

Natural gas (Mmcf)

     821        816        5   

Total production (Mboe)

     455        366        89   

Average daily sales volumes (Boepd)

     5,000        4,022        978   

Average prices:

      

Oil (per Bbl)

   $ 104.53      $ 94.13      $ 10.40   

Natural gas (per Mcf)

   $ 8.77      $ 9.57      $ (0.80

Oil equivalent (per Boe)

   $ 88.88      $ 80.48      $ 8.40   

Revenues:

      

Oil and natural gas sales

   $ 40,441      $ 29,455      $ 10,986   

Sales of purchased natural gas

     491        719        (228

Other

     129        342        (213

Costs and expenses:

      

Production

   $ 4,666      $ 3,328      $ 1,338   

Exploration, abandonment and impairment

     3,775        11,885        (8,110

Cost of purchased natural gas

     440        619        (179

Seismic and other exploration

     892        1,090        (198

Revaluation of contingent consideration

     —          (5,000     5,000   

General and administrative

     7,460        6,893        567   

Depletion

     12,022        8,976        3,046   

Depreciation and amortization

     566        605        (39

Interest and other expense

     1,769        955        814   

Foreign exchange (gain) loss

     (2,494     2,543        (5,037

(Loss) gain on commodity derivative contracts:

      

Cash settlements on commodity derivative contracts

   $ (1,781   $ (484   $ (1,297

Change in fair value on commodity derivative contracts

     (7,741     4,762        (12,503
  

 

 

   

 

 

   

 

 

 

Total (loss) gain on commodity derivative contracts

   $ (9,522   $ 4,278      $ (13,800

Oil and natural gas costs per Boe:

      

Production

   $ 8.98      $ 7.96      $ 1.02   

Depletion

   $ 23.14      $ 21.46      $ 1.68   

Oil and Natural Gas Sales. Total oil and natural gas sales revenues increased $10.9 million to $40.4 million for the three months ended June 30, 2014, from $29.5 million realized in the same period in 2013. Of this increase, $7.2 million was due to an

 

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increase in sales volumes of 89 Mboe. Additionally, we realized a higher average price per Boe, which resulted in higher revenues of $3.8 million. Our average price received increased $8.40 per Boe to $88.88 per Boe for the three months ended June 30, 2014, from $80.48 per Boe for the same period in 2013.

Production. Production expenses for the three months ended June 30, 2014 increased to $4.7 million or $8.98 per Boe, from $3.3 million or $7.96 per Boe for the same period in 2013. The increase was primarily attributable to $1.1 million of operating expenses, which we billed back to our Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) joint venture partners during the three months ended June 30, 2013, following a redetermination of operating costs.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended June 30, 2014 decreased approximately $8.1 million to $3.8 million, from $11.9 million for the same period in 2013. During the three months ended June 30, 2014, we recorded impairment charges of $2.8 million primarily related to the Kazanci-5 well, compared to the three months ended June 30, 2013, when we incurred license impairment charges of $4.6 million. Additionally, three wells were written off for $6.1 million during three months ended June 30, 2013.

General and Administrative. General and administrative expense was $7.5 million for the three months ended June 30, 2014, as compared to $6.9 million for the same period in 2013. The increase was primarily due to an increase in employee-related costs of $0.9 million and an increase in travel expenses of $0.1 million, which was partially offset by a decrease in accounting and consulting expenses of $0.4 million. Employee-related costs increased primarily due to severance payments made to former employees. Accounting and consulting expenses were higher during the three months ended June 30, 2013 primarily 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.

Depletion. Depletion increased to $12.0 million or $23.14 per Boe for the three months ended June 30, 2014, compared to $9.0 million or $21.46 per Boe for the same period of 2013. The increase was primarily due to additions to proved properties during the three months ended June 30, 2014.

Interest and Other Expense. Interest and other expense increased to $1.8 million for the three months ended June 30, 2014, as compared to $1.0 million for the same period in 2013. The increase was primarily due to a $0.5 million write-off of loan financing costs related to the amended and restated credit facility, which was repaid in May 2014. Also contributing to the increase was an increase in our average level of debt outstanding during the three months ended June 30, 2014 compared to the same period in 2013. At June 30, 2014, we had $88.1 million of total debt outstanding, compared to $39.8 million at June 30, 2013.

Foreign Exchange (Gain) Loss. We recorded a foreign exchange gain of $2.5 million during the three months ended June 30, 2014, compared to a loss of $2.5 million for the same period of 2013. The change in foreign exchange was primarily unrealized (non-cash) in nature and resulted from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the New Turkish Lira (“TRY”) amount if it has not been settled previously. The increase in foreign exchange gain during the three months ended June 30, 2014 was due to an increase in the value of the TRY compared to the U.S. Dollar, versus the decrease in the value of the TRY compared to the U.S. Dollar for the three months ended June 30, 2013.

(Loss) Gain on Commodity Derivative Contracts. During the three months ended June 30, 2014, we recorded a net loss on commodity derivative contracts of approximately $9.5 million, as compared to a net gain of $4.3 million for the same period in 2013. During the three months ended June 30, 2014, we recorded a $7.7 million loss to mark our commodity derivatives to their fair value and a $1.8 million loss on settled contracts. During the same period in 2013, we recorded a $4.8 million gain to mark our commodity derivatives to their fair value and a $0.5 million loss on settled contracts. We are required under our Senior Credit Facility to hedge no less than 30% of our anticipated oil sales volumes in our oil fields in Turkey.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations for the three months ended June 30, 2014 and 2013 have been included in discontinued operations.

 

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The results of operations for our Moroccan operations were as follows:

 

     Three Months Ended June 30,  
     2014      2013  
     (in thousands)  

Costs and expenses:

     

Production

   $ —        $ 41   

General and administrative

     —           11   
  

 

 

    

 

 

 

Total costs and expenses

     —           52   
  

 

 

    

 

 

 

Operating loss

     —           (52

Other income (expense):

     

Interest and other expense

     —           (6

Interest and other income

     —           58   
  

 

 

    

 

 

 

Total other income

     —           52   
  

 

 

    

 

 

 

Net income from discontinued operations

   $ —        $ —    
  

 

 

    

 

 

 

Results of Operations—Six Months Ended June 30, 2014 Compared to Six Months Ended June 30, 2013

Our results of operations for the six months ended June 30, 2014 and 2013 were as follows:

 

     Six Months Ended June 30,     Change  
     2014     2013     2014-2013  
     (in thousands of U.S. dollars, except per unit amounts and volumes)  

Wellhead production:

      

Oil (Mbbl)

     580        476        104   

Natural gas (Mmcf)

     1,950        1,782        168   

Total production (Mboe)

     905        773        132   

Average daily wellhead production (Boepd)

     5,000        4,271        729   

Sales volumes:

      

Oil (Mbbl)

     578        470        108   

Natural gas (Mmcf)

     1,755        1,616        139   

Total production (Mboe)

     871        739        132   

Average daily sales volumes (Boepd)

     4,812        4,083        729   

Average prices:

      

Oil (per Bbl)

   $ 101.06      $ 98.44      $ 2.62   

Natural gas (per Mcf)

   $ 8.52      $ 9.85      $ (1.33

Oil equivalent (per Boe)

   $ 84.30      $ 84.14      $ 0.16   

Revenues:

      

Oil and natural gas sales

   $ 73,425      $ 62,180      $ 11,245   

Sales of purchased natural gas

     1,036        1,525        (489

Other

     246        855        (609

Costs and expenses:

      

Production

   $ 8,797      $ 8,855      $ (58

Exploration, abandonment and impairment

     7,916        15,749        (7,833

Cost of purchased natural gas

     925        1,331        (406

Seismic and other exploration

     4,186        1,333        2,853   

Revaluation of contingent consideration

     (2,500     (5,000     2,500   

General and administrative

     14,012        14,416        (404

Depletion

     21,581        17,362        4,219   

Depreciation and amortization

     1,097        1,195        (98

Interest and other expense

     2,972        1,845        1,127   

Foreign exchange (gain) loss

     (1,150     3,030        (4,180

(Loss) gain on commodity derivative contracts:

      

Cash settlements on commodity derivative contracts

   $ (2,533   $ (1,736   $ (797

Change in fair value on commodity derivative contracts

     (6,027     5,238        (11,265
  

 

 

   

 

 

   

 

 

 

Total (loss) gain on commodity derivative contracts

   $ (8,560   $ 3,502      $ (12,062

Oil and natural gas costs per Boe:

      

Production

   $ 8.85      $ 10.49      $ (1.64

Depletion

   $ 21.71      $ 20.56      $ 1.15   

 

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Oil and Natural Gas Sales. Total oil and natural gas sales revenues increased $11.2 million to $73.4 million for the six months ended June 30, 2014, from $62.2 million realized in the same period in 2013. Of this increase, $11.1 million was due to an increase in sales volumes of 132 Mboe. Additionally, we realized a slightly higher average price per Boe, which resulted in an additional $0.1 million of revenue. Our average price received increased $0.16 per Boe to $84.30 per Boe for the six months ended June 30, 2014, from $84.14 per Boe for the same period in 2013.

Production. Production expenses for the six months ended June 30, 2014 decreased to $8.8 million or $8.85 per Boe, from $8.9 million or $10.49 per Boe for the same period in 2013. The decrease of $1.64 per Boe was primarily attributable to an increase in our working interest production volumes during the six months ended June 30, 2014 compared to the same period in 2013.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the six months ended June 30, 2014 decreased approximately $7.8 million to $7.9 million, from $15.7 million for the same period in 2013. During the six months ended June 30, 2014, we impaired two wells for $6.3 million. During the six months ended June 30, 2013, we wrote off four wells for $10.0 million and incurred license impairment charges of $4.6 million.

Seismic and Other Exploration. Seismic and other exploration costs increased to $4.2 million for the six months ended June 30, 2014, as compared to $1.3 million for the same period in 2013. The increase was primarily due to seismic acquisition activity conducted on our West Molla and Osmanli licenses during the six months ended June 30, 2014.

General and Administrative. General and administrative expense was $14.0 million for the six months ended June 30, 2014, compared to $14.4 million for the same period in 2013. The decrease was primarily due to a decrease of $0.6 million in accounting and consulting expenses and a $0.2 million decrease in office expenses and rent, which was partially offset by a $0.4 million increase in employee-related costs. Accounting and consulting expenses were higher during the six months ended June 30, 2013 primarily 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. Employee-related costs increased during the six months ended June 30, 2014 primarily due to severance payments made to former employees.

Depletion. Depletion increased to $21.6 million or $21.71 per Boe for the six months ended June 30, 2014, compared to $17.4 million or $20.56 per Boe for the six months ended June 30, 2013. The increase was primarily due to additions to proved properties during the six months ended June 30, 2014.

Interest and Other Expense. Interest and other expense increased to $3.0 million for the six months ended June 30, 2014, compared to $1.8 million for the same period in 2013. The increase was primarily due to an increase in our average level of debt outstanding during the six months ended June 30, 2014 compared to the same period in 2013. At June 30, 2014, we had $88.1 million of total debt outstanding, compared to $39.8 million at June 30, 2013. Also contributing to the increase was a $0.5 million write-off of loan financing costs related to the amended and restated credit facility, which was repaid in May 2014.

Foreign Exchange (Gain) Loss. We recorded a foreign exchange gain of $1.2 million during the six months ended June 30, 2014, compared to a loss of $3.0 million in the same period of 2013. The change in foreign exchange was primarily unrealized (non-cash) in nature and resulted from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the TRY amount if it has not been settled previously. The increase in foreign exchange gain during the six months ended June 30, 2014 was due to an increase in the value of the TRY compared to the U.S. Dollar, versus the decrease in the value of the TRY compared to the U.S. Dollar for the six months ended June 30, 2013.

(Loss) Gain on Commodity Derivative Contracts. During the six months ended June 30, 2014, we recorded a net loss on commodity derivative contracts of approximately $8.6 million, compared to a net gain of $3.5 million for the same period in 2013. During the six months ended June 30, 2014, we recorded a $6.0 million loss to mark our commodity derivatives to their fair value and

 

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a $2.5 million loss on settled contracts. During the same period in 2013, we recorded a $5.2 million gain to mark our commodity derivatives to their fair value and a $1.7 million loss on settled contracts. We are required under our Senior Credit Facility to hedge no less than 30% of our anticipated oil sales volumes in our oil fields in Turkey.

Discontinued Operations. All revenues and expenses associated with our Moroccan operations for the six months ended June 30, 2014 and 2013 have been included in discontinued operations.

The results of operations for our Moroccan operations were as follows:

 

     Six Months Ended June 30,  
     2014     2013  
     (in thousands)  

Costs and expenses:

    

Production

   $ —        $ 110   

General and administrative

     20        28   
  

 

 

   

 

 

 

Total costs and expenses

     20        138   
  

 

 

   

 

 

 

Operating loss

     (20     (138

Other income (expense):

    

Interest and other expense

     —          (8

Interest and other income

     —          53   
  

 

 

   

 

 

 

Total other income

     —          45   
  

 

 

   

 

 

 

Net loss from discontinued operations

   $ (20   $ (93
  

 

 

   

 

 

 

Capital Expenditures

For the quarter ended June 30, 2014, we incurred $28.7 million in capital expenditures, including license acquisition and seismic expenditures from continuing operations, as compared to $28.1 million for the quarter ended June 30, 2013.

Capital expenditures, including seismic expenditures, for the third and fourth quarters of 2014 are expected to range between $45.0 million and $55.0 million. We expect to spend approximately 75% of these anticipated expenditures in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Selmo, Arpatepe and Molla and processing seismic data. We expect to spend most of the remaining anticipated expenditures in northwestern Turkey, devoted to developing conventional and unconventional natural gas production and building infrastructure. Our projected 2014 capital budget is subject to change, and if cash on hand, borrowings from our credit facilities, 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 2014 were our cash and cash equivalents, cash flow from operations and net borrowings under our Senior Credit Facility. At June 30, 2014, we had cash and cash equivalents of $5.2 million, $28.3 million in short-term debt, $59.8 million in long-term debt, and a working capital deficit of $12.5 million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities), compared to cash and cash equivalents of $12.9 million, $43.3 million in short-term debt, $26.5 million in long-term debt, and a working capital deficit of $39.4 million (excluding assets and liabilities held for sale, deferred income taxes and derivative liabilities) at December 31, 2013. Net cash provided by operating activities from continuing operations for the six months ended June 30, 2014 decreased to $41.5 million, as compared to net cash provided by operating activities from continuing operations of $55.7 million for the six months ended June 30, 2013. This decrease was primarily a result of a decrease in our accounts payable during the six months ended June 30, 2014, compared to an increase in our accounts payable during the same period in 2013.

As of June 30, 2014, the outstanding principal amount of our debt was $88.1 million. In addition to cash, cash equivalents and cash flow from operations, at June 30, 2014, we had a Senior Credit Facility and a credit facility with a Turkish bank, which are discussed below.

Senior Credit Facility. On May 6, 2014, the Borrowers entered into the Senior Credit Facility with BNP Paribas and IFC. The Senior Credit Facility is guaranteed by us and each of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide.

The amount drawn under the Senior Credit Facility may not exceed the lesser of (i) $150.0 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. The lenders have an initial aggregate

 

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commitment of $80.0 million, with individual commitments of $40.0 million each. The Company has the ability to increase the commitments up to an aggregate of $150.0 million by March 31, 2016. On the first day of each fiscal quarter commencing April 1, 2016, the lenders’ commitments are subject to reduction in an amount equal to 7.69% of the aggregate commitments in effect on April 1, 2016.

The borrowing base amount is re-determined semi-annually on April 1st and October 1st of each year, beginning April 1, 2015. The current borrowing base is $74.6 million. The borrowing base amount equals, for any calculation date, the lowest of:

 

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

 

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

The Senior Credit Facility matures on the earlier of (i) March 31, 2019, or (ii) the last date of the borrowing base calculation period that immediately precedes the date that the semi-annual banking case of BNP Paribas and the Borrowers determines that the aggregate amount of hydrocarbons to be produced from the borrowing base assets in Turkey are less than 25% of the amount of hydrocarbons to be produced from the borrowing base assets shown in the initial banking case prepared by BNP Paribas and the Borrowers. The Senior Credit Facility bears various letter of credit sub-limits, including among other things, sub-limits of up to (i) $10.0 million, (ii) the aggregate available unused and uncancelled portion of the lenders’ commitments or (iii) any amount borrowed from an individual lender to the extent it exceeds the aggregate amount of such lender’s individual commitment.

Loans under the Senior Credit Facility accrue interest at a rate of three-month LIBOR plus 5.00% per annum (5.23% at June 30, 2014). The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to (a) 2.00% per annum of the unused and uncancelled portion of the aggregate commitments that is less than or equal to the maximum available amount under the Senior Credit Facility, and (b) 1.00% per annum of the unused and uncancelled portion of the aggregate commitments that exceed the maximum available amount under the Senior Credit Facility and is not available to be borrowed, (ii) on the date of issuance of any letter of credit, a fronting fee in an amount equal to 0.25% of the original maximum amount to be drawn under such letter of credit and (iii) a per annum letter of credit fee for each letter of credit issued equal to the face amount of such letter of credit multiplied by (a) 1.0% for any letter of credit that is cash collateralized or backed by a standby letter of credit issued by a financial institution acceptable to BNP Paribas or (b) 5.00% for all other letters of credit.

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

The Borrowers are required to comply with certain financial and non-financial covenants under the Senior Credit Facility, including maintaining the following financial ratios during the four most recently completed fiscal quarters occurring on or after March 31, 2014:

 

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

 

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

 

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

 

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

The Senior Credit Facility defines EBITDAX as net income (excluding extraordinary items) plus, to the extent deducted in calculating such net income, (i) interest expense (excluding interest paid-in-kind, or non-cash interest expense and interest incurred on certain subordinated intercompany debt or interest on equity recapitalized into subordinated debt), (ii) income tax expense, (iii) depreciation, depletion and amortization expense, (iv) amortization of intangibles and organization costs, (v) any extraordinary, unusual or non-recurring non-cash expenses or losses, (vi) expenses incurred in connection with oil and gas exploration activities entered into in the ordinary course of business (including related drilling, completion, geological and geophysical costs), (vii) transaction costs, expenses and fees incurred in connection with the negotiation, execution and delivery of the Senior Credit Facility and the related loan documents, minus, to the extent included in calculating net income, (a) any extraordinary, unusual or non-recurring income or gains (including, gains on the sales of assets outside of the ordinary course of business) and (b) any other non-cash income or gains.

Pursuant to the terms of the Senior Credit Facility, until amounts under the Senior Credit Facility are repaid, each of the Borrowers shall not, and shall cause each of its subsidiaries not to, in each case subject to certain exceptions (i) incur indebtedness or create any liens, (ii) enter into any agreements that prohibit the ability of any Borrower or its subsidiaries to create any liens, (iii) enter into any merger, consolidation or amalgamation, liquidate or dissolve, (iv) dispose of any property or business, (v) pay any dividends, distributions or similar payments to shareholders, (vi) make certain types of investments, (vii) enter into any transactions with an affiliate, (viii) enter into a sale and leaseback arrangement, (ix) engage in any business or business activity, own any assets or assume

 

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any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and natural gas exploration and production company or operate or carry on business in any jurisdiction outside of Turkey or its jurisdiction of formation, (x) change its organizational documents, (xi) permit its fiscal year to end on a day other than December 31st or change its method of determining fiscal quarters, or alter the accounting principles it uses, (xii) modify certain hydrocarbon licenses and agreements or material contracts, (xiii) enter into any hedge agreement for speculative purposes, (xiv) open or maintain new deposit, securities or commodity accounts, (xv) use the proceeds from any loan in the territories of any country that is not a member of the World Bank, (xvi) incur any expenditure that is not covered by the projections in the most recent corporate cashflow projection, (xvii) modify its social and environmental action plans as determined in conjunction with IFC, (xviii) enter into any transaction or engage in any activity prohibited by the United Nations Security Council, or (xix) engage in any corrupt, fraudulent, coercive, collusive or obstructive practice.

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

At July 1, 2014, we had borrowings of $59.8 million under the Senior Credit Facility and availability of $14.8 million.

TBNG Credit Facility. On June 18, 2013, TBNG entered into a 78.8 million TRY (approximately $37.1 million at June 30, 2014) unsecured line of credit with a Turkish bank, of which 60 million TRY is available in cash for TBNG and 18.8 million TRY 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. We have made three borrowings under this credit facility, each of which has a one-year term at a fixed interest rate of 4.6% per annum. At maturity, we expect to renew the borrowings for one additional year at then current market interest rates. As of June 30, 2014, we had borrowed $26.7 million under this credit facility with no remaining availability.

Contingencies Relating to Production Leases and Exploration Permits

Selmo

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

Morocco

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 believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during 2012 for this contingency.

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 2012 for this contractual obligation.

 

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Direct Petroleum

In July 2013, we entered into a second amendment (the “Amendment”) to the purchase agreement (the “Purchase Agreement”) with Direct Petroleum Exploration, LLC (“Direct”). The Amendment set forth a new obligation to drill and test the Deventci-R2 well by May 1, 2014. We completed the drilling and testing requirements pursuant to the Amendment during April 2014, which resulted in the reversal of the $2.5 million contingent liability recorded in 2011. The reversal is recognized in our consolidated statements of comprehensive income (loss) under the caption “Revaluation of contingent consideration” during the six months ended June 30, 2014.

In addition, the Amendment provides that we will issue $7.5 million in common shares if the Deventci-R2 well is a commercial success (as defined in the Purchase Agreement) on or prior to May 1, 2016. We will record any provision for this contingent consideration when it is estimable and probable. As of June 30, 2014, we had not recorded a contingent liability for this contingent consideration.

Additionally, the Amendment provides that if the Bulgarian government issues a production concession over the stefenetz concession area (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. We do not have enough information to estimate the potential contingent liability we would incur in the event the Bulgarian government issues a production concession over the Stefenetz Concession Area. Any adjustment will be recorded when it becomes probable and estimable.

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, 2013.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at June 30, 2014.

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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Item  3. Quantitative and Qualitative Disclosures About Market Risk

During the second quarter of 2014, 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, 2013. Our oil derivatives contracts are settled based on Brent crude oil pricing. The following tables set forth our outstanding derivatives contracts with respect to future crude oil production as of June 30, 2014:

Fair Value of Derivative Instruments as of June 30, 2014

 

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

     July 1, 2014—December 31, 2014         1,770       $ 85.00       $ 97.25       $ (4,758

Collar

     January 1, 2015—December 31, 2015         1,410       $ 85.00       $ 97.25         (6,027
              

 

 

 
               $ (10,785
              

 

 

 

 

            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, 2016—December 31, 2016         1,066       $ 85.00       $ 97.25       $ 114.25       $ (2,057

Three-way collar contract

     January 1, 2017—December 31, 2017         888       $ 85.00       $ 97.25       $ 114.25         (851

Three-way collar contract

     January 1, 2018—December 31, 2018         726       $ 85.00       $ 97.25       $ 114.25         (282

Three-way collar contract

     January 1, 2019—March 31, 2019         663       $ 85.00       $ 97.25       $ 114.25         (20
                 

 

 

 
                  $ (3,210
                 

 

 

 

 

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, 2014, 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, 2013, our chief executive officer and chief financial officer concluded that, as of June 30, 2014, 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.

 

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Changes in Internal Control over Financial Reporting

There were no changes during the second quarter of 2014 that have affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

 

Item  1. Legal Proceedings

During the second quarter of 2014, 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, 2013.

 

Item  1A. Risk Factors

During the second quarter of 2014, 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, 2013, except as disclosed below:

The majority of our oil is sold to two customers, and the loss of either customer could have a material adverse impact on our results of operations.

Turkiye Petrolleri Anonim Ortakligi (“TPAO”), the national oil company of Turkey, and Türkiye Petrol Rafinerileri A.Ş. (“TUPRAS”), a privately owned oil refinery in Turkey, purchase all of our oil production from the Selmo field. TUPRAS purchases the majority of our oil production from Selmo, representing 66.7% of our total revenues in 2013. If either of these companies reduces their oil purchases or fails to purchase our oil production, or there is a material non-payment, our results of operations could be materially and adversely affected. TPAO or TUPRAS may be subject to their own operating risks that could increase the risk that they could default on their obligations to us.

Acts of violence, terrorist attacks or civil unrest in southeastern Turkey and nearby countries could adversely affect our business.

During 2013, we derived 71.3% of our oil production from the Selmo oil field in southeastern Turkey. Historically, the southeastern area of Turkey and nearby countries such as Iran, Iraq and Syria have experienced political, social, security and economic problems, terrorist attacks, insurgencies, war and civil unrest. Since December 2010, political instability has increased markedly in a number of countries in the Middle East and North Africa. As a result of the civil war in Syria, hundreds of thousands of Syrian refugees have fled to Turkey and more can be expected to cross the border as the conflict continues. Moreover, tensions between Turkey and Syria have escalated and hostilities between Turkey and Syria have broken out over a series of incidents, including mortar fire by Syrian forces into Turkey that killed a number of Turkish civilians. On May 10, 2013, a terrorist attack occurred in the Turkish town of Reyhanlı, Hatay in southern Turkey. On March 23, 2014, Turkey shot down a Syrian combat jet on the Turkish-Syrian border.

The instability surrounding the situation in Iraq, as well as tension in and involving the Kurdish regions of northern Iraq, which are contiguous to the region where the Selmo oil field is located, may have political, social or security implications in Turkey or otherwise have a negative impact on the Turkish economy. Stability and security in Iraq have deteriorated significantly in recent months.

Turkey has also experienced problems with domestic terrorist and ethnic separatist groups. For example, Turkey has been in conflict for many years with the People’s Congress of Kurdistan (formerly known as the PKK), an organization that is listed as a terrorist organization by states and organizations, including Turkey, the European Union and the United States. The issue of civil rights for Kurdish citizens remains a potential source of political instability, which may be exacerbated by continuing instability in the Middle East.

The potential impact on our business from such events, conditions and conflicts in these countries is uncertain. We may be unable to access the locations where we conduct operations or transport oil to our offtakers in a reliable manner. In those locations where we have employees or operations, we may incur substantial costs to maintain the safety of our personnel and our operations. Despite these precautions, the safety of our personnel and operations in these locations may continue to be at risk, and we may in the future suffer the loss of employees and contractors or our operations could be disrupted, any of which could have a material adverse effect on our business and results of operations.

 

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We have concentrated current production of oil in the Selmo oil field.

During 2013, we derived 71.3% of our oil production from the Selmo oil field in southeastern Turkey. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages, litigation or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, we are currently in litigation with a group of villagers who live around the Selmo oil field and who claim ownership of a portion of the surface rights at Selmo. Disruptions in our production of oil in the Selmo oil field from any of these factors could have a material adverse effect on our business and results of operations.

Restrictive covenants in our Senior Credit Facility may restrict our ability to pursue our business strategies and can lead to an event of default that may adversely affect our business, financial condition and results of operations.

The operating and financial restrictions and covenants in our Senior Credit Facility with BNP Paribas and IFC may adversely affect our ability to finance future operations or capital needs or to engage in other business activities. Our Senior Credit Facility contains various covenants that restrict the Borrowers’ ability to, among other things:

 

    incur additional debt;

 

    create liens;

 

    enter into any hedge agreement for speculative purposes;

 

    engage in business, own any assets or assume any liabilities or obligations except as necessary in connection with, or reasonably related to, its business as an oil and natural gas exploration and production company, or operate or carry on the business in any jurisdiction outside of Turkey or its jurisdiction of formation;

 

    enter into sale and leaseback transactions;

 

    enter into any merger, consolidation or amalgamation;

 

    pay any dividends, distributions or other payments to shareholders; or

 

    enter into any transactions with an affiliate.

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

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

In the event of a default and acceleration of indebtedness under the Senior Credit Facility, our business, financial condition and results of operations may be materially and adversely affected.

 

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Our use of 2D and 3D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2D and 3D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and gas services and products may have a material adverse effect on our results of operations.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

 

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

None.

 

Item  3. Defaults Upon Senior Securities

None.

 

Item  4. Mine Safety Disclosures

Not applicable.

 

Item  5. Other Information

None.

 

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Item  6. Exhibits

 

    3.1   Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
    3.2   Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
    3.3   Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
  10.1   Credit Agreement, dated as of May 6, 2014, by and between Amity Oil International Pty Ltd, DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, the lenders party thereto from time to time, and BNP Paribas (Suisse) SA as coordinating mandated lead arranger, sole bookrunner, letter of credit issuer, administrative agent, collateral agent and technical agent and International Finance Corporation, as mandated lead arranger (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014, filed with the SEC on May 8, 2014).
  31.1*   Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  31.2*   Certification of the 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.

 

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Signatures

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

 

By:

 

/s/ N. MALONE MITCHELL 3rd

 

N. Malone Mitchell 3rd

Chief Executive Officer

By:

 

/s/ WIL F. SAQUETON

 

Wil F. Saqueton

Chief Financial Officer

Date: August 7, 2014

 

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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   Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
    3.3   Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
  10.1   Credit Agreement, dated as of May 6, 2014, by and between Amity Oil International Pty Ltd, DMLP, Ltd., Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş., Talon Exploration, Ltd., TransAtlantic Exploration Mediterranean International Pty. Ltd., TransAtlantic Turkey, Ltd., as borrowers, TransAtlantic Petroleum Ltd., TransAtlantic Petroleum (USA) Corp., TransAtlantic Worldwide, Ltd., as guarantors, the lenders party thereto from time to time, and BNP Paribas (Suisse) SA as coordinating mandated lead arranger, sole bookrunner, letter of credit issuer, administrative agent, collateral agent and technical agent and International Finance Corporation, as mandated lead arranger (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014, filed with the SEC on May 8, 2014).
  31.1*   Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
  31.2*   Certification of the 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.

 

34

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, 2014       /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, 2014       /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, 2014 (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, 2014

 

                /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.