UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended: September 30, 2014

OR

For the transition period from                      to                     

Commission file number: 001-34574

 

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

 

 

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):

 

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 November 3, 2014, the registrant had 37,483,306 common shares outstanding.

 

 

 

 

 

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TABLE OF CONTENTS

 

 

 

 

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PART I. FINANCIAL INFORMATION

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

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

 

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

 

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Comprehensive Income (Loss)

(Unaudited)

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

 

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

 

 

 

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TRANSATLANTIC PETROLEUM LTD.

Consolidated Statement of Equity

(Unaudited)

(U.S. Dollars and shares in thousands)

 

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)

 

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 November 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.

 

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern ("ASU 2014-15"), an amendment to FASB Accounting Standards Codification ("ASC") Topic 205, Presentation of Financial Statements.  This update provides guidance on management's responsibility in evaluating whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Company does not expect the adoption of ASU 2014-15 to have a material impact on its financial statement disclosures.

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

 

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:

 

At September 30, 2014 and December 31, 2013, we excluded $5.2 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 September 30, 2014, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $31.0 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $148.2 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 nine months ended September 30, 2014, we recorded $0.6 million and $8.5 million, respectively, of impairment and exploratory dry-hole costs. Of the $8.5 million of costs incurred during the nine months ended September 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 $8.5 million of costs incurred during the nine months ended September 30, 2014, $1.9 million was cash spent during the period.

Capitalized cost greater than one year

As of September 30, 2014, we had $1.6 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.

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Equipment and other property

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

 

 

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 September 30, 2014, we excluded $23.9 million of inventory and $1.9 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 nine months ended September 30, 2014 and for the year ended December 31, 2013:

 

 

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 “Gain (loss) 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

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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 nine months ended September 30, 2014, we recognized a $0.7 million realized loss on the unwinding of these commodity derivative contracts, which is included in our consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on commodity derivative contracts”.

During the three months ended September 30, 2014 and 2013, we recorded a net gain on commodity derivative contracts of $11.0 million and a net loss of $3.1 million, respectively. During the nine months ended September 30, 2014 and 2013, we recorded a net gain on commodity derivative contracts of $2.4 million and $0.4 million, respectively.

At September 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 September 30, 2014

 

 

 

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Fair Value of Derivative Instruments as of December 31, 2013

 

 

 

Balance sheet presentation

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

 

 

 

 

 

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6. Loan payable

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

 

 

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 borrowing base was $71.5 million as of October 1, 2014. The borrowing base amount equals, for any calculation date, the lowest of:

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 September 30, 2014). The Borrowers are also required to pay (i) a commitment fee payable quarterly in arrears at a per annum rate equal to

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(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:

 

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) any other non-cash charges (including dry hole expenses and seismic expenses, to the extent such expenses would be capitalized under the “full cost” accounting method), (vii) 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), and (viii) 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 for any reason to be the executive

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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.

Pursuant to the Senior Credit Facility, at least one of the Borrowers is required to maintain commodity derivative contracts with BNP Paribas that hedge between 30% and 75% of our anticipated oil production volumes in our oil fields in Turkey. TEMI has entered into three-way collar contracts with BNP Paribas, which hedge the price of oil through March 2019.  As of October 1, 2014, we had outstanding borrowings of $64.8 million under the Senior Credit Facility and availability of $6.7 million and were in compliance with all covenants in the Senior Credit Facility.

TBNG credit facility

On June 18, 2013, our wholly owned subsidiary, Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”), entered into a 78.8 million New Turkish Lira (“TRY”) (approximately $34.6 million at September 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 made three borrowings under this credit facility, on October 9, 2013, November 5, 2013 and January 22, 2014, each of which had a one-year term at a fixed interest rate of 4.6% per annum (see note 13).  As of September 30, 2014, we had borrowed $26.7 million and had no remaining availability 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 September 30, 2014, we had outstanding borrowings of $0.2 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

During 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew down our $1.0 million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during 2012 for this contingency.

Aglen

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

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 a $2.5 million contingent liability recorded in 2011. The reversal is recognized in our consolidated statements of

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comprehensive income (loss) under the caption “Revaluation of contingent consideration” during the nine months ended September 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 September 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 provision for this contingent consideration will be recorded when it becomes probable and estimable.

 

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 $0.2 million and $1.0 million with respect to awards of restricted stock units (“RSUs”) was recorded for the three and nine months ended September 30, 2014, respectively. We recorded share-based compensation expense of $0.5 million and $1.3 million for the three and nine months ended September 30, 2013, respectively.

As of September 30, 2014, we had approximately $1.2 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.7 years.

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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 nine months ended September 30, 2014 and 2013 equals net income (loss) divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding RSUs. Diluted earnings per common share for the three and nine months ended September 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 nine months ended September 30, 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:

 

 

 

 

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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:

 

 

 

 

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 September 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 September 30, 2014, we had 14.4 million TRY (approximately $6.3 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY.

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Commodity price risk

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including, but not limited to, supply and demand. At September 30, 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 purchases all of our oil production. The receivables are not collateralized. To date, we have experienced minimal bad debts. The majority of our cash and cash equivalents are held by three financial institutions in the United States and Turkey.

Fair value measurements

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

 

The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2013:

 

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.

 

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11. Related party transactions

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

 

For the three and nine months ended September 30, 2014 and 2013, we incurred expenditures of $25.0 million and $75.5 million, and $27.8 million and $65.5 million, respectively, related to our various related party agreements.

 

12. Discontinued operations

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.

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

 

 

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

 

 

 

13. Subsequent events

On October 31, 2014, TBNG entered into an amendment to its line of credit with a Turkish bank.  Pursuant to the amendment, TBNG will repay the facility in 12 monthly principal installments of $2.3 million each, starting October 31, 2014, and the facility will bear interest at a rate of 6.6% per annum until repaid.  The facility may be prepaid without penalty.  The facility is secured by a lien on the Gundem hotel, which is owned by Mr. Mitchell.

 

 

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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 September 30, 2014, we held interests in approximately 1.7 million net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of November 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 third quarter of 2014 include:

Recent Developments

Pending Stream Acquisition. On September 2, 2014, we entered into an Arrangement Agreement with Stream Oil & Gas Ltd. (“Stream”) providing for an arrangement under British Columbia law (the “Arrangement”), whereby we expect to acquire all of the outstanding common shares of Stream in exchange for up to 3.8 million common shares of the Company based on the terms and subject to the conditions set forth therein.  Stream owns 100% of the interests in three onshore oil fields and one gas concession, consisting of one onshore gas field and one exploration license, all in Albania.

Third Quarter 2014 Operational Update

For the third quarter of 2014, we had average net sales of approximately 5,000 Boepd, which was equivalent to net sales in the second quarter of 2014, and a 23.5% increase over net sales in the third quarter of 2013. Net sales for the third quarter of 2014 were comprised of approximately 3,700 barrels of oil per day (“Bbl/d”) and approximately 8.0 Mmcf of natural gas per day (“Mmcf/d”).

During September 2014, our average net production was more than 5,400 Boepd. We spudded 11 wells and completed six new wells in the third quarter of 2014. Year to date, we spudded 24 wells and completed 19 new wells. We currently have three active rigs in southeastern Turkey and one active rig in the Thrace Basin of northwestern Turkey.

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Turkey-Southeast

Molla. We have completed drilling the Bahar-6 well at a depth of approximately 10,500 feet. We have drilled three vertical wells and one re-entry directional well in the Bahar field this year and plan to monitor their performance before drilling additional Bahar wells in 2015.

We completed the Bahar-3 and Bahar-4 wells in the third quarter of 2014 and both wells are currently flowing up casing. The Bahar-3 produced an average of approximately 400 Bbl/d during its initial 22 days of production, while the Bahar-4 produced 350 Bbl/d on average during its initial 27 days of production. We are currently upgrading the pump on the Bahar-2ST well in the Hazro formation and assessing the well for Mardin formation potential.

Selmo. We continued our horizontal drilling campaign, which is focused on the southeastern portion of the Selmo field. In August 2014, we completed the Selmo-68H3 well, which had initial average gross production of 250 Bbl/d.  In late September 2014, we completed the Selmo-94H1 well, which had initial average gross production of 300 Bbl/d. We spudded three additional Selmo MSD wells in the third quarter and expect to complete them by the end of 2014.

We also continued our implementation of secondary recovery in the Selmo field. A third Selmo well was converted to an injection well for our waterflood of the field, and we expect to convert a fourth well to injection in the fourth quarter of 2014. We also expect to conduct a second phase of polymer injections in the fourth quarter of 2014.

Arpatepe. The Arpatepe-8, a Bedinan appraisal well, was spudded in August 2014 and was drilled to approximately 8,000 feet. We expect the well to be completed in the fourth quarter of 2014. We also plan to initiate a waterflood pilot test to assess the effectiveness of secondary recovery in the Arpatepe field.

Idil. We are preparing to spud a vertical exploration well on our Idil license.  Our joint venture partner, Onshore Petroleum Company AS, will be assigned a 50% interest in the Idil license once it funds 100% of our expected share of the well cost.

Turkey-Northwest

Thrace Basin.  We are drilling a five-well campaign of shallow, conventional vertical wells in the Osmanli area. The first three wells had an average gross cost of less than $1.0 million each and tested 1.5 Mmcf/d gross, 2.0 Mmcf/d gross and 4.0 Mmcf/d gross. We expect to put the first three wells on production and complete the remaining two wells in the fourth quarter of 2014.

In September 2014, we successfully re-drilled an abandoned well resulting in a discovery well in a new zone in the Göçerler field, which tested 4.0 Mmcf/d and is expected to be put on production in the fourth quarter of 2014. The well is our first completion in the Soğucak limestone reef reservoir. All of our previous Thrace Basin completions were in sandstone reservoirs.  The discovery has increased our interest in developing the limestone reef trend in the central Thrace Basin.

Bulgaria

We submitted a request to acidize the Deventci-R2 well in the second quarter of 2014, and expect the government to consider the request during the fourth quarter of 2014. We conducted a long-term pressure build-up test on the Deventci-R2 well in the second quarter of 2014 to evaluate its connectivity to the reservoir following the well’s initial test of approximately 2.0 Mmcf/d gross with condensates.

Strategy

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. We are currently focused on the following strategic objectives:

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Planned Operations

We expect net field capital expenditures for the fourth quarter of 2014 to range between $20 million and $30 million for the drilling of between seven to nine gross wells and completion of eight to ten gross wells, the recompletion of five to ten existing gross wells, and to process remaining seismic data, continue waterflood test projects and complete infrastructure improvements and other capital investments.

Of these expenditures, we expect to spend approximately 10% in the Thrace Basin, devoted to developing conventional and unconventional natural gas production and building infrastructure. Most of the remaining 90% of these anticipated expenditures is expected to be invested in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Arpatepe, Molla and Selmo and acquiring seismic data.  We expect cash on hand, cash flow from operations, borrowings from our senior credit facility 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 fourth quarters of 2014:

Turkey. We plan to drill between seven to nine gross wells, of which approximately five gross wells are expected to be drilled horizontally and approximately 40% of which will be fracture stimulated. We expect to complete eight to ten gross wells, recomplete five to ten existing gross wells, process remaining seismic data, continue waterflood test projects and complete infrastructure improvements and other capital investments.

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 nine months ended September 30, 2014 and September 30, 2013.

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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.

In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern ("ASU 2014-15"), an amendment to FASB Accounting Standards Codification ("ASC") Topic 205, Presentation of Financial Statements.  This update provides guidance on management's responsibility in evaluating whether there is substantial doubt about an entity's ability to continue as a going concern and to provide related footnote disclosures. This ASU 2014-15 is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter. Early adoption is permitted. The Company does not expect the adoption of ASU 2014-15 to have a material impact on its financial statement disclosures.

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.

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

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

 

Oil and Natural Gas Sales. Total oil and natural gas sales revenues increased $3.9 million to $35.5 million for the three months ended September 30, 2014, from $31.6 million realized in the same period in 2013. Of this increase, $6.9 million was due to an increase in sales volumes of 88 Mboe. This increase was partially offset by a lower average price per Boe, which resulted in lower revenues of $3.6 million. Our average price received decreased $7.63 per Boe to $76.76 per Boe for the three months ended September 30, 2014, from $84.39 per Boe for the same period in 2013.

Production. Production expenses for the three months ended September 30, 2014 decreased to $4.5 million or $8.55 per Boe, from $4.6 million or $10.72 per Boe for the same period in 2013. The decrease per Boe was primarily attributable to an increase in our working interest production volumes during the three months ended September 30, 2014 compared to the same period in 2013.

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Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended September 30, 2014 decreased approximately $1.7 million to $0.6 million, from $2.2 million for the same period in 2013. During the three months ended September 30, 2014, we recorded impairment charges of $0.5 million, consisting of cash spent during the third quarter of 2014. During the three months ended September 30, 2013, we had write-offs of two wells at an average of $0.4 million per well.  Additionally, during the three months ended September 30, 2013, we recorded $1.2 million of impairment charges on our unproved properties.

General and Administrative. General and administrative expense was $6.6 million for the three months ended September 30, 2014, as compared to $6.4 million for the same period in 2013. The increase was primarily due to an increase in travel, office, insurance and other expenses of $0.4 million and an increase in employee-related costs of $0.1 million, which was partially offset by a decrease in accounting and consulting expenses of $0.3 million.  Accounting and consulting expenses were lower during the three months ended September 30, 2014 primarily due to the timely filing of our Quarterly Report on Form 10-Q for the three months ended June 30, 2014.

Depletion. Depletion increased to $13.5 million or $25.51 per Boe for the three months ended September 30, 2014, compared to $10.9 million or $25.53 per Boe for the same period of 2013. The increase was primarily due to additions to proved properties and an increase in production during the three months ended September 30, 2014.

Interest and Other Expense. Interest and other expense increased to $1.4 million for the three months ended September 30, 2014, as compared to $0.9 million for the same period in 2013. The increase was primarily due to an increase in our average level of debt outstanding during the three months ended September 30, 2014, compared to the same period in 2013. At September 30, 2014, we had $91.6 million of total debt outstanding, compared to $50.0 million at September 30, 2013.

 

Foreign Exchange Loss. We recorded a foreign exchange loss of $6.5 million during the three months ended September 30, 2014, compared to a loss of $2.9 million for the same period of 2013. The change in foreign exchange was primarily unrealized (non-cash) in nature and resulted from re-measuring specific transactions and monetary accounts in a currency other than our 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 loss was due to a larger decrease in the value of the TRY compared to the U.S. Dollar for the three months ended September 30, 2014 compared to the three months ended September 30, 2013.

 

Deferred Income Tax Expense. Deferred income tax expense increased to $4.5 million for the three months ended September 30, 2014, compared to $1.4 million for the same period of 2013. The increase was primarily due to changes in temporary differences between our U.S. GAAP and statutory balances in Turkey.

Gain (Loss) on Commodity Derivative Contracts. During the three months ended September 30, 2014, we recorded a net gain on commodity derivative contracts of approximately $11.0 million, as compared to a net loss of $3.1 million for the same period in 2013. During the three months ended September 30, 2014, we recorded a $12.0 million gain to mark our commodity derivatives to their fair value and a $1.0 million loss on settled contracts. During the same period in 2013, we recorded a $2.2 million loss to mark our commodity derivatives to their fair value and a $0.9 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.

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Results of Operations—Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2013

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

 

Oil and Natural Gas Sales. Total oil and natural gas sales revenues increased $15.1 million to $109.0 million for the nine months ended September 30, 2014, from $93.8 million realized in the same period in 2013. Of this increase, $18.5 million was due to an increase in sales volumes of 220 Mboe. This increase was partially offset by a lower average price per Boe, which resulted in lower revenues of $3.4 million. Our average price received decreased $2.71 per Boe to $81.68 per Boe for the nine months ended September 30, 2014, from $84.39 per Boe for the same period in 2013.

Production. Production expenses for the nine months ended September 30, 2014 decreased to $13.3 million or $8.74 per Boe, from $13.4 million or $10.56 per Boe for the same period in 2013. The decrease of $1.82 per Boe was primarily attributable to an increase in our working interest production volumes during the nine months ended September 30, 2014.

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Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the nine months ended September 30, 2014 decreased approximately $9.5 million to $8.5 million, from $18.0 million for the same period in 2013. During the nine months ended September 30, 2014, we impaired three wells for $6.8 million.  During the nine months ended September 30, 2013, we wrote-off four wells for $4.3 million, $2.9 million, $1.9 million and $0.9 million and two wells at an average of $0.4 million per well.  Additionally, during the nine months ended September 30, 2013, we recorded $5.7 million of impairment charges which primarily related to our Malkara license.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $4.2 million for the nine months ended September 30, 2014, as compared to $6.4 million for the same period in 2013. The decrease was primarily due to less seismic acquisition activity during the nine months ended September 30, 2014.

General and Administrative. General and administrative expense was $20.7 million for the nine months ended September 30, 2014, compared to $20.8 million for the same period in 2013. The decrease was primarily due to a decrease in accounting and consulting expenses of $0.8 million, which was partially offset by an increase in employee-related expenses of $0.6 million.  Accounting and consulting expenses were higher during the nine months ended September 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 nine months ended September 30, 2014 primarily due to severance payments made to former employees.

Depletion. Depletion increased to $35.1 million or $23.02 per Boe for the nine months ended September 30, 2014, compared to $28.3 million or $22.22 per Boe for the nine months ended September 30, 2013. The increase was primarily due to additions to proved properties and an increase in production during the nine months ended September 30, 2014.

 

Interest and Other Expense. Interest and other expense increased to $4.4 million for the nine months ended September 30, 2014, compared to $2.8 million for the same period in 2013. The increase was primarily due to an increase in our average level of debt outstanding during the nine months ended September 30, 2014 compared to the same period in 2013. At September 30, 2014, we had $91.6 million of total debt outstanding, compared to $50.0 million at September 30, 2013. Also contributing to the increase was a $0.5 million write-off of loan financing costs related our prior senior secured credit facility, which was repaid in May 2014.

Foreign Exchange Loss. We recorded a foreign exchange loss of $5.4 million during the nine months ended September 30, 2014, compared to a loss of $6.0 million in the same period of 2013. The change in foreign exchange loss was primarily unrealized (non-cash) in nature and resulted from re-measuring specific transactions and monetary accounts in a currency other than our 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 decrease in foreign exchange loss was due to a smaller decrease in the value of the TRY compared to the U.S. Dollar during the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013.

Deferred Income Tax Expense. Deferred income tax expense increased to $6.9 million for the nine months ended September 30, 2014, compared to $2.0 million for the same period of 2013. The increase was primarily due to changes in temporary differences between our U.S. GAAP and statutory balances in Turkey.

Gain (Loss) on Commodity Derivative Contracts. During the nine months ended September 30, 2014, we recorded a net gain on commodity derivative contracts of approximately $2.4 million, compared to a net gain of $0.4 million for the same period in 2013. During the nine months ended September 30, 2014, we recorded a $6.0 million gain to mark our commodity derivatives to their fair value and a $3.6 million loss on settled contracts. During the same period in 2013, we recorded a $3.0 million gain to mark our commodity derivatives to their fair value and a $2.7 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.

 

Capital Expenditures

For the quarter ended September 30, 2014, we incurred $33.4 million in capital expenditures, including license acquisition and seismic expenditures from continuing operations, as compared to $34.0 million for the quarter ended September 30, 2013.

We expect net field capital expenditures for the fourth quarter of 2014 to range between $20 million and $30 million.  Of these expenditures, we expect to spend approximately 10% in the Thrace Basin, devoted to developing conventional and unconventional natural gas production and building infrastructure. Most of the remaining 90% of these anticipated expenditures is expected to be invested in southeastern Turkey, devoted to drilling developmental and exploratory oil wells at Arpatepe, Molla and Selmo and acquiring seismic data.  Our projected 2014 capital budget is subject to change, and if cash on hand, cash flow from operations,

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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 third quarter of 2014 were our cash and cash equivalents, cash flow from operations and net borrowings under our senior credit facility. At September 30, 2014, we had cash and cash equivalents of $9.4 million, $33.6 million in short-term debt, $58.1 million in long-term debt, and a working capital deficit of $27.7 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 nine months ended September 30, 2014 increased to $70.2 million, as compared to $69.8 million for the nine months ended September 30, 2013. This increase was primarily due to an increase in our revenues partially offset by a decrease in our accounts payable during the nine months ended September 30, 2014.

As of September 30, 2014, the outstanding principal amount of our debt was $91.6 million. In addition to cash, cash equivalents and cash flow from operations, at September 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, 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”).

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 borrowing base is $71.5 million as of October 1, 2014. The borrowing base amount equals, for any calculation date, the lowest of:

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 September 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.

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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:

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) any other non-cash charges (including dry hole expenses and seismic expenses, to the extent such expenses would be capitalized under the “full cost” accounting method), (vii) 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), and (viii) 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 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.

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Pursuant to the Senior Credit Facility, at least one of the Borrowers is required to maintain commodity derivative contracts with BNP Paribas that hedge between 30% and 75% of our anticipated oil production volumes in our oil fields in Turkey. TEMI has entered into three-way collar contracts with BNP Paribas, which hedge the price of oil through March 2019.

At October 1, 2014, we had borrowings of $64.8 million under the Senior Credit Facility and availability of $6.7 million and were in compliance with all covenants in the Senior Credit Facility.

TBNG Credit Facility. Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) has a 60.8 million TRY (approximately $26.7 million at September 30, 2014) fully drawn credit facility with a Turkish bank.  The facility bears interest at a rate of 6.6% per annum and is due in 12 monthly principal installments of $2.3 million each, starting October 31, 2014.  The facility is secured by a lien on the Gundem hotel, which is owned by Mr. Mitchell.

Contingencies Relating to Production Leases and Exploration Permits

Selmo

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

Morocco

During 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew down our $1.0 million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our Tselfat exploration permit during 2012 for this contingency.

Aglen

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

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 a $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 nine months ended September 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 September 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 provision for this contingent consideration will be recorded when it becomes probable and estimable.

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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 September 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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During the third 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 September 30, 2014:

Fair Value of Derivative Instruments as of September 30, 2014

 

 

 

 

 

 

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 September 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

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officer and chief financial officer concluded that, as of September 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.

Changes in Internal Control over Financial Reporting

Management continues to focus on our internal control remediation efforts, and during the three months ended September 30, 2014, we implemented a more robust comprehensive management review to ensure proper classification and presentation within our consolidated financial statements.  There were no additional changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

 

 

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PART II. OTHER INFORMATION

 

During the third 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.

 

During the third 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 and in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2014 and June 30, 2014, except as follows:

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

Türkiye Petrol Rafinerileri A.Ş. (“TUPRAS”), a privately owned oil refinery in Turkey, purchases all of our oil production from Turkey, representing 66.7% of our total revenues in 2013. If TUPRAS reduces its 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. TUPRAS may be subject to its own operating risks that could increase the risk that it could default on its obligations to us. Under Turkish law, TUPRAS is obligated to purchase all of our oil production in Turkey, and we are prohibited from selling any of our oil produced in Turkey to any other customer.   Pursuant to a purchase and sale agreement with TUPRAS, the price of oil delivered to TUPRAS is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. Changes to Turkish law could adversely affect our business and results of operations.

We engage in transactions with related parties and such transactions present possible conflicts of interest that could have an adverse effect on us.

 

We have entered into a significant number of transactions with related parties.  Related party transactions create the possibility of conflicts of interest with regard to our management. Such a conflict could cause an individual in our management to seek to advance his or her economic interests above those of the Company. Further, the appearance of conflicts of interest created by related party transactions could impair the confidence of our investors. Our board of directors has adopted a Related Party Transactions Policy that requires all related party transactions and any material amendments to such related party transactions to be reviewed by our audit committee, and, if necessary, recommended to our board of directors for its approval. Notwithstanding this, it is possible that a conflict of interest could have a material adverse effect on our business.

 

Virtually all of our operations are conducted in Turkey and Bulgaria, and we could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar worldwide anti-corruption laws.

 

The U.S. Foreign Corrupt Practices Act and similar worldwide anti-corruption laws generally prohibit companies and their intermediaries from making improper payments to non-U.S. officials for the purpose of obtaining or retaining business. We  operate in parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-corruption laws may conflict with local customs and practices. We cannot assure that our internal control policies and procedures will protect us from reckless or criminal acts committed by our employees or agents. Future acquisitions outside the U.S., including the pending acquisition of Stream, could increase the risk of such violations in the future. Violations of these laws, or allegations of such violations, could disrupt our business and result in a material adverse effect on our results of operations or financial condition.

 

Our future acquisitions may yield revenues or production that varies significantly from our projections, and we may encounter unexpected liabilities.

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In acquiring producing properties, including the Stream properties, we assess the recoverable reserves, future natural gas and oil prices, operating costs, potential liabilities and other factors relating to the properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review of a subject property in connection with its acquisition assessment will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of those problems. Any acquisition of property interests may not be economically successful, and unsuccessful acquisitions may have a material adverse effect on our financial condition and future results of operations. We cannot assure you that:

Stream has a significant amount of current and long term liabilities.  

As of August 31, 2014, Stream had approximately $81.1 million of total liabilities, of which $52.1 million were current liabilities.  Stream has not had sufficient funds to pay its liabilities when they became due and has requested and received deferrals of payments that were due from May 2014 through September 2014.  In addition, Stream has requested but not yet obtained deferrals for the September 2014 payment that was due under its debt agreements.  Due to Stream’s non-payment of these past due amounts, the respective lenders have the right to accelerate the outstanding indebtedness under these loans at any time and the lender could foreclose upon Stream’s collateral securing the debt.

If the pending acquisition of Stream is completed, we may be required to dedicate a substantial portion of our liquidity and cash flows from operations to meet Stream’s outstanding obligations. If the Stream acquisition is consummated, our inability to repay, service or refinance Stream’s financial obligations could adversely affect our financial condition and results of operations.

We may not complete the pending acquisition of Stream.

The consummation of the Stream acquisition is subject to certain closing conditions, including conditions that must be met by Stream and which are beyond our control.  In addition, under certain circumstances, we or Stream are able to terminate the Arrangement Agreement.  There can be no assurance that the pending acquisition of Stream will be completed or, if completed, that it will be completed on the terms described in the Arrangement Agreement.

The Stream acquisition involves risks associated with acquisitions and integrating acquired businesses, including the potential exposure to significant liabilities, and the intended benefits of the Stream acquisition may not be realized.

The Stream acquisition involves risks associated with acquisitions and integrating acquired businesses into existing operations, including:

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Even if we successfully integrate Stream into our operations, it may not be possible to realize the full benefits we anticipate or we may not realize these benefits within the expected timeframe. If we fail to realize the benefits we anticipate from the Stream acquisition, our business, results of operations and financial condition may be adversely affected.

If we acquire Stream, our failure to successfully integrate Stream’s business could negatively impact our future business and financial results

If we acquire Stream, our failure to successfully integrate Stream’s business could negatively impact our future business and financial results.  Our acquisition of Stream will represent an expansion of our operations into a new geographic area in an international market, with operating conditions and a regulatory environment that may not be as familiar to us as our existing core operating areas. Our success in operating in Albania will depend, in part, on our ability to realize benefits from integrating Stream’s business with our existing businesses. The integration process may be complex, costly and time-consuming. To realize such benefits, we must successfully combine the businesses in an efficient and effective manner. If we are not able to achieve these objectives within the anticipated time frame, or at all, any benefits related to our acquisition of Stream may not be realized fully, or at all, or may take longer to realize than expected.

Successful integration will require, among other things, combining the companies’:

We may not accomplish this integration successfully and may not realize the benefits contemplated by combining the operations of the Company and Stream.

 

None.

 

None.

 

Not applicable.

 

None.

 

 

 

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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.

 

 

 

 

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INDEX TO EXHIBITS

 

 

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