UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended: June 30, 2015

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 August 3, 2015, the registrant had 41,006,823 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 (Loss) Income

(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, Albania and Bulgaria. As of August 3, 2015, 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, 2014.

Decline in Oil Price

As a result of the decline in prices for Brent crude since December 2014, we have reduced our planned capital expenditures and deferred a significant amount of our planned exploration and development until prices for Brent crude improve. In order to mitigate the impact of reduced prices on our 2015 cash flows and liquidity, we have implemented cost reduction measures and will continue to implement cost-cutting initiatives to reduce our operating costs and general and administrative expenses.

 

During the first half of 2015, we have undertaken significant cost saving efforts including staff reductions, office relocations, negotiations of exploration and development expenses and operating cost reductions with several key vendors and optimization of well designs. We believe this strategy will allow us to preserve our liquidity in order to execute the remainder of our 2015 development program and continue to meet our contractual obligations.  Additionally, at current Brent crude prices, our current hedge positions provide additional liquidity on a monthly recurring basis.

 

Notwithstanding these measures, there remain risks and uncertainties that could negatively impact our results of operations and financial condition. For example, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by the recent decline or any further declines in oil prices. The next borrowing base redetermination is October 1, 2015.

 

2. Recent accounting pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“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.  In July 2015, the FASB decided to delay the effective date of the new revenue standard by one year. The new effective date is for annual reporting periods, and interim periods within that reporting period, beginning after December 15, 2017.  Reporting entities may choose to adopt the standard as of

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the original effective date.  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. We do not expect the adoption of ASU 2014-15 to have a material impact on our consolidated financial statements or results of operations.  If events occur in future periods that affect our ability to continue as a going concern, we will provide the disclosures required by ASU 2014-15.

In April 2015, the FASB issued ASU 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. We currently recognize debt issuance costs as assets on our consolidated balance sheet. The recognition and measurement guidance for debt issuance costs are not affected by ASU 2015-03. ASU 2015-03 is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015 and early adoption is permitted.  Currently, we do not expect the adoption of ASU 2015-03 to have a material impact on our consolidated financial statements or results of operations.

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

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3. Acquisitions

Stream

On November 18, 2014, we acquired Stream Oil & Gas Ltd., a corporation existing under the laws of British Columbia (“Stream”), in exchange for (i) 3.2 million of our common shares issued at closing, and (ii) an additional 0.6 million of our common shares issuable if certain conditions are met (at a deemed price of $7.41 per common share).  We engaged independent valuation experts to assist in the determination of the fair value of the assets and liabilities acquired in the acquisition.  We are still assessing the assets acquired and liabilities assumed.  Thus, the final determination of the value of assets acquired and liabilities assumed may result in adjustments to the values presented below. The following tables summarize the consideration paid in the acquisition and the preliminary amounts of assets acquired and liabilities assumed that have been recognized at the acquisition date:

 

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The following table presents the unaudited pro forma results of operations as though the acquisition of Stream had occurred as of January 1, 2014 (see our Annual Report on Form 10-K for the year ended December 31, 2014 for a discussion of this acquisition):

 

 

4. Property and equipment

Oil and natural gas properties

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

 

At June 30, 2015 and December 31, 2014, we excluded $2.2 million and $0.9 million, respectively, from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At June 30, 2015, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $121.8 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $126.6 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, 2014, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $129.0 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $160.8 million relating to well costs and additional development costs, which are being depleted by the unit-of-production method using proved developed reserves.

Exploratory well costs

During the three and six months ended June 30, 2015, we recorded $4.1 million and $4.4 million, respectively, of impairment and exploratory well costs. Of the $4.4 million of impairment and exploratory well costs incurred during the six months ended June 30, 2015, $3.7 million related to impairment of the Deventci-R2 well in the second quarter of 2015, and $0.8 million was cash spent during the period.

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Capitalized cost greater than one year

As of June 30, 2015, we had $1.4 million and $1.9 million of exploratory well costs capitalized for the Hayrabolu-10 and Bahar-2ST wells in Turkey, which we spud in February 2013 and March 2014, respectively. The Hayrabolu-10 and Bahar-2ST wells continue to be evaluated for completion pending more analysis.

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 have reclassified certain prior year costs of equipment and other property to conform to current period presentation.

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

At June 30, 2015, we excluded $23.7 million of inventory from depreciation as the inventory had not been placed into service. At December 31, 2014, we excluded $24.3 million of inventory and $3.0 million of software from depreciation as the inventory and software had not been placed into service.

 

5. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations (“ARO”) for the six months ended June 30, 2015 and for the year ended December 31, 2014:

 

 

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

 

6. Commodity derivative instruments

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.

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

During the three months ended June 30, 2015 and 2014, we recorded a net loss on commodity derivative contracts of $3.3 million and $9.5 million, respectively. During the six months ended June 30, 2015 and 2014, we recorded a net gain on commodity derivative contracts of $0.5 million and a net loss of $8.6 million, respectively.

At June 30, 2015 and December 31, 2014, we had outstanding contracts with respect to our future crude oil production as set forth in the tables below:

Fair Value of Derivative Instruments as of June 30, 2015

 

 

Fair Value of Derivative Instruments as of December 31, 2014

 

 

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Balance sheet presentation

The following table summarizes both: (i) the gross fair value of our commodity derivative instruments by the appropriate balance sheet classification even when the commodity derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at June 30, 2015 and December 31, 2014, and (ii) the net recorded fair value as reflected on our consolidated balance sheets at June 30, 2015 and December 31, 2014.

 

 

 

 

 

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7. Loan payable

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

 

 

Senior Credit Facility

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

The borrowing base amount is re-determined semi-annually on April 1^st and October 1^st of each year, beginning April 1, 2015.  As of June 30, 2015, we had outstanding borrowings under the Senior Credit Facility of $67.0 million.  Pursuant to the terms of the Senior Credit Facility, the borrowing base resets on the first day of each fiscal quarter.  As of July 1, 2015, the borrowing base was reset to $70.8 million, and we had $3.8 million of availability under the Senior Credit Facility.  Loan under the Senior Credit Facility accrue interest at a rate of three-month LIBOR plus 5.00% per annum (5.28% at June 30, 2015).  The borrowing base amount equals, for any calculation date, the lowest of:

Convertible Notes

As of June 30, 2015, we had $55.0 million aggregate principal amount of outstanding 13.0% convertible notes due in 2017 (the “Convertible Notes”). The Convertible Notes bear interest at a rate of 13.0% per annum and mature on July 1, 2017. The Convertible Notes are convertible, at the election of a holder, any time after July 1, 2015, into our common shares at a conversion price of $6.80 per share.

TBNG credit facility

Our subsidiary, Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”), has a fully drawn credit facility with a Turkish bank.  During the second quarter of 2015, the facility was amended and now bears interest at a rate of 5.9% per annum and is due in monthly principal installments of $1.3 million each, ending April 4, 2016.  The facility may be prepaid without penalty. The facility is secured by a lien on a hotel owned by Gundem Turizm Yatirim ve Isletmeleri Anonim Sirketi (“Gundem”), which is 97.5% beneficially owned by Mr. Mitchell and his children. At June 30, 2015, TBNG owed $13.0 million under the credit facility and had no availability.

 

Term Loan Facility

Stream Oil & Gas Ltd., a Cayman Islands corporation (“Stream Sub”), a subsidiary of Stream, has a term loan facility (the “Term Loan Facility”) with Raiffeisen Bank Sh.A (“Raiffeisen”).  The Term Loan Facility matures on March 31, 2017 and bears interest at the rate of LIBOR plus 5.5%, with a minimum interest rate of 7.0%. Stream Sub is required to repay $1.0 million each quarter on the last business day of each of March, June, September and December. The loan is guaranteed by Stream. Stream Sub may prepay the loan at its option in whole or in part, subject to a 3.0% penalty plus breakage costs.  The Term Loan Facility is secured by substantially all of the assets of Stream Sub.  As of June 30, 2015, we had $7.1 million outstanding under the Term Loan Facility bearing interest at a rate of 7.0% per annum and no availability.

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At June 30, 2015, we were not in compliance with certain conditions subsequent set forth in Section 4 of the Term Loan Facility, including the delivery to Raiffeisen of a copy of an agreement between Albpetrol Sh. A and ourselves concerning postponement of certain capital expenditures. Raiffeisen has granted us a waiver on this requirement until September 30, 2015.

Prepayment Agreement

In April 2013, Stream and Stream Sub entered into the prepayment agreement (the “Prepayment Agreement”) with Trafigura PTE Ltd (“Trafigura”). In October 2013, Stream received a $7.0 million prepayment under the Prepayment Agreement. No further prepayment requests can be made under the Prepayment Agreement. The prepayment is to be repaid by Stream’s delivery of oil to Trafigura in accordance with an oil sales contract between Stream and Trafigura and bears interest at a rate equal to LIBOR plus 6% (6.17% at June 30, 2015). Stream must repay the prepayment at the times and in the quantities as set out in the oil sales contract, and all amounts must be repaid on or before August 31, 2015.  At June 30, 2015, Stream had $0.9 million outstanding under the Prepayment Agreement and no availability.

 

8. Contingencies relating to production leases and exploration permits

Selmo

We are involved in litigation with persons who claim ownership of a portion of the surface at the Selmo oil field in Turkey. These cases are being vigorously defended by TransAtlantic Exploration Mediterranean International Pty Ltd. (“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 six months ended June 30, 2014.

In addition, the Amendment provides that we will issue $7.5 million in common shares if the Deventci-R2 well is a commercial success (as defined in the Purchase Agreement) on or prior to May 1, 2016. We will record any provision for this contingent consideration when it is estimable and probable. As of June 30, 2015, 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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9. Shareholders’ equity

Restricted stock units

We recorded share-based compensation expense of $0.2 million and $0.3 million for awards of restricted stock units (“RSUs”) for the three months ended June 30, 2015 and 2014, respectively.  We recorded share-based compensation expense of $0.5 million and $0.7 million for awards of RSUs for the six months ended June 30, 2015 and 2014, respectively.

As of June 30, 2015, we had approximately $1.3 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.9 years.

Earnings per share

We account for earnings per share in accordance with ASC Subtopic 260-10, Earnings Per Share (“ASC 260-10”). ASC 260-10 requires companies to present two calculations of earnings per share: basic and diluted. Basic earnings per common share for the three and six months ended June 30, 2015 and 2014 equals net income (loss) divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding unvested RSUs. Diluted earnings per common share for the three and six months ended June 30, 2015 and 2014 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes RSUs.  For the three and six months ended June 30, 2015 and 2014, there were no dilutive securities included in the calculation of diluted earnings per share.  The computation of diluted earnings per common share excluded 8.9 million and 8.7 million anti-dilutive common share equivalents from the three and six months ended June 30, 2015, respectively.   

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

 

 

Warrants

On April 24, 2015, we issued 233,333 common share purchase warrants to Mr. Mitchell and certain other related parties as shareholders of Gundem, as consideration for the pledge of the Gundem resort in exchange for an extension of the maturity of a credit agreement between TBNG and a Turkish bank (See Note 7).  The common share purchase warrants have an exercise price of $5.65 per share, expire 18 months from the date of the release of the pledge on the Gundem resort and were immediately exercisable.  The fair value of the warrants was determined using the Black-Scholes model.  During the three and six months ended June 30, 2015, we incurred $0.3 million of compensation expense for these warrants.

 

 

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10. Segment information

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

 

 

 

11. Financial instruments

Cash and cash equivalents, restricted cash, accounts receivable, accounts payable, accrued liabilities and our loans payable were each estimated to have a fair value approximating the carrying amount at June 30, 2015 and December 31, 2014, 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, Term Loan Facility and Prepayment Agreement.

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, Albanian Lek, and Turkish New Lira (“TRY”). We are also subject to foreign currency exposures resulting from translating the functional currency of our foreign subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At June 30, 2015, we had 22.3 million TRY (approximately $8.3 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 June 30, 2015 and December 31, 2014, we were a party to commodity derivative contracts (see Note 6).

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 June 30, 2015:

 

The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2014:

 

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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12. Related party transactions

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

 

Equity transactions

On April 24, 2015, we issued 233,333 common share purchase warrants to Mr. Mitchell and certain other related parties as shareholders of Gundem, as consideration for the pledge of the Gundem resort in exchange for an extension of the maturity of a credit agreement between TBNG and a Turkish bank (See Note 7).  The common share purchase warrants have an exercise price of $5.65 per share, expire 18 months from the date of the release of the pledge on the Gundem resort and were immediately exercisable.  The fair value of the warrants was determined using the Black-Scholes model.  During the three and six months ended June 30, 2015, we incurred $0.3 million of compensation expense for these warrants.

 

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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 an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of June 30, 2015, we held interests in approximately 1.8 million net acres of developed and undeveloped oil and natural gas properties in Turkey, Albania and Bulgaria. As of August 3, 2015, 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.

Decline in Oil Prices

 

As a result of the decline in prices for Brent crude since December 2014, we have reduced our planned capital expenditures and deferred a significant amount of our planned exploration and development until prices for Brent crude improve. In order to mitigate the impact of reduced prices on our 2015 cash flows and liquidity, we have implemented cost reduction measures and will continue to implement cost-cutting initiatives to reduce our operating costs and general and administrative expenses.

 

During the first half of 2015, we have undertaken significant cost saving efforts including staff reductions, office relocations, negotiations of exploration and development expenses and operating cost reductions with several key vendors and optimization of well designs. We believe this strategy will allow us to preserve our liquidity in order to execute the remainder of our 2015 development program and continue to meet our contractual obligations.  Additionally, at current Brent crude prices, our current hedge positions provide additional liquidity on a monthly recurring basis.

 

Notwithstanding these measures, there remain risks and uncertainties that could negatively impact our results of operations and financial condition. For example, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by the recent decline or any further declines in oil prices. The next borrowing base redetermination is October 1, 2015.

 

Financial and Operational Performance Highlights

Highlights of our financial and operational performance for the second quarter of 2015 include:

Second Quarter 2015 Operational Update

During the second quarter of 2015, we further developed our oil fields in southeastern Turkey and began a workover program in the Albanian oil fields we acquired in late 2014. In Southeast Turkey, we commenced drilling the Bahar-9 well, which reached total depth early in the third quarter of 2015, and drilled the South Goksu-1 well. We briefly resumed drilling on the Delvina-34H1 well in Albania during the second quarter of 2015.  During July 2015, we suspended drilling the Delvina-34H1 well and released the rig.  The following summarizes our operations by location during the second quarter of 2015:

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Turkey-Southeast

Selmo. We continued our secondary recovery program and plan to convert several additional wells to injection during the remainder of 2015.  To date we have added approximately 200 barrels of incremental oil production per day (“bbl/d”) above the established decline curve.

Molla. We drilled the South Goksu-1 well to a total depth of 5,900 feet and top set the Mardin formation.  We will finish testing the well in the second half of 2015.  We also reached total vertical depth of approximately 10,900 feet on the Bahar-9 well and will commence the completion in the third quarter of 2015. Log analysis indicates prospective pay as projected.

We attempted to complete the Pinar-1 well; however, due to irretrievable stuck casing issues, the well will be sidetracked at about 7,900 feet and the bottom 2,000 feet of the well will be re-drilled.

Turkey-Northwest

Thrace Basin. We did not engage in any new drilling activities during the second quarter of 2015, but plan to resume drilling and workover activity in the third quarter of 2015.

Albania

We commenced a workover program late in the second quarter of 2015 with the installation of 13 new pumps in our three oil fields.  We have seen positive results to date from the installation of these pumps.

 

We resumed drilling the Delvina-34H1 well in the second quarter of 2015. During July 2015, we suspended drilling the well and released the rig.

Bulgaria

We continue to evaluate our position in Bulgaria with updated geologic models.

Strategy

We continue to actively explore and develop our existing oil and natural gas properties in Turkey and Albania and evaluate opportunities for further activities in Bulgaria. Our success will depend in part on discovering additional hydrocarbons in commercial quantities and then bringing these discoveries into production. For the remainder of 2015, we are focused on accomplishing the following objectives:

Operate Within Existing Cash Flows and Maintain Core Acreage. With the dramatic decline in oil prices, we are cutting our overhead and capital expenditures in an effort to operate within existing cash flow. In the first half of 2015, we drilled the South Goksu-1 obligation well and the Bahar-9 well. Notwithstanding the decline in oil prices, we plan to drill several more wells on the Bahar structure and 1.5 net remaining obligation wells during the remainder of 2015.

Increase Reserves and Production. Once oil prices stabilize and begin to recover, we plan to resume more robust investing in exploration and development to increase our oil and natural gas reserves and production in Turkey on our Arpatepe, Molla, Selmo and Thrace Basin exploration licenses and production leases, including the application of 3D seismic, horizontal drilling, fracture stimulation and enhanced oil recovery techniques. We plan to revitalize our oilfields in Albania through well recompletions and reactivations, enlarging and lowering pumps and expanding waterfloods. We may also deepen and core several oil wells to better measure oil saturations and understand the potential of the oilfields.

Utilize New 3D Seismic Data to Improve Well Targeting. For the year ended December 31, 2014, we spent $3.7 million finalizing our 3D seismic survey over areas of Turkey where 3D seismic data did not previously exist. We received the processed data in the third quarter of 2014 and drilled several wells in the fourth quarter of 2014 and first half of 2015 based on the 3D seismic data, all resulting in successful wells, which are either producing or expected to be productive.

Expand the Use of Horizontal Drilling. During 2014, we extensively used horizontal drilling techniques on our wells in the Selmo field to more effectively extract hydrocarbons and increase our returns on invested capital. We expect to continue using horizontal drilling techniques in the Selmo and Bahar fields.

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Further Optimize Fracture Stimulation Program. In 2013 and 2014, we expanded our use of hydraulic fracturing technology to complete otherwise low permeability formations in Turkey. The evolution of fracturing fluids and stimulation designs has yielded positive results in southeastern Turkey. In the second half of 2015, we plan to continue optimizing our hydraulic fracturing techniques through the use of micro-seismic technology to improve well performance and economics.

Pursue Other Growth or Financing Opportunities. In addition to growing our reserves and production through exploration and development of our substantial acreage in Turkey and Albania, we continually evaluate acquisition, joint venture and farm-in/out opportunities.  We continue to pursue securing joint venture partners on our properties in the Thrace Basin and Southwestern Turkey.  The recent decline in oil prices and deterioration in general market conditions has made completing transactions more difficult, particularly on our planned timeline.   We are focused on both strengthening our positions in Turkey and Albania as well as identifying opportunities in new countries, as we did in 2014 with our acquisition of Stream Oil & Gas, Ltd., a corporation existing under the laws of British Columbia (“Stream”).

Planned Operations

We currently plan to execute the following drilling and exploration activities during the remainder of 2015:

Turkey. We plan to drill several more wells on the Bahar structure and 1.5 net remaining obligation wells during the remainder of 2015. Depending upon oil pricing, we plan to continue drilling in Southeast Turkey. We plan to sidetrack the Pinar-1 well during the second half of 2015.

Albania. We plan to continue workover programs and facilities upgrades.

Discontinued Operations in Morocco

In June 2011, we decided to discontinue our Moroccan operations. We have substantially completed the process of winding down our operations in Morocco. We have presented the Moroccan segment operating results as discontinued operations for the three and six months ended June 30, 2015 and June 30, 2014.

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, 2014 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, 2014.

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Results of Operations—Three Months Ended June 30, 2015 Compared to Three Months Ended June 30, 2014

Our results of operations for the three months ended June 30, 2015 and 2014 were as follows:

 

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $12.5 million to $28.0 million for the three months ended June 30, 2015, from $40.4 million realized in the same period in 2014. Of the decrease, $19.5 million was due to a decrease in the average realized price per Boe.  Our average price received decreased $36.50 per Boe to $52.38 per Boe for the three months ended June 30, 2015, from $88.88 per Boe for the same period in 2014. This decrease was partially offset by an increase in sales volumes of 79 Mboe, which resulted in higher revenues of $7.0 million. Sales volumes increased primarily on our southeast Turkey oil wells due to our successful horizontal drilling program in 2014 and increased as a result of the acquisition of our Albanian fields.  

 Production. Production expenses for the three months ended June 30, 2015 increased to $6.8 million or $11.42 per Boe from $4.7 million or $8.98 per Boe for the same period in 2014. Our production expenses increased $3.4 million due to the addition of our operations in Albania.  This increase was partially offset by a decrease of $1.3 million in Turkey.  The decrease in Turkey was primarily due to fewer workovers, reduced headcount and successful cost cutting measures in our field operations during the three months ended June 30, 2015 as compared to the same period in 2014.  

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended June 30, 2015 increased $0.3 million to $4.1 million, from $3.8 million for the same period in 2014. During the three months ended

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June 30, 2015, we wrote off one well for $3.7 million, as compared to the three months ended June 30, 2014, when we impaired one well for $3.5 million.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $0.1 million for the three months ended June 30, 2015, compared to $0.9 million for the same period in 2014. The decrease was primarily due to seismic acquisition activities conducted on our West Molla license during the three months ended June 30, 2014.

General and Administrative. General and administrative expense was $7.8 million for the three months ended June 30, 2015, compared to $7.5 million for the same period in 2014. Our general and administrative expenses increased $0.8 million due to the addition of our operations in Albania and $0.6 million due to severance and office relocation costs in Turkey.  This increase was partially offset by a decrease in office expenses of $0.5 million, travel costs of $0.1 million and our cost reduction efforts.

Depletion. Depletion decreased to $8.9 million or $15.04 per Boe for the three months ended June 30, 2015, compared to $12.0 million or $23.14 per Boe for the same period of 2014. The decrease was primarily due to fewer additions to proved properties during the three months ended June 30, 2015 as compared to the same period in 2014 and an increase in proved reserves at June 30, 2015 as compared to June 30, 2014.  This was partially offset by an increase of $0.6 million due to the addition of our operations in Albania.

Interest and Other Expense. Interest and other expense increased to $3.7 million for the three months ended June 30, 2015, compared to $1.8 million for the same period in 2014. The increase was primarily due to an increase in our average level of debt outstanding during the three months ended June 30, 2015 as compared to the same period in 2014.  At June 30, 2015, we had $143.0 million of total debt outstanding, as compared to $88.1 million at June 30, 2014.

 

Interest and Other Income. Interest and other income increased to $1.2 million for the three months ended June 30, 2015, as compared to $0.3 million for the same period in 2014. The increase was primarily due to negotiated reductions of our outstanding payables with several vendors.

Foreign Exchange Gain. We recorded a foreign exchange gain of $0.1 million during the three months ended June 30, 2015, as compared to a gain of $2.5 million in the same period in 2014. The change in foreign exchange is primarily unrealized (non-cash) in nature and results from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the New Turkish Lira (“TRY”) amount if it has not been settled previously. The decrease in foreign exchange gain for the three months ended June 30, 2015 was due to a 2.9% decrease in the value of the TRY compared to the U.S. Dollar, versus a 3.0% increase in the value of the TRY for the three months ended June 30, 2014.  The TRY devaluation was offset by an increase in the value of the U.S. Dollar compared to the Albanian LEK (“LEK”) during the three months ended June 30, 2015.  

Loss on Commodity Derivative Contracts. During the three months ended June 30, 2015, we recorded a net loss on commodity derivative contracts of $3.3 million, as compared to a net loss of $9.5 million for the same period in 2014. During the three months ended June 30, 2015, we recorded a $6.1 million loss to mark our commodity derivative contracts to their fair value and a $2.9 million gain on settled contracts. During the same period in 2014, we recorded a $7.7 million loss to mark our derivative contracts to their fair value and a $1.8 million loss on settled contracts. We are required under our Senior Credit Facility (“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 our oil fields in Turkey.

Other Comprehensive (Loss) Income. We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. Dollar reporting currency.  Foreign currency translation adjustment for the three months ended June 30, 2015 increased to a loss of $4.9 million from a gain of $5.1 million for the same period in 2014.  The increase in foreign translation loss in the three months ended June 30, 2015 was due to a 2.9% decrease in the value of the TRY as compared to the U.S. Dollar, versus a 3.0% increase in the value of the TRY for the three months ended June 30, 2014.

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Results of Operations—Six Months Ended June 30, 2015 Compared to Six Months Ended June 30, 2014

Our results of operations for the six months ended June 30, 2015 and 2014 were as follows:

 

 

Oil and Natural Gas Sales. Total oil and natural gas sales revenues decreased $18.8 million to $54.6 million for the six months ended June 30, 2015, from $73.4 million realized in the same period in 2014. Of this decrease, $35.2 million was due to a decrease in the average realized price per Boe.  Our average price received decreased $33.09 per Boe to $51.21 per Boe for the six months ended June 30, 2015, from $84.30 per Boe for the same period in 2014.  This was partially offset by an increase in sales volumes of 195 Mboe, which resulted in higher revenues of $16.4 million.  Sales volumes increased primarily on our southeast Turkey oil wells due to our successful horizontal drilling campaign in 2014 and increased as a result of the acquisition of our Albanian fields.           

Production. Production expenses for the six months ended June 30, 2015 increased to $12.7 million or $10.40 per Boe, from $8.8 million or $8.85 per Boe for the same period in 2014. Our production expenses increased $5.7 million due to the addition of our operations in Albania.  This increase was partially offset by a decrease of $1.8 million in Turkey.  The decrease in Turkey was primarily due to fewer workovers, reduced headcount and successful cost cutting measures in our field operations during the six months ended June 30, 2015 as compared to the same period in 2014.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the six months ended June 30, 2015 decreased approximately $3.5 million to $4.4 million, from $7.9 million for the same period in 2014. During the six months ended June 30, 2015, we wrote off one well for $3.7 million. During the six months ended June 30, 2014, we impaired two wells for $6.3 million.

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Seismic and Other Exploration. Seismic and other exploration costs decreased to $0.2 million for the six months ended June 30, 2015, as compared to $4.2 million for the same period in 2014. The decrease was primarily due to seismic acquisition activity conducted on our West Molla and Osmanli licenses during the six months ended June 30, 2014.

General and Administrative. General and administrative expense was $16.5 million for the six months ended June 30, 2015, as compared to $14.0 million for the same period in 2014.   Our general and administrative expenses increased $1.9 million due to the addition of our operations in Albania and $1.4 million due to severance and office relocation costs in Turkey.  This increase was partially offset by a decrease in office expenses of $0.6 million, travel costs of $0.1 million and our cost reduction efforts.

Depletion. Depletion decreased to $19.8 million or $16.26 per Boe for the six months ended June 30, 2015, compared to $21.6 million or $21.71 per Boe for the six months ended June 30, 2014. The decrease was primarily due to fewer additions to proved properties during the six months ended June 30, 2015 as compared to the same period in 2014, and an increase in proved reserves at June 30, 2015 compared to June 30, 2014.  This was partially offset by an increase of $1.2 million due to the addition of our operations in Albania.

Interest and Other Expense. Interest and other expense increased to $7.0 million for the six months ended June 30, 2015, as compared to $3.0 million for the same period in 2014. The increase was primarily due to an increase in our average level of debt outstanding during the six months ended June 30, 2015 as compared to the same period in 2014. At June 30, 2015, we had $143.0 million of total debt outstanding, compared to $88.1 million at June 30, 2014.

Interest and Other Income. Interest and other income increased to $1.8 million for the six months ended June 30, 2015, as compared to $0.6 million for the same period in 2014. The increase was primarily due to negotiated reductions of our outstanding payables with several vendors.

Foreign Exchange (Loss) Gain. We recorded a foreign exchange loss of $5.0 million during the six months ended June 30, 2015, as compared to a gain of $1.2 million in the same period of 2014. The change in foreign exchange was primarily unrealized (non-cash) in nature and resulted from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the TRY amount if it has not been settled previously. The increase in foreign exchange loss during the six months ended June 30, 2015 was due to a 15.8% decrease in the value of the TRY as compared to the U.S. Dollar, versus a 0.5% increase in the value of the TRY compared to the U.S. Dollar for the same period in 2014.

Gain (Loss) on Commodity Derivative Contracts. During the six months ended June 30, 2015, we recorded a net gain on commodity derivative contracts of $0.5 million, compared to a net loss of $8.6 million for the same period in 2014. During the six months ended June 30, 2015, we recorded a $6.7 million loss to mark our commodity derivatives to their fair value and a $7.2 million gain on settled contracts. During the same period in 2014, we recorded a $6.0 million loss to mark our commodity derivatives to their fair value and a $2.5 million loss on settled contracts. We are required under our Senior Credit Facility to hedge at least 30% of our anticipated oil production volumes in our oil fields in Turkey.

Other Comprehensive (Loss) Income. We record foreign currency translation adjustments from the process of translating the functional currency of the financial statements of our foreign subsidiaries into the U.S. Dollar reporting currency.  Foreign currency translation adjustment for the six months ended June 30, 2015 increased to a loss of $28.5 million from a gain of $1.8 million for the same period in 2014.  The increase in foreign translation loss in the six months ended June 30, 2015 was due to a 15.8% decrease in the value of the TRY as compared to the U.S. Dollar, versus a 0.5% increase in the value of the TRY as compared to the U.S. Dollar for the same period in 2014.

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Capital Expenditures

For the quarter ended June 30, 2015, we incurred $10.9 million in capital expenditures, including seismic and corporate expenditures, as compared to $28.7 million for the quarter ended June 30, 2014.  The decrease was due to our planned reduction in our capital expenditures during the quarter ended June 30, 2015.

We expect our net field capital expenditures for the remainder of 2015 to range between $15.0 million and $25.0 million. We expect cash on hand and cash flow from operations will be sufficient to fund our remaining 2015 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2015 capital expenditure budget is subject to change.

Liquidity and Capital Resources

Our primary sources of liquidity for the second quarter of 2015 were our cash and cash equivalents, cash flow from operations and borrowings under our Senior Credit Facility. At June 30, 2015, we had cash and cash equivalents of $19.3 million, $111.4 million in long-term debt, $31.6 million in short-term debt and a working capital deficit of $32.3 million, compared to cash and cash equivalents of $35.1 million, $106.0 million in long-term debt, $52.6 million in short-term debt and working capital deficit of $42.1 million at December 31, 2014.  Cash provided by operating activities from continuing operations for the six months ended June 30, 2015 was $21.8 million, compared to cash provided by operating activities from continuing operations of $41.5 million for the six months ended June 30, 2014. The decrease is primarily due to a decrease in oil revenues.

Cash used in investing activities from continuing operations for the six months ended June 30, 2015 decreased to $20.4 million, compared to cash used in investing activities from continuing operations of $65.6 million for the six months ended June 30, 2014, due primarily to a decrease in drilling operations due to the low commodity price environment.  Additionally, cash used in financing activities from continuing operations was $15.9 million for the six months ended June 30, 2015, as compared to cash provided by financing activities from continuing operations of $16.0 million for the six months ended June 30, 2014 as a result of $18.5 million of lower borrowings and $15.3 million of higher debt repayments.

 

As a result of the decline in prices for Brent crude since December 2014, we have reduced our planned capital expenditures and deferred a significant amount of our planned exploration and development until prices for Brent crude improve. In order to mitigate the impact of reduced prices on our 2015 cash flows and liquidity, we have implemented cost reduction measures and will continue to implement cost-cutting initiatives to reduce our operating costs and general and administrative expenses.

 

During the first half of 2015, we have undertaken significant cost saving efforts including staff reductions, office relocations, negotiations of exploration and development expenses and operating cost reductions with several key vendors and optimization of well designs. We believe this strategy will allow us to preserve our liquidity in order to execute the remainder of our 2015 development program and continue to meet our contractual obligations.  Additionally, at current Brent crude prices, our current hedge positions provide additional liquidity on a monthly recurring basis.

 

Notwithstanding these measures, there remain risks and uncertainties that could negatively impact our results of operations and financial condition. For example, reductions in our borrowing capacity as a result of a redetermination to our borrowing base could have an impact on our capital resources and liquidity. The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by the recent decline or any further declines in oil prices. The next borrowing base redetermination is October 1, 2015.

As of June 30, 2015, the outstanding principal amount of our debt was $143.0 million. In addition to cash, cash equivalents and cash flow from operations, at June 30, 2015, we had a Senior Credit Facility, a credit facility with a Turkish bank, convertible notes, a term loan facility and a prepayment agreement, all of 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. (“TransAtlantic Turkey”), Amity Oil International Pty. Ltd., (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Urunleri Insaat Sanayi ve Ticaret A.S. (“Petrogas”) (collectively the “Borrowers”) entered into the Senior Credit Facility with BNP Paribas and the 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”).  As of June 30, 2015, we had borrowings of $67.0 million, bearing interest at a rate of 5.28% per annum.  Pursuant to the terms of the Senior Credit Facility, the borrowing base resets on the first day of each fiscal quarter.  As of July 1, 2015, the borrowing base was reset to $70.8 million, and we had $3.8 million of availability under the Senior Credit Facility.  At June 30, 2015, we were in compliance with all covenants under the Senior Credit Facility.

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TBNG Credit Facility. Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) has a fully drawn credit facility with a Turkish bank. During the first quarter of 2015, the facility was amended and now bears interest at a rate of 5.9% per annum and is due in monthly principal installments of $1.3 million each, ending April 4, 2016. The facility may be prepaid without penalty. The facility is secured by a lien on a hotel owned by Gundem Turizm Yatirim ve Isletme A.S. (“Gundem”), which is 97.5% beneficially owned by Mr. Mitchell and his children. At June 30, 2015, TBNG owed $13.0 million under the credit facility and had no availability.

 

Convertible Notes.  At June 30, 2015, we sold $55.0 million aggregate principal amount of 13.0% convertible notes due 2017 (the “Convertible Notes”).  The Convertible Notes were issued pursuant to an indenture, dated as of February 20, 2015 (the “Indenture”), between us and U.S. Bank National Association, as trustee (the “Trustee”).  The Convertible Notes bear interest at an annual rate of 13.0% per annum.  Interest is payable semi-annually, in arrears, on January 1 and July 1 of each year, commencing on July 1, 2015.  The Convertible Notes mature on July 1, 2017, unless earlier redeemed or converted.  The Convertible Notes are convertible, at the election of a holder, any time after July 1, 2015, into our common shares at a conversion price of $6.80 per share.

Term Loan Facility. On September 17, 2014, Stream Oil & Gas Ltd., a Cayman Islands corporation (“Stream Sub”), a subsidiary of Stream, entered into a term loan facility (the “Term Loan Facility”) with Raiffeisen Bank Sh.A (“Raiffeisen”).  The Term Loan Facility matures on December 31, 2016 and bears interest at the rate of LIBOR plus 5.5%, with a minimum interest rate of 7.0%. Stream Sub is required to repay $1.0 million each quarter on the last business day of each of March, June, September and December. The loan is guaranteed by Stream.  Stream Sub may prepay the loan at its option in whole or in part, subject to a 3.0% penalty plus breakage costs.  The Term Loan Facility is secured by substantially all of the assets of Stream Sub.  As of June 30, 2015, we had $7.1 million outstanding under the Term Loan Facility bearing interest at a rate of 7.0% per annum and no availability.  At June 30, 2015, we were not in compliance with certain conditions subsequent set forth in Section 4 of the Term Loan Facility, including the delivery to Raiffeisen of a copy of an agreement between Albpetrol Sh. A and ourselves concerning postponement of certain capital expenditures. Raiffeisen has granted us a waiver on this requirement until September 30, 2015.

Prepayment Agreement. In April 2013, Stream and Stream Sub entered into the prepayment agreement (the “Prepayment Agreement”) with Trafigura PTE Ltd (“Trafigura”). In October 2013, Stream received a $7.0 million prepayment under the Prepayment Agreement. No further prepayment requests can be made under the Prepayment Agreement. The prepayment is to be repaid by Stream’s delivery of oil to Trafigura in accordance with an oil sales contract between Stream and Trafigura and bears interest at a rate equal to LIBOR plus 6%. Stream must repay the prepayment at the times and in the quantities as set out in the oil sales contract, and all amounts must be repaid on or before August 31, 2015.  At June 30, 2015, we had $0.9 million outstanding under the Prepayment Agreement bearing interest at a rate of 6.2% per annum and no availability.

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Our derivative contracts may expose us to credit risk in the event of nonperformance by our counterparty. As of June 30, 2015, one of the lenders under our Senior Credit Facility is a counterparty to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. These agreements allow us to offset our asset position with our liability position in the event of default by the counterparty.

During the second quarter of 2015, there were no material changes in market risk exposures or their management that would affect the Quantitative or Qualitative Disclosures About Market Risk disclosed in our Annual Report on Form 10-K for the year ended December 31, 2014.  The following tables set forth our outstanding derivatives contracts, which are settled based on Brent crude oil pricing, with respect to future crude oil production as of June 30, 2015:

Fair Value of Derivative Instruments as of June 30, 2015

 

 

 

 

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Acquisition of Stream

In November 2014, we acquired Stream.  For purposes of determining the effectiveness of our disclosure controls and procedures, management has excluded the internal control over financial reporting of Stream from its evaluation.  The acquired business represented approximately 28.8% of our consolidated total assets at June 30, 2015 and 25.0% of our consolidated net loss for the three months ended June 30, 2015.

 

Evaluation of Disclosure Controls and Procedures

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

As of June 30, 2015, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and chief financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act). Based upon the evaluation, our chief executive officer and chief financial officer concluded that, as of June 30, 2015, our disclosure controls and procedures were effective at the reasonable assurance level.

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

Changes in Internal Control over Financial Reporting

Excluding Stream, there were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2015 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 second quarter of 2015, 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, 2014.

 

During the second quarter of 2015, there were no material changes to the Risk Factors disclosed in “Part I, Item 1A” in our Annual Report on Form 10-K for the year ended December 31, 2014, except as follows:

Continued depressed or further declining oil and natural gas prices may significantly adversely affect our results of operations, financial condition or ability to meet our capital expenditure obligations and financial commitments.

 

Our revenues, operating results and future rate of growth are substantially dependent upon the prevailing prices of, and demand for, oil and natural gas. Oil prices have declined substantially since mid-2014 and have experienced significant volatility during the first six months of 2015. The market price of Brent crude oil has decreased approximately 50% since June 2014 as a result of market uncertainties over the supply and demand of oil due to increased production in certain regions, decisions made by OPEC, the current state of the global economy and concerns over future global oil demand.  Historically, oil and natural gas prices and markets have been volatile, and they are likely to continue to be volatile in the future.

 

Continued depressed oil prices or a further decrease in oil or natural gas prices will not only reduce revenues and profits, but will also reduce the quantities of reserves that are commercially recoverable, make some wells uneconomical to drill or operate, reduce our ability to develop our properties, reduce our ability to offset the natural decline in production from producing wells through new development and may result in charges to earnings for impairment of the value of these assets. The recent substantial decline in oil prices may also adversely impact the ultimate development of the quantity of reserves that we reported at December 31, 2014.  If oil or natural gas prices continue to be depressed or further decline in the future, we might not be able to generate sufficient cash flow from operations to meet our obligations and make planned capital expenditures. In addition, reductions in our borrowing capacity under the Senior Credit Facility as a result of a redetermination to our borrowing base could have an impact on capital resources and liquidity.  The borrowing base redetermination process considers assumptions related to future commodity prices; therefore, our borrowing capacity could be negatively impacted by the recent decline or any further declines in oil prices.  If our borrowing base is reduced, we could be required to repay a portion of our borrowings under the Senior Credit Facility.  The next borrowing base redetermination is October 1, 2015.

 

Oil and natural gas prices are subject to wide fluctuations in response to relatively minor changes in the supply of, and demand for, oil and natural gas, market uncertainty and a variety of additional factors that are beyond our control. Among the factors that could cause fluctuations are:

Our businesses, results of operations, future rate of growth and quantities of reserves that are commercially recoverable depend heavily on the prices we receive for oil sales. No assurance can be given that current or future oil prices will be at levels which enable us to do business profitably or at levels that make it economically viable to produce from certain wells. Continued depressed oil prices or a further decline in oil or natural gas prices may have a material adverse effect on our business, financial condition and results of operations.

 

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

 

During 2014 and the first six months of 2015, we derived 78.6% and 67.8%, respectively, of our oil production from the Selmo oil field in southeastern Turkey. Historically, the southeastern area of Turkey and nearby countries such as Iran, Iraq and Syria have experienced political, social, security and economic problems, terrorist attacks, insurgencies, war and civil unrest. Since

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December 2010, political instability has increased markedly in a number of countries in the Middle East and North Africa. As a result of the civil war in Syria, hundreds of thousands of Syrian refugees have fled to Turkey and more can be expected to cross the border as the conflict continues. Moreover, tensions between Turkey and Syria have escalated.

 

The current conflict with the terrorist group Islamic State in Iraq and Syria (“ISIS”), as well as tension in and involving the Kurdish regions of northern Iraq, which are contiguous to the region where our southeast Turkey licenses are located, may have political, social or security implications in Turkey or otherwise have a negative impact on the Turkish economy. Stability and security in Iraq and Syria have deteriorated significantly due to the conflict with ISIS.  

 

Turkey has also experienced problems with domestic terrorist and ethnic separatist groups. For example, Turkey has been in conflict for many years with the Kurdistan Workers’ Party (“PKK”), an organization that is listed as a terrorist organization by states and organizations, including Turkey, the European Union and the United States.

 

In response to escalating violence, the United States has increased military operations against ISIS. In addition, in response to recent attacks in Turkey by ISIS and PKK, Turkey has authorized military action, engaging in recent land and air strikes, against ISIS and PKK.  This instability has raised concerns regarding security in the region, including Turkey, and these situations may escalate in the future to more violent events.

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

 

None.

 

None.

 

Not applicable.

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RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our ratio of earnings to fixed charges for the six months ended June 30, 2015. You should read this ratio in connection with our consolidated financial statements and the related notes included in this Quarterly Report on Form 10-Q.  Because we did not have preferred stock outstanding during this period, our ratio of earnings to combined fixed charges and preferred dividends for any given period is equivalent to our ratio of earnings to fixed charges.

 

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

 

PRICE RANGE OF OUR COMMON SHARES

Canada

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

 

United States

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

 

 

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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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