UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

(Mark One)

For the quarterly period ended: March 31, 2018

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  ☒    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  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No   ☒

As of May 7, 2018, the registrant had 50,384,698 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, 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 May 7, 2018, approximately 47% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

TransAtlantic is a holding company with two operating segments – Turkey and Bulgaria.  Its assets consist of its ownership interests in subsidiaries that primarily own assets in Turkey and Bulgaria.

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 the 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, 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, 2017.

 

On February 24, 2017, we closed the sale of our ownership interests in our subsidiary Thrace Basin Natural Gas (Turkiye) Corporation (“TBNG”) for gross proceeds of $20.7 million, and approximate net cash proceeds of $16.1 million, which amounts reflect a $0.2 million post-closing purchase price adjustment.  

 

We classified the assets and liabilities of TBNG within the captions “Assets held for sale” and “Liabilities held for sale” on our consolidated balance sheets as of December 31, 2016. Although the sale of TBNG met the threshold to classify its assets and liabilities as held for sale, it didn’t meet the requirements to classify its operations as discontinued as the sale wasn’t considered a strategic shift in our operations. As such, TBNG’s results of operations are classified as continuing operations for all periods presented (See Note 13, “Assets and liabilities held for sale and discontinued operations”).

 

Revenue Recognition

 

As explained below, on January 1, 2018, the Company adopted Financial Accounting Standards Board (“FASB”) Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606), under the modified retrospective method.  Under this method, the Company recognizes the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings; however, no adjustment was required as a result of adopting the new revenue standard.  Results for reporting periods beginning after January 1, 2018 are presented under the new standard. The comparative information has not been restated and continues to be reported under the historic accounting standards in effect for those periods.  The Company does not expect any impact to its net income from the adoption of ASU 2014-09 on an ongoing basis.

 

The Company’s revenue consists of sales under two contracts, one for crude oil and one for natural gas.  The crude oil is delivered to the inlet of a processing center and control is passed through a custodian to the customer at that point.  The Company is paid for crude oil at the inlet plus or minus an adjustment for quality.  The Company’s natural gas is metered at the inlet of a transportation pipeline and control is passed at that point.  The Company records natural gas sales at the delivery point to the customer, net of any pricing differentials. There is no material inventory remaining at the end of each reporting period.

 

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The Company has previously deducted any transportation costs, processing fees, or adjustments from revenue and recorded the net amount.  Under the new revenue guidance, on January 1, 2018, the Company now records the gross amount of the revenue and records any fees, or deductions as expenses.  The Company’s revenue excludes any amounts collected on behalf of third parties.

 

2. Recent accounting pronouncements

In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, its final standard on revenue from contracts with customers. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In applying the revenue model to contracts within its scope, an entity identifies the contract(s) with a customer, identifies the performance obligations in the contract, determines the transaction price, allocates the transaction price to the performance obligations in the contract and recognizes revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 applies to all contracts with customers and requires significantly expanded disclosures about revenue recognition. ASU 2014-09 has been amended several times with subsequent ASUs including ASU 2015-14 Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.

We have adopted the standard on January 1, 2018 using the modified retrospective approach. We have a small number of contracts with customers and have identified transactions within the scope of the standard. As a result of adoption of ASU 2014-09, we have determined that it will change our method of recording certain transportation and processing charges that were previously recorded as a reduction of revenues to record such charges as an expense under the new standard. The result of this change was an increase to both revenue and expenses of $1.2 million for the three months ended March 31, 2018. The application of the new standard has no impact on our retained earnings and no impact to our net income on an ongoing basis. As of the three months ended December 31, 2017, this change would have been an increase to both revenue and expenses of $1.1 million.

Contracts for the sale of natural gas and crude oil are evidenced by (1) base contracts for the sale and purchase of natural gas or crude oil, which document the general terms and conditions for the sale, and (2) transaction confirmations, which document the terms of each specific sale.

Revenue is measured based on consideration specified in the contract with the customer. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. Revenues are recognized for the sale of the Company’s net share of production volumes. Sales on behalf of other working interest owners and royalty interest owners are not recognized as revenues. The contract consideration in the Company’s contracts are typically allocated to specific performance obligations in the contract according to the price stated in the contract which usually sets the base oil and gas prices based on benchmark prices based on volumes and adjustments for product quality. Payment is generally received one or two months after the sale has occurred.

 

 

*As noted above, prior period amounts have not been adjusted under the modified retrospective method.

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All of the Company’s revenues from contracts with customers represent products transferred at a point in time as control is transferred to the customer and are generated in Turkey.

Transaction Price Allocated to Remaining Performance Obligations. A significant number of the Company’s product sales are short-term in nature with a contract term of one year or less. For those contracts, the Company has utilized the practical expedient exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Contract Balances. Receivables from contracts with customers are recorded when the right to consideration becomes unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $15.6 million and $15.8 million as of March 31, 2018 and December 31, 2017, respectively, and are reported in accounts receivable, net on the Consolidated Balance Sheet. The Company currently has no assets or liabilities related to its revenue contracts, including no upfront or rights to deficiency payments.

Practical Expedients. The Company has made use of certain practical expedients in adopting the new revenue standard, including the value of unsatisfied performance obligations are not disclosed for (i) contracts with an original expected length of one year or less, (ii) contracts for which the Company recognizes revenue at the amount to which the Company has the right to invoice, (iii) variable consideration which is allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (iv) only contracts that are not completed at transition. The Company has not adjusted the promised amount of consideration for the effects of a significant financing component if the Company expects, at contract inception, that the period between when the Company transfers a promised good or service to the customer and when the customer pays for that good or service will be one year or less.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The guidance requires adoption by application of a modified retrospective transition approach for existing long-term leases and is effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Oil and natural gas leases are excluded from the provisions of ASU 2016-02. As of March 31, 2018, we currently have 19 operating leases within the scope of this standard, the last lease expiring in 2022. The effect of ASU 2016-02 is expected to require additional disclosures, and we are currently evaluating the impact that ASU 2016-02 would have on our consolidated financial statements and results of operations.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”).  ASU 2016-13 changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is adopted. We are currently assessing the potential impact of ASU 2016-13 on our consolidated financial statements and results of operations.

In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the statement of cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning after December 15, 2017. We have adopted ASU 2016-15, effective January 1, 2018.  The adoption of ASU 2016-15 had no impact on our retained earnings or net income.

In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”).  ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statements of cash flows.

We adopted ASU 2016-18 effective January 1, 2018. The adoption of ASU 2016-18 had no impact on our retained earnings, and no impact to our net income on an ongoing basis. Adoption of the new standard requires that a statement of cash flows explain the change

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during the period in the total of cash, cash equivalents and amounts generally described as restricted cash, or restricted cash equivalents.  The amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statements of cash flows. The amendments have been applied using a retrospective transition method to each period presented, as required.  The period ended March 31, 2017 has been reclassified to reflect this change.

In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, which clarifies Topic 718, Compensation – Stock Compensation, such that an entity must apply modification accounting to changes in the terms or conditions of a share-based payment award unless all of the following criteria are met: (1) the fair value of the modified award is the same as the fair value of the original award immediately before the modification and the ASU indicates that if the modification does not affect any of the inputs to the valuation technique used to value the award, the entity is not required to estimate the value immediately before and after the modification; (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award immediately before the modification; and (3) the classification of the modified award as an equity instrument or a liability instrument is the same as the classification of the original award immediately before the modification. The ASU is effective for fiscal years beginning after December 15, 2017. We expect the adoption of this ASU will only impact consolidated financial statements if there is a modification to our share-based award agreements in the future.

In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, which amends the hedge accounting recognition and presentation requirements in Accounting Standards Codification (“ASC”) Topic 815. The new standard provides partial relief on the timing of certain aspects of hedge documentation and eliminates the requirement to recognize hedge ineffectiveness separately in income. The amendments in this ASU are effective for fiscal years beginning after December 15, 2018 and for interim periods therein. Early adoption as of the date of issuance is permitted. The new standard does not impact accounting for derivatives that are not designated as accounting hedges. We do not currently account for any of our derivative position as accounting hedges.

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. Series A Preferred Shares

 

Series A Preferred Shares

 

As of March 31, 2018 and 2017, we had 921,000 outstanding shares of our 12.0% Series A Convertible Redeemable Preferred Shares (“Series A Preferred Shares”). The Series A Preferred Shares contain a substantive conversion option, are mandatorily redeemable and convert into a fixed number of common shares. As a result, under U.S GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of March 31, 2018, there were $21.3 million of Series A Preferred Shares and $24.8 million of Series A Preferred Shares – related party outstanding (see Note 12 “Related party transactions”).

 

Pursuant to the Certificate of Designations for the Series A Preferred Shares (the “Certificate of Designations”), each Series A Preferred Share may be converted at any time, at the option of the holder, into 45.754 common shares (which is equal to an initial conversion price of approximately $1.0928 per common share and is subject to customary adjustments for stock splits, stock dividends, recapitalizations or other fundamental changes).  

 

If not converted sooner, on November 4, 2024, we are required to redeem the outstanding Series A Preferred Shares in cash at a price per share equal to the liquidation preference plus accrued and unpaid dividends. At any time on or after November 4, 2020, we may redeem all or a portion of the Series A Preferred Shares at the redemption prices listed below (expressed as a percentage of the liquidation preference amount per share) plus accrued and unpaid dividends to the date of redemption, if the closing sale price of the common shares equals or exceeds 150% of the conversion price then in effect for at least 10 trading days (whether or not consecutive) in a period of 20 consecutive trading days, including the last trading day of such 20 trading day period, ending on, and including, the trading day immediately preceding the business day on which we issue a notice of optional redemption. The redemption prices for the 12-month period starting on the dates below are:

 

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Additionally, upon the occurrence of a change of control, we are required to offer to redeem the Series A Preferred Shares within 120 days after the first date on which such change of control occurred, for cash at a redemption price equal to the liquidation preference per share, plus any accrued and unpaid dividends.  

 

Dividends on the Series A Preferred Shares are payable quarterly at our election in cash, common shares or a combination of cash and common shares at an annual dividend rate of 12.0% of the liquidation preference if paid all in cash or 16.0% of the liquidation preference if paid in common shares. If paid partially in cash and partially in common shares, the dividend rate on the cash portion is 12.0%, and the dividend rate on the common share portion is 16.0%. Dividends are payable quarterly on March 31, June 30, September 30, and December 31 of each year. The holders of the Series A Preferred Shares also are entitled to participate pro-rata in any dividends paid on the common shares on an as-converted-to-common shares basis. For the three months ended March 31, 2018, we paid $1.3 million in cash dividends on the Series A Preferred Shares, which is recorded in our consolidated statements of comprehensive (loss) income under the caption “Interest and other expense”.  

 

Except as required by Bermuda law, the holders of Series A Preferred Shares have no voting rights, except that for so long as at least 400,000 Series A Preferred Shares are outstanding, the holders of the Series A Preferred Shares voting as a separate class have the right to elect two directors to our Board of Directors. For so long as between 80,000 and 399,999 Series A Preferred Shares are outstanding, the holders of the Series A Preferred Shares voting as a separate class have the right to elect one director to our Board of Directors. Upon less than 80,000 Series A Preferred Shares remaining outstanding, any directors elected by the holders of Series A Preferred Shares shall immediately resign from our Board of Directors.

 

The Certificate of Designation also provides that without the approval of the holders of a majority of the outstanding Series A Preferred Shares, we will not issue indebtedness for money borrowed or other securities which are senior to the Series A Preferred Shares in excess of the greater of (i) $100 million or (ii) 35% of our PV-10 of proved reserves as disclosed in our most recent independent reserve report filed or furnished by us on EDGAR.  

 

 

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:

 

For the three months ended March 31, 2018, we recorded foreign currency translation adjustments, which decreased proved properties and increased accumulated other comprehensive loss within shareholders’ equity on our consolidated balance sheets.

At March 31, 2018 and December 31, 2017, we excluded $3.0 million and $0.5 million, respectively, from the depletion calculation for proved development wells currently in progress and for costs associated with fields currently not in production.

At March 31, 2018, the capitalized costs of our oil and natural gas properties, net of accumulated depletion, included $10.1 million relating to acquisition costs of proved properties, which are being depleted by the unit-of-production method using total proved reserves, and $58.8 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, 2017, the capitalized costs of our oil and natural gas properties included $11.2 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $58.7 million relating

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to well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.

Impairments of proved properties and impairment of exploratory well costs

Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. We primarily use Level 3 inputs to determine fair value, including but not limited to, estimates of proved reserves, future commodity prices, the timing and amount of future production and capital expenditures and discount rates commensurate with the risk reflective of the lives remaining for the respective oil and natural gas properties.

During the three months ended March 31, 2018 and 2017, we recorded $0.04 million and $0.1 million, respectively, of impairment of proved properties and exploratory well costs which are primarily measured using Level 3 inputs.  

Capitalized cost greater than one year

As of March 31, 2018, we had $2.3 million of exploratory well costs capitalized for the Pinar-1ST well in Turkey, which we spud in March 2014. The Pinar-1ST well started producing in the first quarter of 2018.

Equipment and other property

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

 

 

At March 31, 2018, we have classified $7.2 million of inventory as a current asset, which represents our expected inventory consumption in the next twelve months. We classify our materials and supply inventory as a long-term asset because such materials will ultimately be classified as a long-term asset when the material is used in the drilling of a well.

At March 31, 2018 and December 31, 2017, we excluded $12.1 million and $12.1 million of inventory, respectively, from depreciation as the inventory had not been placed into service.

 

5. Asset retirement obligations

The following table summarizes the changes in our asset retirement obligations (“ARO”) for the three months ended March 31, 2018 and for the year ended December 31, 2017:

 

 

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.

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6. Commodity derivative instruments

We use collar and put 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 (loss) income 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.”

During the three months ended March 31, 2018 and 2017, we recorded a net loss on commodity derivative contracts of $0.7 million and a net gain of $1.0 million, respectively.

At March 31, 2018 and December 31, 2017, we had outstanding derivative contracts with respect to our future crude oil production as set forth in the tables below:

Fair Value of Derivative Instruments as of March 31, 2018

 

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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 March 31, 2018 and December 31, 2017, and (ii) the net recorded fair value as reflected on our consolidated balance sheets at March 31, 2018 and December 31, 2017.

 

 

 

7. Loans payable

 

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

 

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2016 Term Loan

 

On August 23, 2016, the Turkish branch of TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”) entered into a Credit Agreement (the “Credit Agreement”) with DenizBank, A.S. (“DenizBank”).  The Credit Agreement is a master agreement pursuant to which DenizBank may make loans to TEMI from time to time pursuant to additional loan agreements.

 

On August 31, 2016, DenizBank entered into a $30.0 million term loan with TEMI (the “2016 Term Loan”) under the Credit Agreement. In addition, we and DenizBank entered into additional agreements with respect to up to $20.0 million of non-cash facilities, including guarantee letters and treasury instruments for future hedging transactions.  

 

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The 2016 Term Loan bears interest at a fixed rate of 5.25% (plus 0.2625% for Banking and Insurance Transactions Tax per the Turkish government) per annum and was payable in six monthly installments of $1.25 million each through February 2017 and thereafter in twelve monthly installments of $1.88 million each through February 2018. On April 27, 2017, TEMI and DenizBank approved a revised amortization schedule for the 2016 Term Loan. Pursuant to the revised amortization schedule, the maturity date of the 2016 Term Loan was extended from February 2018 to June 2018, and the monthly principal payments were reduced from $1.88 million to $1.38 million.  The other terms of the 2016 Term Loan remain unchanged. Amounts repaid under the 2016 Term Loan may not be re-borrowed and early repayments under the 2016 Term Loan are subject to early repayment fees.

 

The 2016 Term Loan is guaranteed by DMLP, Ltd. (“DMLP”), TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”), Talon Exploration, Ltd. (“Talon Exploration”) and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) (collectively, the “Guarantors”).

 

The 2016 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting of liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain investments, selling assets or transferring revenue, and other similar matters.  In addition, the 2016 Term Loan prohibits Amity Oil International Pty Ltd (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Urunleri Insaat Sanayi ve Ticaret A.S. (“Petrogas”) from incurring additional debt.  An event of default under the 2016 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and the occurrence of a material adverse effect.

 

The 2016 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate owned by Gundem Turizm Yatirim ve Isletmeleri A.S. (“Gundem”) and (v) certain Diyarbakir real estate owned 80% by N. Malone Mitchell 3^rd and 20% by Selami Erdem Uras.  In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2016 Term Loan.  Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras.  Mr. Mitchell is our chief executive officer and chairman of our board of directors.  Mr. Uras is our vice president, Turkey.  

 

At March 31, 2018, we had $4.1 million outstanding under the 2016 Term Loan and no availability and were in compliance with the covenants in the 2016 Term Loan.

2017 Term Loan

On November 17, 2017, Denizbank entered into a $20.4 million term loan with TEMI (the “2017 Term Loan”) under the Credit Agreement.  We will use the proceeds from the 2017 Term Loan for general corporate purposes.  

The 2017 Term Loan bears interest at a fixed rate of 6.0% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2017 Term Loan has a grace period which bears no interest or payments due until July 2018 and then is payable in one monthly installment of $1.38 million, nine monthly installments of $1.2 million each through April 2019 and thereafter in eight monthly installments of $1.0 million each through December 2019, with the exception of one monthly installment of $1.2 million occurring in October 2019.  The 2017 Term Loan matures in December 2019.  Amounts repaid under the 2017 Term Loan may not be re-borrowed, and early repayments under the 2017 Term Loan are subject to early repayment fees. The 2017 Term Loan is guaranteed by the Guarantors.    

The 2017 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting of liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain investments, selling assets or transferring revenue, and other similar matters.  In addition, the 2017 Term Loan prohibits Amity and Petrogas from incurring additional debt.  An event of default under the 2017 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and the occurrence of a material adverse effect.

The 2017 Term Loan is be secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate owned by Gundem, (v) certain Diyarbakir real estate owned 80% by N. Malone Mitchell 3rd and 20% Selami Erdem Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2017 Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.

 

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At March 31, 2018, we had $20.4 million outstanding under the 2017 Term Loan and no availability, and we were in compliance with the covenants in the 2017 Term Loan.

 

2017 Notes

 

The 2017 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 2017 Notes bore interest at an annual rate of 13.0%, payable semi-annually, in arrears, on January 1 and July 1 of each year.  The 2017 Notes matured on July 1, 2017, and on July 3, 2017, we paid off and retired all remaining outstanding 2017 Notes.

ANBE Note

On December 30, 2015, TransAtlantic Petroleum (USA) Corp (“TransAtlantic USA”) entered into a $5.0 million draw down convertible promissory note (the “ANBE Note”) with ANBE Holdings, L.P. (“ANBE”), an entity owned by the adult children of our chairman and chief executive officer, N. Malone Mitchell 3rd, and controlled by an entity managed by Mr. Mitchell and his wife. The ANBE Note bore interest at a rate of 13.0% per annum. On December 30, 2015, we borrowed $3.6 million under the ANBE Note for general corporate purposes. On June 30, 2016, we issued 355,826 common shares in a private placement to ANBE in lieu of paying cash interest on the ANBE Note.

On October 31, 2016, TransAtlantic USA entered into an amendment of the ANBE Note with ANBE (the “ANBE Amendment”).  The ANBE Amendment extended the maturity date of the Note from October 31, 2016 to September 30, 2017, provided for the ANBE Note to be repaid in four quarterly installments of $0.9 million each in December 2016 and March, June and September 2017, and provided for monthly payments of interest.  

On February 27, 2017, we repaid the ANBE Note in full with proceeds from the sale of TBNG and terminated it.

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 March 31, 2018, we had no outstanding borrowings under these lines of credit.  

 

8. Contingencies relating to production leases and exploration permits

Selmo

We are involved in litigation with persons who claim ownership of a portion of the surface at the Selmo oil field in Turkey. These cases are being vigorously defended by TEMI and Turkish governmental authorities. We do not have enough information to estimate the potential additional operating costs 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.

Bulgaria

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.

In October 2015, the Bulgarian Ministry of Energy and Economy filed a suit against our subsidiary, Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”), claiming a $200,000 penalty for Direct Bulgaria’s alleged failure to fulfill the work program associated with the Aglen exploration permit.  Direct Bulgaria received a force majeure recognition in 2012 from the Bulgarian Ministry of Energy and Economy, and the force majeure event has not been rectified. While we believe that Direct Bulgaria is not under any obligation to fulfill the work program until the force majeure event is rectified and continue to vigorously defend this claim, we continue to engage in discussions with the Ministry of Energy and Economy regarding settlement possibilities.

 

9. Shareholders’ equity

Restricted stock units

We recorded share-based compensation expense of $0.1 million and $0.1 million for awards of restricted stock units (“RSUs”) for the three months ended March 31, 2018 and 2017, respectively.

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As of March 31, 2018, we had approximately $0.2 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 0.5 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 months ended March 31, 2018 and 2017 equals net 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 months ended March 31, 2018 and 2017 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, preferred shares and warrants (prior to January 6, 2018), whether exercisable or not.  For the three months ended March 31, 2018, 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:

 

Warrants

 

On December 31, 2014, April 24, 2015 and August 13, 2015, we issued 233,334, 233,333 and 233,333 common share purchase warrants (“Warrants”), respectively, to the shareholders of Gundem as consideration for the pledge of Turkish real estate in exchange for an extension of the maturity of a credit agreement between us and a Turkish bank.  As consideration for the pledge of Turkish real estate, the independent members of our board of directors approved the issuance of the Warrants to be allocated in accordance with each shareholder’s ownership percentage of Gundem.  The Warrants were issued pursuant to a warrant agreement, whereby the Warrants were immediately exercisable and entitled the holder to purchase one common share for each Warrant.  The Warrants were issued in December 2014, April 2015 and August 2015 at an exercise price of $5.99, $5.65 and $2.99 per share, respectively. The Warrants expired, unexercised, pursuant to their terms on January 6, 2018.

 

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10. 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:

 

 

 

11. Financial instruments

 

Interest rate risk

We are exposed to interest rate risk as a result of our variable rate short-term cash holdings.

Foreign currency risk

We have underlying foreign currency exchange rate exposure. Our currency exposures primarily relate to transactions denominated in the Bulgarian Lev, the European Union Euro, and the New Turkish Lira (“TRY”). We are also subject to foreign currency exposures resulting from translating the functional currency of our subsidiary financial statements into the U.S. Dollar reporting currency. We have not used foreign currency forward contracts to manage exchange rate fluctuations. At March 31, 2018, we had 15.8 million TRY (approximately $4.0 million) in cash and cash equivalents, which exposes us to exchange rate risk based on fluctuations in the value of the TRY.

Commodity price risk

We are exposed to fluctuations in commodity prices for oil and natural gas. Commodity prices are affected by many factors, including, but not limited to, supply and demand. At March 31, 2018 and December 31, 2017, we were a party to commodity derivative contracts (See Note 6 “Commodity derivative instruments”).

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 (“TPAO”), the national oil company of Turkey, Zorlu Dogal Gaz Ithalat Ihracat ve Toptan Ticaret A.S. (“Zorlu”), a privately owned natural gas distributor in Turkey, and TUPRAS, which purchase the majority of our oil and natural gas production. The receivables are not collateralized. To date, we have experienced minimal bad debts and have no allowance for doubtful accounts for TUPRAS. The majority of our cash and cash equivalents are held by three financial institutions in the United States and Turkey.

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Fair value measurements

 

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 March 31, 2018 and December 31, 2017, due to the short maturity of those instruments.

 

The following table summarizes the valuation of our financial assets and liabilities as of March 31, 2018:

 

The following table summarizes the valuation of our financial assets and liabilities as of December 31, 2017:

 

We remeasure our derivative contracts on a recurring basis, with changes flowing through earnings.  At March 31, 2018 and December 31, 2017, both of the fair values of the 2017 Term Loan and the 2016 Term Loan were estimated using a discounted cash flow analysis based on unobservable Level 3 inputs, including our own credit risk associated with the loans payable.

 

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12. Related party transactions

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

 

Services transactions

 

Effective May 1, 2008, we entered into a service agreement (as amended, the “Service Agreement”), with Longfellow Energy, LP (“Longfellow”), Viking Drilling LLC (“Viking Drilling”), MedOil Supply, LLC and Riata Management, LLC (“Riata Management”) (collectively, the “Service Entities”). Mr. Mitchell and his wife own 100% of Riata Management. In addition, Mr. Mitchell, his wife and his children indirectly own 100% of Longfellow. Riata Management owns 100% of MedOil Supply, LLC. Dalea Partners, LP (“Dalea”), an affiliate of Mr. Mitchell, owns 100% of Viking Drilling. Under the terms of the Service Agreement, we pay, or are paid, for the actual cost of the services rendered plus the actual cost of reasonable expenses on a monthly basis. Under the terms of the Service Agreement, the Service Entities agreed to provide the Company upon its request certain computer services, payroll and benefits services, insurance administration services and entertainment services, and the Company and the Service Entities agreed to provide to each other certain management consulting services, oil and natural gas services and general accounting services (collectively, the “Services”). Under the terms of the Service Agreement, the Company pays, or is paid, for the actual cost of the Services rendered plus the actual cost of reasonable expenses on a monthly basis. The Company or the Service Entities may terminate the Service Agreement at any time by providing advance notice of termination to the other party.

 

On March 20, 2017, we entered into a second amendment to the Service Agreement among us and Longfellow, Viking Drilling, Riata Management, Longfellow Nemaha, LLC, a Texas limited liability company, Red Rock Minerals, LP, a Delaware limited partnership, Red Rock Advisors, LLC, a Texas limited liability company, Production Solutions International Limited, a Bermuda exempted company, and Nexlube Operating, LLC, a Delaware limited liability company, and their subsidiaries (collectively, the “Riata Entities”), adding and removing certain of the Service Entities and the Riata Entities and expanding the scope of Services. As this agreement is a related party transaction, the independent members of our board of directors reviewed and approved this amendment.  

 

As of March 31, 2018, we had $0.5 million of outstanding receivables and $0.4 million of outstanding payables pursuant to the Service Agreement.

On March 3, 2016, Mr. Mitchell closed a transaction whereby he sold his interests in Viking Services B.V. (“Viking Services”), the beneficial owner of Viking International Limited (“Viking International”), Viking Petrol Sahasi Hizmetleri A.S. (“VOS”) and Viking Geophysical Services Ltd. (“Viking Geophysical”), to a third party.  As part of the transaction, Mr. Mitchell acquired certain equipment used in the performance of stimulation, wireline, workover and similar services, which equipment will be owned and operated by a new entity, Production Solutions International Petrol Arama Hizmetleri Anonim Sirketi (“PSIL”).  PSIL is beneficially owned by Dalea Investment Group, LLC, which is controlled by Mr. Mitchell. Consequently, on March 3, 2016, TEMI entered into a master services agreement (the “PSIL MSA”) with PSIL on substantially similar terms to our then current master services agreements with Viking International, VOS and Viking Geophysical.  Pursuant to the PSIL MSA, PSIL will perform the services on behalf of TEMI and its affiliates.  The master services agreement with each of Viking International, VOS and Viking Geophysical currently remain in effect.  

As of March 31, 2018, we had $0.7 million of outstanding receivables and $4.2 million of outstanding payables pursuant to the PSIL MSA.

 

Office

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On June 26, 2017, and effective as of January 1, 2017, our wholly owned subsidiary, TransAtlantic USA entered into an Amended and Restated Office Lease (the “Office Lease”) with Longfellow to lease approximately 10,000 square feet of corporate office space in Addison, Texas. The initial lease term under the Office Lease commenced on January 1, 2017 (the “Commencement Date”), and expires five years after the Commencement Date, unless earlier terminated in accordance with the Office Lease. TransAtlantic USA has the option to extend the lease term for two additional periods of five years each. If TransAtlantic USA exercises its option to extend the lease term, the monthly rent payable during such extended term shall be at a mutually agreed upon amount for monthly rent during the renewal term. During the first five months of the initial lease term, TransAtlantic USA is required to pay monthly rent of $14,745.16 to Longfellow, plus utilities, real property taxes and liability insurance (to the extent that TransAtlantic does not obtain its own liability insurance). Monthly rent increases by $2,754.84 the sixth month of the initial lease term, by $833.33 the second year of the initial lease term and by approximately $417 each year thereafter during the initial lease term.

 

Dalea Amended Note and Pledge Agreement

 

On April 19, 2016, we entered into a note amendment agreement (the “Note Amendment Agreement”) with Mr. Mitchell, and Dalea Partners, LP (“Dalea”), pursuant to which Dalea agreed to deliver an amended and restated promissory note (the “Amended Note”) in favor of us, in the principal sum of $7,964,053, which Amended Note would amend and restate that certain Promissory Note, dated June 13, 2012, made by Dalea in favor of us in the principal amount of $11.5 million (the “Original Note”). The Note Amendment Agreement reduced the principal amount of the Original Note to $7,964,053 in exchange for the cancellation of an account payable of approximately $3.5 million (the “Account Payable”) owed by TransAtlantic Albania Ltd. (“TransAtlantic Albania”), a former subsidiary of TransAtlantic, to Viking International Limited.  We have indemnified a third party for any liability relating to the payment of the Account Payable.

Pursuant to the Note Amendment Agreement, on April 19, 2016, we entered into the Amended Note, which amended and restated the Original Note that was issued in connection with our sale of our subsidiaries, Viking International and Viking Geophysical Services, to a joint venture owned by Dalea and Abraaj Investment Management Limited in June 2012. In the Amended Note, we and Dalea acknowledged that (i) while the sale of Dalea’s interest in Viking Services enabled us to take the position that the Original Note was accelerated in accordance with its terms, the principal purpose of including the acceleration events in the Original Note was to ensure that certain oilfield services provided by Viking Services to us would continue to be available to us, and (ii) such services will now be provided pursuant to the PSIL MSA.  PSIL is beneficially owned by Dalea Investment Group, LLC, which is controlled by Mr. Mitchell. As a result, the Amended Note revised the events triggering acceleration of the repayment of the Original Note to the following: (i) a reduction of ownership by Dalea (and other controlled affiliates of Mr. Mitchell) of equity interest in PSIL to less than 50%; (ii) the sale or transfer by Dalea or PSIL of all or substantially all of its assets to any person (a “Transferee”) that does not own a controlling interest in Dalea or PSIL and is not controlled by Mr. Mitchell (an “Unrelated Person”), or the subsequent transfer by any Transferee that is not an Unrelated Person of all or substantially all of its assets to an Unrelated Person; (iii) the acquisition by an Unrelated Person of more than 50% of the voting interests of Dalea or PSIL; (iv) termination of the PSIL MSA other than as a result of an uncured default thereunder by TEMI; (v) default by PSIL under the PSIL MSA, which default is not remedied within a period of 30 days after notice thereof to PSIL; and (vi) insolvency or bankruptcy of PSIL. The maturity date of the Amended Note was extended to June 13, 2019. The interest rate on the Amended Note remains at 3.0% per annum and continues to be guaranteed by Mr. Mitchell.  The Amended Note contains customary events of default.

In addition, pursuant to the Note Amendment Agreement, on April 19, 2016, we entered into a pledge agreement (the “Pledge Agreement”) with Dalea, whereby Dalea pledged the $2.0 million principal amount of the 2017 Notes owned by Dalea (the “Dalea Convertible Notes”), including any future securities for which the Dalea Convertible Notes are converted or exchanged, as security for the performance of Dalea’s obligations under the Amended Note. The Pledge Agreement provides that interest payable to Dalea under the Dalea Convertible Notes (or any future securities for which the Dalea Convertible Notes are converted or exchanged) will be credited first against the outstanding principal balance of the Amended Note and, upon full repayment of the outstanding principal balance of the Amended Note, any accrued and unpaid interest on the Amended Note. The Pledge Agreement contains customary events of default. On November 4, 2016, Dalea exchanged $2.0 million of 2017 Notes for 40,000 Series A Preferred Shares.  

On June 30, 2016, we entered into a waiver with Dalea, whereby we waived our right under the Pledge Agreement to receive the interest payment due July 1, 2016 under the Dalea Convertible Notes in connection with the payment of 201,459 common shares to Dalea with respect to the 2017 Note interest payment paid on June 30, 2016.  

During the three months ended March 31, 2018, we reduced the principal amount of the Amended Note by $0.1 million for cash dividends paid on the Series A Preferred Shares.

As of March 31, 2018, the amount receivable under the Amended Note was $6.5 million.

 

Pledge fee agreements

 

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In connection with the pledge of the Gundem real estate and Muratli real estate to DenizBank as collateral for the 2016 Term Loan, on August 31, 2016, we entered into a pledge fee agreement with Gundem (the “Gundem Fee Agreement”) pursuant to which we pay Gundem a fee equal to 5% per annum of the collateral value of the Gundem real estate and Muratli real estate. Pursuant to the Gundem Fee Agreement, the Gundem real estate has a deemed collateral value of $10.0 million and the Muratli real estate has a deemed collateral value of $5.0 million.  

 

In connection with the pledge of the Diyarbakir real estate to DenizBank as collateral for the 2016 Term Loan, on August 31, 2016, we entered into a pledge fee agreement with Messrs. Mitchell and Uras (the “Diyarbakir Fee Agreement”) pursuant to which we pay Mr. Mitchell and Selami Erdem Uras a fee of 5% per annum of the collateral value of the Diyarbakir real estate.  Mr. Uras is our vice president, Turkey.  Pursuant to the Diyarbakir Fee Agreement, the Diyarbakir real estate has a deemed collateral value of $5.0 million.

 

Amounts payable to Mr. Mitchell under the Gundem Fee Agreement and the Diyarbakir Fee Agreement are used to reduce the outstanding principal amount of the Amended Note. During the three months ended March 31, 2018, we reduced the principal amount of the Amended Note by $0.2 million for amounts payable under the pledge fee agreements.

13. Assets and liabilities held for sale and discontinued operations

TBNG assets and liabilities held for sale

 

On October 13, 2016, we entered into a share purchase agreement (the “Purchase Agreement”) with Valeura Energy Netherlands B.V. (“Valeura Netherlands”) for the sale of all of the equity interests in TBNG, our wholly-owned subsidiary. TBNG owned a portion of our interests in the Thrace Basin area in Turkey.  

 

We classified the assets and liabilities of TBNG within the captions “Assets held for sale” and “Liabilities held for sale” on our consolidated balance sheets as of December 31, 2016.  Although the sale of TBNG met the threshold to classify its assets and liabilities as held for sale, it didn’t meet the requirements to classify its operations as discontinued as the sale wasn’t considered a strategic shift in our operations. As such, TBNG’s results of operations are classified as continuing operations for all periods presented.  

 

On February 24, 2017, we closed on the sale of TBNG for gross proceeds of $20.7 million, and approximate net cash proceeds of $16.1 million, which amounts reflect a $0.2 million post-closing purchase price adjustment.    

 

For the three months March 31, 2017, we recorded a non-cash net loss of $15.2 million on the sale of TBNG. The loss related to the reclassification of the TBNG accumulated foreign currency translation adjustment that was realized into earnings from accumulated other comprehensive loss within shareholders’ equity, and presented below:

 

 

As a result of the TBNG sale, there were no remaining assets or liabilities held for sale as of December 31, 2017. As of March 31, 2018, there were no assets or liabilities held for sale. For the three months ended March 31, 2018 and March 31, 2017, we had no significant operating results from discontinued operations.

 

14. Subsequent Events

 

Exploration License 5046 in West Molla expires in June 2018. Based on the successful discovery on the Pinar-1ST exploration well, we applied to convert the exploration license to a production license in the first quarter of 2018. In March 2018, we spud the Yeniev-1 exploration well on Exploration License 5046. If a successful discovery is made on the Yeniev-1 exploration well, the southern portion of Exploration License 5046 may also convert to a production license.

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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 March 31, 2018, we held interests in approximately 367,000 and 163,000 net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria, respectively. As of May 7, 2018, approximately 47% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our chief executive officer and chairman of our board of directors.

TransAtlantic is a holding company with two operating segments – Turkey and Bulgaria.  Its assets consist of its ownership interests in subsidiaries that primarily own assets in Turkey and Bulgaria.

On January 16, 2018, a strategic committee of the board of directors engaged Tudor Pickering Holt & Co. to act as financial advisor to market the Company and explore strategic alternatives to increase shareholder value. There is no assurance that the strategic alternatives process will result in us completing a sale of the Company or any of its assets.

 

Financial and Operational Performance Summary

The following summarizes our financial and operational performance for the first quarter of 2018:

First Quarter 2018 Operational Update

During the first quarter of 2018, we spud two wells and continued workover and recompletion production optimizations in Southeastern Turkey.  The following summarizes our operations by location during the first quarter of 2018:

Southeastern Turkey.

Selmo

In January 2018, we spud the Selmo-81H2 well, which is the first of a six-well Selmo development program. Completion is ongoing, and we expect to commence production in the second quarter of 2018. We expect to resume drilling in the Selmo field in the third quarter of 2018.

Bahar

We expect to drill one development well in the Bahar field in 2018. We may drill an additional Bahar development well in the fourth quarter of 2018, contingent on financing.  

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Molla

In March 2018, we spud the Yeniev-1 exploration well, targeting the Bedinan, Hazro and Mardin formations.  We expect to complete drilling in the second quarter of 2018.  We have completed 3-D on the eastern Molla Block extension. We expect to complete processing of this data in the second quarter of 2018. We expect to complete interpretation and analysis in the third quarter of 2018.

Northwestern Turkey. We continue to evaluate our prospects in the Thrace Basin, in light of the recent positive production test results at the Yamalik-1 exploration well, operated by Valeura Energy Inc. (“Valeura”) with their partner Statoil Banarli Turkey B.V. (“Statoil”). The Yamalik-1 exploration well is directly adjacent to our 120,000 net acres in the Thrace Basin of which we believe approximately 50,000 net acres (100% working interest, 87.5% net revenue interest) is analogous to the Valeura and Statoil acreage. We expect to resume production operations on our Yildurm-1 well on the Temrez license in 2018. Contingent on financing, we may commence a three-well drilling program on our Temrez license starting in the fourth quarter of 2018.

Bulgaria. We have prepared plans to side track and re-drill the Devinci R-1 well, which we plan to commence during 2018, contingent on financing.

Planned Operations

We expect our net field capital expenditures for the remainder of 2018 to range between $18.0 million and $21.0 million. We expect net field capital expenditures during the remainder of 2018 to include between $14.0 million and $17.0 million in drilling and completion expense for eight wells and approximately $4.0 million in recompletions.  We expect that any additional 2018 expenditures would be invested in the Selmo, Bahar and Molla fields in southeastern Turkey and the Koynare license in Bulgaria.  We expect that cash on hand and cash flow from operations will be sufficient to fund the remainder of our 2018 net field capital expenditures.  If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected remaining 2018 capital expenditure budget is subject to change.

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 U.S. GAAP. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3. Significant accounting policies” to our audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2017 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.

 

Effective January 1, 2018, the Company adopted new accounting standards for revenue, statement of cash flows and restricted cash disclosures in statement of cash flows. (See Note 2. “Recent accounting pronouncements”)

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Results of Continuing Operations—Three Months Ended March 31, 2018 Compared to Three Months Ended March 31, 2017

Our results of continuing operations for the three months ended March 31, 2018 and 2017 were as follows:

 

Oil and Natural Gas Sales. Total oil and natural gas sales revenues increased $0.9 million to $16.7 million for the three months ended March 31, 2018, from $15.8 million realized in the same period in 2017.  The increase was primarily due to an increase in the average realized price per Boe.  Our average price received increased $18.47 per Boe to $64.17 per Boe for the three months ended March 31, 2018, from $45.70 per Boe for the same period in 2017.  This was partially offset by a decrease in our average daily sales volumes of 948 Boepd for the three months ended March 31, 2018 compared to the same period in 2017.

 Production. Production expenses for the three months ended March 31, 2018 decreased to $2.9 million, or $10.28 per Boe, from $3.1 million, or $7.74 per Boe, for the same period in 2017.  The decrease was primarily due to less workovers during the three months ended March 31, 2018, as compared to the same period in 2017.

Transportation and processing. Transportation and processing expense for the three months ended March 31, 2018 increased to $1.2 million from zero for the same period in 2017. The increase is due to the new revenue reporting regulation, ASC 606, which requires cost, previously netted in revenue, to be reported separately. For the three months ended March 31, 2017, the transportation and processing costs were $1.2 million and were netted against oil and natural gas sales.

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Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs for the three months ended March 31, 2018 did not significantly change from the same period in 2017.

General and Administrative. General and administrative expense was $3.3 million for the three months ended March 31, 2018, compared to $3.6 million for the same period in 2017.  Our general and administrative expenses decreased $0.3 million primarily due to a $0.2 million decrease in legal and a $0.1 million decrease in insurance expenses.

Depletion. Depletion decreased to $4.2 million, or $14.53 per Boe, for the three months ended March 31, 2018, compared to $4.3 million, or $10.93 per Boe, for the same period of 2017. The decrease was primarily due to a reduction in production volumes.  

Interest and Other Expense. Interest and other expense increased to $2.8 million for the three months ended March 31, 2018, compared to $2.4 million for the same period in 2017. The increase was primarily due to our higher average debt balances during the three months ended March 31, 2018 versus the same period in 2017.

 

Interest and Other Income. Interest and other income did not significantly change during the three months ended March 31, 2018 from the same period in 2017.

Foreign Exchange Loss. We recorded a foreign exchange loss of $2.1 million during each of the three months ended March 31, 2018 and 2017. Foreign exchange gains and losses are 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 TRY amount if it has not been settled previously.

Gain (Loss) on Commodity Derivative Contracts. During the three months ended March 31, 2018, we recorded a net loss on commodity derivative contracts of $0.7 million, as compared to a net gain of $1.0 million for the same period in 2017. During the three months ended March 31, 2018, we recorded a $0.6 million gain to mark our derivative contracts to their fair value and a $1.3 million loss on settled contracts. During the same period in 2017, we recorded a $1.0 million gain to mark our commodity derivative contracts to their fair value.

Capital Expenditures

For the quarter ended March 31, 2018, we incurred $5.2 million in capital expenditures, including seismic and corporate expenditures, as compared to $6.5 million for the quarter ended March 31, 2017.  

We expect our net field capital expenditures for the remainder of 2018 to range between $18.0 million and $21.0 million. We expect net field capital expenditures during the remainder of 2018 to include between $14.0 million and $17.0 million in drilling and completion expense for eight wells and approximately $4.0 million in recompletions.  We expect that any additional 2018 expenditures would be invested in the Selmo, Bahar and Molla fields in southeastern Turkey and the Koynare license in Bulgaria.  We expect that cash on hand and cash flow from operations will be sufficient to fund the remainder of our 2018 net field capital expenditures.  If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected remaining 2018 capital expenditure budget is subject to change.

Cashflows

Net cash provided by operating activities during the three months ended March 31, 2018 was $7.8 million, an increase from net cash provided by operating activities of $1.9 million for the same period in 2017.  The increase was primarily due to the timing of collecting our receivables and paying our accounts payable.

Net cash used in investing activities during the three months ended March 31, 2018 was $7.0 million, as compared to net cash provided by investing activities of $11.2 million for the same period in 2017.  The change in net cash was primarily due to the proceeds received from the sale of TBNG of $17.8 million during the quarter ended March 31, 2017.

Net cash used in financing activities during the three months ended March 31, 2018 was $4.1 million, a decrease from net cash used in financing activities of $11.4 million for the same period in 2017.  The change in net cash was due to a decrease in debt principal repayments.

Liquidity and Capital Resources

As of March 31, 2018, we had $24.5 million of indebtedness, not including $9.6 million of trade payables, as further described below.  We believe that our cash flow from operations will be sufficient to meet our normal operating requirements and to fund planned capital expenditures during the next 12 months. As of March 31, 2018, we had a working capital surplus of $9.3 million.

 

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Outstanding Debt and Series A Preferred Shares

 

2016 Term Loan. On August 23, 2016, the Turkish branch of TEMI entered into the Credit Agreement with DenizBank.  The Credit Agreement is a master agreement pursuant to which DenizBank may make loans to TEMI from time to time pursuant to additional loan agreements.

 

     On August 31, 2016, DenizBank entered the 2016 Term Loan under the Credit Agreement. In addition, we and DenizBank entered into additional agreements with respect to up to $20.0 million of non-cash facilities, including guarantee letters and treasury instruments for future hedging transactions. The 2016 Term Loan bears interest at a fixed rate of 5.25% (plus 0.2625% for Banking and Insurance Transactions Tax per the Turkish government) per annum and is payable in monthly installments of $1.38 million through June 2018. Amounts repaid under the 2016 Term Loan may not be re-borrowed and early repayments under the 2016 Term Loan are subject to early repayment fees. The 2016 Term Loan is guaranteed by the Guarantors.

 

       The 2016 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting of liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain investments, selling assets or transferring revenue, and other similar matters.  In addition, the 2016 Term Loan prohibits Amity and Petrogas from incurring additional debt.  An event of default under the 2016 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and the occurrence of a material adverse effect.

 

       The 2016 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate owned by Gundem and (v) certain Diyarbakir real estate owned 80% by N. Malone Mitchell 3^rd and 20% by Selami Erdem Uras.  In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2016 Term Loan.  Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras.  Mr. Mitchell is our chief executive officer and chairman of our board of directors.  Mr. Uras is our vice president, Turkey.   

 

        At March 31, 2018, we had $4.1 million outstanding under the 2016 Term Loan and no availability and were in compliance with the covenants in the 2016 Term Loan.

       2017 Term Loan. On November 17, 2017, Denizbank entered into the 2017 Term Loan under the Credit Agreement.  We will use the proceeds from the 2017 Term Loan for general corporate purposes.  

        The 2017 Term Loan bears interest at a fixed rate of 6.0% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2017 Term Loan has a grace period which bears no interest or payments due until July 2018 and then is payable in one monthly installment of $1.38 million, nine monthly installments of $1.2 million each through April 2019 and thereafter in eight monthly installments of $1.0 million each through December 2019, with the exception of one monthly installment of $1.2 million occurring in October 2019.  The 2017 Term Loan matures in December 2019.  Amounts repaid under the 2017 Term Loan may not be re-borrowed, and early repayments under the 2017 Term Loan are subject to early repayment fees. The 2017 Term Loan is guaranteed by the Guarantors.    

        The 2017 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting of liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain investments, selling assets or transferring revenue, and other similar matters.  In addition, the 2017 Term Loan prohibits Amity and Petrogas from incurring additional debt.  An event of default under the 2017 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and the occurrence of a material adverse effect.

        The 2017 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate owned by Gundem, (v) certain Diyarbakir real estate owned 80% by N. Malone Mitchell 3rd and 20% Selami Erdem Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2017 Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.

 

         At March 31, 2018, we had $20.4 million outstanding under the 2017 Term Loan and no availability, and we were in compliance with the covenants in the 2017 Term Loan.

 

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       2017 Notes. The 2017 Notes were issued pursuant to the Indenture.  The 2017 Notes bore interest at an annual rate of 13.0%, payable semi-annually, in arrears, on January 1 and July 1 of each year.  The 2017 Notes matured on July 1, 2017, and on July 3, 2017, we paid off and retired all remaining outstanding 2017 Notes.

 

      ANBE Note. On December 30, 2015, TransAtlantic USA entered into the ANBE Note. The ANBE Note bore interest at a rate of 13.0% per annum.  On December 30, 2015, we borrowed $3.6 million under the ANBE Note for general corporate purposes. On June 30, 2016, we issued 355,826 common shares in a private placement to ANBE in lieu of paying cash interest on the ANBE Note.

      On October 31, 2016, TransAtlantic USA entered into the ANBE Amendment, which extended the maturity date of the Note from October 31, 2016 to September 30, 2017, provided for the ANBE Note to be repaid in four quarterly installments of $0.9 million each in December 2016 and March, June and September 2017, and provided for monthly payments of interest.

      On February 27, 2017, we repaid the ANBE Note in full with proceeds from the sale of TBNG and terminated it.

 

Series A Preferred Shares. As of March 31, 2018, we have 921,000 Series A Preferred Shares outstanding. The Series A Preferred Shares contain a substantive conversion option, are mandatorily redeemable and convert into a fixed number of common shares. As a result, under U.S GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheets. As of March 31, 2018, there were $21.3 million of Series A Preferred Shares and $24.8 million of Series A Preferred Shares – related party outstanding. (See Note 3. “Series A Preferred Shares”)

 

     Our derivative contracts may expose us to credit risk in the event of nonperformance by our counterparty. Denizbank 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 first quarter of 2018, 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, 2017.  The following table sets forth our derivatives contracts, which are settled based on Brent oil pricing, with respect to future crude oil production as of March 31, 2018:   

 

 

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

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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 principal accounting and financial officer, as appropriate to allow timely decisions regarding required disclosure.

     As of March 31, 2018, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and principal accounting and 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 principal accounting and financial officer concluded that, as of March 31, 2018, 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

     There were no changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2018 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 first quarter of 2018, 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, 2017.

 

During the first quarter of 2018, there were no material changes to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2017.

 

 

None

 

None.

 

Not applicable.

 

 

Not applicable.

 

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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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