(in thousands of U.S. Dollars, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements
1. General
Nature of operations
TransAtlantic Petroleum Ltd. (together with its subsidiaries, “we,” “us,” “our,” the “Company” or “TransAtlantic”) is an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored petroleum systems, have stable governments, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. We hold interests in developed and undeveloped oil and natural gas properties in Turkey and Bulgaria. As of March 20, 2020, N. Malone Mitchell 3rd beneficially owned approximately 49.9% our outstanding common shares. Persons and entities associated with Mr. Mitchell also owned 739,000 of our 12.0% Series A Convertible Redeemable Preferred Shares (“Series A Preferred Shares”). Mr. Mitchell’s affiliates are currently prohibited from converting any of their Series A Preferred Shares to common shares if such conversion would cause Mr. Mitchell or his affiliates to obtain beneficial ownership in excess of 49.9% of the outstanding common shares; however, Mr. Mitchell, upon 61 days’ prior notice, may increase or decrease such percentage cap.
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 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, stock based compensation and financial derivatives, collectability of accounts receivable, 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.
2. Going Concern
These consolidated financial statements have been prepared on the basis of accounting principles applicable to a going concern. These principles assume that we will be able to realize our assets and discharge our obligations in the normal course of operations for the foreseeable future.
We incurred a net loss of $5.4 million for the year ended December 31, 2019. As of December 31, 2019, we had $2.9 million in long-term debt, $17.1 million in short-term debt, $9.7 million in cash and a $2.0 million working capital surplus.
Recent Oil Price Decline
In March 2020, crude oil prices declined to approximately $25 per barrel for Brent crude as a result of market concerns about the economic impact from the coronavirus (COVID-19) as well as the ability of OPEC and Russia to agree on a perceived need to implement further production cuts in response to weaker worldwide demand. The current futures forward curve for Brent crude indicates that prices may continue at or near current prices for an extended time. As a result, we have reduced our planned capital expenditures to those necessary for production lease maintenance and those projecting a return on invested capital at current prices. In order to mitigate the impact of reduced prices on our 2020 cash flows and liquidity, we plan to implement cost reduction measures to reduce our operating costs and general and administrative expenses. In connection therewith, we intend to prioritize funding operating expenditures over general and administrative expenditures, whenever possible.
Notwithstanding these measures, there remain risks and uncertainties regarding our ability to generate sufficient revenues at current oil prices to pay our debt obligations and accounts payable when due. As a result, there is substantial doubt about our ability to continue as a going concern.
Management believes the going concern assumption to be appropriate for these consolidated financial statements. If the going concern assumption was not appropriate, adjustments would be necessary to the carrying values of assets and liabilities, reported revenues and expenses and in the balance sheet classifications used in these consolidated financial statements.
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3. Significant accounting policies
Basis of preparation
Our reporting standard for the presentation of our consolidated financial statements is U.S. GAAP. The consolidated financial statements include the accounts of the Company and all majority-owned and controlled subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.
Accounts receivable, net
We have receivables for sales of oil and natural gas, as well as receivables related to joint interest accounts, which have a contractual maturity of one year or less. An allowance for doubtful accounts has been established based on management’s review of the collectability of the receivables in light of historical experience, the nature and volume of the receivables and other subjective factors. Accounts receivable are charged against the allowance, upon approval by management, when they are deemed uncollectible. Our allowance for doubtful accounts was $0.1 million and $0.5 million at December 31, 2019 and 2018, respectively.
Cash and cash equivalents
Cash and cash equivalents include term deposits and investments with original maturities of three months or less at the date of purchase. We consider all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. We determine the appropriate classification of our investments in cash and cash equivalents and marketable securities at the time of purchase and reevaluate such designation at each balance sheet date.
Derivative instruments
Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging (“ASC 815”), requires derivative instruments to be recognized as either assets or liabilities in the balance sheet at fair value. We do not designate our derivative financial instruments as hedging instruments and, as a result, we recognize the change in a derivative contract’s fair value currently in earnings as a component of other income (expense).
Fair value measurements
We follow ASC 820, Fair Value Measurements and Disclosures (“ASC 820”). This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements. ASC 820 does not require any new fair value measurements, but applies to assets and liabilities that are required to be recorded at fair value under other accounting standards.
ASC 820 characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value measurement hierarchy are as follows:
|
Level 1:
|
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities.
|
|
Level 2:
|
Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
|
|
Level 3:
|
Measured based on prices or valuation models that required inputs that are both significant to the fair value measurement and less observable for objective sources (i.e., supported by little or no market activity).
|
As required by ASC 820, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, which may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The determination of the fair values takes into account the market for our financial assets and liabilities, the associated credit risk and other factors as required by ASC 820. We consider active markets as those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Foreign currency remeasurement and translation
The functional currency of our subsidiaries in Turkey and Bulgaria is the New Turkish Lira (“TRY”) and the Bulgarian Lev, respectively. We follow ASC 830, Foreign Currency Matters (“ASC 830”). ASC 830 requires the assets, liabilities, and results of
F-8
operations of a foreign operation to be measured using the functional currency of that foreign operation. Exchange gains or losses from remeasuring transactions and monetary accounts in a currency other than the functional currency are included in current earnings.
For certain subsidiaries, translation adjustments result from the process of translating the functional currency of subsidiary financial statements into the U.S. Dollar reporting currency. These translation adjustments are reported separately and accumulated in the consolidated balance sheets as a component of accumulated other comprehensive loss.
Oil and natural gas properties
In accordance with the successful efforts method of accounting for oil and natural gas properties, costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. Acquisition costs of proved properties are amortized using the unit-of-production method based on total proved reserves, and exploration well costs and additional development costs are amortized using the unit-of-production method based on proved developed reserves. Proceeds from the sale of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned.
Exploration costs, such as exploratory geological and geophysical costs, delay rentals and exploration overhead, are charged to expense as incurred. Exploratory drilling costs, including the cost of stratigraphic test wells, are initially capitalized but charged to exploration expense if and when the well is determined to be non-productive. The determination of an exploratory well’s ability to produce must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.
Equipment and other property
Equipment and other property are stated at cost, and inventory is stated at weighted average cost which does not exceed replacement cost. Depreciation is calculated using the straight-line method over the estimated useful lives (ranging from 3 to 7 years) of the respective assets. The costs of normal maintenance and repairs are charged to expense as incurred. Material expenditures that increase the life of an asset are capitalized and depreciated over the estimated remaining useful life of the asset. The cost of equipment sold, or otherwise disposed of, and the related accumulated depreciation, are removed from the accounts and any gain or loss is reflected in current earnings.
Impairment of long-lived assets
We follow the provisions of ASC 360, Property, Plant, and Equipment (“ASC 360”). ASC 360 requires that our long-lived assets be assessed for potential impairment of their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Proved oil and natural gas properties are evaluated by field for potential impairment. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of a field are less than its carrying value. If an impairment occurs, the carrying value of the impaired field is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach.
Unproved oil and natural gas properties do not have producing properties and are valued on acquisition by management, with the assistance of an independent expert when necessary. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers (i) estimated potential reserves and future net revenues from an independent expert, (ii) our history in exploring the area, (iii) our future drilling plans per our capital drilling program prepared by our reservoir engineers and operations management and (iv) other factors associated with the area. Impairment is taken on the unproved property value if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.
Joint interest activities
Certain of our exploration, development and production activities are conducted jointly with other entities and, accordingly, the consolidated financial statements reflect only our proportionate interest in such activities.
F-9
Asset retirement obligations
We recognize a liability for the fair value of all legal obligations associated with the retirement of tangible, long-lived assets and capitalize an equal amount as a cost of the asset. The cost associated with the abandonment obligation is included in the computation of depreciation, depletion and amortization. The liability accretes until we settle the obligation. We use a credit-adjusted risk-free interest rate in our calculation of asset retirement obligations.
Revenue recognition
On January 1, 2018, we adopted Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), under the modified retrospective method. Under this method, we recognize 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 timing of revenue recognition for our various revenue streams was not materially impacted by the adoption of this standard. We believe our business processes, systems, and controls are appropriate to support recognition and disclosure under ASU 2014-09. The adoption of ASU 2014-09 did not have any impact to our net income.
We recognize revenue in accordance with ASC 606, Revenue from Contracts with Customers (“ASC 606”). Revenues are recognized when control is transferred to customers in amounts that reflect the consideration we expect to be entitled to receive in exchange for those goods. Revenue recognition is evaluated through the following five steps: (i) identification of the contract(s) with a customer; (ii) identification of the performance obligations in the contract; (iii) determination of the transaction price; (iv) allocation of the transaction price to the performance obligations in the contract; and (v) recognition of revenue when or as a performance obligation is satisfied.
Our 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. We are paid for crude oil at the inlet plus or minus an adjustment for quality. Our natural gas is metered at the inlet of a transportation pipeline and control is passed at that point. We record 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.
We have 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, we now record the gross amount of the revenue and records any fees, or deductions as expenses. Our revenue excludes any amounts collected on behalf of third parties.
During the years ended December 31, 2019 and 2018, we sold $65.8 million and $68.2 million, respectively, of oil to Türkiye Petrol Rafinerileri A.Ş. (“TUPRAS”), a privately-owned oil refinery in Turkey, which represented approximately 97.7%, and 96.4% of our total revenues, respectively.
Share-based compensation
We follow ASC 718, Compensation—Stock Compensation (“ASC 718”), which requires the measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, based on estimated grant date fair values. Restricted stock units are valued using the market price of our common shares on the date of grant. We record compensation expense, net of estimated forfeitures, over the requisite service period.
Series A Preferred Shares
On November 4, 2016, we issued 921,000 shares of 12.0% Series A Convertible Redeemable Preferred Shares (the “Series A Preferred Shares”). All of the Series A Preferred Shares were issued at a value of $50.00 per share. As the shares can be redeemed, they have been classified outside of equity (see Note 5 “Series A Preferred Shares”).
Income taxes
We follow the asset and liability method prescribed by ASC 740, Income Taxes (“ASC 740”). Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities
F-10
are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under ASC 740, the effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in earnings in the period that includes the enactment date.
As of December 31, 2019 and 2018, we have recorded a $6.8 million and $6.7 million liability, respectively, primarily due to uncertain tax positions related to the unwinding of all of our crude oil hedge collars and three-way contracts, which are included in long-term accrued liabilities on our consolidated balance sheet.
We do not believe there will be any material changes in our unrecognized tax positions over the next twelve months. Our policy is that we recognize interest and penalties accrued on any unrecognized tax positions as a component of income tax expense.
We are a Bermuda exempted company, and under current Bermuda law, we are not subject to tax on profits, income or dividends, nor is there any capital gains tax applicable to us in Bermuda.
Comprehensive income
We follow ASC 220, Comprehensive Income, which establishes standards for reporting and displaying comprehensive income and its components (revenue, expenses, gains and losses) in a full set of general-purpose financial statements.
Business combinations
We follow ASC 805, Business Combinations (“ASC 805”) and ASC 810-10-65, Consolidation. ASC 805 requires most identifiable assets, liabilities, non-controlling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under ASC 805, all business combinations are accounted for by applying the acquisition method.
Per share information
Basic per share amounts are calculated using the weighted average common shares outstanding during the year, excluding unvested restricted stock units. We use the treasury stock method to determine the dilutive effect of stock options and other dilutive instruments. Under the treasury stock method, only “in the money” dilutive instruments impact the diluted calculations in computing diluted earnings per share. Diluted calculations reflect the weighted average incremental common shares that would be issued upon exercise of dilutive options assuming the proceeds would be used to repurchase shares at average market prices for the period.
4. New accounting pronouncements
In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which establishes a new lease accounting model for leases. The most significant changes include the clarification of the definition of a lease, the requirement for lessees to recognize for all leases a right-of-use asset and a lease liability in the consolidated balance sheet, and additional quantitative and qualitative disclosures which are designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. Expenses are recognized in the consolidated statement of income in a manner similar to current accounting guidance. Lessor accounting under the new standard is substantially unchanged. The new standard became effective for us beginning with the first quarter of 2019. We adopted the accounting standard using a prospective transition approach, which applied the provisions of the new guidance at the effective date without adjusting the comparative periods presented. We elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed us to carry forward the historical accounting relating to lease identification and classification for existing leases upon adoption. We also made an accounting policy election to keep leases with an initial term of 12 months or less off of the consolidated balance sheet. On January 1, 2019 we recognized $2.7 million of additional right-of-use assets and liabilities on our consolidated balance sheets.
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.
F-11
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 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 became effective for fiscal years beginning after December 15, 2018 and for interim periods therein. 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.
In June 2018, the FASB issued ASU 2018-07, Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting. This update applied the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. This update became effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. We adopted this standard effective January 1, 2019. The adoption of this update had no impact on our consolidated financial statements and results of operations.
In November 2018, the FASB issued ASU 2018-19, Codification Improvements to Topic 326, Financial Instruments-Credit Losses. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We do not believe the adoption of this standard will have an impact on its consolidated financial statements.
In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes. This update removes certain exceptions to the general principles in Topic 740 and provides clarifications related to certain franchise taxes, transactions with a government that result in a step-up in the tax basis of goodwill, allocation of current and deferred income tax expense and the annual effective tax rate. This update is effective January 1, 2021. We are currently assessing the potential impact of this update on our consolidated financial statements and results of operations.
We have reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our consolidated results of operations, financial position and cash flows. Based on that review, we believe that none of these pronouncements will have a significant effect on current or future earnings or operations.
5. Series A Preferred Shares
Series A Preferred Shares
On November 4, 2016, we issued 921,000 Series A Preferred Shares. All of the Series A Preferred Shares were issued at a value of $50.00 per share. 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 sheet. As of December 31, 2019, there were $5.0 million of Series A Preferred Shares and $41.1 million of Series A Preferred Shares – related party outstanding (see Note 16 “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 of the Company (which is equal to an initial conversion price of approximately $1.0928 per common share and is subject to customary adjustment 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 date below are:
|
|
Period Commencing
|
Redemption Price
|
November 4, 2020
|
105.000%
|
November 4, 2021
|
103.000%
|
November 4, 2022
|
101.000%
|
November 4, 2023 and thereafter
|
100.000%
|
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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 June 30, September 30, December 31, and March 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 year ended December 31, 2018, we paid $4.0 million in cash and issued 1,808,001 common shares as dividends on the Series A Preferred Shares. For the year ended December 31, 2019, we paid $1.4 million in cash and issued 9,507,092 common shares as dividends on the Series A Preferred Shares.
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.
6. Property and equipment
Oil and natural gas properties
The following table sets forth the capitalized costs under the successful efforts method for oil and natural gas properties:
|
2019
|
|
|
2018
|
|
|
(in thousands)
|
|
Oil and natural gas properties, proved:
|
|
|
|
|
|
|
|
Turkey
|
$
|
167,446
|
|
|
$
|
162,494
|
|
Bulgaria
|
|
502
|
|
|
|
512
|
|
Total oil and natural gas properties, proved
|
|
167,948
|
|
|
|
163,006
|
|
Oil and natural gas properties, unproved:
|
|
|
|
|
|
|
|
Turkey
|
|
12,978
|
|
|
|
14,965
|
|
Bulgaria
|
|
-
|
|
|
|
730
|
|
Total oil and natural gas properties, unproved
|
|
12,978
|
|
|
|
15,695
|
|
Gross oil and natural gas properties
|
|
180,926
|
|
|
|
178,701
|
|
Accumulated depletion
|
|
(101,232
|
)
|
|
|
(100,582
|
)
|
Net oil and natural gas properties
|
$
|
79,694
|
|
|
$
|
78,119
|
|
At December 31, 2019 and 2018, we excluded $0.2 million and $0.5 million, respectively, of costs from the depletion calculation for development wells in progress.
At December 31, 2019, the capitalized costs of our oil and natural gas properties included $5.0 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $63.8 million relating to well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.
At December 31, 2018, the capitalized costs of our oil and natural gas properties included $6.5 million relating to acquisition costs of proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $53.4 million relating to well costs and additional development costs, which are being amortized by the unit-of-production method using proved developed reserves.
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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. The factors used to determine fair value include (Level 3 inputs), but are 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 year ended December 31, 2019, we recorded $6.3 million of exploratory dry-hole costs which were primarily measured using Level 3 inputs.
During the year ended December 31, 2018, we recorded $0.3 million of impairment of proved properties and exploratory well costs which were primarily measured using Level 3 inputs.
Capitalized costs greater than one year
As of December 31, 2019 and 2018, there were no capitalized exploratory well costs greater than one year.
Equipment and other property
The historical cost of equipment and other property, presented on a gross basis with accumulated depreciation, is summarized as follows:
|
2019
|
|
|
2018
|
|
|
(in thousands)
|
|
Other equipment
|
$
|
1,121
|
|
|
$
|
1,240
|
|
Land
|
|
132
|
|
|
|
149
|
|
Inventory
|
|
3,209
|
|
|
|
6,791
|
|
Gas gathering system and facilities
|
|
172
|
|
|
|
194
|
|
Vehicles
|
|
304
|
|
|
|
336
|
|
Leasehold improvements, office equipment and software
|
|
5,264
|
|
|
|
5,698
|
|
Gross equipment and other property
|
|
10,202
|
|
|
|
14,408
|
|
Accumulated depreciation
|
|
(5,378
|
)
|
|
|
(5,268
|
)
|
Net equipment and other property
|
$
|
4,824
|
|
|
$
|
9,140
|
|
At December 31, 2019 and 2018, we classified $7.1 million and $5.2 million of inventory, respectively, as a current asset, which represents our expected inventory consumption during the next twelve months. We classify the remainder of 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 December 31, 2019 and 2018, we excluded $10.3 million and $12.0 million of inventory, respectively, from depreciation, as the inventory had not been placed into service.
7. Derivative instruments
We use derivative instruments to manage certain risks related to commodity prices and foreign currency exchange rates. The use of derivative instruments for risk management is covered by operating policies and is closely monitored by our senior management. We do not hold any derivatives for speculative purposes and do not use derivatives with leveraged or complex features. 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.
Commodity price derivatives
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 operations and comprehensive loss under the caption “(Loss) gain on derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of cash flows under the caption “Cash settlement on derivative contracts.”
F-14
At December 31, 2019, we had outstanding commodity derivative contracts with respect to our future crude oil production as set forth in the tables below:
Fair Value of Derivative Instruments as of December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Contracts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
|
|
|
Weighted
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
|
|
|
Average
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum
|
|
|
Maximum
|
|
|
Additional Call
|
|
|
|
|
|
|
|
|
|
Quantity
|
|
|
Price
|
|
|
Price
|
|
|
Ceiling
|
|
|
Estimated Fair
|
|
Type
|
|
Period
|
|
(Bbl/day)
|
|
|
(per Bbl)
|
|
|
(per Bbl)
|
|
|
(per Bbl)
|
|
|
Value of Asset (Liability)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
Three-way collar
|
|
January 1, 2020—April 30, 2020
|
|
|
1,000
|
|
|
$
|
55.00
|
|
|
$
|
72.90
|
|
|
$
|
80.00
|
|
|
$
|
21
|
|
Swap
|
|
January 1, 2020—December 31, 2020
|
|
|
986
|
|
|
$
|
60.30
|
|
|
|
|
|
|
|
|
|
|
|
(987
|
)
|
Total estimated fair value of liability
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
(966
|
)
|
As of December 31, 2018, we had no outstanding derivative contracts with respect to our future crude oil production.
During the years ended December 31, 2019 and 2018, we recorded a net loss on derivative contracts of $1.0 million and $1.8 million, respectively.
On March 9, 2020, we unwound our commodity derivative contracts with respect to our future crude oil production. See Note 17 “Subsequent Events.”
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 December 31, 2019, and (ii) the net recorded fair value as reflected on our consolidated balance sheets at December 31, 2019. At December 31, 2018, we did not have any commodity or foreign exchange derivative contracts.
|
|
|
|
As of December 31, 2019
|
|
|
|
|
|
|
|
|
|
Gross
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount
|
|
|
Net Amount of
|
|
|
|
|
|
Gross
|
|
|
Offset in the
|
|
|
Liabilities
|
|
|
|
|
|
Amount of
|
|
|
Consolidated
|
|
|
Presented in the
|
|
|
|
|
|
Recognized
|
|
|
Balance
|
|
|
Consolidated
|
|
Underlying Commodity
|
|
Location on Balance Sheet
|
|
Liabilities
|
|
|
Sheet
|
|
|
Balance Sheet
|
|
|
|
|
|
(in thousands)
|
|
Crude oil
|
|
Current liabilities
|
|
$
|
987
|
|
|
$
|
(21
|
)
|
|
$
|
966
|
|
F-15
8. Asset retirement obligations
As part of our development of oil and natural gas properties, we incur asset retirement obligations (“ARO”). Our ARO results from our responsibility to abandon and reclaim our net share of all working interest properties and facilities. At December 31, 2019, the net present value of our total ARO was estimated to be $4.7 million, with the undiscounted value being $8.7 million. Total ARO at December 31, 2019 and 2018 shown in the table below consists of amounts for future plugging and abandonment liabilities on our wellbores and facilities based on third-party estimates of such costs, adjusted for inflation at a rate of 8.42% and 12.65% per annum for Turkey for the years ended December 31, 2019 and 2018, respectively. These values are discounted to present value using our credit-adjusted risk-free rate of 7.55% per annum for Turkey for the years ended December 31, 2019 and 2018. The following table summarizes the changes in our ARO for the years ended December 31, 2019 and 2018:
|
2019
|
|
|
2018
|
|
|
(in thousands)
|
|
Asset retirement obligations at beginning of period
|
$
|
4,667
|
|
|
$
|
4,727
|
|
Foreign exchange change effect
|
|
(519
|
)
|
|
|
(1,270
|
)
|
Additions
|
|
388
|
|
|
|
1,036
|
|
Accretion expense
|
|
213
|
|
|
|
174
|
|
Asset retirement obligations at end of period
|
|
4,749
|
|
|
|
4,667
|
|
Long-term portion
|
$
|
4,749
|
|
|
$
|
4,667
|
|
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.
9. Loans payable
As of the dates indicated, our third-party debt consisted of the following:
|
December 31,
|
|
|
December 31,
|
|
|
2019
|
|
|
2018
|
|
Fixed and floating rate loans
|
(in thousands)
|
|
Term Loan (1)
|
$
|
20,000
|
|
|
$
|
22,000
|
|
Loans payable
|
|
20,000
|
|
|
|
22,000
|
|
Less: current portion
|
|
17,143
|
|
|
|
22,000
|
|
Long-term portion
|
$
|
2,857
|
|
|
$
|
–
|
|
_______________________________________________________________________________________________________________
|
(1)
|
Includes 2019, 2018, 2017 and 2016 Term Loans.
|
2016 Term Loan
On August 31, 2016, DenizBank, A.S. (“DenizBank”) entered into a $30.0 million term loan (the “2016 Term Loan”) with TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”) under our general credit agreement with DenizBank (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 bore 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 remained unchanged.
On June 28, 2018, we repaid the 2016 Term Loan in full in accordance with its terms.
2017 Term Loan
On November 17, 2017, DenizBank entered into a $20.4 million term loan (the “2017 Term Loan”) with TEMI under the Credit Agreement.
F-16
The 2017 Term Loan bore 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 had a grace period which bore no interest or payments due until July 2018. Thereafter, the 2017 Term Loan was 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 matured in December 2019.
On December 30, 2019, we repaid the 2017 Term Loan in full in accordance with its terms.
2018 Term Loan
On May 28, 2018, DenizBank entered into a $10.0 million term loan (the “2018 Term Loan”) with TEMI under the Credit Agreement.
The 2018 Term Loan bore interest at a fixed rate of 7.25% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2018 Term Loan had a grace period through July 2018 during which no payments were due. Thereafter, accrued interest on the 2018 Term Loan was payable monthly and the principal on the 2018 Term Loan was payable in five monthly installments of $0.2 million each through December 2018, four monthly installments of $0.5 million each through April 2019, four monthly installments of $1.0 million each through August 2019, and four monthly installments of $0.75 million each through December 2019. The 2018 Term Loan matured in December 2019.
On December 30, 2019, we repaid the 2018 Term Loan in full in accordance with its terms.
2019 Term Loan
On February 22, 2019, DenizBank entered into a $20.0 million term loan (the “2019 Term Loan”) with TEMI under the Credit Agreement.
The 2019 Term Loan bears interest at a fixed rate of 7.5% (plus 0.375% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2019 Term Loan has a grace period through December 2019 during which no payments were due. Thereafter, accrued interest on the 2019 Term Loan is payable monthly, and the principal on the 2019 Term Loan is payable in 14 monthly installments of $1.4 million each. The 2019 Term Loan matures in February 2021. Amounts repaid under the 2019 Term Loan may not be reborrowed, and early repayments under the 2019 Term Loan are subject to early repayment fees. The 2019 Term Loan is guaranteed by Petrogas Petrol Gaz ve Petrokimya Urunleri Insaat Sanayi ve Ticaret A.S. (“Petrogas”), Amity Oil International Pty Ltd (“Amity”), Talon Exploration, Ltd. (“Talon Exploration”), DMLP, Ltd. (“DMLP”), and TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”).
The 2019 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on encumbering or creating restrictions or limitations on all or a part of its assets, revenues, or properties, giving guaranties or sureties, selling assets or transferring revenues, dissolving, liquidating, merging, or consolidating, incurring additional debt, paying dividends, making certain investments, undergoing a change of control, and other similar matters. In addition, the 2019 Term Loan prohibits Amity, Talon Exploration, DMLP, and TransAtlantic Turkey from incurring additional debt. An event of default under the 2019 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 2019 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) certain Gundem real estate and Muratli real estate owned by Gundem Turizm Yatirim ve Isletmeleri A.S. (“Gundem”), (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. 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 2019 Term Loan.
At December 31, 2019, we had $20.0 million outstanding under the 2019 Term Loan and no availability, and we were in compliance with the covenants in the 2019 Term Loan.
During the years ended December 31, 2019 and 2018, we recorded interest expense related to the 2016, 2017, 2018, and 2019 Term Loan of $2.2 million and $1.8 million, respectively.
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 December 31, 2019 and 2018, we had no outstanding borrowings under these lines of credit.
F-17
Loan financing costs
We capitalize certain costs in connection with obtaining our borrowings, such as lender’s fees and related attorney’s fees. These costs are amortized on a straight line basis, which approximates the effective interest method over the term of the loan as a component of interest expense. Amortization of loan financing costs totaled approximately $0.1 million during each of 2019 and 2018.
10. Shareholders’ equity
Share issuances to holders of Series A Preferred Shares
On December 31, 2018, we issued an aggregate of 1,808,001 common shares to holders of the Series A Preferred Shares as payment of the December 31, 2018 quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of $1.0188 per common share, which was equal to the 15-day volume weighted average price through the close of trading of the common shares on the NYSE American exchange on December 14, 2018.
On July 2, 2019, we issued an aggregate of 2,321,568 common shares to holders of the Series A Preferred Shares as payment of the June 30, 2019 quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of $0.7934 per common share, which was equal to the 15-day volume weighted average price through the close of trading of the common shares on the NYSE American exchange on June 14, 2019.
On September 30, 2019, we issued an aggregate of 2,664,164 common shares to holders of the Series A Preferred Shares as payment of the September 30, 2019 quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of $0.6914 per common share, which was equal to the 15-day volume weighted average price through the close of trading of the common shares on the NYSE American exchange on September 13, 2019.
On December 31, 2019, we issued an aggregate of 4,521,360 common shares to holders of the Series A Preferred Shares as payment of the December 31, 2019 quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of $0.4074 per common share, which was equal to the 15-day volume weighted average price through the close of trading of the common shares on the NYSE American exchange on December 13, 2019.
Restricted stock units
Under our 2009 Long-Term Incentive Plan (the “2009 Incentive Plan”) and our 2019 Long-Term Incentive Plan (the “2019 Incentive Plan” and together with the 2009 Incentive Plan, the “Incentive Plans”), we awarded restricted stock units (“RSUs”) and other share-based compensation to certain of our directors, officers, employees and consultants. Each RSU is equal in value to one of our common shares on the grant date. Upon vesting, an award recipient is entitled to a number of common shares equal to the number of vested RSUs. The RSU awards can only be settled in common shares. As a result, RSUs are classified as equity. At the grant date, we make an estimate of the forfeitures expected to occur during the vesting period and record compensation cost, net of the estimated forfeitures, over the requisite service period. The current forfeiture rate is estimated to be 12.5%.
Under the Incentive Plans, RSUs vest over specified periods of time ranging from immediately to four years. RSUs are deemed full value awards and their value is equal to the market price of our common shares on the grant date. ASC 718 requires that the Incentive Plan be approved in order to establish a grant date. Under ASC 718, the approval date for the 2009 Incentive Plan was February 9, 2009 and the approval date for the 2019 Incentive Plan was April 16, 2019, in each case, the date our board of directors approved the Incentive Plans.
Share-based compensation of approximately $0.4 million and $0.5 million with respect to awards of RSUs was recorded for the years ended December 31, 2019 and 2018, respectively. As of December 31, 2019, we had approximately $0.5 million of unrecognized compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 1.1 years. The following table sets forth RSU activity for the year ended December 31, 2019:
|
|
Number of RSUs
(in thousands)
|
|
|
Weighted Average Grant Date Fair Value Per RSU
|
|
Unvested RSUs outstanding at December 31, 2018
|
|
|
454
|
|
|
$
|
1.42
|
|
Granted
|
|
|
767
|
|
|
|
0.77
|
|
Forfeited
|
|
|
(4
|
)
|
|
|
1.29
|
|
Vested
|
|
|
(362
|
)
|
|
|
1.42
|
|
Unvested RSUs outstanding at December 31, 2019
|
|
|
855
|
|
|
$
|
0.84
|
|
F-18
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 years ended December 31, 2019 and 2018 equals net income divided by the weighted average shares outstanding during the periods. Weighted average shares outstanding are equal to the weighted average of all shares outstanding for the period, excluding RSUs. Diluted earnings per common share for the years ended December 31, 2019 and 2018 are computed in the same manner as basic earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents, which includes stock options, RSUs, preferred shares and warrants, whether exercisable or not. The computation of diluted earnings per common share excluded 41.6 million and 42.0 million antidilutive common share equivalents for the years ended December 31, 2019 and 2018, respectively.
The following table presents the basic and diluted earnings per common share computations:
(in thousands, except per share amounts)
|
|
2019
|
|
|
2018
|
|
Net loss
|
|
$
|
(5,366
|
)
|
|
$
|
(5,216
|
)
|
Basic net loss per common share:
|
|
|
|
|
|
|
|
|
Shares:
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding
|
|
|
55,134
|
|
|
|
50,505
|
|
Basic net loss per common share:
|
|
$
|
(0.10
|
)
|
|
$
|
(0.10
|
)
|
Diluted net loss per common share:
|
|
|
|
|
|
|
|
|
Shares:
|
|
|
|
|
|
|
|
|
Weighted average common and common equivalent shares
outstanding
|
|
|
55,134
|
|
|
|
50,505
|
|
Diluted net loss per common share:
|
|
$
|
(0.10
|
)
|
|
$
|
(0.10
|
)
|
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.
11. Income taxes
The income tax provision differs from the amount that would be obtained by applying the Bermuda statutory income tax rate of 0% for 2019 and 2018 to income (loss) from operations as follows:
|
2019
|
|
|
2018
|
|
|
(in thousands except rates)
|
|
Statutory rate
|
|
0.00
|
%
|
|
|
0.00
|
%
|
|
|
|
|
|
|
|
|
Income before income taxes
|
$
|
3,528
|
|
|
$
|
4,458
|
|
Increase (decrease) resulting from:
|
|
|
|
|
|
|
|
Foreign tax rate differentials
|
$
|
4,339
|
|
|
$
|
4,720
|
|
Uncertain tax position
|
|
861
|
|
|
|
935
|
|
Unremitted earnings
|
|
1,387
|
|
|
|
2,927
|
|
Change in valuation allowance
|
|
(3,127
|
)
|
|
|
(4,743
|
)
|
Expiration of non-capital tax loss carryovers
|
|
2,005
|
|
|
|
4,793
|
|
Other
|
|
3,429
|
|
|
|
1,042
|
|
Total
|
$
|
8,894
|
|
|
$
|
9,674
|
|
F-19
The components of the net deferred income tax liability at December 31, 2019 and 2018 were as follows:
|
2019
|
|
|
2018
|
|
|
(in thousands)
|
|
Deferred tax assets
|
|
|
|
|
|
|
|
Property and equipment
|
$
|
299
|
|
|
$
|
609
|
|
Timing of accruals
|
|
593
|
|
|
|
574
|
|
Non-capital loss carryovers
|
|
12,030
|
|
|
|
13,261
|
|
Valuation allowance
|
|
(12,030
|
)
|
|
|
(13,261
|
)
|
Total deferred tax assets
|
$
|
892
|
|
|
$
|
1,183
|
|
Deferred tax liabilities
|
|
|
|
|
|
|
|
Property and equipment
|
$
|
(12,524
|
)
|
|
$
|
(9,728
|
)
|
Unremitted earnings
|
|
(9,690
|
)
|
|
|
(9,401
|
)
|
Timing of accruals
|
|
(1,406
|
)
|
|
|
(2,368
|
)
|
Total deferred tax liabilities
|
|
(23,620
|
)
|
|
|
(21,497
|
)
|
Net deferred tax liabilities
|
$
|
(22,728
|
)
|
|
$
|
(20,314
|
)
|
Components of net deferred tax liabilities
|
|
|
|
|
|
|
|
Non-current assets
|
$
|
892
|
|
|
$
|
1,183
|
|
Non-current liabilities
|
|
(23,620
|
)
|
|
|
(21,497
|
)
|
Net deferred tax liabilities
|
$
|
(22,728
|
)
|
|
$
|
(20,314
|
)
|
We have accumulated losses or resource-related deductions available for income tax purposes in Turkey, Romania, Bulgaria and the United States. As of December 31, 2019, we had (i) non-capital tax losses in Turkey of approximately 7.1 million TRY (approximately $1.2 million), which will begin to expire in 2020; (ii) non-capital tax losses in Romania of approximately 1.6 million Romanian New Leu (approximately $0.4 million), which will begin to expire in 2020; (iii) non-capital losses in Bulgaria of approximately 18.9 million Bulgarian Lev (approximately $10.8 million), which will begin to expire in 2020; and (iv) non-capital tax losses in the United States of approximately $50.6 million, which will begin to expire in 2020. As of December 31, 2019 and 2018, we recorded a valuation allowance of $12.0 million and $13.3 million, respectively, as a reduction to our net operating losses and deferred tax assets.
We file income tax returns in the United States, Turkey, Bulgaria and Cyprus, with Turkey being the only jurisdiction with significant amounts of taxes due. Except for the outstanding examination of the 2011 income tax filings for Petrogas, Turkish income tax filings before 2012 are no longer subject to examination. As the result of 2016 Turkish legislation allowing us the option to enter into an agreement to exempt corporate income tax filings from examination, we were able to close additional years from examination.
As of December 31, 2019 and 2018, we recorded a $6.8 million and $6.7 million liability, respectively, primarily due to uncertain tax positions related to the unwinding of all our crude oil hedge collars and three-way contracts, which are included in long-term accrued liabilities on our consolidated balance sheet. The unrecognized tax benefits at December 31, 2019 and 2018 were as follows:
|
2019
|
|
|
2018
|
|
|
(in thousands)
|
|
Unrecognized tax benefits at beginning of period
|
$
|
6,714
|
|
|
$
|
8,663
|
|
Gross increases - tax positions in prior period
|
|
861
|
|
|
|
935
|
|
Foreign exchange change effect
|
|
(784
|
)
|
|
|
(2,884
|
)
|
Unrecognized tax benefits at end of period
|
$
|
6,791
|
|
|
$
|
6,714
|
|
As of December 31, 2019, there were no material uncertain tax positions for which the total amounts of unrecognized tax benefits will significantly increase or decrease within the next 12 months.
Unremitted earnings
Our foreign subsidiaries generate earnings that are not subject to Turkish dividend withholding taxes so long as they are permanently reinvested in our operations in Turkey. Pursuant to ASC Topic No. 740-30, undistributed earnings of foreign subsidiaries that are no longer permanently reinvested would become subject to Turkish dividend withholding taxes. Prior to fiscal year 2015, we asserted that the undistributed earnings of our foreign Turkish subsidiaries were permanently reinvested.
F-20
Primarily due to our obligation to pay dividends on our Series A Preferred Shares, management concluded that the ability to access certain amounts of foreign earnings would provide greater flexibility to meet corporate cash flow needs without constraining foreign objectives. Accordingly, in the fourth quarter of 2015, we withdrew the permanent reinvestment assertion on 135.2 million TRY of cumulative earnings generated by certain of our Turkish foreign subsidiaries through fiscal year 2015. We provided for Turkish dividend withholding taxes on the 135.2 million TRY of cumulative undistributed foreign Turkish earnings, resulting in the recognition of a deferred tax liability. As of December 31, 2019 and 2018, we provided for Turkish dividend, withholding taxes on 383.7 million and 329.7 million TRY, respectively, of cumulative undistributed foreign Turkish earnings, resulting in an additional increase in our deferred tax liability.
There is no certainty as to the timing of when or if such Turkish foreign earnings will be distributed in whole or in part.
F-21
12. Segment information
In accordance with ASC 280, Segment Reporting (“ASC 280”), we have two reportable geographic segments: Turkey and Bulgaria. Summarized financial information concerning our geographic segments is shown in the following tables:
|
Corporate
|
|
|
Turkey
|
|
|
Bulgaria
|
|
|
Total
|
|
|
|
(in thousands)
|
|
|
For the year ended December 31, 2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
$
|
–
|
|
|
$
|
67,380
|
|
|
$
|
–
|
|
|
$
|
67,380
|
|
|
Production
|
|
–
|
|
|
|
11,513
|
|
|
|
161
|
|
|
|
11,674
|
|
|
Transportation costs
|
|
–
|
|
|
|
5,101
|
|
|
|
–
|
|
|
|
5,101
|
|
|
Exploration, abandonment, and impairment
|
|
–
|
|
|
|
–
|
|
|
|
6,267
|
|
|
|
6,267
|
|
|
Seismic and other exploration
|
|
–
|
|
|
|
330
|
|
|
|
–
|
|
|
|
330
|
|
|
General and administrative
|
|
5,373
|
|
|
|
6,274
|
|
|
|
138
|
|
|
|
11,785
|
|
|
Depreciation, depletion and amortization
|
|
132
|
|
|
|
13,095
|
|
|
|
–
|
|
|
|
13,227
|
|
|
Accretion of asset retirement obligations
|
|
–
|
|
|
|
190
|
|
|
|
23
|
|
|
|
213
|
|
|
Total costs and expenses
|
|
5,505
|
|
|
|
36,503
|
|
|
|
6,589
|
|
|
|
48,597
|
|
|
Operating (loss) income
|
|
(5,505
|
)
|
|
|
30,877
|
|
|
|
(6,589
|
)
|
|
|
18,783
|
|
|
Interest and other expense
|
|
(8,450
|
)
|
|
|
(2,217
|
)
|
|
|
–
|
|
|
|
(10,667
|
)
|
|
Interest and other income
|
|
419
|
|
|
|
528
|
|
|
|
–
|
|
|
|
947
|
|
|
Loss on commodity derivative contracts
|
|
–
|
|
|
|
(966
|
)
|
|
|
–
|
|
|
|
(966
|
)
|
|
Foreign exchange gain (loss)
|
|
117
|
|
|
|
(4,626
|
)
|
|
|
(60
|
)
|
|
|
(4,569
|
)
|
|
(Loss) income before income taxes
|
|
(13,419
|
)
|
|
|
23,596
|
|
|
|
(6,649
|
)
|
|
|
3,528
|
|
|
Income tax expense
|
|
–
|
|
|
|
(8,894
|
)
|
|
|
–
|
|
|
|
(8,894
|
)
|
|
Net loss (income)
|
$
|
(13,419
|
)
|
|
$
|
14,702
|
|
|
$
|
(6,649
|
)
|
|
$
|
(5,366
|
)
|
|
Total assets at December 31, 2019
|
$
|
7,810
|
|
|
$
|
127,986
|
|
|
$
|
708
|
|
|
$
|
136,504
|
|
|
Capital expenditures for the year ended December 31, 2019
|
$
|
–
|
|
|
$
|
25,146
|
|
|
$
|
5,537
|
|
|
$
|
30,683
|
|
|
For the year ended December 31, 2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues
|
$
|
–
|
|
|
$
|
70,789
|
|
|
$
|
–
|
|
|
$
|
70,789
|
|
|
Production
|
|
–
|
|
|
|
10,649
|
|
|
|
120
|
|
|
|
10,769
|
|
|
Transportation costs
|
|
–
|
|
|
|
4,665
|
|
|
|
–
|
|
|
|
4,665
|
|
|
Exploration, abandonment, and impairment
|
|
–
|
|
|
|
401
|
|
|
|
–
|
|
|
|
401
|
|
|
Seismic and other exploration
|
|
–
|
|
|
|
488
|
|
|
|
1
|
|
|
|
489
|
|
|
General and administrative
|
|
9,222
|
|
|
|
5,344
|
|
|
|
153
|
|
|
|
14,719
|
|
|
Depreciation, depletion and amortization
|
|
142
|
|
|
|
13,917
|
|
|
|
–
|
|
|
|
14,059
|
|
|
Accretion of asset retirement obligations
|
|
–
|
|
|
|
151
|
|
|
|
23
|
|
|
|
174
|
|
|
Total costs and expenses
|
|
9,364
|
|
|
|
35,615
|
|
|
|
297
|
|
|
|
45,276
|
|
|
Operating (loss) income
|
|
(9,364
|
)
|
|
|
35,174
|
|
|
|
(297
|
)
|
|
|
25,513
|
|
|
Interest and other expense
|
|
(7,026
|
)
|
|
|
(3,022
|
)
|
|
|
–
|
|
|
|
(10,048
|
)
|
|
Interest and other income
|
|
184
|
|
|
|
897
|
|
|
|
1
|
|
|
|
1,082
|
|
|
Loss on commodity derivative contracts
|
|
–
|
|
|
|
(1,797
|
)
|
|
|
–
|
|
|
|
(1,797
|
)
|
|
Foreign exchange loss
|
|
(351
|
)
|
|
|
(9,932
|
)
|
|
|
(9
|
)
|
|
|
(10,292
|
)
|
|
(Loss) income before income taxes
|
|
(16,557
|
)
|
|
|
21,320
|
|
|
|
(305
|
)
|
|
|
4,458
|
|
|
Income tax expense
|
|
–
|
|
|
|
(9,674
|
)
|
|
|
–
|
|
|
|
(9,674
|
)
|
|
Net (loss) income
|
$
|
(16,557
|
)
|
|
$
|
11,646
|
|
|
$
|
(305
|
)
|
|
$
|
(5,216
|
)
|
|
Total assets at December 31, 2018
|
$
|
8,358
|
|
|
$
|
122,325
|
|
|
$
|
1,917
|
|
|
$
|
132,600
|
|
|
Capital expenditures for the year ended December 31, 2018
|
$
|
–
|
|
|
$
|
23,517
|
|
|
$
|
–
|
|
|
$
|
23,517
|
|
|
13. Financial instruments
Foreign currency risk
We have underlying foreign currency exchange rate exposure. Our currency exposures primarily relate to transactions denominated in the Bulgarian Lev, European Union Euro, and 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 used foreign currency forward and swap contracts to manage exchange rate fluctuations. At December 31, 2019 and 2018, we had 28.6 million TRY and 7.8
F-22
million TRY, respectively (approximately $4.8 million and $1.5 million, respectively) 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.
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.
Fair value measurements
Cash and cash equivalents, receivables, notes receivable, accounts payable and accrued liabilities were each estimated to have a fair value approximating the carrying amount at December 31, 2019 and 2018 due to the short maturity of those instruments.
The financial assets and liabilities measured on a recurring basis at December 31, 2019 consisted of our commodity derivative contracts and the 2019 Term Loan. Fair values for options are based on counterparty market prices. The counterparties use market standard valuation methodologies incorporating market inputs for volatility and risk free interest rates in arriving at a fair value for each option contract. Prices are verified by us using analytical tools. There are no performance obligations related to the collar and swap contracts to hedge our oil production.
We utilize models based on a range of observable market inputs, including pricing models, quoted market prices of publicly traded securities with similar duration and yield, time value, yield curve, prepayment spreads, default rates and discounted cash flow and the values for these contracts are disclosed in Level 2 of the fair value hierarchy to determine the fair value of our commodity derivative contracts. We review prices received from our counterparty for unusual fluctuations to ensure that the prices represent a reasonable estimate of fair value.
The 2019 Term Loan was estimated using a discounted cash flow analysis based on unobservable Level 3 inputs, including our own credit risk associated with the loan payable. At December 31, 2019, the carrying value approximated the fair value for the 2019 Term Loan.
The following table summarizes the valuation of our financial liabilities as of December 31, 2019:
|
Fair Value Measurement Classification
|
|
|
Quoted Prices in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Active Markets for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identical Assets or
|
|
|
Significant Other
|
|
|
Significant
|
|
|
|
|
|
|
Liabilities
|
|
|
Observable Inputs
|
|
|
Unobservable Inputs
|
|
|
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Total
|
|
|
(in thousands)
|
|
Measured on a recurring basis
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity derivative contracts
|
$
|
–
|
|
|
$
|
(966
|
)
|
|
$
|
–
|
|
|
$
|
(966
|
)
|
Disclosed but not carried at fair value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019 Term Loan
|
|
–
|
|
|
|
–
|
|
|
|
(17,333
|
)
|
|
|
(17,333
|
)
|
Total
|
$
|
–
|
|
|
$
|
(966
|
)
|
|
$
|
(17,333
|
)
|
|
$
|
(18,299
|
)
|
At December 31, 2018, the fair value of the 2018 Term Loan and 2017 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. At December 31,
F-23
2018, the carrying value approximated the fair value for the 2018 Term Loan and 2017 Term Loan. The following table summarizes the valuation of our financial liabilities as of December 31, 2018:
|
Fair Value Measurement Classification
|
|
|
Quoted Prices in
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Active Markets for
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identical Assets or
|
|
|
Significant Other
|
|
|
Significant
|
|
|
|
|
|
|
Liabilities
|
|
|
Observable Inputs
|
|
|
Unobservable Inputs
|
|
|
|
|
|
|
(Level 1)
|
|
|
(Level 2)
|
|
|
(Level 3)
|
|
|
Total
|
|
|
(in thousands)
|
|
Disclosed but not carried at fair value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2017 Term Loan
|
|
–
|
|
|
|
–
|
|
|
|
(11,938
|
)
|
|
|
(11,938
|
)
|
2016 Term Loan
|
|
–
|
|
|
|
–
|
|
|
|
(8,192
|
)
|
|
|
(8,192
|
)
|
Total
|
$
|
–
|
|
|
$
|
–
|
|
|
$
|
(20,130
|
)
|
|
$
|
(20,130
|
)
|
14. Leases
Operating and financing leases
We lease office space in Dallas, Texas, Bulgaria, and Turkey. We also lease apartments, vehicles, and operations yards in Turkey. The terms of our lease agreements generally range from one to five years, and some contain options to renew, cancel or purchase. We determine if an arrangement meets the definition of a lease at inception, at which time we also perform an analysis to determine whether the lease qualifies as an operating or financing lease.
Our operating and financing leases are included in other assets and accrued liabilities (current and long-term) on our consolidated balance sheet. Lease expense for our operating leases is recognized in our consolidated statements of operations and comprehensive loss under the caption “General and administrative”. Lease expense for our operating leases for our operations yards in Turkey is recognized in our consolidated statements of operations and comprehensive loss under the caption “Production”.
Lease right-of-use assets and lease liabilities are measured using the present value of future minimum lease payments over the lease term at commencement date. The right-of-use asset also includes any lease payments made on or before the commencement date of the lease, less any lease incentives received. As the rate implicit in the lease is not readily determinable in our leases, we use our incremental borrowing rates based on the information available at the lease commencement date in determining the present value of lease payments.
For leases with an initial non-cancelable lease term of less than one year and no option to purchase, we have elected not to recognize the lease on our consolidated balance sheets and instead recognize lease payments on a straight-line basis over the lease term.
Operating lease costs were comprised of the following:
|
December 31, 2019
|
|
|
(in thousands)
|
|
Operations yards
|
$
|
584
|
|
Office rent
|
|
176
|
|
Vehicles
|
|
128
|
|
Other
|
|
82
|
|
Total lease costs
|
$
|
970
|
|
F-24
Future non-cancelable minimum lease payments under our operating and financing lease commitments as of December 31, 2019 were as follows for each of the next five years and thereafter:
|
December 31, 2019
|
|
|
(in thousands)
|
|
2020
|
$
|
960
|
|
2021
|
|
867
|
|
2022
|
|
867
|
|
2023
|
|
557
|
|
2024
|
|
200
|
|
Thereafter
|
|
-
|
|
Total
|
$
|
3,451
|
|
Less: Imputed interest
|
|
342
|
|
Present value of lease liabilities
|
$
|
3,109
|
|
As of December 31, 2019, the weighted average remaining lease term is 3.5 years, and the weighted average discount rate used was 7.6%.
Future non-cancelable minimum lease payments under our operating lease commitments as of December 31, 2018 were as follows for each of the next five years and thereafter:
|
December 31, 2018
|
|
|
(in thousands)
|
|
2019
|
$
|
963
|
|
2020
|
|
710
|
|
2021
|
|
636
|
|
2022
|
|
626
|
|
2023
|
|
316
|
|
Thereafter
|
|
-
|
|
Total
|
$
|
3,251
|
|
15. Contingencies
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 Bulgarian 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 Minister of Energy filed a suit in the Sofia City Court against Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”), claiming $200,000 in liquidated damages for Direct Bulgaria’s alleged failure to fulfill its obligations under the Aglen exploration permit work program. In May 2018, the Sofia City Court concluded that Direct Bulgaria did not fail to fulfill its obligations under the Aglen exploration permit work program as Direct Bulgaria received a force majeure event recognition as a result of a fracture stimulation ban in 2012, imposed by the Bulgarian Parliament, which force majeure event had not been terminated before the expiry of Direct Bulgaria’s obligations under the Aglen exploration permit work program. Additionally, the Sofia City Court concluded that, even if Direct Bulgaria had failed to fulfill its obligations under the Aglen exploration permit work program, the Bulgarian Minister of Energy failed to file suit within the three-year limitation period. Therefore, the Sofia City Court dismissed all claims of the Bulgarian Minister of Energy and ordered the Bulgarian Minister of Energy to pay Direct Bulgaria’s attorney’s fees and legal costs for court experts. In June 2018, the Bulgarian Minister of Energy filed an appeal in the Sofia Court of Appeal. In
F-25
November 2018, the Sofia Court of Appeal concluded that the judgement of the Sofia City Court was correct and, therefore, dismissed the Bulgarian Minister of Energy’s appeal. In January 2019, the Bulgarian Minister of Energy filed an appeal in the Supreme Court of Cassation. The Supreme Court of Cassation held a court hearing on October 21, 2019. Pursuant to a notice on the website of the Supreme Court of Cassation, a ruling was issued on March 10, 2020, by virtue of which the court rejected to admit the appeal of the Minster of Energy. Such ruling should be final; however, it has not been published as of the date hereof, and therefore, we cannot conclusively confirm the ruling.
As a result of the judgement of the Sofia Court of Appeal, we are currently evaluating an adjustment to our contingencies relating to production leases and exploration permits.
TUPRAS
We sell all of our Southeastern Turkey oil to TUPRAS pursuant to a domestic crude oil purchase and sale agreement between TUPRAS and TEMI. The price of the oil delivered pursuant to the purchase and sale agreement is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. In February 2019, Turkey entered into the Pricing Amendment to change the statutory pricing formula for purchases of Turkish domestic crude oil.
In November 2019, TUPRAS filed a lawsuit against us, and filed similar lawsuits against other domestic oil producers, in the Batman 4th Civil Court of First Instance seeking restitution from TEMI for alleged overpayments resulting from the implementation of the Pricing Amendment plus interest thereon. In addition, TUPRAS claimed that the Pricing Amendment violates the Constitution of the Republic of Turkey and seeks to have the Pricing Amendment cancelled. TEMI is vigorously defending against these allegations. Any adjustment arising out of the claims will be recorded when it becomes probable and measurable.
16. Related party transactions
Series A Preferred Shares transactions
On November 4, 2016, we issued 921,000 Series A Preferred Shares. Of the 921,000 Series A Preferred Shares, (i) 815,000 shares were issued in exchange for $40.75 million of our 13.0% Senior Convertible Notes due 2017 (the “2017 Notes”), at an exchange rate of 20 Series A Preferred Shares for each $1,000 principal amount of 2017 Notes (the “Exchange Offer”), and (ii) 106,000 shares were issued and sold for $5.3 million of cash to certain holders of the 2017 Notes (the “Offering”). In the Exchange Offer, Pinon Foundation, a non-profit charitable organization directed by Mr. Mitchell’s spouse exchanged $10.0 million of the 2017 Notes for 200,000 Series A Preferred Shares; Dalea exchanged $2.1 million of the 2017 Notes for 41,000 Series A Preferred Shares; and trusts benefitting Mr. Mitchell’s four adult children each exchanged $2.0 million of the 2017 Notes for 40,000 Series A Preferred Shares. In the Offering, the Pinon Foundation purchased 5,000 Series A Preferred Shares for $250,000; and each of Mr. Mitchell’s four adult children purchased 1,000 Series A Preferred Shares for $50,000. Pinon Foundation subsequently sold its Series A Preferred Shares to Longfellow Energy, LP (“Longfellow”), an entity controlled by Mr. Mitchell. Additionally, in December 2019, Longfellow acquired 328,000 additional Series A Preferred Shares in private transactions. For more information see Note 5 “Series A Preferred Shares”.
Equity transactions
On December 31, 2014, April 24, 2015 and August 13, 2015, we issued 134,169, 134,168 and 134,168 Warrants, respectively, to Mr. Mitchell and 23,333, 23,333 and 23,333 Warrants, respectively, to each of Mr. Mitchell’s children, as shareholders of Gundem, as consideration for the pledge of Turkish real estate in exchange for an extension of the maturity date 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 issued in December 2014, April 2015 and August 2015 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.
On December 5, 2016, Randy Rochman, chief executive officer of West Family Investments, and Jonathon Fite, co-owner of the general partner of KMF Investment Partners, LP, were appointed to our board of directors. Randy Rochman and KMF Investment Partners, LP held, and currently hold, 15,000 and 69,000 Series A Preferred Shares, respectively. On March 31, 2017, these 84,000 shares ($4.2 million in liquidation value) were re-classified to related party.
On December 31, 2018, we issued an aggregate of 1,808,001 common shares to holders of the Series A Preferred Shares as payment of the December 31, 2018 quarterly dividend on the Series A Preferred Shares (see Note 10 “Shareholder’s Equity”). Of the 1,808,001 common shares, 971,724 common shares were issued to Dalea, the trusts of Mr. Mitchell’s four children, Longfellow Energy, an entity controlled by Mr. Mitchell, KMF Investment Partners, LP, and Randy Rochman.
F-26
For the year ended December 31, 2019, we issued 9,507,092 common shares as dividends on the Series A Preferred Shares as payment of the June 30, 2019, September 30, 2019, and the December 31, 2019 quarterly dividends. Of the 9,507,092 common shares, 6,710,071 common shares were issued to Dalea, the trusts of Mr. Mitchell’s four children, Longfellow Energy, an entity controlled by Mr. Mitchell, KMF Investment Partners, LP, and Randy Rochman.
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, 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 $8.0 million in exchange for the cancellation of an account payable of approximately $3.5 million (the “Account Payable”) owed by TransAtlantic Albania Ltd. (“TransAtlantic Albania”), our former subsidiary, to Viking International Limited (“Viking International”). 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 former subsidiaries, Viking International and Viking Geophysical Services Ltd. (“Viking Geophysical”) 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 B.V., the beneficial owner of Viking International, VOS and Viking Geophysical (“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 Master Services Agreement, dated March 3, 2016, by and between Production Solutions International Petrol Arama Hizmetleri Anomin Sirketi (“PSI”), an affiliate of Mr. Mitchell, and TEMI (the “PSI MSA”). PSI 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 PSI to less than 50%; (ii) the sale or transfer by Dalea or PSI of all or substantially all of its assets to any person (a “Transferee”) that does not own a controlling interest in Dalea or PSI 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 PSI; (iv) termination of the PSI MSA other than as a result of an uncured default thereunder by TEMI; (v) default by PSI under the PSI MSA, which default is not remedied within a period of 30 days after notice thereof to PSI; and (vi) insolvency or bankruptcy of PSI. 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. During 2019 and 2018, we recorded $0.1 million and $0.2 million, respectively, in interest income on the Amended Note.
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 the 2017 Notes for 40,000 Series A Preferred Shares.
On February 28, 2019, we and Dalea entered into an amendment (the “Note Amendment”) to the Amended Note (as amended by the Note Amendment, the “Note”), pursuant to which we and Dalea agreed to extend the maturity date of the Note to February 26, 2021 (unless otherwise accelerated in accordance with the terms of the Note).
On June 28, 2019, we and Dalea entered into an amendment to the Pledge Agreement, pursuant to which we and Dalea agreed that any interest payable on the Series A Preferred Shares held by Dalea and pledged under the Pledge Agreement (i) if paid in cash, will be credited first against the outstanding principal of the Note, and upon full repayment of the outstanding principal balance of the Note, any accrued and unpaid interest on the Note, and (ii) if paid other than in cash, will be paid to Dalea and, within five business days of such payment to Dalea, Dalea will pay $61,500 toward the principal and, upon full repayment of the outstanding principal of the Note, any accrued and unpaid interest on the Note.
During 2019, we reduced the principal amount of the Note by $1.0 million for amounts repaid by Dalea on February 28, 2019 in conjunction with the Note Amendment and by $0.2 million as a result of dividends paid on the Series A Preferred Shares.
F-27
As of December 31, 2019 and 2018, the amount receivable under the Amended Note was $4.0 million and $5.8 million, respectively.
Pledge fee agreements
In connection with the pledge of the Gundem real estate and Muratli real estate to DenizBank as collateral for certain loans, 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 certain Diyarbakir real estate to DenizBank as collateral for certain loans, 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 Messrs. Mitchell and Uras a fee of 5% per annum of the collateral value of the Diyarbakir real estate. Pursuant to the Diyarbakir Fee Agreement, the Diyarbakir real estate has a deemed collateral value of $5.0 million.
In connection with the pledge of certain Ankara real estate to DenizBank as collateral for certain loans, on November 28, 2017, we entered into a pledge fee agreement with Mr. Uras (the “Uras Fee Agreement”) pursuant to which we pay Mr. Uras a fee of 5% per annum of the collateral value of the Ankara real estate. Pursuant to the Uras Fee Agreement, the Ankara real estate has a deemed collateral value of $5.2 million.
Amounts payable to Mr. Mitchell under the Gundem Fee Agreement and the Diyarbakir Fee Agreement will be used to reduce the outstanding principal amount of the Amended Note. During the years ended December 31, 2019 and 2018, we reduced the principal amount of the Amended Note by $0.6 million for amounts earned by Mr. Mitchell under the Gundem Fee Agreement and the Diyarbakir Fee Agreement.
Leases
On August 7, 2018 and effective as of June 14, 2018, our wholly owned subsidiary, TransAtlantic USA, entered into a sublease agreement (the “Sublease”) with Longfellow to lease corporate office space located at 16803 North Dallas Parkway, Addison, Texas. TransAtlantic USA subleases approximately 10,000 square feet of corporate office space in Addison, Texas. The initial lease term under the Sublease commenced on June 14, 2018 (the “Commencement Date”) and expires on June 30, 2020, unless earlier terminated in accordance with the Sublease. From the Commencement Date until June 30, 2019, TransAtlantic USA is required to pay monthly rent of $18,333.33 to Longfellow, plus utilities, real property taxes, and liability insurance (to the extent that TransAtlantic USA does not obtain its own liability insurance). The monthly rent increases by $416.67 for the period commencing June 30, 2019 and ending June 30, 2021.
Pursuant to the Sublease, effective as of June 14, 2018, TransAtlantic USA and Longfellow agreed to terminate the Amended and Restated Office Lease, dated June 26, 2017, by and between TransAtlantic USA and Longfellow.
On July 1, 2018, our wholly owned subsidiary, TransAtlantic Turkey, entered into a yard lease agreement (the “Gundem Yard Lease”) with Gundem to lease four parcels of land located at Muratli – Ballihoca Degirmenyolu, Tekirdag in the Republic of Turkey. TransAtlantic Turkey is permitted to use the land for storage, maintenance, and staging of materials and equipment. The lease term under the Gundem Yard Lease commenced on July 1, 2018 and expires on June 30, 2023, unless earlier terminated in accordance with the Gundem Yard Lease. From July 1, 2018 to December 31, 2018, TransAtlantic Turkey is required to pay monthly rent of $8,500.00; from January 1, 2019 to December 31, 2019, TransAtlantic Turkey is required to pay monthly rent of $8,755.00; from January 1, 2020 to December 31, 2020, TransAtlantic Turkey is required to pay monthly rent of $9,017.00; from January 1, 2021 to December 31, 2021, TransAtlantic Turkey is required to pay monthly rent of $9,288.00; from January 1, 2022 to December 31, 2022, TransAtlantic Turkey is required to pay monthly rent of $9,566.00; and from January 1, 2023 to June 30, 2023, TransAtlantic Turkey is required to pay monthly rent of $9,853.00.
On January 1, 2019, our wholly owned subsidiary, TEMI, entered into a yard lease agreement (the “Diyarbakir Yard Lease”) with Mr. Uras to lease six parcels of land located at Diyarbakir in the Republic of Turkey. TransAtlantic Turkey is permitted to use the land for storage, maintenance, and staging of materials and equipment. The lease term under the Diyarbakir Yard Lease commenced on January 1, 2018 and expires on June 30, 2023, unless earlier terminated in accordance with the Diyarbakir Yard Lease. From January 1, 2019 to December 31, 2019, TransAtlantic Turkey is required to pay monthly rent of $40,000.00; from January 1, 2020 to December 31, 2020, TransAtlantic Turkey is required to pay monthly rent of $41,000.00; from January 1, 2021 to December 31, 2021, TransAtlantic Turkey is required to pay monthly rent of $42,025.00; from January 1, 2022 to December 31, 2022, TransAtlantic
F-28
Turkey is required to pay monthly rent of $43,076.00; and from January 1, 2023 to June 30, 2023, TransAtlantic Turkey is required to pay monthly rent of $44,153.00.
Service transactions
We are a party to a Service Agreement (as amended, the “Service Agreement”) with Longfellow, Viking Drilling LLC, Riata Management, LLC, MedOil Supply, LLC, LFN Holdco, LLC, Red Rock Minerals, LP, Red Rock Minerals II, LP, Red Rock Advisors, LLC, Production Solutions International Limited, NexLube Operating, LLC, and their subsidiaries (collectively, the “Riata Entities”), under which we and the Riata Entities agreed to provide technical and administrative services to each other from time to time on an as-needed basis. Under the terms of the Service Agreement, the Riata Entities agree to provide us upon our request certain computer services, payroll and benefits services, insurance administration services, and entertainment services, and we and the Riata Entities agree 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, we pay, or are paid, for the actual cost of the Services rendered plus the actual cost of reasonable expenses on a monthly basis. We or any Riata Entity may terminate the Service Agreement at any time by providing advance notice of termination to the other parties.
On June 13, 2012, we entered into separate master services agreements with each of Viking International, Viking Petrol Sahasi Hizmetleri AS (“VOS”) and Viking Geophysical in connection with the sale of our oilfield services business to a joint venture owned by Dalea and funds managed by Abraaj Investment Management Limited. Pursuant to the master services agreements with Viking International and VOS, we are entitled to receive certain oilfield services and materials, including, but not limited to, drilling rigs and fracture stimulation that are needed for our operations in Bulgaria and Turkey. Pursuant to the master services agreement with Viking Geophysical, we are also entitled to receive geophysical services and materials that are needed for our operations in those countries. Each master services agreement is for a five-year term, with automatic one-year extensions absent notice of termination from either party. Currently, we can contract for services and materials on a firm basis and, to the extent that we do not contract for all of their services or materials, Viking International, VOS and Viking Geophysical are allowed to contract with third parties for any remaining capacity.
On March 3, 2016, Mr. Mitchell closed a transaction whereby he sold his interest in Viking Services 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 is owned and operated by PSI. PSI is beneficially owned by Dalea Investment Group, LLC, which is controlled by Mr. Mitchell. Consequently, on March 3, 2016, TEMI entered into the PSI MSA on substantially similar terms to our prior master services agreements with Viking International, VOS and VGS. Pursuant to the PSI MSA, PSI will perform services on behalf of TEMI and its affiliates. On February 28, 2019, TEMI and PSI entered into an amendment (the “PSI MSA Amendment”) to the PSI MSA, pursuant to which PSI and TEMI agreed to extend the primary term of the PSI MSA to February 26, 2021, with automatic successive renewal terms of one (1) year each, unless terminated by PSI or TEMI by written notice at least sixty (60) days prior to the end of the primary term or any successive renewal term. The master services agreements with each of Viking International, VOS and Viking Geophysical currently remain in effect.
For the years ended December 31, 2019 and 2018, we incurred capital and operating expenditures of $10.5 million and $10.6 million, respectively, related to our various related party agreements.
The following table summarizes related party accounts receivable and accounts payable as of December 31, 2019 and December 31, 2018:
|
2019
|
|
|
2018
|
|
|
(in thousands)
|
|
Related party accounts receivable:
|
|
|
|
|
|
|
|
Service Agreement
|
$
|
433
|
|
|
$
|
526
|
|
PSIL MSA
|
|
128
|
|
|
|
352
|
|
Total related party accounts receivable
|
$
|
561
|
|
|
$
|
878
|
|
Related party accounts payable:
|
|
|
|
|
|
|
|
Service Agreement
|
$
|
204
|
|
|
$
|
372
|
|
PSIL MSA
|
|
3,959
|
|
|
|
2,439
|
|
Board of Directors
|
|
99
|
|
|
|
111
|
|
Total related party accounts payable
|
$
|
4,262
|
|
|
$
|
2,922
|
|
F-29
17. Subsequent events
On February 24, 2020, we sold the shares in our wholly-owned subsidiary Petrogas, which held the Edirne, Dogu Adatepe, Adatepe, and Gocerler production leases (the “Petrogas Leases”) and 14 employees, to Reform Ham Petrol Dogal Gaz Arama Uretim Sanayi ve Ticaret A.S. (“Reform”) in exchange for $1.5 million and a release of all plugging and abandonment obligations for 65 wells on the Petrogas Leases and certain former leases. During 2019, average production for the Petrogas Leases was approximately 500 Mcf/d or 83 Boepd.
On March 9, 2020, we unwound our three-way collar contract with DenizBank, which hedged approximately 1,000 Bbl/d of our oil production in Turkey. The three-way collar contract had a Brent floor of $55.00, a Brent ceiling of $72.90, and a Brent long call of $80.00, and was in place through April 30, 2020. We also unwound our swap contract with Denizbank, which hedged approximately 1,000 Bbl/d of our oil production in Turkey. The swap contract had a Brent strike price of $60.30 and was in place through December 31, 2020. In connection with these transactions, we will receive approximately $6.5 million. We used these proceeds to pay down the 2019 Term Loan (as defined below), which left approximately $10.6 million outstanding under the 2019 Term Loan. Following these transactions, we do not have any commodity derivative contracts that hedge our oil price risk.
F-30
TRANSATLANTIC PETROLEUM LTD.
Supplemental Information
(unaudited)
Supplemental quarterly financial data (unaudited)
The following table summarizes results for each of the four quarters in the years ended December 31, 2019 and 2018.
|
Three Months Ended (1)
|
|
|
March 31,
|
|
|
June 30,
|
|
|
September 30,
|
|
|
December 31,
|
|
|
(in thousands, except per share data)
|
|
For the year ended December 31, 2019:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
19,041
|
|
|
$
|
17,215
|
|
|
$
|
14,653
|
|
|
$
|
16,471
|
|
Net (loss) income
|
|
(3,902
|
)
|
|
|
(9
|
)
|
|
|
1,070
|
|
|
|
(2,525
|
)
|
Comprehensive (loss) income
|
|
(8,128
|
)
|
|
|
(425
|
)
|
|
|
1,878
|
|
|
|
(4,017
|
)
|
Basic and diluted net (loss) income per common share
|
$
|
(0.07
|
)
|
|
$
|
(0.00
|
)
|
|
$
|
0.02
|
|
|
$
|
(0.04
|
)
|
For the year ended December 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues
|
$
|
16,926
|
|
|
$
|
18,198
|
|
|
$
|
20,140
|
|
|
$
|
15,525
|
|
Net loss
|
|
(1,775
|
)
|
|
|
(1,006
|
)
|
|
|
(1,720
|
)
|
|
|
(715
|
)
|
Comprehensive (loss) income
|
|
(4,118
|
)
|
|
|
(10,115
|
)
|
|
|
(13,485
|
)
|
|
|
5,247
|
|
Basic and diluted net loss per common share
|
$
|
(0.04
|
)
|
|
$
|
(0.02
|
)
|
|
$
|
(0.03
|
)
|
|
$
|
(0.01
|
)
|
|
(1)
|
The sum of the individual quarterly net (loss) income amounts per share may not agree with full year net (loss) income per share as each quarterly computation is based on the net income or loss for that quarter and the weighted-average number of shares outstanding during that quarter.
|
Supplemental oil and natural gas reserves information (unaudited)
As required by the FASB and the SEC, the standardized measure of discounted future net cash flows (the “Standardized Measure”) presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10% to proved reserves. We do not believe the Standardized Measure provides a reliable estimate of our expected future cash flows to be obtained from the development and production of our oil and natural gas properties or of the value of our proved oil and natural gas reserves. The Standardized Measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year-to-year as prices change.
Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure reserves estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. We engaged DeGolyer & MacNaughton to prepare our reserves estimates in Turkey and Bulgaria.
The following unaudited schedules are presented in accordance with required disclosures about oil and natural gas producing activities to provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies.
All of our proved reserves are located in Turkey and all prices are held constant in accordance with SEC rules.
F-31
Oil and natural gas prices used to estimate reserves were computed by applying the volume-weighted, arithmetic average of the closing price on the first day of each month for the 12-month period prior to December 2019 and 2018. The oil and natural gas prices used to estimate reserves are shown in the table below.
|
12-Month
|
|
|
Average Price
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
per (Bbl)
|
|
|
per (Mcf)
|
|
Turkey
|
|
|
|
|
|
|
|
2019
|
$
|
58.79
|
|
|
$
|
5.29
|
|
2018
|
$
|
64.91
|
|
|
$
|
4.82
|
|
The following table sets forth our estimated net proved reserves, including changes therein, and proved developed reserves:
Disclosure of reserves quantities
|
Turkey
|
|
|
Oil (Mbbls)
|
|
Total proved reserves
|
|
|
|
December 31, 2017
|
|
14,783
|
|
Revisions of previous estimates
|
|
(5,872
|
)
|
Sale of reserves
|
|
2,085
|
|
Sales volumes
|
|
(1,020
|
)
|
December 31, 2018
|
|
9,976
|
|
Revisions of previous estimates
|
|
229
|
|
Extensions and discoveries
|
|
1,059
|
|
Sales volumes
|
|
(1,005
|
)
|
December 31, 2019
|
|
10,259
|
|
Proved developed reserves
|
|
|
|
December 31, 2018:
|
|
|
|
Proved developed producing
|
|
4,575
|
|
Proved developed non-producing
|
|
472
|
|
Total
|
|
5,047
|
|
December 31, 2019:
|
|
|
|
Proved developed producing
|
|
4,651
|
|
Proved developed non-producing
|
|
973
|
|
Total
|
|
5,624
|
|
Proved undeveloped reserves
|
|
|
|
|
|
|
|
As of December 31, 2018
|
|
4,929
|
|
As of December 31, 2019
|
|
4,635
|
|
F-32
|
Turkey
|
|
|
Gas (Mmcf)
|
|
Total proved reserves
|
|
|
|
December 31, 2017
|
|
4,158
|
|
Revisions of previous estimates
|
|
(1,506
|
)
|
Sales volumes
|
|
(212
|
)
|
December 31, 2018
|
|
2,440
|
|
Revisions of previous estimates
|
|
224
|
|
Sales volumes
|
|
(198
|
)
|
December 31, 2019:
|
|
2,466
|
|
|
|
|
|
Proved developed reserves
|
|
|
|
December 31, 2018:
|
|
|
|
Proved developed producing
|
|
424
|
|
Proved developed non-producing
|
|
1,833
|
|
Total
|
|
2,257
|
|
December 31, 2019:
|
|
|
|
Proved developed producing
|
|
456
|
|
Proved developed non-producing
|
|
1,825
|
|
Total
|
|
2,281
|
|
Proved undeveloped reserves
|
|
|
|
As of December 31, 2018
|
|
184
|
|
As of December 31, 2019
|
|
185
|
|
Proved Reserves
Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes, and other factors. See “Oil and Natural Gas Reserves under U.S. Law.”
At December 31, 2019, our estimated proved reserves were 10,670 Mboe, an increase of 287 Mboe, or 2.8%, compared to 10,383 Mboe at December 31, 2018. This increase was primarily attributable to the discovery of productive pay in the Beloka formation in the Yeniev field of 1,059 Mboe. This was partially offset by 1,038 Mboe for volumes sold.
Proved Undeveloped Reserves
At December 31, 2019, our estimated proved undeveloped reserves were 4,666 Mboe, a decrease of 294 Mboe, or 6%, compared to 4,960 Mboe at December 31, 2018. The decrease in proved undeveloped reserves was primarily attributable to revisions of previously estimated recoveries in the Yeniev, Bahar and Selmo oil fields. This decrease was partially offset by a 1,059 Mboe increase in proved undeveloped reserves due to the discovery of productive pay in the Beloka formation in the Yeniev oil field. All of our proved undeveloped reserves as of December 31, 2019 will be developed within five years of the date the reserve was first disclosed as a proved undeveloped reserve. The estimated undiscounted capital costs associated with our proved undeveloped reserves in Turkey is $54.9 million.
The proved undeveloped reserves assume development costs will be funded from future cash flows from operations and financing activities, which may not be sufficient or available at commercially economic terms and could impact the timing of these development activities.
F-33
Standardized measure of discounted future net cash flows
The Standardized Measure relating to estimated proved reserves as of December 31, 2019 and 2018 are shown in the table below. In our calculation of Standardized Measure, we have utilized statutory tax rate of 22% for Turkey. DeGolyer and MacNaughton did not estimate the Standardized Measure or future income tax expense.
|
Total
|
|
|
(in thousands)
|
|
As of and for the year ended December 31, 2019
|
|
|
|
Future cash inflows
|
$
|
616,259
|
|
Future production costs
|
|
(126,960
|
)
|
Future development costs
|
|
(56,168
|
)
|
Future income tax expense
|
|
(76,762
|
)
|
Future net cash flows
|
|
356,369
|
|
10% annual discount for estimated timing of cash flows
|
|
(121,901
|
)
|
Standardized measure of discounted future net cash flows
related to proved reserves
|
$
|
234,468
|
|
As of and for the year ended December 31, 2018
|
|
|
|
Future cash inflows
|
$
|
659,435
|
|
Future production costs
|
|
(122,767
|
)
|
Future development costs
|
|
(56,893
|
)
|
Future income tax expense
|
|
(77,533
|
)
|
Future net cash flows
|
|
402,242
|
|
10% annual discount for estimated timing of cash flows
|
|
(136,085
|
)
|
Standardized measure of discounted future net cash flows
related to proved reserves
|
$
|
266,157
|
|
F-34
Changes in the standardized measure of discounted future net cash flows
The following are the principal sources of changes in the Standardized Measure applicable to proved oil and natural gas reserves for the years ended December 31, 2019 and 2018.
|
Total
|
|
|
(in thousands)
|
|
For the year ended December 31, 2019
|
|
|
|
Standardized measure, January 1,
|
$
|
266,157
|
|
Net change in sales and transfer prices and in production (lifting)
costs related to future production
|
|
(45,944
|
)
|
Changes in future estimated development costs
|
|
(20,593
|
)
|
Sales and transfers of oil and natural gas during the period
|
|
(55,155
|
)
|
Net change due to extensions and discoveries
|
|
-
|
|
Net change due to revisions in quantity estimates
|
|
40,476
|
|
Previously estimated development costs incurred during the period
|
|
25,146
|
|
Accretion of discount
|
|
31,066
|
|
Other
|
|
(7,335
|
)
|
Net change in income taxes
|
|
650
|
|
Standardized measure, December 31,
|
$
|
234,468
|
|
For the year ended December 31, 2018
|
|
|
|
Standardized measure, January 1,
|
$
|
227,133
|
|
Net change in sales and transfer prices and in production (lifting)
costs related to future production
|
|
139,915
|
|
Changes in future estimated development costs
|
|
55,559
|
|
Sales and transfers of oil and natural gas during the period
|
|
(58,797
|
)
|
Net change due to sales of reserves
|
|
72,036
|
|
Net change due to revisions in quantity estimates
|
|
(211,509
|
)
|
Previously estimated development costs incurred during the period
|
|
23,285
|
|
Accretion of discount
|
|
27,955
|
|
Other
|
|
6,033
|
|
Net change in income taxes
|
|
(15,453
|
)
|
Standardized measure, December 31,
|
$
|
266,157
|
|
Costs incurred in oil and natural gas property acquisition, exploration and development
Costs incurred in oil and natural gas property acquisition, exploration and development activities for the years ended December 31, 2019 and 2018 are summarized as follows:
|
Total
|
|
|
(in thousands)
|
|
For the year ended December 31, 2019
|
|
|
|
Exploration
|
$
|
10,127
|
|
Development
|
|
20,556
|
|
Total costs incurred
|
$
|
30,683
|
|
For the year ended December 31, 2018
|
|
|
|
Exploration
|
$
|
12,001
|
|
Development
|
|
11,516
|
|
Total costs incurred
|
$
|
23,517
|
|
F-35