10-K

t

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-34574

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

Bermuda	None
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
16803 Dallas Parkway Addison, Texas	75001
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (214) 220-4323

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Ticker Symbol	Name of each exchange on which registered
Common shares, par value $0.10	TAT	NYSE American

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ☐    No  ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ☐    No  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

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

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☒
Emerging growth company	☐

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

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

The aggregate market value of common shares, par value $0.10 per share, held by non-affiliates of the registrant, based on the last sale price of the common shares on June 30, 2019 (the last business day of the registrant’s most recently completed second fiscal quarter), was approximately $17.0 million. For purposes of this computation, all officers, directors and 10% beneficial owners of the registrant are deemed to be affiliates. Such determination should not be deemed an admission that such officers, directors or 10% beneficial owners are, in fact, affiliates of the registrant.

As of March 20, 2020, there were 62,349,063 common shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2020 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates.

TRANSATLANTIC PETROLEUM LTD.

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2019

INDEX

		Page
PART I
Item 1.	Business	1
Item 1A.	Risk Factors	10
Item 1B.	Unresolved Staff Comments	21
Item 2.	Properties	22
Item 3.	Legal Proceedings	34
Item 4.	Mine Safety Disclosures	36
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	37
Item 6.	Selected Financial Data	37
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk.	48
Item 8.	Financial Statements and Supplementary Data	48
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	48
Item 9A.	Controls and Procedures	48
Item 9B.	Other Information	49
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	50
Item 11.	Executive Compensation	50
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	50
Item 13.	Certain Relationships and Related Transactions, and Director Independence	50
Item 14.	Principal Accountant Fees and Services	50
PART IV
Item 15.	Exhibits and Financial Statement Schedules	51

Forward-Looking Statements

Certain statements in this Annual Report on Form 10-K constitute “forward-looking statements” within the meaning of applicable U.S. and Canadian securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as “plans,” “expects,” “estimates,” “budgets,” “intends,” “anticipates,” “believes,” “projects,” “indicates,” “targets,” “objective,” “could,” “should,” “may,” or other similar words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity, and achievements to differ materially from those expressed or implied by such statements, including the factors discussed under Item 1A. Risk Factors in this Annual Report on Form 10-K. Such factors include, but are not limited to, the following: our ability to access sufficient capital to fund our operations, pay our debt and accounts payable when due and continue as a going concern; fluctuations in and volatility of the market prices for oil and natural gas products; the ability to produce and transport oil and natural gas; the results of exploration and development drilling and related activities; global economic conditions, particularly in the countries in which we carry on business, especially economic slowdowns; actions by governmental authorities including increases in taxes, legislative and regulatory initiatives related to fracture stimulation activities, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including sanctions, armed conflicts, and actions by insurgent groups; the negotiation and closing of material contracts or sale of assets; future capital requirements and the availability of financing; risks associated with drilling, operating and decommissioning wells; actions of third-party co-owners of interests in properties in which we also own an interest; and the other factors discussed in other documents that we file with or furnish to the U.S. Securities and Exchange Commission (the “SEC”) and Canadian securities regulatory authorities. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors and our course of action would depend upon our assessment of the future, considering all information then available. In that regard, any statements as to: future oil or natural gas production levels; capital expenditures; asset sales; the allocation of capital expenditures to exploration and development activities; sources of funding for our capital expenditure programs or operations; drilling of new wells; demand for oil and natural gas products; expenditures and allowances relating to environmental matters; dates by which certain areas will be developed or will come on-stream; expected finding and development costs; future production rates; ultimate recoverability of reserves, including the ability to convert probable and possible reserves to proved reserves; dates by which transactions are expected to close; future cash flows, uses of cash flows, collectability of receivables and availability of trade credit; expected operating costs; changes in any of the foregoing; and other statements using forward-looking terminology are forward-looking statements, and there can be no assurance that the expectations conveyed by such forward-looking statements will, in fact, be realized.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.

Readers should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements, except as required by law.

Glossary of Selected Oil and Natural Gas Terms

The following are abbreviations and definitions of terms commonly used in the oil and natural gas industry and this Annual Report on Form 10-K.

2D seismic. Geophysical data that depict the subsurface strata in two dimensions.

3D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2D seismic.

Appraisal wells. Wells drilled to convert an area or sub-region from the resource to the reserves category.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bbl/d. Barrels of oil per day.

i

Bcf. One billion cubic feet of natural gas.

Boe. Barrels of oil equivalent. Boe is not included in the DeGolyer and MacNaughton reserves report and is derived by us by converting natural gas to oil in the ratio of six Mcf of natural gas to one Bbl of oil. The conversion factor is the current convention used by many oil and natural gas companies. Boe may be misleading, particularly if used in isolation. A Boe conversion ratio of six Mcf to one Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

Boepd. Barrels of oil equivalent per day.

Commercial well; commercially productive well. An oil and natural gas well which produces oil and natural gas in sufficient quantities such that proceeds from the sale of such production exceed royalties, production expenses, and taxes.

Completion. The communication of the formation to the well bore, which may include installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage. The number of acres which are allocated to a production license or assignable to producing wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Directional drilling. The technique of drilling a well while varying the angle of direction of a well and changing the direction of a well to hit a specific target.

Dry hole; dry well. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Exploitation. The continuing development of a known producing formation in a previously discovered field, including efforts to maximize the ultimate recovery of oil or natural gas from the field by development wells, secondary recovery equipment, or other suitable processes and technology.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field or not in an area previously found to be productive of oil or natural gas in another reservoir. Generally, an exploratory well is any well that is not a development well.

Farm-in or farm-out. An agreement to assign an interest in a drilling location and related acreage conditional upon the drilling of a well on that location, the completion of other work commitments related to that acreage, or some combination thereof.

Formation. A geological stratum identifiable by distinct age or composition that was deposited under the same general geologic conditions.

Frac; fracture stimulation. A stimulation treatment involving the fracturing of a reservoir and then injecting water and generally sand and/or chemicals into the fractures under pressure to contact greater surface area to stimulate hydrocarbon production in low-permeability reservoirs.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Horizontal drilling. A technique used in certain formations where a well is drilled near vertically to a certain depth and then drilled at an angle parallel with a specified formation.

Initial production rate. Generally, the maximum 24-hour production volume from a well.

Mbbl. One thousand stock tank barrels.

Mboe. One thousand barrels of oil equivalent.

Mboepd. One thousand barrels of oil equivalent per day.

ii

Mcf. One thousand cubic feet of natural gas.

Mcf/d. One thousand cubic feet of natural gas per day.

Mmbbl. One million stock tank barrels.

Mmboe. One million barrels of oil equivalent.

Mmcf. One million cubic feet of natural gas.

Mmcf/d. One million cubic feet of natural gas per day.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells.

Overriding royalty interest. An interest in an oil or natural gas property entitling the owner to a share of oil and natural gas production free of some costs of production as defined by agreement.

Play. A term applied during a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and natural gas reserves.

Present value of estimated future net revenues or PV-10. The present value of estimated future net revenues is an estimate of future net revenues from a property at the date indicated, without giving effect to derivative financial instrument activities, after deducting production and ad valorem taxes, future capital costs, abandonment costs, and operating expenses, but before deducting future federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their “present value.” The present value is shown to indicate the effect of time on the value of the net revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil and natural gas prices and operating and capital costs at the date indicated, at its acquisition date, or as otherwise indicated. We believe that the present value of estimated future net revenues before income taxes, while not a financial measure in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”), is an important financial measure used by investors and independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions because the tax characteristics of comparable companies can differ materially.

Productive well. A productive well is a well that is not a dry well.

Proved developed reserves. Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate.

Proved reserves. Those quantities of oil and natural gas, which, 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.

The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

iii

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Recompletion. An operation within an existing well bore to make the well produce oil or natural gas from a different, separately producible zone other than the zone from which the well had been producing or to stimulate a currently producing formation with a different completion.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Sales volumes. The amount of production of oil or natural gas sold after deducting royalties and working interests owned by third parties.

Shale. Fine-grained sedimentary rock composed of consolidated clay or mud but also commonly containing carbonate or elastic material. Shale is one of the most frequently occurring sedimentary rocks.

Standardized measure of discounted future net cash flows or the Standardized Measure. Under the Standardized Measure, future cash flows for the years ended December 31, 2019 and 2018 are estimated by applying the simple average spot prices for the trailing twelve month period using the first day of each month beginning on January 1 and ending on December 1 of each respective year, adjusted for fixed and determinable escalations, to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end and future plugging and abandonment costs to determine pre-tax cash inflows. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate to arrive at the Standardized Measure.

Tcf. One trillion cubic feet of natural gas.

Undeveloped acreage. License or lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Wellhead production. The volume of oil or natural gas produced before deducting royalties and working interests owned by third parties prior to any oil and natural gas lost or used from wellhead to market.

Working interest (“WI”). The operating interest that gives the owner the right to drill, produce and conduct activities on the property and a share of production.

iv

PART I

Item 1. Business

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

Our Business

We are an international oil and natural gas company engaged in acquisition, exploration, development, and production. We have focused our operations in countries that have established, yet underexplored, petroleum systems, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of December 31, 2019, we held interests in 365,171 and 162,800 net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria, respectively. As of March 20, 2020, N. Malone Mitchell 3^rd beneficially owned approximately 49.9% of 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.

Based on the reserves report prepared by DeGolyer and MacNaughton, independent petroleum engineers, our estimated proved reserves at December 31, 2019 in Turkey were 10,670 Mboe, of which 96.1% was oil. Of these estimated proved reserves, 56.3% were proved developed reserves. As of December 31, 2019 and 2018, the Standardized Measure and PV-10 of our proved reserves in Turkey were $234.5 million and $288.5 million, respectively. See “Item 2. Properties—Value of Proved Reserves” for a reconciliation of PV-10 to the Standardized Measure.

Internal Restructuring

Historically, our operations in Turkey have been conducted through various subsidiaries that we acquired over time. These subsidiaries are predominantly domiciled in Australia or the Bahamas. During the fourth quarter of 2019, we commenced an internal restructuring with the goal of consolidating our Turkish operations in a new Turkish domiciled operating subsidiary. We believe that the restructuring will simplify our organizational structure, simplify and reduce the cost of our accounting, and allow us to more effectively utilize certain net operating loss carryforwards. We expect to complete the restructuring in the second quarter of 2020.

Recent Oil Price Decline and Going Concern

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.  

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

1

Recent Developments

On February 24, 2020, we sold the shares in our wholly-owned subsidiary Petrogas Petrol Gaz ve Petrokemya Urunleri Insaat Sanayive Ticaret A.S. (“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, A.S. (“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 received 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.

Our Properties and Operations

Summary of Geographic Areas of Operations

The following table shows net reserves information as of December 31, 2019:

			Proved
	Proved Developed		Undeveloped		Total Proved		Probable Reserves		Possible Reserves
	Reserves (Mboe)		Reserves (Mboe)		Reserves (Mboe)		(Mboe)		(Mboe)
Turkey		6,004		4,666		10,670		7,353		6,906

For more information on our reserves, see “Item 2. Properties”.

Turkey

As of December 31, 2019, we held interests in four onshore exploration licenses and 20 onshore production leases covering a total of 436,388 gross (365,171 net) acres in Turkey. As of December 31, 2019, we had total net proved reserves of 10,259 Mbbl of oil and 2,466 Mmcf of natural gas, net probable reserves of 7,212 Mbbl of oil and 845 Mmcf of natural gas and net possible reserves of 6,742 Mbbl of oil and 984 Mmcf of natural gas in Turkey. During 2019, our average wellhead production was 2,850 net Boepd of oil and natural gas in Turkey. The following summarizes our core producing properties in Turkey:

Southeastern Turkey. During 2019, substantially all of our oil production was concentrated in Southeastern Turkey, primarily in the Arpatepe, Bahar, Goksu, Selmo, and Yeniev oil fields. These fields are located in the northwest region within the Turkish portion of the North Arabian Basin. The North Arabian Basin includes prolific oil trends that extend from Iran and Iraq into Turkey.

We hold a 100% working interest in the Selmo production lease, which expires in June 2025. We also hold a 100% working interest in the Selmo exploration license. The Selmo oil field is the second largest oil field in Turkey in terms of historical cumulative production and is responsible for a large portion of our current crude oil production. For 2019, our net wellhead production of crude oil from the Selmo field was 486,545 Bbls at an average rate of 1,333 Bbl/d. Turkiye Petrolleri Anonim Ortakligi (“TPAO”), a Turkish government-owned oil and natural gas company, and Türkiye Petrol Rafinerileri A.Ş. (“TUPRAS”), a privately-owned oil refinery in Turkey, purchase all of our crude oil production, which are transported by truck to their neighboring facilities. At December 31, 2019, we had 51 gross and net producing wells in the Selmo oil field.

We hold a 100% working interest in the Molla exploration license, which includes the Bahar and Cavuslu fields. We also hold a 100% working interest in each of the three Molla production leases, which includes the Goksu, Yeniev, West Yeniev, Pinar, Catak and Bati Yasince fields. In the Molla licenses, we target Bedinan, Dadas, Hazro, and Mardin formations, which produce on the licenses.  For 2019, our net wellhead production of crude oil from the Molla area was 478,150 Bbls at an average rate of 1,310 Bbl/d. At December 31, 2019, we had 20 gross and net producing wells on the Molla licenses.

We hold a 50% working interest in our Arpatepe production lease. For 2019, our share of wellhead production of net crude oil from the Arpatepe field was 42,340 Bbls at an average rate of 116 Bbl/d. At December 31, 2019, we had four gross (two net) producing wells on the Arpatepe production lease. We have operated the Arpatepe production lease since December 2015.

2

We hold a 50% working interest in the Bakuk production lease.  In 2017, our production was shut in due to security precautions and remained shut in during 2019.

Northwestern Turkey. Substantially all of our natural gas production is concentrated in the Thrace Basin, which is one of Turkey’s most productive onshore natural gas regions. It is located in northwestern Turkey close to Istanbul province.  For 2019, our net wellhead production was 197,753 Mcf at an average rate of 542 Mcf/d from all of the gas fields. On February 24, 2020, we sold the shares in Petrogas, which held certain of our production leases in the Thrace Basin. See “Item 1. Business—Recent Developments.”

Bulgaria

As of December 31, 2019, we held interests in one production concession covering a total of 162,800 net undeveloped acres in Bulgaria. During 2019, we had no production or reserves in Bulgaria.  

Current Operations

Southeastern Turkey

Molla

During 2020, we plan to continue our recompletion, workover, and production optimization plans in our producing fields, including Bahar, Yeniev, Goksu, Pinar, Southeast Bahar, Catak, and Karagoz. Drilling additional wells will be dependent on oil prices.

Bahar Field. In the first quarter of 2020, we started construction of phase II electrification of the Bahar field to replace diesel generated power with gas generated power, which will be distributed to each well in the field. The phase II electrification is expected to be completed and operational in the second quarter of 2020.

Goksu Field. We whipstocked the Goksu-4H well in January 2020. The well was re-drilled to a total depth of 5,720 feet. Although we encountered high permeability in the Mardin formation, tests did not indicate commercial quantities of oil.

Arpatepe Field.  In the first quarter of 2020, we started implementation of a full field waterflood of the Arpatepe field. We plan to recomplete four wells in the field as water injection wells and one well as a water source well. Additionally, we plan to build a central facility and gathering system to handle increased volumes.

Selmo

During 2020, we plan to continue our recompletion, workover, and production optimization operations in the Selmo field.

Bulgaria

We are currently evaluating future activity in Bulgaria.

Planned Operations

We expect our net field capital expenditures for 2020 to range between $2.5 million and $15.0 million. We expect net field capital expenditures during 2020 to include between $1.0 million and $9.0 million in drilling and completion expense for between one and five planned wells, between $1.0 million and $3.0 million for recompletions, between $1.0 million and $2.0 million implementing a waterflood in the Bedinan sandstone in the Arpatepe field, and approximately $1.0 million in facilities upgrades to our natural gas power generation infrastructure. Our projected 2020 capital expenditure budget is subject to change.

Customers

Oil. During 2019, 78.5% of our oil production, which is U.S. Dollar indexed, was concentrated in the Selmo and Bahar oil fields in Turkey. TUPRAS purchases substantially all of our oil production. During 2019, we sold $65.8 million of oil to TUPRAS, representing 97.7% of our total revenues. We sell all of our Southeastern Turkey oil to TUPRAS pursuant to a domestic crude oil purchase and sale agreement. Under the purchase and sale agreement, TUPRAS purchases oil produced by us that is delivered to TPAO’s Batman tanks from which it is pumped to a TUPRAS vessel at the Dörtyol plant via the national pipeline operated by Boru

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Hatlari ile Petrol Tasima A.S. (“BOTAŞ”). 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.The purchase and sale agreement automatically renews for successive one-year terms unless earlier terminated in writing by either party.All payments for our oil production made by TUPRAS for the past nine years have been in full and on time. In November 2019, TUPRAS filed a lawsuit seeking restitution from us for alleged overpayments resulting from a February 2019 amendment to the Turkish domestic crude oil pricing formula under Petroleum Market Law No. 5015. See “Item 3. Legal Proceedings.”No other purchasers of our oil accounted for more than 10% of our total revenues.

Natural Gas. During 2019, no purchasers of our natural gas production, which is indexed on the New Turkish Lira (“TRY”), accounted for 10% or more of our total revenues.

Competition

We operate in the highly competitive areas of oil and natural gas exploration, development, production and acquisition with a number of other companies, including U.S.-based and international companies doing business in each of the countries in which we operate. We face competition from both major and other independent oil and natural gas companies in each of the following areas seeking oil and natural gas exploration licenses and production licenses and leases and acquiring desirable producing properties or new leases for future exploration.

Many of our competitors have substantially greater financial, managerial, technological and other resources than we do. To the extent competitors are able to pay more for properties than we are paying, we will be at a competitive disadvantage. Further, many of our competitors enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Our ability to explore for and produce oil and natural gas prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

Fracture Stimulation Program

Oil and natural gas may be recovered from our properties through the use of fracture stimulation combined with modern drilling and completion techniques. Fracture stimulation involves the injection of water, and generally sand and/or chemicals under pressure into formations to fracture the oil or gas formation by contacting greater surface area to stimulate production. We have successfully utilized fracture stimulation in our Thrace Basin, Molla, and Selmo licenses and production leases.

Fracture stimulations in Thrace Basin and Molla are conducted in a low permeability reservoir. These stimulations generally consist of injecting between 20,000 and 100,000 gallons of fluid that contain between 80,000 and 150,000 pounds of sand per stage. Fluids are generally a mixture of slickwater and gels, which is typical in stimulation. The size of fracture stimulation treatments is dependent on net pay thickness and stress barriers.

Although the cost of each well will vary, on average approximately 10% to 60% of the total cost of completing a well in both Thrace Basin and Molla is associated with stimulation activities. We account for these costs as typical drilling and completion costs and include them in our capital expenditure budget.

We diligently review best practices and industry standards in connection with fracture stimulation activities and strive to comply with all regulatory requirements in the protection of potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across potable water sources, cementing surface casing from setting depth to surface and second string from setting depth up-well past multiple frac barriers above the formation and, in some cases, to surface, continuously monitoring the fracture stimulation process in real time, and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources or at a certified water treatment plant. In Southeast Turkey, the base of potable water is generally 3,000 feet to 8,000 feet above the hydrocarbon zones.  There have not been any incidents, citations, or suits involving environmental concerns related to our fracture stimulation operations on our properties.

In the Thrace Basin, Selmo, and Molla, we have access to water resources which we believe will be adequate to execute any stimulation activities that we may perform in the future. We also employ procedures for environmentally friendly disposal of fluids recovered from fracture stimulation.

For more information on the risks of fracture stimulation, please read “Item 1A. Risk Factors—Risks Related to the Oil and Natural Gas Industry—Our oil and natural gas operations are subject to extensive and complex laws and government regulation in the jurisdictions in which we operate and compliance with existing and future laws may increase our costs or impair our operations” and

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“Item 1A. Risk Factors—Risks Related to the Oil and Natural Gas Industry—Legislative and regulatory initiatives and increased public scrutiny relating to fracture stimulation activities could result in increased costs and additional operating restrictions or delays.”

Governmental Regulations

Government Regulations. Our current or future operations, including exploration and development activities on our properties, require permits from various governmental authorities, and such operations are and will be governed by laws and regulations concerning exploration, development, production, exports, taxes, labor laws and standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters. Compliance with these requirements may prove to be difficult and expensive. Due to our international operations, we are subject to the following issues and uncertainties that can affect our operations adversely:

• the risk of expropriation, nationalization, war, revolution, political instability, border disputes, renegotiation or modification of existing contracts, sanctions, and import, export and transportation regulations and tariffs;

• laws of foreign governments affecting our ability to fracture stimulate oil or natural gas wells, such as the legislation enacted in Bulgaria in January 2012;

• the risk of not being able to procure residency and work permits for our expatriate personnel;

• taxation policies, including royalty and tax increases and retroactive tax claims;

• exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over international operations;

• laws and policies of the United States affecting foreign trade, taxation and investment, including anti-bribery and anti-corruption laws;

• the possibility of being subjected to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and

• the possibility of restrictions on repatriation of earnings or capital from foreign countries.

Permits and Licenses. In order to carry out exploration and development of oil and natural gas interests or to place these into commercial production, we may require certain licenses and permits from various governmental authorities. There can be no guarantee that we will be able to obtain all necessary licenses and permits that may be required. In addition, such licenses and permits are subject to change and there can be no assurances that any application to renew any existing licenses or permits will be approved.

Repatriation of Earnings. Currently, there are no prohibitions on the repatriation of earnings or capital to foreign entities from Turkey or Bulgaria. However, there can be no assurance that any such prohibitions on repatriation of earnings or capital from the aforementioned countries or any other country where we may invest will not be imposed in the future. We may be liable for the payment of taxes upon repatriation of certain earnings from the aforementioned countries.

Environmental. The oil and natural gas industry is subject to extensive and varying environmental regulations in each of the jurisdictions in which we operate. Environmental regulations establish standards respecting health, safety and environmental matters and place restrictions and prohibitions on emissions of various substances produced concurrently with oil and natural gas. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products and waste created by water and air pollution control procedures. These regulations can have an impact on the selection of drilling locations and facilities, and potentially result in increased capital expenditures. In addition, environmental legislation may require those wells and production facilities to be abandoned and sites reclaimed to the satisfaction of local authorities. Such regulation has increased the cost of planning, designing, drilling, operating and, in some instances, abandoning wells. We are committed to complying with environmental and operational legislation wherever we operate.

Such laws and regulations not only expose us to liability for our own negligence but may also expose us to liability for the conduct of others or for our actions that were in compliance with all applicable laws at the time those actions were taken. We may incur significant costs as a result of environmental accidents, such as oil spills, natural gas leaks, ruptures, or discharges of hazardous materials into the environment, including clean-up costs and fines or penalties. Additionally, we may incur significant costs in order to comply with environmental laws and regulations and may be forced to pay fines or penalties if we do not comply.

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There has been interest among the media, government regulators and private citizens concerning the possible negative environmental and geological effects of fracture stimulation. Some have alleged that fracture stimulation results in the contamination of aquifers and may even contribute to seismic activity. In January 2012, the government of Bulgaria enacted legislation that banned the fracture stimulation of oil and natural gas wells in the Republic of Bulgaria and imposed large monetary penalties on companies that violate that ban.  There is a risk that Turkey could at some point impose similar legislation or regulations. Such legislation or regulations could severely impact our ability and the cost to drill and complete wells. We are committed to complying with legislation and regulations involving fracture stimulation wherever we operate.

Insurance

We currently carry general liability insurance and excess liability insurance, including pollution insurance. These insurance policies contain maximum policy limits and are subject to customary exclusions and limitations. Our general liability insurance covers us and our subsidiaries for third-party claims and liabilities arising out of lease operations and related activities. The excess liability insurance is in addition to, and is triggered if, the general liability insurance per occurrence limit is reached.  In addition, we carry a political risk policy, which covers our scheduled production facilities in the event of an act of terrorism. We will continue to monitor our insurance coverage and will maintain appropriate levels of insurance to satisfy applicable regulations, as well as maintain levels of insurance appropriate for prudent operations within the industry in which we operate.

We require our third-party service providers to sign master service agreements with us pursuant to which they generally agree to indemnify us for the personal injury and death of the service provider’s employees as well as subcontractors that are hired by the service provider. Similarly, we generally agree to indemnify our third-party service providers against similar claims regarding our employees and our other contractors.

We also require our third-party service providers that perform fracture stimulation operations for us to sign master service agreements containing the indemnification provisions noted above. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to fracture stimulation operations. We believe that our general liability, excess liability and pollution insurance policies would cover third-party claims related to fracture stimulation operations and associated legal expenses, in accordance with, and subject to, the terms of such policies. However, these policies may not cover fines, penalties or costs and expenses related to government-mandated environmental clean-up responsibilities.

Bermuda Tax Exemption

As 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. Profits can be accumulated, and it is not obligatory for us to pay dividends.

Furthermore, we have received an assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966, as amended, that in the event that Bermuda enacts any legislation imposing tax computed on profits, income, any capital asset, gain or appreciation, we and any of our operations or our shares, debentures or other obligations shall be exempt from the imposition of such tax until March 31, 2035, provided that such exemption shall not prevent the application of any tax payable in accordance with the provisions of the Land Tax Act, 1967 or otherwise payable in relation to land in Bermuda leased to us.

We are required to pay an annual government fee (the “AGF”), which is determined on a sliding scale by reference to our authorized share capital and share premium account, with a minimum fee of $1,995 Bermuda Dollars and a maximum fee of $31,120 Bermuda Dollars. The Bermuda Dollar is treated at par with the U.S. Dollar. The AGF is payable each year on or before the end of January and is based on the authorized share capital and share premium account on August 31 of the preceding year.

In Bermuda, stamp duty is not chargeable in respect of the incorporation, registration, licensing of an exempted company or, subject to certain minor exceptions, on their transactions.

Employees

As of December 31, 2019, we employed 117 people in Turkey, 25 people in Addison, Texas and 5 people in Bulgaria. Approximately 36 of our employees at one of our subsidiaries operating in Turkey were represented by collective bargaining agreements with the Petroleum, Chemical and Rubber Workers Union of Turkey (“PETROL-IS”). We consider our employee relations to be satisfactory.

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Formation

We were incorporated under the laws of British Columbia, Canada on October 1, 1985 under the name Profco Resources Ltd. and continued to the jurisdiction of Alberta, Canada under the Business Corporations Act (Alberta) on June 10, 1997. Effective December 2, 1998, we changed our name to TransAtlantic Petroleum Corp. Effective October 1, 2009, we continued to the jurisdiction of Bermuda under the Bermuda Companies Act 1981 under the name TransAtlantic Petroleum Ltd.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our website at www.transatlanticpetroleum.com as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. The SEC maintains a website that contains reports, proxy and information statements, and other information regarding issues, including us, that electronically file with the SEC at http://www.sec.gov.

Our common shares are listed on the NYSE American exchange. Section 110 of the NYSE American company guide permits the NYSE American to consider the laws, customs and practices of foreign issuers in relaxing certain NYSE American listing criteria, and to grant exemptions from NYSE American listing criteria based on these considerations. A description of the significant ways in which our governance practices differ from those followed by U.S. domestic companies pursuant to NYSE American standards is available on our website, www.transatlanticpetroleum.com, under Corporate Governance page, which is accessible under the About heading on the home page.

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Information about our Executive Officers

The following table and text sets forth certain information with respect to our executive officers as of March 1, 2020:

Name	Age	Positions
N. Malone Mitchell 3rd	58	Chairman and Chief Executive Officer
Todd C. Dutton	66	President
Selami E. Uras	62	Executive Vice President, Turkey
G. Fabian Anda	48	Vice President, Finance
Tabitha T. Bailey	34	Vice President, General Counsel and Corporate Secretary
Michael P. Hill	38	Chief Accounting Officer
David G. Mitchell	39	Vice President of Engineering

N. Malone Mitchell 3rd has served as our chief executive officer since May 2011, as a director since April 2008, and as our chairman since May 2008. Since 2005, Mr. Mitchell has served as the president of Riata Corporate Group, LLC and Longfellow Energy, LLC, a Dallas-based private oil and natural gas exploration and production company. From June to December 2006, Mr. Mitchell served as president and chief operating officer of SandRidge Energy, Inc. (formerly Riata Energy, Inc.), an independent oil and natural gas company concentrating in exploration, development, and production activities. Until he sold his controlling interest in Riata Energy, Inc. in June 2006, Mr. Mitchell also served as president, chief executive officer, and chairman of Riata Energy, Inc., which Mr. Mitchell founded in 1985 and built into one of the largest privately held energy companies in the United States. Mr. Mitchell earned a B.S. from Oklahoma State University.

Todd C. Dutton has served as our president since May 2014. Mr. Dutton has served as president of Longfellow Energy, LP, a Dallas, Texas-based independent oil and natural gas exploration and production company owned by our chairman and chief executive officer, N. Malone Mitchell 3rd and his family (“Longfellow”), since January 2007, where his primary responsibility is to originate and develop oil and natural gas projects. He brings 42 years of experience in the oil and natural gas industry, focusing on exploration, acquisitions and property evaluation. He has served in various supervisory and management roles at Texas Pacific Oil Company, Coquina Oil Corporation, BEREXCO INC., and Riata Energy, Inc. Mr. Dutton earned a B.B.A. in Petroleum Land Management from the University of Oklahoma.

Selami E. Uras has served as our executive vice president since 2016. From 2006 to 2016, Mr. Uras served as our resident representative / manager in Turkey. Prior to joining us in 2006, Mr. Uras served as the resident general manager of ARCO Oil and Gas Company in Turkey for fifteen years. Mr. Uras began his career in the oil and gas industry in 1980 at Geophysical Services Inc., a subsidiary of Texas Instruments Corporation. Mr. Uras is also a successful entrepreneur in certain other industries, including mining. Mr. Uras graduated from TED Ankara College in 1976 and earned his CPA certificate from The Faculty of Economical & Commercial Sciences in Ankara in 1980.

G. Fabian Anda has served as our vice president of finance since January 2019. Mr. Anda served as our principal accounting and financial officer and vice president of finance from January 2018 to January 2019, as our interim principal accounting and financial officer and vice president of finance from October 2016 to January 2018, and as our director of finance and accounting from October 2011 to October 2016. Mr. Anda previously served as a finance director with ConocoPhillips, where he worked for ten years in positions of increasing responsibility in the Houston, Texas location. Mr. Anda earned a B.B.A in Finance and an MBA in International Finance from the University of St. Thomas at Houston.

Tabitha T. Baileyhas served as our vice president, general counsel, and corporate secretary since January 2019, and as associate general counsel from June 2017 to January 2019. Previously, Ms. Bailey served as an attorney in the corporate department at Akin Gump Strauss Hauer & Feld LLP from October 2013 to June 2017, where she represented clients in mergers, acquisitions, capital raising, securities compliance, and other strategic transactions across a broad range of industries. Ms. Bailey began her career as an attorney in the corporate department at Haynes and Boone, LLP. Ms. Bailey earned a B.A. in International Studies from the University of Mississippi and a J.D. from Vanderbilt University Law School.

Michael P. Hill has served as our chief accounting officer and principal accounting and principal financial officer since January 2019. Mr. Hill served as chief accounting officer of AVAD Energy Partners, LLC from December 2017 to January 2019, where he was responsible for internal and external financial reporting, cash management, debt compliance, relationships with oil and gas purchasers, execution of the hedging strategy, and analyzing profitability. Previously, Mr. Hill served as our corporate controller from June 2017 to December 2017, our financial reporting manager from 2012 to June 2017, and our senior financial reporting accountant from 2010 to 2012. Mr. Hill also served as international controller at Toreador Resources Corporation and began his career as an auditor at Grant Thornton LLP. Mr. Hill earned a B.B.A. in Accounting and Finance from Texas Tech University.

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David G. Mitchell has served as our vice president of engineering since February 2017. Previously, Mr. Mitchell served as our operations manager from January 2017 to February 2017 and senior operations engineer from May 2013 to January 2017. In addition to his experience at the Company, Mr. Mitchell has also served in corresponding positions at Longfellowsince May 2016. Previously, Mr. Mitchell held various positions in production, midstream, development, and completions engineering throughout British Columbia, Alberta, New York, and Pennsylvania with Talisman Energy. Mr. Mitchell holds a BASC (Engineering) from the University of British Columbia and is a registered Professional Engineer (Alberta).

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Item 1A. Risk Factors

Risks Related to Our Business

The prevailing commodity price environment may require us to sell certain assets, restructure our debt, raise additional capital or seek bankruptcy protection.

During March 2020, crude oil prices declined to approximately $25 per barrel for Brent crude, and the price remains volatile and unpredictable.  At current prices for Brent crude, our current liquidity position is constrained and is forecast to worsen during 2020 as revenues are insufficient to meet our ordinary course expenditures and debt obligations. Our management is actively pursuing improving our working capital position and/or reducing our future debt service obligations in order to remain a going concern for the foreseeable future. If we are unable to restructure our outstanding debt or accounts payable obligations, obtain additional debt or equity financing, or raise adequate proceeds from sales of assets, we may not be able to make payments on our indebtedness or accounts payable, and we may find it necessary to file a voluntary petition for reorganization relief in order to provide us additional time to identify an appropriate solution to our financial situation and implement a plan of reorganization aimed at improving our capital structure.

There is substantial doubt about our ability to continue as a going concern.

We incurred a net loss of $5.4 million for the fiscal year ended December 31, 2019. We continue to experience decreased liquidity as a result of the decline in oil commodity prices. 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. These risks and uncertainties raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements included in this report do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts of liabilities that might result from the outcome of this uncertainty.

All of our operations are conducted in Turkey and Bulgaria, and we are subject to political, economic and other risks and uncertainties in these countries.

All of our operations are performed in the emerging markets of Turkey and Bulgaria, which may expose us to risks different than those associated with U.S. or Canadian markets. Due to our foreign operations, we are subject to the following issues and uncertainties that can adversely affect our operations:

• the risk of, and disruptions due to, expropriation, nationalization, war, terrorism, revolution, election outcomes, economic instability, political instability, or border disputes;

• the uncertainty of local contractual terms, renegotiation or modification of existing contracts and enforcement of contractual terms in disputes before local courts;

• the risk of import, export and transportation regulations and tariffs, including boycotts and embargoes;

• the risk of not being able to procure residency and work permits for our expatriate personnel;

• the requirements or regulations imposed by local governments upon local suppliers or subcontractors, or being imposed in an unexpected and rapid manner;

• taxation and revenue policies, including royalty and tax increases, retroactive tax claims and the imposition of unexpected taxes or other payments on revenues;

• exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over foreign operations;

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• laws and policies ofCanada and the United States, including the U.S. Foreign Corrupt Practices Act (“FCPA”), and of the other countries in which we operate affecting foreign trade, taxation and investment, including sanctions and anti-bribery and anti-corruption laws;

• our internal control policies may not protect us from reckless and criminal acts committed by our employees or agents, including violations or alleged violations of the FCPA;

• the possibility of being subjected to the exclusive jurisdiction of foreign courts in connection with legal disputes and the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and

• the possibility of restrictions on repatriation of earnings or capital from foreign countries.

To manage these risks, we sometimes form joint ventures and/or strategic partnerships with local private and/or governmental entities. Local partners provide us with local market knowledge. However, there can be no assurance that changes in conditions or regulations in the future will not affect our profitability or ability to operate in such markets.

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

During 2019, we derived all of our revenue from our operations in Turkey and substantially all of our oil production was derived from Southeastern Turkey. Historically, the Southeastern area of Turkey and nearby countries such as Iran, Iraq, and Syria have occasionally experienced political, social, security, and economic problems, terrorist attacks, insurgencies, war, and civil unrest. Since December 2010, political instability has increased in a number of countries in the Middle East and North Africa. As a result of the civil war in Syria, large numbers of Syrian refugees have fled to Turkey. In addition, tensions continue between Turkey and Syria. In October 2019, President Trump announced a decision to withdraw U.S. military forces from certain areas of Northeastern Syria, and Turkey announced the establishment of a safe zone along the border with Syria, contiguous to the region where our Southeast Turkey licenses are located. Separately, Turkey has experienced occasional terrorist incidents.  In July 2016, there was a failed attempt to overthrow the government of President Recep Tayyip Erdoğan.

On October 14, 2019, U.S. President Trump issued an executive order authorizing certain sanctions against Turkey, including specifically parties specially designated under this order in connection with Turkey’s military actions in Northern Syria. The U.S. Department of Treasury’s Office of Foreign Assets Control (“OFAC”) specifically designated and placed sanctions on two Turkish ministries and three government officials, including the Turkish Ministry of Energy and Natural Resources (“MENR”) and the Turkish Minister of Energy and Natural Resources, and issued a 30-day wind down license for affected operations and businesses. Our licenses in Turkey are issued by the MENR. Subsequently, on October 23, 2019, OFAC lifted these sanctions designations, while leaving the executive order in place. While the executive order does not impose any specific sanctions affecting Turkey at this time, additional sanctions could be imposed by OFAC under authority established by this order against ministries, entities, or persons in Turkey, including in connection with or unrelated to draft bills that have been proposed in the U.S. House of Representatives and the U.S. Senate that call for a range of potential new sanctions on Turkey, including sanctions against the Turkish energy industry, that could have a materially adverse effect on our business.

On November 11, 2019, the European Union adopted a framework for restrictive measures in response to Turkey’s illegal drilling activities in the Eastern Mediterranean.  On February 27, 2020, the EU took its first action under this framework, designating two individuals connect4ed with TPAO, namely Mehmet Ferru Akalin, the Vice-President and member of the Board of Directors, and Mr. Ali Coscun Namoglu, Deputy Director of the Exploration Department.  While the designations of these two individuals does not prohibit activities with TPAO, additional sanctions could be imposed by the EU under authority established by this framework including further sanctions against the Turkish energy industry, that could have a materially adverse effect on our business.  

The recent conflict with the terrorist group Islamic State in Iraq and Syria (“ISIS”), the tension in and involving the Kurdish regions of Northern Iraq and Northern Syria, which are contiguous to the region where our Southeast Turkey licenses are located, the aftermath of the attempted coup d’etat, as well as activities relating to Libya, and the threat of sanctions on Turkey may have political, social, or security implications in Turkey or otherwise may impact the Turkish economy.

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

The potential impact on our business from such events, conditions, and conflicts in these countries is uncertain. We may be unable to access the locations where we conduct operations or transport oil to our offtakers in a reliable manner. In those locations where we have employees or operations, we may incur substantial costs to maintain the safety of our personnel and our operations.

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We have a history of losses and may not achieve consistent profitability in the future.

We have incurred substantial losses in prior years. During 2019, we generated a net loss of $5.4 million. We will need to generate and sustain increased revenue levels in future periods in order to become consistently profitable, and even if we do, we may not be able to maintain or increase our level of profitability. We may incur losses in the future for a number of reasons, including the risks described herein, unforeseen expenses, difficulties, complications and delays and other unknown risks.

We depend on the services of our chairman and chief executive officer.

We depend on the performance of Mr. Mitchell, our chairman and chief executive officer. The loss of Mr. Mitchell could negatively impact our ability to execute our strategy. We do not maintain a key person life insurance policy on Mr. Mitchell.

We could lose permits or licenses on certain of our properties in Turkey unless the permits or licenses are extended or we commence production and convert the permits or licenses to production leases or concessions.

At December 31, 2019, of our total net undeveloped acreage, 38.5% and 9.3% will expire during 2020 and 2023, respectively, unless we are able to extend the permits or licenses covering this acreage or commence production on this acreage and convert the permits or licenses into production leases or concessions. If our permits or licenses expire, we will lose our right to explore and develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including factors that are beyond our control. Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals.  In addition, if our liquidity continues to be constrained and we are not able to access additional capital, we may be unable to fund the drilling of some of our obligation wells, and we could lose some of our licenses.

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

TUPRAS, an affiliate of Koç Holding, purchases substantially all of our oil production from Turkey, representing 97.7% of our total revenues in 2019. Under Turkish law, TUPRAS is obligated to purchase all of our oil production in Turkey, and we are prohibited from selling any of our oil produced in Turkey to any other customer. Pursuant to a purchase and sale agreement with TUPRAS, the price of oil delivered to TUPRAS is determined under the Petroleum Market Law No. 5015 (the “Pricing Amendment”) under the laws of the Republic of Turkey. In February 2019, Turkey amended Petroleum Market Law No. 5015 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 TransAtlantic Exploration Mediterranean International Pty Ltd (“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. If TUPRAS reduces its oil purchases or fails to purchase our oil production, or there is a material non-payment, our results of operations could be materially and adversely affected. TUPRAS may be subject to its own operating risks that could increase the risk that it could default on its obligations to us. Changes to Turkish law or our commercial relationship with TUPRAS could adversely affect our business and results of operations.

A significant failure of our computer systems may increase our operating costs or otherwise adversely affect our business.

We depend upon our computer systems to perform accounting and administrative functions as well as manage other aspects of our operations. We maintain normal backup polices with respect to our computer systems and networks.  Nevertheless, our computer systems and networks are subject to risks that may cause interruptions in service, including, but not limited to, security breaches, physical damage, power loss, software defects, hacking attempts, computer viruses and malware, lost data and programming and/or human errors. Significant interruptions in service, security breaches or lost data may have a material adverse effect on our business, financial condition or results of operations.

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Our indebtedness could adversely affect our financial condition and prevent us from fulfilling our debt service and other obligations.

Our indebtedness could have significant effects on our business. For example, it could:

• make it more difficult for us to satisfy our financial obligations, including with respect to our indebtedness, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the agreements governing our indebtedness;

• increase our vulnerability to general adverse economic, industry and competitive conditions, especially declines in oil and natural gas prices;

• limit our ability to borrow additional funds; and

• limit our financial flexibility.

Each of these factors may have a material and adverse effect on our financial condition and viability. Our ability to make payments with respect to our indebtedness and to satisfy any other debt obligations will depend on commodity prices and our future operating performance, which will be affected by prevailing economic conditions and financial, business and other factors affecting us and our industry, many of which are beyond our control.

We could experience labor disputes that could disrupt our business in the future.

As of December 31, 2019, 36 of our employees at one of our subsidiaries operating in Turkey were represented by collective bargaining agreements with PETROL-IS. Potential work disruptions from labor disputes with these employees could disrupt our business and adversely affect our financial condition and results of operations.

Risks Related to the Oil and Natural Gas Industry

Oil and natural gas prices are volatile. Declines in prices could adversely affect our financial condition, results of operations, cash flows, access to capital, and ability to grow.

Oil and natural gas prices are volatile.  The decline since late 2014 in oil and natural gas prices has reduced our revenue, cash flows, and access to capital, and on March 9, 2020, the price of oil fell approximately 20% due to a dispute over production levels between Russia and Saudi Arabia, as a result of which Saudi Arabia increased its production to record levels.  Since that time, the price of oil has continued to fall due to concerns about the impact of coronavirus (COVID-19) on the demand for oil. Lower oil and natural gas prices also potentially reduce the amount of oil and natural gas that we can economically produce resulting in a reduction in the proved oil and natural gas reserves we could recognize. Thus, significant and sustained commodity price reductions could materially and adversely affect our financial condition and results of operations which could impact, maintain or increase our current levels of borrowing, our ability to repay current or future indebtedness, refinance our current indebtedness or obtain additional capital on attractive terms.

The markets for crude oil and natural gas have historically been, and are likely to continue to be, volatile and subject to wide fluctuations in response to numerous factors, including the following:

• worldwide and domestic supplies of oil and gas, and the productive capacity of the oil and gas industry as a whole;

• changes in the supply and the level of consumer demand for such fuels;

• overall global and domestic economic conditions;

• political conditions in oil, natural gas, and other fuel-producing and fuel-consuming areas;

• the availability and capacity of gathering, transportation, processing, and/or refining facilities in regional or localized areas that may affect the realized price for crude oil or natural gas;

• the price and level of imports of crude oil, refined petroleum products, and liquefied natural gas;

• weather conditions, including effects of weather conditions on prices and supplies in worldwide energy markets;

• the occurrence or threat of epidemic or pandemic diseases, such as the recent outbreak of coronavirus (COVID-19), or any government response to such occurrence or threat;

• technological advances affecting energy consumption and conservation;

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• the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) and other exporting countries to agree to and maintain crude oil prices and production controls;

• the oil price war between Russia and Saudi Arabia;

• the competitive position of each such fuel as a source of energy as compared to other energy sources;

• strengthening and weakening of the U.S. Dollar relative to other currencies; and

• the effect of governmental regulations and taxes on the production, transportation, and sale of oil, natural gas, and other fuels.

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and gas price movements with any certainty, but in general we expect oil and gas prices to continue to fluctuate significantly.

The recent global downturn in the price of oil may materially and adversely affected our results of operations, cash flows and financial condition, and this trend could continue during 2020 and potentially beyond. As mentioned above, in early March 2020, the market experienced a precipitous decline in oil prices in response to oil demand concerns due to the economic impacts of the a highly transmissible and pathogenic coronavirus (COVID-19) and anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia. The recent announcement by Saudi Arabia of a significant reduction in its export prices as well as a recent announcement by Russia that previously agreed upon production cuts will expire on April 1, 2020, have contributed to the recent significant decline in the price of oil. Generally, demand for oil has declined substantially. These trends could materially and adversely affect our results of operations, cash flows and financial condition, and unless conditions in our industry improve, this trend will continue during 2020 and potentially beyond.

In addition, if a pandemic or epidemic such as the coronavirus (COVID-19) pandemic were to significantly impact areas of Turkey where we have operations, our local workforce could be affected which could also significantly disrupt our operations and decrease our ability to produce oil or natural gas.  The duration of the business disruption and related financial impact from the coronavirus (COVID-19) pandemic cannot be reasonably estimated at this time. If the impact of the coronavirus (COVID-19) pandemic continues for an extended period of time, it could materially adversely affect the demand for oil or natural gas and our ability to operate our business. The extent to which the coronavirus (COVID-19) or other health pandemics or epidemics may impact our results will depend on future developments, which are highly uncertain and cannot be predicted.

Reserves estimates depend on many assumptions that may turn out to be inaccurate.

Our reserves are estimated by independent petroleum engineers. Any material inaccuracies in our reserves estimates or underlying assumptions could materially affect the quantities and present values of our reserves. The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and various assumptions, including assumptions relating to economic factors. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of reserves that we may report. In order to prepare these estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions relating to matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and pre-tax net present value of reserves that we may report. In addition, we may adjust estimates of proved, probable, and possible reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Moreover, there can be no assurance that our reserves will ultimately be produced or that our proved undeveloped, probable, and possible reserves will be developed within the periods anticipated. Any significant variance in the assumptions could materially affect the estimated quantity and value of our reserves.

Investors should not assume that the pre-tax net present value of our proved, probable, and possible reserves is the current market value of our estimated oil and natural gas reserves. We base the pre-tax net present value of future net cash flows from our proved, probable, and possible reserves on prices and costs on the date of the estimate. Actual future prices, costs, and the volume of produced reserves may differ materially from those used in the pre-tax net present value estimate.

Commodity price declines may result in write-downs of our asset carrying values.

We follow the successful efforts method of accounting for our oil and gas operations. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether proved

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reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed.

The capitalized costs of our oil and natural gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated fair value (discounted future net cash flows of that depletion pool). Any such charge will not affect our cash flow from operating activities or liquidity but will reduce our earnings and shareholders’ equity. The recent decline in oil or natural gas prices could cause an impairment write-down of capitalized costs and a non-cash charge against future earnings. Once incurred, a write-down of oil and natural gas properties cannot be reversed at a later date, even if oil or natural gas prices increase.

We may be unable to acquire or develop additional reserves, which would reduce our cash flow and income.

In general, production from oil and natural gas properties declines over time as reserves are depleted, with the rate of decline depending on reservoir characteristics. If we are not successful in our exploration and development activities or in acquiring properties containing reserves, our reserves will generally decline as reserves are produced. Our oil and natural gas production is highly dependent upon our access to capital and our ability to economically find, develop or acquire reserves in commercial quantities.

To the extent cash flow from operations is reduced, either by a decrease in prevailing prices for oil and natural gas or an increase in finding and development costs, and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. Even with sufficient available capital, our future exploration and development activities may not result in additional reserves, and we might not be able to drill productive wells at acceptable costs.

Our future exploration, development and production activities may not be profitable or achieve our expected returns.

The long-term performance of our business depends upon our ability to identify, acquire and develop additional oil and natural gas reserves that are economically recoverable. Future success depends upon our ability to acquire working and revenue interests in properties upon which oil and natural gas reserves are ultimately discovered in commercial quantities, and the ability to develop prospects that contain additional proven oil and natural gas reserves to the point of production. Without successful acquisition and exploration activities, we will not be able to develop additional oil and natural gas reserves or generate additional revenues. There are no assurances that additional oil and natural gas reserves will be identified or acquired on acceptable terms or that oil and natural gas reserves will be discovered in sufficient quantities to enable us to recover our exploration and development costs or sustain our business.

The successful acquisition and development of oil and natural gas properties requires an assessment of recoverable reserves, future oil and natural gas prices and operating costs, potential environmental and other liabilities, and other factors. Such assessments are inherently uncertain. In addition, no assurance can be given that our exploration and development activities will result in the discovery of additional reserves. Operations may be curtailed, delayed or canceled as a result of lack of adequate capital and other factors, such as lack of availability of rigs and other equipment, title problems, weather, compliance with governmental regulations or price controls, mechanical difficulties, or unusual or unexpected formations, pressures and/or work interruptions. In addition, the costs of exploration and development may materially exceed our internal estimates.

Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.

Our long-term success depends on the success of our exploration, development and production activities in each of our prospects. These activities are subject to numerous risks beyond our control, including the risk that we will be unable to economically produce our reserves or be able to find commercially productive oil or natural gas reservoirs. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. The cost of drilling, completing and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project unprofitable. Further, many factors may curtail, delay or prevent drilling operations, including:

• unexpected drilling conditions;

• pressure or irregularities in geological formations;

• equipment failures or accidents;

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• pipeline and processing interruptions or unavailability;

• title problems;

• adverse weather conditions;

• lack of market demand for oil and natural gas;

• the occurrence or threat of epidemic or pandemic diseases, such as the recent outbreak of coronavirus (COVID-19), or any government response to such occurrence or threat that disrupts our operations;

• delays imposed by, or resulting from, compliance with environmental laws and other regulatory requirements;

• declines in oil and natural gas prices; and

• shortages or delays in the availability of drilling rigs, equipment and qualified personnel.

Our future drilling activities might not be successful, and drilling success rates overall or within a particular area could decline. We could incur losses by drilling unproductive wells. Shut-in wells, curtailed production and other production interruptions may materially adversely affect our business, financial condition and results of operations.

The development of proved undeveloped reserves is uncertain. In addition, there are no assurances that our probable and possible reserves will be converted to proved reserves.

Our reserves are estimated by independent petroleum engineers. At December 31, 2019, approximately 43.7% of our total estimated net proved reserves in Turkey were proved undeveloped reserves. Undeveloped reserves, by their nature, are significantly less certain than developed reserves. At December 31, 2019, we also had a significant amount of unproved reserves, which consist of probable and possible reserves. There is significant uncertainty attached to unproved reserves estimates. The discovery, determination and exploitation of undeveloped or unproved reserves requires significant capital expenditures and successful drilling and exploration programs. We do not currently have the funds available to develop our undeveloped reserves. We may not be able to raise the additional capital that we need to develop these reserves. There is no certainty that we will be able to convert undeveloped reserves to developed reserves or unproved reserves into proved reserves or that our undeveloped or unproved reserves will be economically viable or technically feasible to produce.

Legislative and regulatory initiatives and increased public scrutiny relating to fracture simulation activities could result in increased costs and additional operating restrictions or delays.

Fracture stimulation is an important and commonly used process for the completion of oil and natural gas wells and involves the pressurized injection of water and generally sand and/or chemicals into rock formations to contact greater surface area to stimulate production. Recently, there has been increased public concern regarding the potential environmental impact of fracture stimulation activities. Most of these concerns have raised questions regarding the drilling fluids used in the fracturing process, their effect on drinking water supplies, the use of water in connection with completion operations, and the potential for impact to surface water, groundwater and the environment generally.

The increased attention regarding fracture stimulation could lead to greater opposition, including litigation, to oil and natural gas production activities using fracture stimulation techniques. Increased public scrutiny may also lead to additional levels of regulation in the countries in which we operate that could cause operational restrictions or delays, make it more difficult to perform fracture stimulation or could increase our costs of compliance and doing business. Additional legislation or regulation, such as a requirement to disclose the chemicals used in fracture stimulation, could make it easier for third parties opposing fracture stimulation to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. A substantial portion of our operations rely on fracture stimulation, and the adoption of legislation in Bulgaria have placed restrictions on our fracture stimulation activities, causing us to suspend our fracture stimulation activities in Bulgaria. The adoption of legislative or regulatory initiatives in Turkey restricting fracture stimulation could impose operational delays, increased operations costs and additional related burdens on our exploration and production activities which could suspend or make it more difficult to perform fracture stimulation, cause a material decrease in the drilling of new wells and related completion activities and increase our costs of compliance and doing business, which could materially impact our business and profitability.

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We are subject to operating hazards.

The oil and natural gas exploration and production business involves a variety of operating risks, including the risk of fire, explosion, blowout, pipe failure, casing collapse, stuck tools, uncontrollable flows of oil or natural gas, abnormally pressured formations and environmental hazards such as oil spills, surface cratering, natural gas leaks, pipeline ruptures, discharges of toxic gases, underground migration, surface spills, mishandling of fracture stimulation fluids, including chemical additives, and natural disasters. The occurrence of any of these events could result in substantial losses to us due to injury and loss of life, loss of or damage to well bores and/or drilling or production equipment, costs of overcoming downhole problems, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Gathering systems and processing facilities are subject to many of the same hazards and any significant problems related to those facilities could adversely affect our ability to market our production.

Our oil and natural gas operations are subject to extensive and complex laws and government regulation in the jurisdictions in which we operate and compliance with existing and future laws may increase our costs or impair our operations.

Our oil and natural gas operations are subject to numerous federal, state, local, foreign and provincial laws and regulations, including those related to the environment, employment, immigration, labor, oil and natural gas exploration and development, payments to local, foreign and provincial officials, taxes and the repatriation of foreign earnings. If we fail to adhere to any applicable federal, state, local, foreign and provincial laws or regulations, or if such laws or regulations restrict exploration or production, or negatively affect the sale, of oil and natural gas, our business, prospects, results of operations, financial condition or cash flows may be impaired. We may be subject to governmental sanctions, such as fines or penalties, as well as potential liability for personal injury, property or natural resource damage and might be required to make significant capital expenditures to comply with federal, state or international laws or regulations. In addition, existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations could adversely affect our business or operations, or substantially increase our costs and associated liabilities.

In addition, exploration for, and exploitation, production and sale of, oil and natural gas in each country in which we operate is subject to extensive national and local laws and regulations requiring various licenses, permits and approvals from various governmental agencies. If these licenses or permits are not issued or unfavorable restrictions or conditions are imposed on our exploration or drilling activities, we might not be able to conduct our operations as planned. Alternatively, failure to comply with these laws and regulations, including the requirements of any licenses or permits, might result in the suspension or termination of operations and subject us to penalties. We incur costs to comply with these numerous laws, regulations, licenses and permits.

Specifically, our oil and natural gas operations are subject to stringent laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the imposition of administrative, civil and/or criminal penalties, incurring investigatory or remedial obligations and the imposition of injunctive relief.

Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our industry in general and on our own results of operations, competitive position or financial condition. Although we intend to comply in all material respects with applicable environmental laws and regulations, we cannot assure you that we will be able to comply with existing or new regulations. In addition, the risk of accidental spills, leakages or other circumstances could expose us to extensive liability. We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.

Under certain environmental laws that impose strict, joint and several liability, we may be required to remediate our contaminated properties regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were or were not in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property may result from environmental and other impacts of our operations. Moreover, new or modified environmental, health or safety laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. Therefore, the costs to comply with environmental, health or safety laws or regulations or the liabilities incurred in connection with them could significantly and adversely affect our business, financial condition or results of operations.

In addition, many countries have agreed to regulate emissions of “greenhouse gases.” Methane, a primary component of natural gas, and carbon dioxide, a byproduct of burning of oil and natural gas, are greenhouse gases. Regulation of greenhouse gases could adversely impact some of our operations and demand for some of our services or products in the future.

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We do not plan to insure against all potential operating risks. We might incur substantial losses from, and be subject to substantial liability claims for, uninsured or underinsured risks related to our oil and natural gas operations.

We do not intend to insure against all risks. Our oil and natural gas exploration and production activities are subject to numerous hazards and risks associated with drilling for, producing and transporting oil and natural gas, and storing, transporting and using explosive materials, and any of the following risks can cause substantial losses:

• environmental hazards, such as uncontrollable flows of natural gas, oil, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination, underground migration and surface spills or mishandling of fracture stimulation fluids, including chemical additives;

• abnormally pressured formations;

• leaks of oil, natural gas and other hydrocarbons or losses of these hydrocarbons as a result of accidents during drilling and completion operations, including fracture stimulation activities, or from the gathering and transportation of oil, natural gas and other hydrocarbons, malfunctions of pipelines, processing or other facilities in our operations or at delivery points to third parties;

• spillage or mishandling of oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by third-party service providers;

• mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

• fires and explosions;

• personal injuries and death;

• regulatory investigations and penalties; and

• natural disasters or other catastrophic events.

As is customary in the oil and natural gas industry, we maintain insurance against some, but not all, of our operating risks. Our insurance may not be adequate to cover potential losses or liabilities and insurance coverage may not continue to be available at commercially acceptable premium levels or at all. We might not elect to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Losses and liabilities arising from uninsured or under-insured events could require us to make large unbudgeted cash expenditures that could adversely impact our business, financial condition or results of operations.

We might not be able to identify liabilities associated with properties or obtain protection from sellers against them, which could cause us to incur losses.

Our review and evaluation of prospects and future acquisitions might not necessarily reveal all existing or potential problems. For example, inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, may not be readily identified even when an inspection is undertaken. Even when problems are identified, a seller may be unwilling or unable to provide effective contractual protection against all or part of those problems, and we may assume environmental and other risks and liabilities in connection with acquired properties.  

We might not be able to obtain necessary permits, approvals or agreements from one or more government agencies, surface owners, or other third parties, which could hamper our exploration, development or production activities.

There are numerous permits, approvals, and agreements with third parties, which will be necessary in order to enable us to proceed with our exploration, development or production activities and otherwise accomplish our objectives. The government agencies in each country in which we operate have discretion in interpreting various laws, regulations, and policies governing operations under the licenses. Further, we may be required to enter into agreements with private surface owners to obtain access to, and agreements for, the location of surface facilities. In addition, because many of the laws governing oil and natural gas operations in the international countries in which we operate have been enacted relatively recently, there is only a relatively short history of the government agencies handling and interpreting those laws, including the various regulations and policies relating to those laws. This short history does not provide extensive precedents or the level of certainty that allows us to predict whether such agencies will act favorably toward us. The governments have broad discretion to interpret requirements for the issuance of drilling permits. Our inability to meet any such requirements could have a material adverse effect on our exploration, development or production activities.

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Hedging transactions that we enter into from time to time may expose us to counterparty credit risk.

From time to time, we enter into commodity derivative contracts to hedge the price volatility of oil. These hedging transactions may expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract, and we may not be able to realize the benefit of the derivative contract. As of March 15, 2020, we were not a party to any commodity derivative contracts that hedge our oil price risk.

Competition in the oil and natural gas industry is intense, and many of our competitors have greater financial, technological and other resources than we do, which may adversely affect our ability to compete.

We operate in the highly competitive areas of oil and natural gas exploration, development, production and acquisition with a number of other companies, including U.S.-based and foreign companies doing business in each of the countries in which we operate. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil and natural gas companies in seeking oil and natural gas exploration licenses and production licenses and acquiring desirable producing properties or new leases for future exploration.

Many of our competitors have substantially greater financial, managerial, technological and other resources than we do. These companies are able to pay more for exploratory prospects and productive oil and natural gas properties than we can. To the extent competitors are able to pay more for properties than we are paying, we will be at a competitive disadvantage. Further, many of our competitors enjoy technological advantages over us and may be able to implement new technologies more rapidly than we can. Our ability to explore for and produce oil and natural gas prospects and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, implement advanced technologies, evaluate and select suitable properties and consummate transactions in this highly competitive environment.

Risks Related to Our Common Shares

The interests of our controlling shareholder may not coincide with yours and such controlling shareholder may make decisions with which you may disagree.

As of March 20, 2020, Mr. Mitchell beneficially owned approximately 49.9% of our outstanding common shares. Persons and entities associated with Mr. Mitchell also own Series A Preferred Shares. Dalea Partners, LP, an affiliate of Mr. Mitchell, owns 42,000 Series A Preferred Shares; trusts benefitting three of Mr. Mitchell’s children each own 41,000 Series A Preferred Shares; one of Mr. Mitchell’s children owns 41,000 Series A Preferred Shares, and Longfellow owns 533,000 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. As a result, Mr. Mitchell could control substantially all matters requiring shareholder approval, including the election of directors and approval of significant corporate transactions. In addition, this concentration of ownership may delay or prevent a change in control of the Company and make some future transactions more difficult or impossible without the support of Mr. Mitchell. The interests of Mr. Mitchell may not coincide with your interests or the interests of our other shareholders.

We may seek to raise additional funds or restructure or increase our debt by issuing securities that would dilute your ownership. Depending on the terms available to us, if these activities result in significant dilution, it may negatively impact the trading price of our common shares.

We may seek to raise additional funds or restructure or increase our debt by issuing common shares, preferred shares, or securities convertible into or exercisable for common shares, that would dilute your ownership. Depending on the terms available to us, if these activities result in significant dilution, it may negatively impact the trading price of our common shares. Further, any additional financing that we secure may require the granting of rights, preferences or privileges senior to, or pari passu with, those of our common shares. Any issuances by us of equity securities may be at or below the prevailing market price of our common shares and in any event may have a dilutive impact on your ownership interest, which could cause the market price of our common shares to decline. We may also raise additional funds through the incurrence of convertible debt or the issuance or sale of other securities or instruments senior to our common shares. If we experience dilution from the issuance of additional securities and we grant superior rights to new securities over common shareholders, it may negatively impact the trading price of our common shares and you may lose all or part of your investment.

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The value of our common shares may be affected by matters not related to our own operating performance.

The value of our common shares may be affected by matters that are not related to our operating performance and which are outside of our control. These matters include the following:

• general economic conditions in the United States, Turkey, Bulgaria and globally;

• industry conditions, including fluctuations in the price of oil and natural gas;

• the ability of the members of OPEC and other exporting countries to agree to and maintain crude oil prices and production controls;

• the oil price war between Russia and Saudi Arabia;

• governmental regulation of the oil and natural gas industry, including environmental regulation and regulation of fracture stimulation activities;

• fluctuation in foreign exchange or interest rates;

• liabilities inherent in oil and natural gas operations;

• geological, technical, drilling and processing problems;

• unanticipated operating events which can reduce production or cause production to be shut in or delayed;

• the occurrence or threat of epidemic or pandemic diseases, such as the recent outbreak of coronavirus, or any government response to such occurrence or threat;

• failure to obtain industry partner and other third-party consents and approvals, when required;

• stock market volatility and market valuations;

• competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;

• the need to obtain required approvals from regulatory authorities;

• worldwide supplies and prices of, and demand for, oil and natural gas;

• political conditions and developments in each of the countries in which we operate;

• political conditions in oil and natural gas producing regions;

• revenue and operating results failing to meet expectations in any particular period;

• investor perception of the oil and natural gas industry;

• limited trading volume of our common shares;

• announcements relating to our business or the business of our competitors;

• the sale of assets;

• the issuance of common shares, debt or other securities;

• our liquidity;

• our ability to raise additional funds or restructure our debt; and

• loss of key management.

In the past, companies that have experienced volatility in the trading price of their common shares have been the subject of securities class action litigation. We might become involved in securities class action litigation in the future. Such litigation often results in substantial costs and diversion of management’s attention and resources and could have a material adverse effect on our business, financial condition and results of operation.

U.S. shareholders who hold common shares during a period when we are classified as a passive foreign investment company may be subject to certain adverse U.S. federal income tax consequences.

Management believes that we are not currently a passive foreign investment company. However, we may have been a passive foreign investment company during one or more of our prior taxable years and could become a passive foreign investment company in

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the future. In general, classification of our company as a passive foreign investment company during a period when a U.S. shareholder holds common shares could result in certain adverse U.S. federal income tax consequences to such shareholder.

Certain U.S. shareholders who hold common shares during a period when we are classified as a controlled foreign corporation may be subject to certain adverse U.S. federal income tax rules.

Management believes that we currently are a controlled foreign corporation for U.S. federal income tax purposes and that we will continue to be so treated. Consequently, a U.S. shareholder that owns 10% or more of the total combined voting power of all classes of our shares entitled to vote on the last day of our taxable year may be subject to certain adverse U.S. federal income tax rules with respect to the shareholder’s investment in us.

Item 1B. Unresolved Staff Comments

Not applicable.

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Item 2. Properties

Turkey

General. As of December 31, 2019, we held interests in four onshore exploration licenses and 20 onshore production leases covering a total of 436,388 gross (365,171 net) acres in Turkey. We acquired our interests in Turkey through acquisitions, farm-in agreements with existing third-party license holders and applications submitted to the Turkish General Directorate of Mineral and Petroleum Affairs (the “GDMPA”), the agency responsible for the regulation of oil and natural gas activities under the Ministry of Energy and Natural Resources in Turkey. The following map shows our interests in Turkey:

Reserves. As of December 31, 2019, we had total net proved reserves of 10,259 Mbbl of oil and 2,466 Mmcf of natural gas, net probable reserves of 7,212 Mbbl of oil and 845 Mmcf of natural gas and net possible reserves of 6,742 Mbbl of oil and 984 Mmcf of natural gas in Turkey.

Equipment Yards. As of December 31, 2019, we leased equipment yards in Muratli and Diyarbakir and owned an equipment yard at Gocerler. On February 24, 2020, we sold the shares in Petrogas, which held the Gocerler equipment yard. Additionally, in connection with the sale of Petrogas, Reform transferred an equipment yard in Tekirdağ to us. See “Item 1. Business—Recent Developments.”

Commercial Terms. Turkey’s fiscal regime for oil and natural gas licenses is presently comprised of royalties and income tax. The royalty rate is 12.5%. As of December 31, 2019, the corporate income tax rate was 22%. There is a 5% net profits interest burden for certain of our non-core wells in the Thrace region of Turkey.  Dividends repatriated from Turkey would be subject to a withholding tax rate of 15% unless reduced by a tax treaty. There is also an 18% value added tax. However, for exploration licenses, no value added tax is assessed on drilling, completion, workover, seismic and geologic activities.

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Licensing Regime. The licensing process in Turkey for oil and natural gas concessions occurs in three stages: permit, license, and lease. Under a permit, the government grants the non-exclusive right to conduct a geological investigation over an area. The size of the area and the term of the permit are subject to the discretion of the GDMPA. A new petroleum law was passed by the Turkish government in May 2013, amending some of the processes related to licensing and operations in Turkey. The regulations concerning implementation were passed by the Turkish government in January 2014. The existing licenses and future licensing processes are currently in a transition phase from the old petroleum law to the new petroleum law. The new law provides that operators have the option to maintain their licenses under the old petroleum law for the duration of the existing terms of a license or to convert their licenses to the new petroleum law prior to the expiration of the license.

The GDMPA awards a license after it approves the applicant’s work program, which may include obligations such as geological and geophysical work, seismic reprocessing and interpretation and contingent shooting of seismic and drilling of wells. A license grants exclusive rights over an area for the exploration for and production of petroleum.

Licensing Under the Old Petroleum Law. A license has a term of four years and requires drilling activities by the third year, but this obligation may be deferred into the fourth year by posting a bond. A license is eligible for two separate two-year extensions by fulfilling prior work commitments and subscribing to additional work commitments. A final three-year term may be granted as an appraisal period for any oil or natural gas discovery registered in the previous terms. No single company may own more than an aggregate of 100% of eight licenses within a district. Rentals are due annually based on the size of the license.

Once a discovery is made, the license holder may apply to convert the area, not to exceed 25,000 hectares (approximately 62,000 acres), to a lease. Under a lease, the lessee may produce oil and natural gas. The term of a lease is for 20 years and may be extended for two further terms of 10 years each. Annual rentals are due based on the size of the lease. The production lease holder is typically able to apply for a new exploration license covering the area of the original exploration license, minus the area of the newly-granted production lease.

Licensing Under the New Petroleum Law. A license has a term of five years and requires the license holder to post a bond equal to 2% of the cost of the work commitments to secure the fulfillment of the work commitments. Licenses shall be based on map sections of scale equal to 1/50,000 (approximately 148,000 acres) or 1/25,000 (approximately 37,000 acres). A license is eligible for two separate two-year extensions by fulfilling prior work commitments and subscribing to additional work commitments including the drilling of at least one well in each separate extension period and providing a bond to secure fulfillment of the additional work commitments. A final two-year term may be granted to appraise a petroleum discovery made during the prior terms. An additional six-month extension may be granted during any of the foregoing terms in order to complete the drilling or testing of a well.

Once a discovery is made, the license holder may apply to convert part of the license area, covering the prospective petroleum field, to a production lease. Under a lease, the lessee may produce oil and natural gas. Based on production level, the term of a lease is for between 5 and 20 years and may be extended up to 40 years in total. The production lease holder is typically able to apply for a new exploration license covering the area of the original exploration license, minus the area of the newly-granted production lease.

The expiration dates reported on our exploration licenses and production leases below are subject to various extensions available under the old petroleum law and the new petroleum law. Those portions of exploration licenses with production are available during any term for conversion to a production lease with a term of between 5 and 20 years plus further extensions if production is maintained. We have converted some of our qualifying acreage into the new petroleum law regulations.  Conversion into the new petroleum law provides for the renewal of the exploration license terms for qualifying acreage.

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Southeastern Turkey. The following mapshows our interests in Southeastern Turkey at December 31, 2019:

Arpatepe (Production Lease 5003). We own a 50% working interest in Production Lease 5003, which covers approximately 11,200 gross acres. For 2019, our wellhead production of oil from the Arpatepe field was 42,340 Bbls of oil, at an average rate of 116 Bbl/d.  We are the operator of this production lease, which expires in November 2028, with extensions available under the new petroleum laws.

Bakuk (Production Lease 5043). We own a 50% working interest in Production Lease 5043, which covers approximately 34,400 gross acres.  Park Place Energy, Ltd. is the operator of this production lease, which expires in January 2032, with extensions available under the new petroleum laws. The Bakuk-1R well was shut in during 2017 for security precautions and remained shut in during 2019.

Bati Yasince (Production Lease M45-A1-1). We own a 100% operated working interest in Production LeaseM45-A1-1, which covers 7,200 gross acres.  We are the operator of this production lease, with extensions available under the new petroleum laws. We applied for an extension of this production lease in November 2019.  During 2019, we reentered the Bati-Yasince-1 well, targeting the Hazro formation.

Göksu (Production Lease M45-A4-1). We own a 100% operated working interest in Production LeaseM45-A4-1, which covers approximately 14,500 gross acres. For 2019, our wellhead production of oil from this production lease was 14,965 Bbls of oil, at an average rate of 41 Bbls/d. We are the operator of this production lease, which expires in December 2020, with extensions available under the new petroleum laws.  We expect to apply for extension of this production lease in 2020.

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New Molla (Production Lease M45 -A1-2). We own a 100% operated working interest in the Bahar wells inProduction LeaseM45-A1-2, which coversapproximately 24,130 gross acres. For 2019, our wellhead production of oil from the Bahar wells was 302,585 Bbls of oil, at an average rate of 829 Bbl/d. We are the operator of thisproduction lease, which expires in March 2039, with extensions available under the new petroleum laws.During 2019, we drilled the Southeast Bahar-1 well and the Bahar-12 well, both of which began producing in 2019.

New Molla (Production Lease M45 -A2-1). We own a 100% operated working interest in Production Lease M45-A2-1, which covers approximately 29,331 gross acres.  We are the operator of this production lease, which expires in March 2024, with extensions available under the new petroleum laws.  During 2019, we drilled the Blackeye-1 well which began producing in 2019.

West Molla (Production Lease M44-B2-1). We own a 100% operated working interest in Production Lease M44-B2-1. In 2019, our wellhead production of oil from this production lease was 152,935 Bbls of oil, at an average rate of 419 Bbl/d. We are the operator of this production lease, which expires in June 2023, with extensions available under the new petroleum laws. During 2019, we drilled the Yeniev-4, Yeniev-5 and Yeniev-6 wells on this production lease. These wells began producing in 2019.

Selmo (Production Lease 829). We own a 100% operated working interest in Production Lease 829, which covers approximately 8,900 gross acres and includes the Selmo oil field.  For 2019, our wellhead production of oil in the Selmo field was 486,545 Bbls of oil, at an average rate of 1,333 Bbl/d. We are the operator of this production lease, which expires in June 2025.  

Selmo (Exploration License L46-C1). We own a 100% operated working interest in Exploration License L46-C1, which covers 28,921 gross acres. We are the operator of this exploration license, which expires in November 2023, with extensions available under the new petroleum laws.

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Northwestern Turkey. The following map shows our interests in northwestern Turkey at December 31, 2019:

Adatepe (Production Lease 4959). We owned a 50% operated working interest in Production Lease 4959, which covers 3,086 gross acres.  We were the operator of this production lease, which expires in September 2031, with extensions available under the new petroleum laws. On February 24, 2020, we sold the shares in Petrogas, which held this production lease. See “Item 1. Business—Recent Developments.”

Alpullu (Production Lease 4794) and Temrez (Exploration Licenses F17-B3, F18-A3, F18-A4, and F18-B4). We own a 100% operated working interest in this production lease and these exploration licenses, which cover 3,158 acres and 119,865 acres, respectively.  We are the operator of this production lease and these exploration licenses, which expire in September 2028 and July 2020, respectively, with extensions available under the new petroleum laws. In 2019, we drilled the Karli-1 well.

Banarli (Production Lease 5059). We own a 50% operated working interest in Production Lease 5059, which covers 4,608 gross acres.  We are the operator of this production lease, which expires in February 2032, with extensions available under the new petroleum laws.

Dogu Adatepe (Production Lease F19-B4-1). We owned a 50% working interest in Production Lease F19-B4-1, which covers part of our former Cayirdere license and approximately 4,000 gross acres. TPAO is the operator of this production lease, which expires in October 2020, with an additional 32 years of extensions under the new petroleum laws available with the maintenance of production on the lease. On February 24, 2020, we sold the shares in Petrogas, which held this production lease. See “Item 1. Business—Recent Developments.”

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Edirne (Production Leases Ortakci E17-B4-1, Arpaci-Ikihoyuk E17-C2-1, and Umur-Kuzey Arpaci E17-C1-1) and Habiller (Production Lease Kisla E17-C1-2). We owned a 55% operated working interest in Production Leases Ortakci E17-B4-1, Arpaci-Ikihoyuk E17-C2-1, and Umur-Kuzey Arpaci E17-C1-1and a 100% operated working interest in Production Lease Kisla E17-C1-2, which cover an aggregate of approximately 65,000 gross acres.  We were the operator of these production leases, which each expire in 2020, with extensions available under the new petroleum laws. On February 24, 2020, we sold the shares in Petrogas, which held these production leases. See “Item 1. Business—Recent Developments.”

Gocerler (Production Lease 4200 and Production Leases E18-C3-2, E19-D4-1, and F19-A1-1). We owned a 50% operated working interest in Production Lease 4200 and Production Leases E18-C3-2, E19-D4-1, and F19-A1-1, which cover approximately 3,363 gross acres and 37,000 gross acres, respectively.  We were the operator of these production leases, which expire in May 2023 and August 2021 through August 2025, respectively, with extensions available under the new petroleum laws. On February 24, 2020, we sold the shares in Petrogas, which held these production leases. See “Item 1. Business—Recent Developments.”

In 2019, our net wellhead production was 197,753 Mcf at an average rate of 542 Mcf/d from all the gas fields listed above.

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Bulgaria

General. As of December 31, 2019, we operated and held interests in one production concession in Bulgaria.  In January 2012, the Bulgarian Parliament enacted legislation that banned the fracture stimulation of oil and natural gas wells in the Republic of Bulgaria. The legislation also had the effect of preventing conventional drilling and completion activities. In June 2012, the Bulgarian Parliament amended the legislation to clarify that conventional drilling and completion activities were not intended to be affected by the law. As long as this legislation remains in effect, completion activity, production from our cased cemented existing wells, and our unconventional natural gas exploration, development, and production activities in Bulgaria will be significantly constrained. The following map shows our interests in Bulgaria at December 31, 2019:

Reserves. As of December 31, 2019, there were no reserves associated with our properties in Bulgaria.

Commercial Terms. Bulgaria’s petroleum laws provide a framework for investment and operation that allows foreign investors to retain the proceeds from the sale of petroleum production. The fiscal regime is comprised of royalties and income tax.

The royalty ranges from 2.5% to 30%, based on an “R factor” which is particular to each production concession agreement, but is typically calculated by dividing the total cumulative revenues from a production concession by the total cumulative costs incurred for that production concession.

The production concession holder pays Bulgarian corporate income tax, which is assessed at a rate of 10%. All costs incurred in connection with exploration, development, and production operations are deductible for corporate income tax purposes.

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Resident companies which remit dividends outside of Bulgaria are subject to a dividend withholding tax between 10% and 15%, depending on the proportion of the capital owned by the recipient. No customs duty is payable on the export of petroleum, however a customs duty may be payable on the import of material necessary to conduct petroleum operations in certain conditions. There is also a 20% value added tax. Oil is priced at market while natural gas is tied to a bundle pricing based in part on the import price and in part on the domestic price.

Licensing Regime. The licensing process in Bulgaria for oil and natural gas concessions occurs in two stages: exploration permit and then production concession.

Under an exploration permit, the government grants exploration rights for a term of up to five years to conduct seismic and other exploratory activities, including drilling. The recipient of an exploration permit commits to a work program and posts a bank guarantee in the amount of 10% of the estimated cost for the program. The area covered by an onshore exploration permit may be as large as 5,000 square kilometers. The exploration permit may be extended for up to two additional two-year terms, subject to fulfillment of minimum work programs, and may be extended for an additional one-year term in order to appraise potential geologic discoveries. Interests under an exploration permit are transferable, subject to government approval. The permit holder is required to pay an annual area fee equal to 40 Bulgarian Lev (approximately $23 at December 31, 2019) per square kilometer, or 40 Bulgarian Lev (approximately $23 at December 31, 2019) per square kilometer in the event the permit term is extended.

Upon the registration of a commercial discovery, an exploration permit holder may apply for a production concession. The production concession size corresponds to the area of the commercial discovery. The duration of a production concession is 35 years and may be extended by a further 15 years subject to the terms and conditions of the production concession agreement. Interests under a production concession are transferable, subject to government approval. No bonus is paid to the government by us upon conversion to a production concession.

Koynare. We own a 100% working interest, subject to a 3.02% overriding royalty interest, in the Koynare production concession covering approximately 163,000 acres. The Koynare Concession Area contains the Devinci-R1 well, where we discovered a reservoir in the Jurassic-aged Ozirovo formation at a depth of approximately 13,800 feet, which the Bulgarian government has certified as a geologic and commercial discovery. We commenced the side-track and re-drilling of the Deventci R-1 well in December 2018, targeting the Ozirovu and Dolmi Dabnik formations. The well was drilled to a total depth of 16,450 feet. Although we encountered the targeted formations, tests did not indicate commercial quantities of reservoir quality rock, and we plugged and abandoned the well.  We are currently evaluating future activity in Bulgaria.  For purposes of our royalty conversion under the “R” factor, we have a cost recovery pool of approximately $47.2 million at December 31, 2019.

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Summary of Oil and Natural Gas Reserves

The following table summarizes our net proved, probable, and possible reserves at December 31, 2019.  

	Reserves
	Oil and Condensate (Mbbl)		Natural Gas (Mmcf)		Total (Mboe)
Reserves Category
Total (1)
Proved reserves
Proved developed		5,624		2,281		6,004
Proved undeveloped		4,635		185		4,666
Total proved		10,259		2,466		10,670
Probable reserves
Probable developed		920		815		1,056
Probable undeveloped		6,292		30		6,297
Total probable		7,212		845		7,353
Possible reserves
Possible developed		1,062		951		1,221
Possible undeveloped		5,680		33		5,686
Total possible		6,742		984		6,906

(1) All of our reserves are located in Turkey

Value of Proved Reserves

The following table shows our estimated future net revenue, Standardized Measure, and PV-10 as of December 31, 2019:

	Total
	(in thousands)
Future net revenue	$	433,131
Total Standardized Measure (1)	$	234,468
Total PV-10 (2)	$	288,510

(1) DeGolyer and MacNaughton did not estimate the Standardized Measure.  

(2) The PV-10 value of the estimated future net revenue is not intended to represent the current market value of the estimated oil and natural gas reserves we own. Management believes that the presentation of PV-10, while not a financial measure in accordance with U.S. GAAP, provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and natural gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of financial or operating performance under U.S. GAAP. PV-10 should not be considered as an alternative to the Standardized Measure as defined under U.S. GAAP. The Standardized Measure represents the PV-10 after giving effect to income taxes. The following table provides a reconciliation of our PV-10 to our Standardized Measure:

	Total
	(in thousands)
Total PV-10	$	288,510
Future income taxes (1)		(76,762	)
Discount of future income taxes at 10% per annum (1)		22,720
Standardized Measure (1)	$	234,468

(1) DeGolyer and MacNaughton did not estimate future income taxes, the discount of future income taxes at 10% per annum, or the Standardized Measure.

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.”

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At December 31, 2019, our estimated proved reserves were 10,670 Mboe, anincreaseof 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 5.9%, 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.  

Probable Reserves

Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions 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.”

When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir. Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

Possible Reserves

Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions 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.”

When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates. Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project. Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

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Internal Controls

Management has established, and is responsible for, a number of internal controls designed to provide reasonable assurance that the estimates of proved, probable, and possible reserves are computed and reported in accordance with rules and regulations provided by the SEC as well as established industry practices used by independent engineering firms and our peers. These internal controls consist of documented process workflows and qualified professional engineering and geological personnel with specific reservoir experience. We also retained an outside independent engineering firm to prepare estimates of our proved, probable, and possible reserves for Turkey. We work closely with this firm, and management is responsible for providing accurate operating and technical data to it. Management has tested the processes and controls regarding our reserves estimates for 2019. Senior management reviews and approves our reserves estimates, whether prepared internally or by third parties. In addition, our audit committee serves as our reserves committee and is composed of three outside directors, all of whom have experience in the review of energy company reserves evaluations. The audit committee reviews the final reserves estimate and also meets with representatives from the outside engineering firm to discuss their process and findings.

Oil and Natural Gas Reserves under U.S. Law

In the United States, we are required to disclose proved reserves, and we are permitted to disclose probable and possible reserves, using the standards contained in Rule 4-10(a) of the SEC’s Regulation S-X. The estimates of proved, probable, and possible reserves presented as of December 31, 2019 for Turkey have been prepared by DeGolyer and MacNaughton, our external engineers. The technical person at DeGolyer and MacNaughton that is primarily responsible for overseeing the preparation of our reserves estimates is a Registered Professional Engineer in the State of Texas and has a Bachelor of Science degree in Petroleum Engineering from Texas A&M University. He has over 35 years of experience in oil and natural gas reservoir studies and evaluations and is a member of the Society of Petroleum Engineers.

We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with DeGolyer and MacNaughton to ensure the integrity, accuracy and timeliness of data furnished to them for the preparation of their reserves estimates. Our vice president of engineering has over 12 years of experience in oil and natural gas reservoir studies and evaluations. He has a BASC (Engineering) from the University of British Columbia and is a registered Professional Engineer (Alberta).

Estimates of oil and natural gas reserves are projections based on a process involving an independent third-party engineering firm’s collection of all required geologic, geophysical, engineering and economic data, and such firm’s complete external preparation of all required estimates and are forward-looking in nature. These reports rely upon various assumptions, including assumptions required by the SEC, such as constant oil and natural gas prices, operating expenses and future capital costs. We also make assumptions relating to availability of funds and timing of capital expenditures for development of our proved undeveloped, probable, and possible reserves. These reports should not be construed as the current market value of our reserves. The process of estimating oil and natural gas reserves is also dependent on geological, engineering and economic data for each reservoir. Because of the uncertainties inherent in the interpretation of this data, we cannot ensure that the reserves will ultimately be realized. Our actual results could differ materially. See “Supplemental Information-Supplemental oil and natural gas reserves information (unaudited)” to our consolidated financial statements for additional information regarding our oil and natural gas reserves.

The technologies and economic data used in the estimation of our proved, probable, and possible reserves include, but are not limited to, electrical logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity. These wells were considered to be analogous based on production performance from the same formation and completion using similar techniques.

The estimates of proved, probable, and possible reserves prepared by DeGolyer and MacNaughton for the year ended December 31, 2019 included a detailed evaluation of our Selmo, Arpatepe, Bakuk, Molla, and certain Thrace Basin properties in Turkey. DeGolyer and MacNaughton determined that their estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about whether proved reserves are economically producible from a given date forward, under existing economic conditions, operating methods and government regulations, consistent with the definition in Rule 4-10(a)(24) of SEC Regulation S-X.

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Oil and Natural Gas Reserves under Canadian Law

As a reporting issuer under Alberta, British Columbia and Ontario securities laws, we are required under Canadian law to comply with National Instrument 51-101 “Standards of Disclosure for Oil and Gas Activities” (“NI 51-101”) implemented by the members of the Canadian Securities Administrators in all of our reserves related disclosures. DeGolyer and MacNaughton evaluated our reserves as of December 31, 2019 for Turkey in accordance with the reserves definitions of NI 51-101 and the Canadian Oil and Gas Evaluators Handbook (“COGEH”). Our annual oil and natural gas reserves disclosures prepared in accordance with NI 51-101 and COGEH and filed in Canada are available at www.sedar.com.

Oil and Natural Gas Sales Volumes

The following table sets forth our sales volumes of oil and natural gas (including by field for any field that contained 15% or more of our total proved reserves) for 2019 and 2018:

	Sales Volumes
	Oil (1)		Natural Gas		Total
Year	(Bbls)		(Mcf)		(Boe)
2019
Total Turkey		1,004,980		197,753		1,037,939
Selmo field		485,760		–		485,760
Bahar field		303,534		–		303,534
Yeniev field		151,870		–		151,870
2018
Total Turkey		1,020,144		211,686		1,055,425
Selmo field		570,189		–		570,189
Bahar field		322,129		–		322,129

(1) “Oil” volumes include condensate (light oil) and medium crude oil.

Average Sales Price and Production Costs

The following table sets forth the average sales price per Bbl of oil and Mcf of natural gas and the average production cost, not including ad valorem and severance taxes, per unit of production for each of 2019 and 2018:

	2019		2018
Turkey:
Average Sales Price Oil ($/Bbl)	$	65.34	$	67.84
Natural Gas ($/Mcf)	$	5.88	$	5.01
Unit Costs Production ($/Boe)	$	9.85	$	8.93

Drilling Activity

The following table sets forth the number of net productive and dry exploratory wells and net productive and dry development wells we drilled in 2019 and 2018:  

	Development Wells				Exploratory Wells
	Productive		Dry		Productive		Dry
Turkey:
2019		3.0		–		3.0		–
2018		3.0		–		2.0		–
Bulgaria:
2019		–		–		–		1.0
2018		–		–		–		–

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Oil and Natural Gas Properties, Wells, Operations and Acreage

Productive Wells. The following table sets forth the number of productive wells (wells that were producing oil or natural gas or were capable of production) in which we held a working interest as of December 31, 2019: 

	Oil				Natural Gas
	Gross (1)		Net (2)		Gross (1)		Net (2)
Turkey		75.0		73.0		33.0		23.5
Bulgaria		–		–		–		–

(1) “Gross wells” means the wells in which we held a working interest (operating or non-operating).

(2) “Net wells” means the sum of the fractional working interests owned in gross wells.

Developed Acreage. The following table sets forth our total gross and net developed acreage as of December 31, 2019:  

	Developed Acres
	Gross (1)		Net (2)
Turkey		287,601		216,384
Bulgaria		–		–
Total		287,601		216,384

(1) “Gross” means the total number of acres in which we had a working interest.

(2) “Net” means the sum of the fractional working interests owned in gross acres.

Undeveloped Acreage. The following table sets forth our undeveloped land position as of December 31, 2019: 

	Undeveloped Acres
	Gross (1)		Net (2)
Turkey		148,787		148,787
Bulgaria		162,800		162,800
Total		311,587		311,587

(1) “Gross” means the total number of acres in which we had a working interest.

(2) “Net” means the sum of the fractional working interests owned in gross acres.

Undeveloped Acreage Expirations. The following table summarizes by year our undeveloped acreage as of December 31, 2019 that is scheduled to expire in the next five years:

	Undeveloped Acres				% of Total Undeveloped Acres
	Gross (1)		Net (2)		Net (2)
2020		119,865		119,865		38.5
2021		-		-		–
2022		-		-		–
2023		28,922		28,922		9.3
2024		-		-		–

(1) “Gross” means the total number of acres in which we had a working interest.

(2) “Net” means the sum of the fractional working interests owned in gross acres.

We anticipate that we will be able to extend the license terms for substantially all of our undeveloped acreage in Turkey scheduled to expire in 2020 through the execution of our current work commitments.

Item 3. Legal Proceedings

TEMI Litigation. TEMI has been involved in a number of lawsuits with a group of villagers living around the Selmo oil field who claim ownership of a portion of the surface at Selmo in order to claim a legal right with respect to the receipt of surface use damages and land rental fees. These cases are being vigorously defended by TEMI and Turkish government authorities. We do not have enough information to estimate the potential additional operating costs we could incur in the event the purported surface owners’ claims are ultimately successful. The following is a summary of these cases.

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In 2003, the villagers applied to the Kozluk Civil Court of First Instance in Turkey with seven title survey certificates dating back to Ottoman times. These villagers were granted title registration certificates, and in 2005, these villagers applied to the Kozluk Civil Court of First Instance to enlarge the areas covered by the certificates to approximately 20 square kilometers. Neither we nor, to our knowledge, any ministry in the Turkish government received notice of this court proceeding. Almost all of our production wells at the Selmo oil field lie within this enlarged area. In 2009, the Supreme Court overruled the Kozluk Civil Court of First Instance and directed it to re-examine the case (the “Surface Litigation”). On June 27, 2012, the Kozluk Civil Court of First Instance dismissed the Surface Litigation. The court issued its formal decision on August 8, 2012, and the plaintiffs filed an appeal with the Court of Appeal. The decision was reversed by the Court of Appeal and sent back to the Kozluk Civil Court of First Instance in August 2014. The Court of Appeals ruled that the Kozluk Civil Court of First Instance investigate the merits of the dispute to determine the ownership position of the parties, that TPAO should be added as a party to the litigation, and that the cadastral map sheet depicting the real properties at issue must be investigated.  The parties then appealed to the Court of Appeals for correction of judgment. The file was reversed by the Court of Appeals and sent back to the Kozluk Cadastre Court on May 4,2015.TheKozluk Cadastre Court merged the Surface Litigation with other similar files and dismissed the Surface Litigation. The plaintiffs then appealed to the Court of Appeals. On March 4, 2018, the Court of Appeals sent the Surface Litigation back to the Kozluk Cadastre Court on the grounds of insufficient examination. The Kozluk Cadastre Court is conducting notification procedures. Upon the completion of the notification procedures, the Surface Litigation will be resent to the Court of Appeals for correction of judgment.

In 2006, the Turkish Forestry Authority filed a claim in the Kozluk Cadastre Court against the villagers for attempting to register land that is registered with the Turkish government as forest. TEMI joined the Turkish government as a plaintiff in that case. On January 15, 2016, the Kozluk Cadastre Court merged this case with the Surface Litigation.

In addition, TEMI is a defendant in two nuisance cases filed in the Kozluk Cadastre Court and two claims for damages filed in the Kozluk Civil Court of First Instance. The plaintiffs in the nuisance cases are the same villagers in the Surface Litigation. The plaintiff in the damages cases is a single villager. The Turkish Treasury Department and the Turkish Forestry Authority have joined TEMI as defendants in each of these cases. The Kozluk Cadastre Court has decided to suspend each of the nuisance cases until there is a resolution of the Surface Litigation. On December 27, 2012, the Kozluk Civil Court of First Instance dismissed the first damages case, and the plaintiff appealed that decision. In June 2015, the Court of Appeal reversed that decision and sent the case back to the Kozluk Civil Court of First Instance. In May 2016, the Kozluk Civil Court of First Instance decided to merge the two damages cases (as the parties and the facts underlying each damages case are substantially the same and the primary difference is the time period for which the plaintiff is seeking damages) and suspend the merged damages case until there is a resolution of the Surface Litigation.

We continue to operate on the surface at Selmo and have paid surface damages and rentals for locations at Selmo from the time we began operating the Selmo lease to present.

Bulgarian Minister of Energy. 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 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.

TUPRAS Litigation. During 2019, we sold $65.8 million of oil to TUPRAS, representing 97.7% of our total revenues. 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 4^th Civil Court of First Instance seeking restitution from TEMI for alleged overpayments resulting from the implementation of

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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.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Shares and Dividends

Our common stock is traded on the NYSE American exchange under the symbol TAT. As of March 20, 2020, we had 62,349,063 common shares issued and outstanding and held by 167 record holders, including nominee holders such as banks and brokerage firms who hold shares for beneficial owners.

We have not declared any dividends to date on our common shares. We have no present intention of paying any cash dividends on our common shares in the foreseeable future, as we intend to use cash flow from operations to invest in our business.

Foreign Exchange Control Regulations

We have been designated as a non-resident for Bermuda exchange control purposes by the Bermuda Monetary Authority. Because of this designation, there are no restrictions on our ability to transfer funds in and out of Bermuda.

The transfer of shares between persons regarded as residents outside Bermuda for exchange control purposes and the sale of our common shares to or by such persons may take place without specific consent under the Exchange Control Act 1972. Issuances and transfers of shares involving any person regarded as a resident in Bermuda for exchange control purposes require specific approval under the Exchange Control Act 1972.

As an “exempted company,” we are exempt from Bermuda laws which restrict the percentage of share capital that may be held by non-Bermuda residents, but as an exempted company, we may not participate in certain business transactions, including: (1) the acquisition or holding of land in Bermuda (except that required for our business and held by way of lease or tenancy for terms of not more than 50 years) without the express authorization of the Bermuda legislature, (2) the taking of mortgages on land in Bermuda to secure an amount in excess of $50,000 without the consent of the Minister of Finance, (3) the acquisition of any bonds or debentures secured by any land in Bermuda, other than certain types of Bermuda government securities, or (4) the carrying on of business of any kind in Bermuda, except in furtherance of our business carried on outside Bermuda.  

Item 6. Selected Financial Data

Not applicable.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored, petroleum systems, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of December 31, 2019, we held interests in 365,171 and 162,800 net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria, respectively. As of March 20, 2020, Mr. Mitchell beneficially owned approximately 49.9% of our outstanding common shares. Persons and entities associated with Mr. Mitchell also owned 739,000 of our 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.  

Recent Oil Price Decline and Going Concern

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.  

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

2019 Financial and Operational Performance

• We derived 98.3% of our revenues from the production of oil and 1.7% of our revenues from the production of natural gas during the year ended December 31, 2019.

• Total oil and natural gas sales revenues decreased 4.9% to $66.8 million for in 2019, compared to $70.3 million in 2018. The decrease was primarily the result of a decrease in our average realized price which decreased $2.19 to $64.39 per Boe in 2019 compared to $66.58 per Boe in 2018, resulting in a $2.3 million decrease in revenue.  Additionally, revenues decreased $1.1 million due to a decrease in our sales volumes of 17 Mboe.

• Sales volumes were 1,005 Mbbls of oil and 198 Mmcf of natural gas in 2019, as compared to 1,020 Mbbls of oil and 212 Mmcf of natural gas in 2018.

• In 2019, we incurred $31.0 million in total capital expenditures, including license acquisition, seismic and corporate expenditures, as compared to $23.7 million in total capital expenditures in 2018.

• As of December 31, 2019, we had $2.9 million in long-term debt, $17.1 million in short-term debt and $46.1 million in Series A Preferred Shares, as compared to no long-term debt, $22.0 million in short-term debt and $46.1 million Series A Preferred Shares as of December 31, 2018.

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2019 Operations

Southeastern Turkey

Molla

We reprocessed approximately 1,023 square kilometers of 3D seismic to better evaluate our acreage.

Yeniev Field. We drilled the Yeniev-4 well to a total measured depth of 9,520 feet for a drilling cost of approximately $2.5 million. We successfully recovered 84 feet of core from the Bedinan sandstone. The well was completed naturally in the Bedinan sandstone with an unstimulated initial production rate of 167 Bbl/d.

We drilled the Yeniev-5 well to a total measured depth of 7,060 feet for a drilling cost of approximately $2.0 million. We successfully recovered 159 feet of core from two intervals within the Mardin, both of which showed live streaming oil on the cores. The well was completed in the Mardin formation with an initial production rate of 75 Bbl/d.

We drilled the Yeniev-6 well to a total measured depth of 9,650 feet for a drilling cost of approximately $3.0 million. The well was completed in the Bedinan sandstone with an unstimulated initial production rate of 110 Bbl/d, which increased to 135 Bbl/d following stimulation.

Bahar Field. We drilled the Southeast Bahar-1 well to a total measured depth of 11,000 feet for a drilling cost of approximately $5.0 million. Oil shows were observed in both the Bedinan and Mardin formations. The well was completed in the Bedinan sandstone with an initial production rate of 71 Bbl/d. After a production test period the Bedinan was temporarily suspended to test uphole oil shows in the Hazro and Mardin formations. Completions operations are ongoing.

We drilled the Bahar-12 well to a total measured depth of 10,790 feet for a drilling cost of approximately $4.2 million. We successfully recovered a total of 274 feet of core from intervals within the Bedinan and Hazro formations. A three-stage Bedinan stimulation was executed. The well had an initial production rate of 382 Bbl/d flowing naturally.

Bati-Yasince Field. We redrilled the Bati-Yasince-1 well to a total measured depth of 8,628 feet for a drilling cost of approximately $1.3 million. We tested several intervals within the Hazro and Mardin but were unable to establish commercial production.

Blackeye Field. We drilled the Blackeye-1 well to a total measured depth of 11,105 feet for a drilling cost of approximately $2.8 million. The well encountered oil shows in the Hazro, Mardin, and Bedinan formations. The well was completed in the Hazro formation with an initial production rate of 34 Bbl/d.

Arpatepe Field. We engaged in technical design and planning of a waterflood of the Arpatepe field.  Following completion of the design and planning, we along with our partners, have approved the implementation of full field water development.

Selmo

We re-entered the Selmo-1 well for a cost of approximately $0.8 million. During a short-term flow test of a previously untested interval, the well tested 29 Bbl/d of 45.6 API condensate along with 8.5 Mmcf/d of natural gas containing a high carbon dioxide percentage component. The well was suspended following the production test.

Northwestern Turkey

We reprocessed approximately 715 square kilometers of 3D seismic to better evaluate our acreage.

We drilled the Karli-1 well to a total measured depth of 1,289 feet for a drilling cost of approximately $0.3 million. While the shallow gas horizon proved non-productive, the well may be deepened at a later time.

Bulgaria

We reentered the Deventci R-1 well and executed a side-track to a total depth of 16,450 feet for a drilling cost of approximately $6.3 million. Although we encountered the targeted formations, tests did not indicate commercial quantities of reservoir quality rock, and we plugged and abandoned the well.

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Current Operations

Southeastern Turkey

Molla

During 2020, we plan to continue our recompletion, workover, and production optimization plans in our producing fields, including Bahar, Yeniev, Goksu, Pinar, Southeast Bahar, Catak, and Karagoz. Drilling additional wells will be dependent on oil prices.

Bahar Field. In the first quarter of 2020, we started construction of phase II electrification of the Bahar field to replace diesel generated power with gas generated power, which will be distributed to each well in the field. The phase II electrification is expected to be completed and operational in the second quarter of 2020.

Goksu Field. We whipstocked the Goksu-4H well in January 2020. The well was re-drilled to a total depth of 5,720 feet. Although we encountered high permeability in the Mardin formation, tests did not indicate commercial quantities of oil.

Arpatepe Field. In the first quarter of 2020, we started implementation of a full field waterflood of the Arpatepe field. We plan to recomplete four wells in the field as water injection wells and one well as a water source well. Additionally, we plan to build a central facility and gathering system to handle increased volumes.

Selmo

During 2020, we plan to continue our recompletion, workover, and production optimization operations in the Selmo field.

Bulgaria

We are currently evaluating future activity in Bulgaria.

Planned Operations

We expect our net field capital expenditures for 2020 to range between $2.5 million and $15.0 million. We expect net field capital expenditures during 2020 to include between $1.0 million and $9.0 million in drilling and completion expense for between one and five planned wells, between $1.0 million and $3.0 million for recompletions, between $1.0 million and $2.0 million implementing a waterflood in the Bedinan sandstone in the Arpatepe field, and approximately $1.0 million in facilities upgrades to our natural gas power generation infrastructure. Our projected 2020 capital expenditure budget is subject to change.

Critical Accounting Policies

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosures. Our significant accounting policies are described in “Note 3—Significant accounting policies” to our consolidated financial statements included in this Annual Report on Form 10-K. We have identified below policies that are of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. These estimates are based on historical experience, information received from third parties, and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions.

We believe the following critical accounting policies affect the significant judgments and estimates used in the preparation of our consolidated financial statements.

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

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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 generally 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.

Impairment of Long-Lived Assets. We follow the provisions of Accounting Standards Codification (“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.

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 will be accounted for by applying the acquisition method.

Foreign Currency Translation and Remeasurement. We follow ASC 830, Foreign Currency Matters (“ASC 830”) which requires the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation. The functional currency for each of our subsidiaries in Turkey and Bulgaria is the local currency. For certain entities, translation adjustments result from the process of translating the functional currency of the foreign operation’s financial statements into our U.S. Dollar reporting currency, which is a non-cash transaction. These translation adjustments are reported separately and accumulated in the consolidated balance sheets as a component of accumulated other comprehensive loss.

ASC 830 requires the assets, liabilities, and results of operations of a foreign operation to be measured using the functional currency of that foreign operation. Exchange gains or losses from re-measuring transactions and monetary accounts in a currency other than the functional currency are included in current earnings.

Oil and Gas Reserves. The estimates of proved oil and natural gas reserves utilized in the preparation of the consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. We engaged DeGolyer and MacNaughton, our independent reserve engineers, to independently evaluate our Turkey and Bulgaria properties that result in estimates for all of our estimated proved reserves at December 31, 2019.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates while decreases in recoverable economic volumes generally increase per unit depletion rates.

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 are measured using enacted tax rates expected to apply to taxable income in the years in which those

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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.

Other Recent Accounting Pronouncements and Reporting Rules.

     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.

     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.

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Results of Operations—Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

	Year Ended December 31,						Change
	2019			2018			2019-2018
	(in thousands of U.S. Dollars, except per unit amounts and production volumes)
Sales volumes:
Oil (Mbbl)		1,005			1,020			(15	)
Natural gas (Mmcf)		198			212			(14	)
Total production (Mboe)		1,038			1,055			(17	)
Average daily sales volumes (Boepd)		2,844			2,892			(48	)
Average prices:
Oil (per Bbl)	$	65.34		$	67.84		$	(2.50	)
Natural gas (per Mcf)	$	5.88		$	5.01		$	0.87
Oil equivalent (per Boe)	$	64.39		$	66.58		$	(2.19	)
Revenues:
Oil and natural gas sales	$	66,829		$	70,268		$	(3,439	)
Other		551			521			30
Total revenues		67,380			70,789			(3,409	)
Costs and expenses:
Production		11,674			10,769			905
Transportation costs		5,101			4,665			436
Exploration, abandonment and impairment		6,267			401			5,866
Seismic and other exploration		330			489			(159	)
General and administrative		11,785			14,719			(2,934	)
Depletion		12,702			13,387			(685	)
Depreciation and amortization		525			672			(147	)
Interest and other expense		10,667			10,048			619
Foreign exchange loss		4,569			10,292			(5,723	)
Deferred income tax expense		5,775			6,854			(1,079	)
(Loss) gain on commodity derivative contracts:
Cash settlements on derivative contracts		-			(4,012	)		4,012
Change in fair value on derivative contracts		(966	)		2,215			(3,181	)
Total loss on derivative contracts		(966	)		(1,797	)		831
Oil and natural gas costs per Boe:
Production	$	9.85		$	8.93		$	0.92
Depletion	$	10.71		$	11.10		$	(0.39	)

Oil and Natural Gas Sales. Total oil and natural gas sales decreased to $66.8 million in 2019 compared to $70.3 million in 2018. The $3.4 million decrease was primarily a result of a decrease in our average realized price by $2.19 to $64.39 per Boe in 2019, compared to $66.58 per Boe in 2018, resulting in a $2.3 million decrease in revenue. Additionally, revenues decreased $1.1 million due to a decrease in sales volumes of 17 Mboe.  Our sales of oil are denominated in U.S. Dollars and are not impacted by foreign exchange rates.

Production. Production expenses in 2019 increased to $11.7 million or $9.85 per Boe, compared to $10.8 million or $8.93 per Boe in 2018.  The $0.9 million increase was primarily due to increased costs for electricity, rental equipment, diesel fuel consumption and repairs and maintenance compared to the same period in 2018.  

Transportation and Processing. Transportation and processing expense increased to $5.1 million in 2019 compared to $4.7 million in 2018. The increase was due to an increase in the service cost per barrel as compared to 2018.

Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs increased to $6.3 million in 2019, compared to $0.4 million in 2018.  The increase was primarily due to the exploratory dry hole write-off of the Deventci R-1 well.

Seismic and Other Exploration. Seismic and other exploration costs decreased to $0.3 million in 2019, compared to $0.5 million in 2018. The decrease was primarily due to lower seismic acquisition activities conducted during 2019.

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General and Administrative. General and administrative expense decreased$2.9 million to $11.8 million in 2019, compared to $14.7 million in 2018. The decrease was primarily due to decreases in wages and professional fees associated with the evaluation of strategic alternatives in 2018.

Depletion. Depletion expense decreased to $12.7 million or $10.71 per Boe in 2019, compared to $13.4 million or $11.10 per Boe in 2018. The decrease was due primarily to a reduction in our sales volumes year-over-year.

Interest and Other Expense. Interest and other expense increased to $10.7 million in 2019, compared to $10.0 million in 2018. The increase was primarily due to a higher average interest rates during 2019 as compared to 2018.

Foreign Exchange Loss. We recorded a foreign exchange loss of $4.6 million in 2019, compared to $10.3 million in 2018. The change in foreign exchange is primarily unrealized (non-cash) in nature and results from the re-measuring of specific transactions and monetary accounts in a currency other than the functional currency. For example, a U.S. Dollar transaction which occurs in Turkey is re-measured at the period-end to the TRY amount if it has not been settled previously. Generally, a strengthening of the U.S.Dollar to the TRY increases our foreign exchange loss. The decrease in foreign exchange loss in 2019 was due to a 13.0% devaluation of the TRY compared to the U.S. Dollar in 2019, compared to a 39.5% devaluation during 2018 and was partially offset by fluctuations in our U.S. Dollar denominated balances in Turkey. At December 31, 2019, the exchange rate was 5.9402 as compared to 5.2609 at December 31, 2018.  

Deferred Income Tax Expense. Deferred income tax expense decreased to an expense of $5.8 million in 2019, compared to a $6.9 million expense in 2018.  The decrease was primarily due to changes in our deferred tax liabilities related to our permanent reinvestment assertion in Turkey and changes in temporary differences between our U.S. GAAP and statutory balances in Turkey.

Loss on Commodity Derivative Contracts. During 2019, we recorded a net loss on derivative contracts of $1.0 million, compared to $1.8 million in 2018.  In 2019, we recorded a $1.0 million gain to mark our commodity derivative contracts to their fair value.  In 2018, we recorded a $4.0 million loss on settled contracts and a $2.2 million gain to mark our commodity derivative contracts to their fair value.

Capital Expenditures

In 2019, we incurred $31.0 million in total capital expenditures, including license acquisition, seismic and corporate expenditures from operations, compared to $23.7 million for 2018.

We expect our net field capital expenditures for 2020 to range between $2.5 million and $15.0 million. We expect net field capital expenditures during 2020 to include between $1.0 million and $9.0 million in drilling and completion expense for between one and five planned wells, between $1.0 million and $3.0 million for recompletions, between $1.0 million and $2.0 million implementing a waterflood in the Bedinan sandstone in the Arpatepe field, and approximately $1.0 million in facilities upgrades to our natural gas power generation infrastructure. Our projected 2020 capital expenditure budget is subject to change.

Liquidity and Capital Resources

Our primary sources of liquidity for 2019 were our cash and cash equivalents, cash flow from operations and borrowings under the 2019 Term Loan. At December 31, 2019, we had cash and cash equivalents of $9.7 million, $2.9 million in long-term debt, $17.1 million in short-term debt and a working capital surplus of $2.0 million, compared to cash and cash equivalents of $9.9 million, no long-term debt, $22.0 million in short-term debt and a working capital surplus of $2.5 million at December 31, 2018.

During 2019, we repaid the 2017 Term Loan and the 2018 Term Loan (each as defined below) in full in accordance with their terms. In addition, we entered into the 2019 Term Loan under our general credit agreement with DenizBank (the “Credit Agreement”).

Net cash provided by operations during 2019 was $33.2 million, an increase from net cash provided by operations of $28.7 million in 2018, primarily due to a decrease in cash settlements on our commodity derivative contracts and a decrease in our general and administrative expenses, which was partially offset by a decrease in our oil and natural gas revenues.  

Net cash used in investing activities during 2019 was $30.8 million, compared to net cash used in investing activities of $26.5 million in 2018, primarily due to an increase in additions of oil and gas properties in 2019 compared to the same period in 2018.

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Net cash used in financing activities was $1.1 million in 2019, compared to net cash used in financing activities of $6.6 million in 2018.  The decrease was primarily due toa decrease in our net debt borrowings and repayments in 2019 compared to the same period in 2018.

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.

On March 9, 2020, we unwound our commodity derivative contracts with respect to our future crude oil production.See “Item 1. Business—Recent Developments.” In connection with these transactions, we received approximately $6.5 million. We used these proceeds to pay down the 2019 Term Loan, which left approximately $10.6 million outstanding under the 2019 Term Loan.

In March 2020, crude oil prices declined to approximately $25 per barrel for Brent crude, and the price remains volatile and unpredictable.  At current prices for Brent crude, our current liquidity position is constrained and is forecast to worsen during 2020 as revenues are insufficient to meet our ordinary course expenditures and debt obligations. Our management is actively pursuing improving our working capital position and/or reducing our future debt service obligations in order to remain a going concern for the foreseeable future.

As of December 31, 2019, we had $20.0 million of debt and $46.1 million of Series A Preferred Shares outstanding, which we discuss below.

Series A Preferred Shares. As of December 31, 2019 and 2018 we had 921,000 Series A Preferred Shares.  The Series A Preferred Shares contain a substantive conversion option, are mandatorily redeemable, and convert into a fixed number of common shares.  As a result, under U.S GAAP, we have classified the Series A Preferred Shares within mezzanine equity in our consolidated balance sheet.    

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

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.  

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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 in cash or 16.0% of the liquidation preference if paid in common shares. If paid partially in cash and partially in common shares, the dividend rate on the cash portion is 12.0%, and the dividend rate on the common share portion is 16.0%. Dividends are payable quarterly, on March 31, June 30, September 30, and December 31of each year.  The holders of the Series A Preferred Shares are also entitled to participate pro-rata in any dividends paid on the common shares on an as-converted-to-common shares basis.  For 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 its most recent independent reserve report filed or furnished on EDGAR.  

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

The 2016 Term Loan 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.  

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.

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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 had 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 and 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, (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. On March 9, 2020, we unwound our commodity derivative contracts with respect to our future crude oil production.See “Item 1. Business—Recent Developments.” In connection with these transactions, we received approximately $6.5 million. We used these proceeds to pay down the 2019 Term Loan, which left approximately $10.6 million outstanding under the 2019 Term Loan.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements at December 31, 2019.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Not applicable.

Item 8. Financial Statements and Supplementary Data

See Index to Financial Statements on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

As of December 31, 2019, management carried out an evaluation, under the supervision and with the participation of our chief executive officer and principal accounting and financial officer, of the effectiveness of our disclosure controls and procedures. Based upon the evaluation, our chief executive officer and principal accounting and financial officer concluded that, as of December 31, 2019, our disclosure controls and procedures were effective.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, is a process designed by, or under the supervision of, the chief executive officer and principal accounting and financial officer, or persons performing similar functions, and effected by the board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP and includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of assets, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, (iii) provide reasonable assurance that receipts and expenditures are being made only in accordance with appropriate authorizations of management and the board of directors, and (iv) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or that the degree of compliance with the policies or procedures may deteriorate.

Our management, under the supervision and with the participation of our chief executive officer and principal accounting and financial officer, conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2019.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

Certain information required in response to this Item 10 is contained under the heading “Information about our Executive Officers” in Part I of this Annual Report on Form 10-K. Other information required in response to this Item 10 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act, not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

Code of Business Conduct

We have adopted a code of ethics that applies to all our officers, directors and employees, including our principal executive officer, principal financial officer, principal accounting officer and controller. The full text of our Code of Conduct is published on our website at www.transatlanticpetroleum.com, on the Corporate Governance page under the About tab. We intend to disclose future amendments to certain provisions of the Code of Conduct, or waivers of such provisions granted to executive officers and directors, on our website within four business days following the date of such amendment or waiver.

Item 11. Executive Compensation

The information required in response to this Item 11 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required in response to this Item 12 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required in response to this Item 13 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

Item 14. Principal Accountant Fees and Services

The information required in response to this Item 14 is incorporated herein by reference to our definitive proxy statement to be filed with the SEC pursuant to Regulation 14A promulgated under the Exchange Act not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) Documents filed as part of the Report.

1.	Report of Independent Registered Public Accounting Firm
	Consolidated Balance Sheets as of December 31, 2019 and 2018
	Consolidated Statements of Operation and Comprehensive Loss for the years ended December 31, 2019 and 2018
	Consolidated Statements of Equity for the years ended December 31, 2019 and 2018
	Consolidated Statements of Cash Flows for the years ended December 31, 2019 and 2018
	Notes to Consolidated Financial Statements
2.	Exhibits required to be filed by Item 601 of Regulation S-K

The exhibits required to be filed by this Item 15 are set forth in the Exhibit Index accompanying this report.

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EXHIBIT INDEX

3.1	Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).
3.2	Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
3.3	Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).
3.4	Certificate of Designations of 12.0% Series A Convertible Redeemable Preferred Shares of TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 31, 2016, filed with the SEC on November 4, 2016).
3.5	Memorandum of Increase of Share Capital of TransAtlantic Petroleum Ltd., dated July 2017 (incorporated by reference to Exhibit 3.5 to the Company’s Annual Report on Form 10-K dated December 31, 2018, filed with the SEC on March 26, 2019).
4.1	Amended and Restated Registration Rights Agreement, dated December 30, 2008, by and between TransAtlantic Petroleum Corp. and Riata Management, LLC (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K dated December 30, 2008, filed with the SEC on January 6, 2009).
4.2	Specimen Common Share certificate (incorporated by reference to Exhibit 3.3 to the Company’s Current Report on Form 8-K dated March 4, 2014, filed with the SEC on March 6, 2014).
4.3*	Description of TransAtlantic Petroleum Ltd.’s common stock.
10.1	Service Agreement, effective as of May 1, 2008, by and among TransAtlantic Petroleum Corp., Longfellow Energy, LP, Viking Drilling, LLC, Longe Energy Limited and Riata Management, LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated August 6, 2008, filed with the SEC on February 12, 2009).
10.2	Amendment to Service Agreement, effective as of October 1, 2008, by and among TransAtlantic Petroleum Corp., Longfellow Energy, LP, Viking Drilling, LLC, Longe Energy Limited, MedOil Supply LLC and Riata Management, LLC (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated August 6, 2008, filed with the SEC on February 12, 2009).
10.3	Domestic Crude Oil Purchase/Sale Agreement, dated as of January 26, 2009, by and between Türkiye Petrol Rafinerileri A.Ş. and TransAtlantic Exploration Mediterranean International Pty. Ltd. (incorporated by reference to Exhibit 10.13 to the Company’s Annual Report on Form 10-K, filed with the SEC on April 21, 2011).
10.4†	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, dated July 13, 2011, filed with the SEC on July 19, 2011).
10.5	Master Services Agreement, dated March 3, 2016, by and between TransAtlantic Exploration Mediterranean International Pty Ltd and Production Solutions International Petrol Arama Hizmetleri Anonim Sirketi (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated February 29, 2016, filed with the SEC on March 4, 2016).
10.6	Form of General Credit Agreement, dated August 23, 2016, by and among DenizBank A.S., TransAtlantic Exploration Mediterranean International Pty Ltd, TransAtlantic Turkey, Ltd., DMLP, Ltd. and Talon Exploration, Ltd (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 10-Q dated September 30, 2016, filed with the SEC on November 9, 2016).
10.7	Note Amendment Agreement, dated April 19, 2016, by and among TransAtlantic Petroleum Ltd., Dalea Partners, LP., and N. Malone Mitchell 3rd (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated April 19, 2016, filed with the SEC on April 22, 2016).
10.8	Amended and Restated Promissory Note, dated April 19, 2016, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated April 19, 2016, filed with the SEC on April 22, 2016).

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10.9	Pledge Agreement, dated April 19, 2016, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K dated April 19, 2016, filed with the SEC on April 22, 2016).
10.10	Indemnity Agreement, dated May 9, 2016, by and between TransAtlantic Petroleum Ltd. and Mr. Mitchell (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 10-Q dated March 31, 2016, filed with the SEC on May 10, 2016).
10.11	Gundem Pledge Fee Agreement, dated August 31, 2016, by and between Gundem Turizm Yatirim Ve Isletmeleri A.S. and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.20 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 22, 2017).
10.12	Diyarbakir Pledge Fee Agreement, dated August 31, 2016, by and among Mr. Mitchell, Mr. Uras and TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 10.21 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 22, 2017).
10.13	Second Amendment to Service Agreement, dated March 20, 2017, by and among TransAltantic Petroleum Ltd. and Longfellow Energy, LP, Riata Management, LLC, Longfellow Nemaha, LLC, Red Rock Minerals, LP, Red Rock Advisors, LLC, Production Solutions International Limited and Nexlube Operating, LLC (incorporated by reference to Exhibit 10.22 to the Company’s Annual Report on Form 10-K, filed with the SEC on March 22, 2017).
10.14	Current Account Loan Contract, dated November 28, 2017, by and between TransAtlantic Exploration Mediterranean International Pty Ltd and DenizBank A.S. (incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K dated December 31, 2017, filed with the SEC on March 21, 2018).
10.15	Form of Retention Incentive Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated April 6, 2018, filed with the SEC on April 6, 2018).
10.16	Term Credit Contract, dated May 28, 2018, by and between TransAtlantic Exploration Mediterranean International Pty Ltd and DenizBank A.S. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated May 28, 2018, filed with the SEC on June 1, 2018).
10.17	Sublease Agreement, dated August 7, 2018 and effective June 14, 2018, by and between TransAtlantic Petroleum (USA) Corp. and Longfellow Energy, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated August 7, 2018, filed with the SEC on August 7, 2018).
10.18	Term Loan Contract, dated February 22, 2019, by and between TransAtlantic Exploration Mediterranean International Pty Ltd and DenizBank A.S. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated February 22, 2019, filed with the SEC on February 28, 2019).
10.19	Amendment No. 1 to the Amended and Restated Promissory Note, dated February 28, 2019, by and between the Company and Dalea Partners, LP (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated February 22, 2019, filed with the SEC on February 28, 2019).
10.20	Amendment No. 1 to the Master Services Agreement, dated February 28, 2019, by and between TransAtlantic Exploration Mediterranean International Pty Ltd and Production Solutions International Petrol Arama Hizmetleri Anomin Sirketi (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K dated February 22, 2019, filed with the SEC on February 28, 2019).
10.21	Third Amendment to Service Agreement, dated April 17, 2019 and effective as of August 1, 2017, by and among TransAtlantic Petroleum Ltd. and its subsidiaries and Longfellow Energy, LP, Viking Drilling, LLC, Riata Management, LLC, LFN Holdco LLC, Red Rock Minerals, LP, Red Rock Minerals II, LP, Red Rock Advisors, LLC, Production Solutions International Limited, and NexLube Operating, LLC and their subsidiaries (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated April 17, 2019, filed with the SEC on April 17, 2019).
10.22	TransAtlantic Petroleum Ltd. 2019 Long-Term Incentive Plan (incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement filed with the SEC on April 18, 2019).
10.23	Form of Restricted Stock Unit Award Agreement (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K dated June 4, 2019, filed with the SEC on June 7, 2019).

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10.24	Amendment No. 1 to the Pledge Agreement, dated June 28, 2019, by and between TransAtlantic Petroleum Ltd. and Dalea Partners, LP (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K dated June 28, 2019, filed with the SEC on June 28, 2019).
10.25*	Pledge Fee Agreement, dated November 28, 2017, by and between Selami Erdem Uras and TransAtlantic Petroleum Ltd.
10.26*	Diyarbakir Amended Yard Lease Agreement, effective as of January 1, 2019, by and between Selami Erdem Uras and TransAtlantic Exploration Med. Int. Pty. Ltd. Merkezi Avustralya Turkiye Ankara Subesi
10.27*	Thrace “Gundem Property” Yard Lease Agreement, effective as of July 1, 2018, by and between Gundem Yatirim ve Ticaret A.S. and TransAtlantic Turkey Ltd. Turkiye Ankara Subesi
21.1*	Subsidiaries of the Company.
23.1*	Consent of RBSM LLP.
23.2*	Consent of DeGolyer and MacNaughton.
31.1*	Certification of the Chief Executive Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of the Principal Accounting and Financial Officer of the Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of the Chief Executive Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of the Principal Accounting and Financial Officer of the Company, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	Report of DeGolyer and MacNaughton, dated March 3, 2020.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

† Management contract or compensatory plan arrangement.

* Filed herewith.

** Furnished herewith.

54

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

March 25, 2020

TRANSATLANTIC PETROLEUM LTD.

/S/ N. MALONE MITCHELL 3^rd

N. Malone Mitchell 3^rd

Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Capacity	Date
/S/ N. MALONE MITCHELL 3rd	Chairman and Chief Executive Officer	March 25, 2020
N. Malone Mitchell 3rd	(Principal Executive Officer)
/S/ MICHAEL P. HILL	Chief Accounting Officer	March 25, 2020
Michael P. Hill	(Principal Financial Officer and Principal Accounting Officer)
/S/ BOB G. ALEXANDER	Director	March 25, 2020
Bob G. Alexander
/S/ CHARLES J. CAMPISE	Director	March 25, 2020
Charles J. Campise
/S/ JONATHON T. FITE	Director	March 25, 2020
Jonathon T. Fite
/S/ H. Lee Muncy	Director	March 25, 2020
H. Lee Muncy
/S/ GREGORY K. RENWICK	Director	March 25, 2020
Gregory K. Renwick
/S/ MEL G. RIGGS	Director	March 25, 2020
Mel G. Riggs
/S/ RANDY I. ROCHMAN	Director	March 25, 2020
Randy I. Rochman

55

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

	Page
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of December 31, 2019 and 2018	F-3
Consolidated Statements of Operations and Comprehensive Loss for the years ended December 31, 2019 and 2018	F-4
Consolidated Statements of Equity for the years ended December 31, 2019 and 2018	F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2019 and 2018	F-6
Notes to Consolidated Financial Statements	F-7

F-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Transatlantic Petroleum Ltd.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Transatlantic Petroleum Ltd. and subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of operations and comprehensive loss, shareholders’ equity, and cash flows for each of the two years in the period ended December 31, 2019, and the related notes (collectively referred to as the financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and comprehensive loss and its cash flows for each of the two years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

Going Concern Matter

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the consolidated financial statements, the Company has suffered recurring net losses and had an accumulated deficit that raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Emphasis of a Matter

As discussed in Notes 1 and 16 to the consolidated financial statements, there are a number of significant related party transactions with the primary shareholder of the Company.  This shareholder is the Company's chief executive officer and chairman of the board of directors. Significant related party transactions with this shareholder include ownership of Series A Preferred Shares, equity transactions, a note receivable, pledge fee agreements and service transactions.

Change in Accounting Principle

As discussed in Note 4 to the financial statements, the Company changed its method of accounting for leases in 2019 due to the adoption of ASU No. 2016-02, Leases (Topic 842), as amended, effective January 1, 2019, using a prospective transition approach.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.  

Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ RBSM LLP

We have served as the Company’s auditor since 2018.

New York, NY

March 25, 2020

F-2

TRANSATLANTIC PETROLEUM LTD.

Consolidated Balance Sheets

As of December 31, 2019 and 2018

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

	2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	9,664		$	9,892
Accounts receivable, net
Oil and natural gas sales		13,299			12,912
Joint interest and other		1,218			982
Related party		561			878
Prepaid and other current assets		12,375			8,696
Note receivable - related party		–			5,828
Inventory		7,091			5,167
Total current assets		44,208			44,355
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved		167,948			163,006
Unproved		12,978			15,695
Equipment and other property		10,202			14,408
		191,128			193,109
Less accumulated depreciation, depletion and amortization		(106,610	)		(105,850	)
Property and equipment, net		84,518			87,259
Other long-term assets:
Other assets		3,827			986
Note receivable - related party		3,951			–
Total other assets		7,778			986
Total assets	$	136,504		$	132,600
LIABILITIES, SERIES A PREFERRED SHARES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	4,555		$	3,896
Accounts payable - related party		4,262			2,922
Accrued liabilities		15,244			13,073
Derivative liability		966			–
Loans payable		17,143			22,000
Total current liabilities		42,170			41,891
Long-term liabilities:
Asset retirement obligations		4,749			4,667
Accrued liabilities		10,370			7,259
Deferred income taxes		22,728			20,314
Loans payable		2,857			–
Total long-term liabilities		40,704			32,240
Total liabilities		82,874			74,131
Commitments and contingencies
Series A preferred shares, $0.01 par value, 100,000 shares authorized; 100,000 shares issued and outstanding with a liquidation preference of $50 per share as of December 31, 2019 and 426,000 shares authorized; 426,000 shares issued and outstanding with a liquidation preference of $50 per share as of December 31, 2018		5,000			21,300
Series A preferred shares-related party, $0.01 par value, 821,000 shares authorized; 821,000 shares issued and outstanding with a liquidation preference of $50 per share as of December 31, 2019 and 495,000 shares authorized; 495,000 shares issued and outstanding with a liquidation preference of $50 per share as of December 31, 2018		41,050			24,750
Shareholders' equity:
Common shares, $0.10 par value, 200,000,000 shares authorized; 62,230,058 shares and 52,413,588 shares issued and outstanding as of December 31, 2019 and 2018, respectively		6,223			5,241
Treasury shares		(970	)		(970	)
Additional paid-in-capital		582,359			577,488
Accumulated other comprehensive loss		(147,347	)		(142,021	)
Accumulated deficit		(432,685	)		(427,319	)
Total shareholders' equity		7,580			12,419
Total liabilities, Series A preferred shares and shareholders' equity	$	136,504		$	132,600

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

F-3

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Operations and Comprehensive Loss

For the Years ended December 31, 2019 and 2018

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

	2019			2018
Revenues:
Oil and natural gas sales	$	66,829		$	70,268
Other		551			521
Total revenues		67,380			70,789
Costs and expenses:
Production		11,674			10,769
Transportation costs		5,101			4,665
Exploration, abandonment and impairment		6,267			401
Seismic and other exploration		330			489
General and administrative		11,785			14,719
Depreciation, depletion and amortization		13,227			14,059
Accretion of asset retirement obligations		213			174
Total costs and expenses		48,597			45,276
Operating income		18,783			25,513
Other (expense) income:
Interest and other expense		(10,667	)		(10,048	)
Interest and other income		947			1,082
Loss on commodity derivative contracts		(966	)		(1,797	)
Foreign exchange loss		(4,569	)		(10,292	)
Total other expense		(15,255	)		(21,055	)
Income before income taxes		3,528			4,458
Current income tax expense		(3,119	)		(2,820	)
Deferred income tax expense		(5,775	)		(6,854	)
Net loss		(5,366	)		(5,216	)
Other comprehensive loss:
Foreign currency translation adjustment		(5,326	)		(17,255	)
Comprehensive loss	$	(10,692	)	$	(22,471	)
Net loss per common share:
Basic net loss per common share	$	(0.10	)	$	(0.10	)
Weighted average common shares outstanding		55,134			50,505
Diluted net loss per common share	$	(0.10	)	$	(0.10	)
Weighted average common and common equivalent shares outstanding		55,134			50,505

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

F-4

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Equity

For the Years ended December 31, 2019 and 2018

(U.S. Dollars and shares in thousands)

																Accumulated
													Additional			Other						Total
	Common		Treasury					Common		Treasury			Paid-in			Comprehensive			Accumulated			Shareholders'
	Shares		Shares		Warrants			Shares (at par)		Stock			Capital			Income (Loss)			Deficit			Equity
Balances at December 31, 2017		50,319		333		699		$	5,032	$	(970	)	$	575,412		$	(124,766	)	$	(422,103	)	$	32,605
Issuance of common shares		1,808		–		–			181		–			1,660			–			–			1,841
Issuance of restricted stock units		286		–		–			28		–			(28	)		–			–			-
Expiration of warrants		–		–		(699	)		–		–			–			–			–			-
Tax withholding on restricted stock units		–		–		–			–		–			(11	)		–			–			(11	)
Share-based compensation		–		–		–			–		–			455			–			–			455
Foreign currency translation adjustment		–		–		–			–		–			–			(17,255	)		–			(17,255	)
Net loss		–		–		–			–		–			–			–			(5,216	)		(5,216	)
Balances at December 31, 2018		52,413		333		–		$	5,241	$	(970	)	$	577,488		$	(142,021	)	$	(427,319	)	$	12,419
Issuance of common shares		9,507		–		–			950		–			4,576			–			–			5,526
Issuance of restricted stock units		310		–		–			32		–			(32	)		–			–			-
Tax withholding on restricted stock units		–		–		–			–		–			(92	)		–			–			(92	)
Share-based compensation		–		–		–			–		–			419			–			–			419
Foreign currency translation adjustment		–		–		–			–		–			–			(5,326	)		–			(5,326	)
Net loss		–		–		–			–		–			–			–			(5,366	)		(5,366	)
Balances at December 31, 2019		62,230		333		–		$	6,223	$	(970	)	$	582,359		$	(147,347	)	$	(432,685	)	$	7,580

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

F-5

TRANSATLANTIC PETROLEUM LTD.

Consolidated Statements of Cash Flows

For the Years ended December 31, 2019 and 2018

(in thousands of U.S. Dollars)

	2019			2018
Operating activities:
Net loss	$	(5,366	)	$	(5,216	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-based compensation		419			455
Foreign currency loss		5,136			13,299
Loss on commodity derivative contracts		966			1,797
Cash settlement on commodity derivative contracts		–			(4,012	)
Amortization on loan financing costs		41			42
Interest on Series A Preferred Shares paid in common shares		5,526			1,842
Deferred income tax expense		5,775			6,854
Exploration, abandonment and impairment		6,267			401
Depreciation, depletion and amortization		13,227			14,059
Accretion of asset retirement obligations		213			174
Changes in operating assets and liabilities:
Accounts receivable		(1,102	)		(1,358	)
Prepaid expenses and other assets		(7,013	)		(6,673	)
Accounts payable and accrued liabilities		9,114			7,031
Net cash provided by operating activities		33,203			28,695
Investing activities:
Additions to oil and natural gas properties		(29,348	)		(23,517	)
Additions to equipment and other properties		(1,482	)		(3,015	)
Net cash used in investing activities		(30,830	)		(26,532	)
Financing activities:
Tax withholding on restricted share units		(92	)		(11	)
Note receivable - related party		1,000			–
Loan proceeds		20,605			10,000
Loan repayment		(22,605	)		(16,625	)
Net cash used in financing activities		(1,092	)		(6,636	)
Effect of exchange rate on cash flows, cash equivalents and restricted cash		(1,504	)		(5,931	)
Net decrease in cash, cash equivalents and restricted cash		(223	)		(10,404	)
Cash, cash equivalents and restricted cash, beginning of year (1)		10,027			20,431
Cash, cash equivalents and restricted cash, end of year (2)	$	9,804		$	10,027
Supplemental disclosures:
Cash paid for interest	$	4,151		$	7,917
Cash paid for taxes	$	3,436		$	3,239

(1) The balance at January 1, 2018 includes cash and cash equivalents of $18.9 million and restricted cash of $1.5 million in other assets.  The balance at January 1, 2019 includes cash and cash equivalents of $9.9 million and restricted cash of $0.1 million in other assets.

(2) The end of period balance at December 31, 2018 includes cash and cash equivalents of $9.9 million and restricted cash of $0.1 million in other assets. The end of period balance at December 31, 2019 includes cash and cash equivalents of $9.7 million and restricted cash of $0.1 million in other assets.  

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

F-6

TRANSATLANTIC PETROLEUM LTD.

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.  

F-7

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.

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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.”

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 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

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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.  

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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.  

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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 $0.1millionduring 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 millionwith 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

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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 42.0million 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

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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.

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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.

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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

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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,

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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

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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

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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 4^th 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.

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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.

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As of December 31, 2019 and 2018, the amount receivable under the Amended Note was $4.0million 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 millionfor 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

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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.

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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

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	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.  

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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

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EX-4.3

Exhibit 4.3

DESCRIPTION OF THE REGISTRANT’S SECURITIES REGISTERED PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

As of December 31, 2019, TransAtlantic Petroleum Ltd. (the “Company,” “we,” “us,” and “our”) had one class of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”): our common shares, $0.10 par value per share (the “Common Shares”).

Description of Capital Stock

The following summary of our capital stock does not purport to be complete and is subject to and qualified in its entirety by reference to our Altered Memorandum of Continuance (the “Memorandum of Continuance”), our Memorandum of Increase of Share Capital (the “Memorandum of Increase”), our Certificate of Designations of 12% Series A Convertible Redeemable Preferred Shares (the “Certificate of Designations”) and our Amended Bye-Laws (the “Bye-Laws”). Copies of the Memorandum of Continuance, the Bye-Laws, Certificate of Designations and the Memorandum of Increase have been filed with the Securities and Exchange Commission as Exhibits 3.2, 3.3, 3.4 and 3.5, respectively, to our Annual Report on Form 10-K.

Shares Generally

Pursuant to the Memorandum of Continuance, the Memorandum of Increase and the Bye-Laws, we are authorized to issue 200,000,000 Common Shares and 100,000,000 undesignated shares of par value $0.01 each (the “Undesignated Shares”). From the Undesignated Shares, pursuant to the Certificate of Designations, the Company created a series of preferred shares, designated as the “12.0% Series A Convertible Redeemable Preferred Shares,” par value $0.01 per share (the “Series A Preferred Shares”). The authorized number of Series A Preferred Shares is 950,000 shares. The Bye-Laws permit our board of directors to authorize us to repurchase our shares whether for cancellation or to be held as treasury shares, provided we are, after the repurchase, able to pay our liabilities as they become due. The Bye-Laws permit us to issue redeemable shares.

Common Shares

Holders of our Common Shares are entitled to one vote per share on all matters submitted to a vote of the shareholders. The Bye-Laws do not provide for cumulative voting. Any action to be taken by the shareholders at any meeting at which a quorum is in attendance is decided by the affirmative vote of a majority of the votes cast at such meeting, except as otherwise set forth in the Bye-Laws or the Companies Act 1981 of Bermuda (the “Companies Act”).

An amendment of certain specified provisions of the Bye-Laws requires an affirmative vote of at least 80% of the issued Common Shares entitled to vote, and any alteration or abrogation of any rights attached to any class of shares requires (i) consent in writing of 100% of the issued shares of that class or (ii) the approval of the holders of not less than 75% of the issued shares of that class. In addition, the following actions requires an affirmative vote of no less than two-thirds of the votes cast: amalgamations, sale, lease or exchange of substantially all of our assets, voluntary winding up or continuance to a foreign jurisdiction. There are no limitations imposed by Bermuda law or the Bye-Laws on the right of shareholders who are not Bermuda residents to hold or vote their Common Shares. Holders of our Common Shares do not have any pre-emptive rights.

Under the Bye-Laws and Bermuda law, our board of directors may declare and pay dividends from time to time unless there are reasonable grounds for believing that we are, or after the payment would be, unable to pay our liabilities as they become due or that the realizable value of our assets would thereby be less than the aggregate of our liabilities and issued share capital and share premium accounts. Each Common Share is entitled to dividends only if, as and when dividends are declared by our board of directors. The payment of future dividends, if any, is determined by our board of directors.

In the event of our liquidation, dissolution or winding up, holders of Common Shares are entitled to share rateably in proportion to their shareholding in our assets, if any, remaining after the payment of all of our debts and liabilities, subject to any liquidation preference on any outstanding preference shares. As of December 31, 2019, we had 62,230,058 Common Shares outstanding.

Preferred Shares

The Company is authorized to issue 950,000 Series A Preferred Shares with such rights, preferences, privileges and restrictions, including dividend rights, voting rights, conversion rights, terms of redemption and liquidation preferences as designated by the board of directors in the Certificate of Designations, which could affect the holders of Common Shares. As of December 31, 2019, we had 921,000 Series A Preferred Shares issued and outstanding. Pursuant to the Certificate of Designations, each Series A Preferred Share may be converted at any time, at the option of the holder, into 45.754 Common Shares (which is equal to an initial conversion price of approximately $1.0928 per Common Share and is subject to customary 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%

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 in cash or 16.0% of the liquidation preference if paid in Common Shares. If paid partially in cash and partially in Common Shares, the dividend rate on the cash portion is 12.0%, and the dividend rate on the Common Share portion is 16.0%. Dividends are payable quarterly, on March 31, June 30, September 30, and December 31 of each year.  The holders of the Series A Preferred Shares are also entitled to participate pro-rata in any dividends paid on the Common Shares on an as-converted-to-Common Shares basis.

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 on EDGAR.  

In the event of any liquidation, winding-up or dissolution of the Company, whether voluntary or involuntary, each holder of Series A Preferred Shares shall be entitled to receive and to be paid out of the assets of the Company available for distribution to its shareholders plus accumulated dividends to the date fixed for liquidation, winding-up or dissolution in preference to the holders of, and before any payment or distribution is made on the Common Shares.

Undesignated Shares

The Memorandum of Continuance and the Bye-Laws authorize the issuance of 100,000,000 undesignated shares, of which the Company authorized 950,000 Series A Preferred Shares. The remaining undesignated shares may be issued with such preferred, qualified or other special rights, privileges and conditions and subject to such restrictions, as the board of directors may determine, in one or more series. The issuance of shares with voting rights, conversion rights or preferential

rights could adversely affect the voting power of our holders of Common Shares and could have the effect of delaying or preventing a change of control.

Anti-Takeover Provisions

Issuance of Undesignated Shares

Our board of directors has broad discretion to designate and issue shares from our remaining undesignated shares, which could be deemed to have an anti-takeover affect.

Super-Majority Voting

As described above, there are super-majority requirements for certain shareholder votes, including an amendment to certain provisions of the Bye-Laws, amalgamations and a sale, lease or exchange of substantially all of our assets.

Shareholder Action by Written Consent

The Bye-Laws provide that any action that may be done by resolutions of the shareholders of the Company in a general meeting or by resolutions of any class of shareholders in a separate general meeting may be done by resolution in writing, except for the removal of auditors or directors.

Advance Notice and Quorum Requirements

The Bye-Laws require that an annual general meeting and a special general meeting be called not less 21 clear days’ notice in writing prior to the date of the meeting, which notice must set forth the place, day and time of the meeting and the nature of the business to be considered. A resolution may only be put to a vote at a general meeting if: (i) it is proposed by or at the direction of our board of directors; (ii) it is proposed at the direction of the Supreme Court of Bermuda; (iii) it is proposed on the requisition in writing of such number of shareholders as is prescribed by the relevant provisions of the Companies Act; or (iv) the chairman of the meeting decides that the resolution may properly be regarded as within the scope of the meeting. No amendment may be made to a resolution unless the chairman of the meeting decides that the amendment may properly be put to a vote at the meeting. No business shall be transacted at any general meeting unless a quorum is present when the meeting proceeds to business. Unless otherwise stated in the Bye-Laws, at least two shareholders present in person or by proxy and entitled to vote representing the holders of not less than 10% of the issued Common Shares entitled to vote at such meeting shall be a quorum for all purposes.

Number of Directors and Vacancies and Removal of Directors

The Bye-Laws provide that the number of directors shall be fixed and determined from time to time by our board of directors. Our board of directors has the power at any time to appoint any individual to be a director so as to fill a vacancy in the board of directors not filled by the shareholders at any general meetings, including any vacancies created by an increase in the number of directors by the board of directors between general meetings.

The Bye-Laws provide that the Company may in a special general meeting called for that purpose remove a director, provided notice of any such meeting shall be served upon the director concerned not less than 14 days before the meeting and such director shall be entitled to be heard at that meeting. A director may be removed by the affirmative vote of a majority of the votes cast by our shareholders at the special general meeting. Any vacancy created by the removal of a director at a special general meeting may be filled at the meeting by the election of another director or, in the absence of any such election, by the board of directors.

Director and Officer Indemnity

The Bye-Laws require us to indemnify our officers and directors against all liabilities, loss, damage or expense incurred or suffered by such person in such capacity or by reason of any act done, conceived or omitted in the conduct of our business or in the discharge of such person’s duties; provided that such indemnification shall not extend to any matter which would render it void pursuant to Bermuda law. Bermuda law permits us to indemnify directors and officers against liability attaching to them arising from their duties, but such indemnification may not extend to acts of fraud or dishonesty. The Bye-Laws require us to advance funds to directors or officers for their defense upon receipt of an undertaking to repay the funds if any allegation of fraud or dishonesty is proved, and only if such advance is specifically authorized in accordance with Bye-Law 44.6. The Bye-Laws permit the purchase of indemnity insurance.

Foreign Exchange Control Regulations

We have been designated as a non-resident for Bermuda exchange control purposes by the Bermuda Monetary Authority. Because of this designation, there are no restrictions on our ability to transfer funds in and out of Bermuda.

The transfer of shares between persons regarded as resident outside Bermuda for exchange control purposes and the sale of our Common Shares to or by such persons may take place without specific consent under the Exchange Control Act 1972. Issuances and transfers of shares involving any person regarded as resident in Bermuda for exchange control purposes require specific approval under the Exchange Control Act 1972.

As an “exempted company,” we are exempt from Bermuda laws which restrict the percentage of share capital that may be held by non-Bermuda residents, but as an exempted company, we may not participate in certain business transactions, including: (1) the acquisition or holding of land in Bermuda (except that required for our business and held by way of lease or tenancy for terms of not more than 50 years) without the express authorization of the Bermuda legislature, (2) the taking of mortgages on land in Bermuda to secure an amount in excess of $50,000 without the consent of the Minister of Finance, (3) the acquisition of any bonds or debentures secured by any land in Bermuda, other than certain types of Bermuda government securities or (4) the carrying on of business of any kind in Bermuda, except in furtherance of our business carried on outside Bermuda.

EX-10.25

Exhibit 10.25

PLEDGE FEE AGREEMENT

This Pledge Fee Agreement (the “Agreement”), dated as of November 28, 2017, is entered into by and between Selami Uras (“Pledgor”) and TransAtlantic Petroleum Ltd., a Bermuda exempted company with limited liability (the “Company”).

WHEREAS, the Turkish branch of TransAtlantic Exploration Mediterranean International Pty Ltd, a subsidiary of the Company (“TEMI”), proposes to enter into a $20.375 million term loan (the “2017 Term Loan”) under that certain General Credit Agreement (the “Credit Agreement”), dated as of August 23, 2016, by and between TEMI and DenziBank A.S. (the “Lender”);

WHEREAS, as a condition to providing the 2017 Term Loan to TEMI, the Lender has required the Pledgor to pledge its ownership interests in the real property located at Hirfanlı Sokak 5 GOP, Cankaya Ankara – Turkey 06700 (the “Property”) as collateral for the 2017 Term Loan pursuant to that certain Pledge Agreement (the “Pledge Agreement”), by and between Pledgor and Lender dated as of the date hereof;

WHEREAS, the Lender and the Company have determined that the Property has a value of $5.2 million (collectively, the “Collateral Value”); and

WHEREAS, in order to induce the Pledgor to pledge the Property to the Lender as collateral for the 2017 Term Loan, the Company has agreed to pay the Pledgor a fee of 5.0% of the Collateral Value per annum (the “Pledge Fee”) in cash upon the terms set forth below.

NOW, THEREFORE, in consideration of the mutual covenants contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

1. Payment of Pledge Fee. For so long as the Property is pledged to the Lender as collateral for the 2017 Term Loan, the Company hereby agrees to pay the Pledgor the Pledge Fee in cash on the last day of each month, beginning November 30, 2017. The Pledge Fee shall be pro-rated for any period of less than one month.

2. Subrogation, Property Foreclosure. In the event all or any part of the Property has been foreclosed upon by or for the benefit of the Lender, Pledgor shall (i) be subrogated to all rights and liens that the Lender may have or may have had against the Company, TEMI, and each other guarantor of the 2017 Term Loan and all collateral or other security, and all rights of subrogation in or under any of the 2017 Term Loan documents or to participate in any way therein, and in all right, title or interest in or to any security for the 2017 Term Loan, (ii) be entitled to receive from the Company interest at the rate specified in the 2017 Term Loan documentation (i.e., the regular or default rate in effect at the time) with respect to a notional principal amount equal to the Collateral Value of the Property foreclosed upon, and (iii) be entitled to recourse, reimbursement, exoneration, contribution, indemnification, and all other similar rights available under applicable law against the Company, TEMI, and each other guarantor of or for all or any part of the 2017 Term Loan; provided, that until the 2017 Term Loan has been paid in full, such rights are expressly made subordinate in form and substance and upon terms acceptable to Lender in its sole and absolute discretion if and to the extent required by the 2017 Term Loan documentation. Upon request by Pledgor from time to time, the Company agrees to enter, or to cause its subsidiaries to enter, into additional definitive documentation in support of the foregoing to ensure that Pledgor obtains all legal and economic benefits contemplated by this Agreement, including, without limitation, loan documentation on terms substantially similar to the 2017 Term Loan documents.

3. Income Seizure.In the event all or any part of the income derived from the Property has been foreclosed upon by or for the benefit of the Lender, Pledgor shall (i) be subrogated to all rights and liens thatthe Lender may have or may have had against the Company, TEMI, and each other guarantor of the 2017 Term Loan and all collateral or other security, and all rights of subrogation in or under any of the 2017 Term Loan documents or to participate in any way therein, and in all right, title or interest in or to any security for the 2017 Term Loan, (ii) be entitled to receive from the Company interest at the rate specified in the 2017 Term Loan documentation (i.e., the regular or default rate in effect at the time) with respect toany proceeds from any Property foreclosed upon,(iii) be entitled to continue to receive the Pledge Fee, and (iv) be entitled to recourse, reimbursement, exoneration, contribution, indemnification, and all other similar rights available under applicable law against the Company, TEMI, and each other guarantor of or for all or any part of the 2017 Term Loan; provided, that until the 2017 Term Loan has been paid in full, such rights are expressly made subordinate in form and substance and upon terms acceptable to Lender in its sole and absolute discretion if and to the extent required by the 2017 Term Loan documentation.Upon request by Pledgor from time to time, the Company agrees to enter, or to cause its subsidiaries to enter, into additional definitive documentation in support of the foregoing to ensure that Pledgor obtains all legal and economic benefits contemplated by this Agreement, including, without limitation, loan documentation on terms substantially similar to the 2017 Term Loan documents.

4. Property Appreciation. On an annual basis beginning on the date one year from the date of this Agreement, the Collateral Value shall be increased using the Turkey Consumer Price Index (“CPI”). When this determination is made, the principal amount of the 2017 Term Loan described in Paragraph 2 shall be modified to reflect the increase in value.

5. Sale of the Property. Pledgor reserves the right to assign, transfer, or sell its interest in the Property at any time, subject only to the Lender’s approval. In the event such assignment, transfer, or sale is made, the Company shall be obligated to replace the collateral with property approved by the Lender.

6. Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Texas, without regard to its principles regarding conflicts of laws. Venue of any action tried hereunder will be in Dallas County, Texas, whether in federal or state court.

7. Successors. All agreements of the Company and the Pledgor in this Agreement shall bind their successors and assigns.

8. No Waiver or Amendment. No waiver of any of the terms, provisions or conditions hereof, or any modification of such terms, provisions or conditions, shall be effective unless in writing and signed by a duly authorized officer of each party.

9. Assignment of this Agreement. This Agreement and the duties, right and obligations of the parties hereunder shall not be assignable by either party without the prior written consent of the other party.

10. Entire Agreement. This Agreement represents the entire agreement between the parties, and supersedes and nullifies all prior representations, negotiations, proposals, and statements with regard to the Pledge of the Property.

11. Counterparts. This Agreement may be executed in multiple counterparts, each of which shall be deemed an original, but all of which together constitute one and the same instrument.

[Signature page follows]

2

TRANSATLANTIC PETROLEUM LTD.
By:	/s/ Chad D. Burkhardt_________________
Name:	Chad D. Burkhardt
Title:	Vice President, General Counsel & Corporate Secretary
SELAMI URAS
/s/ Selami Uras___________________

Signature Page to Pledge Fee Agreement

EX-10.26

Exhibit 10.26

DIYARBAKIR AMENDED YARD LEASE AGREEMENT-TEMI Lessor: lami Erdem Uras - Resident in Blrlik Mahallesi Zirvekent 2. Etap, C4/3 06610 Ankara, Turkey Lessee: TransAtlantic Exploration Med. Int. Pt y. Ltd. Merkezi Avustralya Tiirkiye Ankara Ubesi­ lran Cad . No 21 Karum I Merkezi F Blok Kat:5/427 Kavaklidere Ankaya Ankara Effective Date: January 1, 2019 Foradequateconsideration,thereceiptandsufficiencyofwhichisacknowledged,Lessor,namedabove, leasesandletstoLessee,namedabove,aportion(suchportionbeingreferredtohereinasthe"Leased Premises")ofthefollowingsixparcelsoflandlocatedatDiyarbakirUrfaRoadat12kilometer,Diyarbakir in the Republic of Turkey. The portion of the Yard that constitutes the "Leased Premises" is more specifically described on the Certificates attached hereto under Exhibit "A", the entirety of the six parcels being referred to as the "Yard". The portion of the Yard that constitutes the "Leased Premises" ismorespecificallydescribedonattachedExhibit"B" This Lease amends and supersedes all existing leases of the Yard or Leased Premises between Lessor and Lessee .For adequate consideration, this Agreement is entered into and a lease of the Yard (the "lease") is granted by lessor and accepted by Lessee on the following terms: Basic Terms 1. Use of the Leased Premise: :LessorshallbepermittedtousetheleasedPremisesforstorage, maintenanceandstagingofmaterials andequipmentforoilfieldservicesandservicesrelatedto oil & gas drilling , exploration, development, geological or geophysical activities or oilfield infrastructure for the term of thisAgreement.2. Purpose lessee agrees that the lease of the leased Premises shall be for the sole purpose of the lessee's uses related to oilfield services and services related to oil & gas drilling, exploration, development, geological or geophysical activities and infrastructure.  Any costs associated with the use and maintenance of the property by the Lessee for lessee's purposes shall be at the sole expense of theLessee.3. Lease Period: ThetermofthisAgreementshallcommenceupontheeffectivedateandshall extend for a period of 60months.4. Rent: The lessor agrees to provide the lessee with the use of the Leased Premises for a monthly gross rental amount in US Dollars payable within first five (5) business days of each month for the term of this Agreement into the Turkish bank account designated by the lessor, during each yearly period asfollows:

Yearly Period Gross Monthly Payment (in USD includes Withholding) 01 January-19 31 December-19$ 40,000.000l January- 20 31 December- 20 $41,000.0001 January- 2131 December- 21 $42,025.00 01 January- 22 31 December – 22$ 43,076.00 01 January -2330 June - 23$ 44,153.00All tax withholdings as are required under Turkish law are included in the gross rental. The Lessee shall regularly furnish the Lessor with copies of the receipts for deposits into the Tax Office of the relevant taxes. 5.Leasing of Remainder of Yard: Lessor shall be entitled to lease, sublease, sell, trade or otherwise dispose of that portion of the Yard not included as part of the Leased Premises; provided no such disposition shall impair or adversely impact Lessee's use of the Leased Premises. Lessee acknowledges that a portion of the Yard within the Leased Premises is already or may in the future be under lease to a third party and agrees that all revenues associated with the lease to the third party shall be for lessor's account.6.Cost of Operations: The Lessee shall bear the entire cost of its operation on the Leased Premises, Including utility bills . The Lessee shall pay to Production Solutions International Limited or its designee {"Operator''), as operator of the Leased Premises, each month in addition to Gross Monthly Rent a fixed reimbursement of the cost to operate the Leased Premises, including utility bills. lessee shall pay to Operator internet, water, and electricity. Lessee will pay the cost of its own security of the Leased Premises and landlord and Operator shall have no responsibility therefor  Lessee will be able to Install a private antenna, ifthe apartment which constitutes part of the Leased Premises lacks a general one. The charges for consumption on such installations aswell as, the subscription charges of the telephone (if same is provided as a fixture), shall be borne by the Lessee.7.Subleasing:  Lessee shall be entitled to sub-let the le, a sed Premises to a third party, in part or in its entirety, with the permission of Lessor which shall not be unreasonably withheld. Any rents or other revenues derived from such sublease shall be the property of Lessee. Provided, in the event the Leased Premises are in any way damaged or altered by sublessee, the Lessor may require Lessee to terminate the sublease, and the Lessee would be obligated to compensate for such damages, as well, without any need for the issuance of a protest or securing of court decree.

8. Improvements to the Leased Premises: Lessee agrees that the Leased Premises are provided "as is" and the Lessor has no obligation to provide improvements to the Leased Premises for the Lessee's use. Any improvements required by the Lessee shall be provide at the sole expense of the Lessee. The costs of putting signs, shingles or ornamentation in or outside the Leased Premises, but the Lessee shall be borne entirely by him, and, all fixtures, appurtenances and immovable construction added to the Leased Premises shall accede to the Lessor at the expiry of the lease period, without any right on the part of the Lessee to demand any costs, expenses or compensation therefor whatsoever. GENERAL TERMS Maintenance: The Lessee agrees to perform maintenance of the Leased Premises as required during the term of the Lease. Lessee shall maintain the Leased Premises at all times in a reasonablemannerandcondition.Lesseeisobligedtoproperly usetheLeasedPremisesasifit was his own and to refrain from doing anything that depreciate the qualifications, reputation and the value thereof. If there are others in the same property, coordinate his own use with them. 2. Extent & Condition of the Leased Premises:  The Lessee shall accept the Leased Premises "as Is." This Agreement shall not obligate the Lessor to guarantee the condition of the Leased Premises, the suitability of the Leased Premises for the Lessee's intended use, the duration that theLeasedPremisesmaysafelyoccupied,ortheavailabilityofalternatefacilities. 3. Use for another Purpose Prohibited: If the Leased Premises are used for a purpose other than a purpose permitted by this Agreement or if the Leased Premises are in any way materially damaged or altered, the Lessor may terminate this Lease, and the Lessee would be obligated to compensate for such damages, as well, without any need for the issuance of a protest or securingofcourtdecree.Theinflictingofsaiddamages byathird party(i.e.sub-lessor)shallnot affect the rights of the Lessor to claim it from the principalLessee. 4. Repairs: If it becomes necessary to repair the Leased Premises beyond ordinary wear and tear or if a third-party claims rights over the same, the Lessee is obliged to promptly inform the Lessor. If he fails to so notify, the Lessee shall be responsible for any damages. The Lessee is obliged to permit the carrying out of necessary repairs. If minor items such as the putting of hinges,window-panes,locksandslides,white-washwhicharefortheordinaryuseoftheLeased PremisesaremadewithoutInformingtheLessorandwithoutwaitingforanappropriateperiod, the costs thereof cannot be claimed fromLessor. 5 Taxes: Subject to the provision for Lessor to withhold and deposit all relevant taxes on the lease rental payments, property taxes will be paid by the lessor whereas all taxes and municipal fees arising due to the operational activity will be paid by the lessee. (Local) customs shall prevail in this matter. Municipal and other taxes and fees due to the operational activity of the lessee will be paid by thelessee 6. Return of the Leased Premises: The Lessee will be obliged to return the Leased Premises back to the Lessor in the same condition as he found it and duly observing {local) customsLessee.

shall return all fixtures and Installations which were in the property, fully when the lease period expires. In case these fixtures and/or the accessories of the Leased Premises are missing or have depreciated in their value over and above the depreciation through normal use, the Lessee shall also be obliged to compensate therefor, and if the Lessor so demands, reinstate them to their original condition. Lessee shall not be responsible for deterioration and depreciation of the Leased Premises when used pursuant to the Lease. It must be presumed that the Lessee took over the Leased Premises in good condition.7. End of Lease Matters: Lessee may not object to potential applicants to come and see the Leased Premises and its qualifications, during the final three (3) months of the Lease period. If the Lessee shall not have vacated the Leased Premises upon expiry of the lease period, he shall compensate the Lessor for any damages resulting therefrom. 8. Termination of this Agreement by the lessee: After the first 12 months period is completed and paid for, either party may terminate this agreement by notifying the other party 12 months prior to termination.9.Relationship of Parties: Under this agreement, Lessee shall not be considered a partner, agent, officer, or employee of the Lessor. The Lessee's officers, members, affiliates, volunteers, employees and independent contractors shall not be considered agents, officers or employees of the Lessor.10. Assignment: The Lessee shall not assign this Agreement to another party without the Lessor's prior written consent which shall not be unreasonably withheld.11.Insurance: The Lessee shall provide proof of insurance in accordance with the requirements established in Exhibit "C" to this Agreement.12.Indemnification: The Lessee shall indemnify and save harmless the Lessor, its officers, agents, and employees against: AnyandalldamagetoordestructionofthepropertyoftheLessor,itsofficers,agentsor employees,occupiedorusedbyorinthecare,custody,orcontroloftheLessee,orin proximitytothesiteoftheLessee'swork,causedbyanyactoromissiononoftheLessee under thisAgreement; Any and all claims and demands which may be made against the Lessor, its officers, agents or employees by reason of injury to or death of or damage suffered or sustained by an employee or agent of the of the Lessee under this Agreement to the extent of the Lessee's negligence or willful misconduct. The Lessor shall be liable to the extent of its grossnegligenceorwillfulmisconductinanyscenariowhichiscoveredbyClause12(b).

c. Any and all claims and demands which may be made against the Lessor, its officers, agents or employees by reason of infringement or alleged infringement of any trademark or copyright rights or claims caused by the use of any apparatus, appliance, or materials furnished by the Lessee under this Agreements; d.Any and all penalties imposed or damages sought on account of the violation of any law or regulation or of any term or condition of any permit, when said violation of any law or regulation or of any term or condition of any permit is due to negligence on the part of the Lessee; and e.The Lessee, at its own costs, expense, and risk shall defend any and all suits, actions, or other legal proceedings that may be brought against or for employees on any such claim or demand of such third persons, or to enforce any such penalty, and pay and satisfy any judgment or decree that may be rendered against the Lessor, its officers, agents or employees in any such suit, action, or other legal proceeding, when same were due to negligence of the Lessee. 13.Controlling Law: This Agreement shall be Interpreted and enforced in accordance with the laws of the Republic of Turkey. 14.Notice: All notice provided relative to the terms and conditions of this agreement shall be in writing to the addresses at the start of this Agreement. 15.Entirety and Integrity of this Agreement: This document represents the entire and integrated Agreement between the lessor and the lessee. This document supersedes and negates all prior negotiations, representations, agreements and amendments, either written or oral, regarding the Leased Premises and the use of the Leased Premises by Lessee. Both parties also recognize that some issues may not have been anticipated or addressed herein, and that changes to the Agreement may be warranted. This Agreement may be amended upon written consent of both parties.

EX-10.27

Exhibit 10.27

THRACE "GUNDEM PROPERTY'' YARD LEASE AGREEMENT – TAT Lessor: Giindem Yatmm ve Ticaret A. - Giimbet Mahallesi Yakamoz Sok. No:6 Bodrum/Mugla Lessee: TransAtlantic Turkey Ltd. Tiirkiye Ankara Ubesi - Iran Cad. Karum i merkezi No:21 Karum i merkezi F Blok Kat:5 <;:ankaya Ankara Turkey Effective Date: July 1, 2018 Foradequateconsideration,thereceiptandsufficiencyofwhichisacknowledged,Lessor,namedabove, leasesandletstoLessee, namedabove,aportion(suchportionbeingreferredtohereinasthe"Leased Premises") ofthefollowingfourparcelsoflandlocatedatMurath-BalhhocaDegirmenyolu,Tekirdagin theRepublic ofTurkey,asmorespecificallydescribedontheCertificatesattachedheretounderExhibit " A", the entirety of the four parcels being referred to as the "Thrace Yard". The portion of the Thrace Yardthatconstitutes the"Leased Premises"ismorespecificallydescribedonattachedExhibit"B". Foradequateconsideration,thisAgreementisenteredintoandaleaseoftheThraceYard(the"Lease") isgrantedbyLessorandacceptedbyLessee onthe followingterms: BASIC TERMS 1. Use of the Leased Premises: Lessee shall be permitted to use the Leased Premises for storage, maintenance and staging of materials and equipment for oilfield services and services related to oil & gas drilling , exploration, development, geological or geophysical activities or oilfield infrastructure for the term of this Agreement. 2. Purpose: Lessee agrees that the lease of the Leased Premises shall be for the sole purpose of theLessee'susesrelatedtooilfieldservicesandservicesrelatedtooil&gasdrilling,exploration, development,geologicalorgeophysicalactivitiesandinfrastructure.Anycostsassociatedwith theuseandmaintenanceofthepropertybytheLesseeforLessee'spurposesshallbeatthesole expense of theLessee. 3. Lease Period: The term of this Agreement shall commence upon the Effective Date shown hereinabove and shall extend for a period of 60months. 4. Rent: The Lessor agrees to provide the Lessee with the use of the Leased Premises for a monthlygrossrentalamountinUSDollarspayablewithinfirstfive(5)business daysofeach monhforthetermofthisAgreementintotheTurkishbankaccountdesignatedby theLessor, duringeachyearlyperiodasfollows:

Yearly Period Gross Monthly Payment (in USD excludes Withholding) 01June-18 31December-18 $8,500.00 01January – 19 31 December-19 $8,755.00 01 January – 20 31 December – 20 $9,017.00 01 January- 21 31December – 21 $9,288.00 01 January – 22 31 December- 22 $9,566.00 01 January – 23 30 June -23 $9,853.00 AlltaxwithholdingsasarerequiredunderTurkishlawareexcludedinthe netrental.TheLessee shall regularly furnish the Lessor with copies of the receipts for deposits into the Tax Office of the relevant taxes. V.A.T. will be exempted if Lessee provides the exemption certificate to Lessor. 2.LeasingofRemainderofThraceYard:Lessorshallbeentitledtolease,sublease,sell,tradeor otherwise dispose of that portion of the Thrace Yard not included as part of the Leased Premises; provided no such disposition shall impair or adversely impact Lessee's use of the LeasedPremises. LesseeacknowledgesthataportionoftheThraceYardwithintheLeased Premises is already or may in the future be under lease to a third party and agrees that all revenuesassociatedwiththeleasetothethirdpartyshallbeforLessor'saccount.3.Subleasing: Lessee shall be entitled to sub-let the Leased Premises to a third party , in part or in its entirety, with the permission of Lessor which shall not be unreasonably withheld.  Any rents or other revenues derived from such sublease shall be the property of Lessee. Provided, in the event the Leased Premises are in any way damaged or altered by sublessee, the Lessor may require Lessee to terminate the sublease, and the Lessee would be obligated to compensate for such damages, as well, without any need for the issuance of a protest or securing of court decree.4.Improvements to the Leased Premises: Lessee agrees that the Leased Premises are provided "as is" and the Lessor has no obligation to provide improvements to the Leased Premises for the Lessee's use. Any improvements required by the Lessee shall be provide at the sole expense of the Lessee. The costs of putting signs, shingles or ornamentation in or outside the Leased Premises, but the Lessee shall be borne entirely by him, and, all fixtures, appurtenances and immovable construction added to the Leased Premises shall accede to the Lessor at the  expiry of the lease period, without any right on the part of the Lessee to  demand any costs, expenses or compensation thereforwhatsoever.

GENERAL TERMS 1. Maintenance:TheLesseeagreestoperformmaintenanceoftheLeasedPremisesasrequired during the term of the Lease. Lessee shall maintain the Leased Premises at all times in a reasonablemannerandcondition.LesseeisobligedtoproperlyusetheLeasedPremisesasifit was his own and to refrain from doing anything that depreciate the qualification s, reputation and the value thereof. If there are others in the same property, coordinate his own use with them. 2. Extent&ConditionoftheleasedPremises:TheLesseeshallaccepttheLeasedPremises"as is." This Agreement shall not obligate the Lessor to guarantee the condition of the Leased Premises,thesuitabilityoftheLeasedPremisesfortheLessee'sintendeduse,thedurationthat theLeasedPremisesmaysafelyoccupied,ortheavailabilityof alternatefacilities. 3. UseforanotherPurposeProhibited:Ifthe LeasedPremises areusedforapurposeotherthana purpose permitted by this Agreement or if the Leased Premises are in any way materially damagedoraltered,theLessormayterminatethisLease andtheLesseewouldbeobligatedto compensate for such damages, as well, without any need for the issuance of a protest or securingofcourtdecree.Theinflictingofsaiddamagesbyathirdparty(i.e.sub-lessor)shallnot affecttherightsoftheLessortoclaimitfromtheprincipalLessee. 4.Repairs:IfitbecomesnecessarytorepairtheLeasedPremisesbeyondordinarywearandtear or if a third-party claims rights over the same, the Lessee is obliged to promptly inform the Lessor. If he fails to so notify, the Lessee shall be responsible for any damages. The Lessee is obligedto permitthecarryingoutofnecessaryrepairs.  Ifminoritemssuch asthe puttingof hinges,window-panes, locksandslides,white-washwhicharefortheordinary useoftheLeased PremisesaremadewithoutinformingtheLessorandwithoutwaitingforanappropriateperiod, thecoststhereofcannotbeclaimedfromLessor. 5. Taxes:Subjecttotheprovisionfor Lessortowithholdanddepositallrelevanttaxesonthelease rental payments, property taxes will be paid by the lessor whereas all taxes and municipal fees arisingduetotheoperationalactivitywillbepaidbythelessee.(Local)customsshallprevailin thismatter.Municipalandothertaxesand feesduetotheoperationalactivityofthelesseewill be paid bythe lessee. 6.ReturnoftheLeasedPremises: TheLesseewillbeobligedtoreturntheLeasedPremisesback to the Lessor in the same condition as he found it and duly observing (local) customs. Lessee shallreturnallfixturesandinstallationswhichwereintheproperty,fullywhentheleaseperiod expires.Incasethesefixturesand/orthe accessoriesoftheLeasedPremisesaremissingorhave depreciatedintheirvalueoverandabovethedepreciationthroughnormaluse,theLesseeshall also be obliged to compensate therefor, and if the Lessor so demands, reinstate them to their original condition. Lessee shall not be responsible for deterioration and depreciation of the Leased Premises when used pursuant to the Lease. It must be presumed that the Lessee took overtheLeasedPremisesingoodcondition. 7.End of Lease Matters: Lessee may not object to potential

applicants to come and see the Leased Premises and its qualifications, during the final three (3) months of the Lease period. If

the Lessee shall not have vacated the Leased Premises upon expiry of the lease period, he shall compensate the Lessor for any damages resulting therefrom. 8. Termination of this Agreement by the lessee: After the first 12 months period is completed andpaidfor,either partymayterminate thisagreementbynotifyingtheotherpartysixmonths prior totermination.9.Relationship of Parties: Under this agreement, Lessee shall not be considered a partner, agent, officer, or employee of the Lessor. The Lessee's officers, members, affiliates, volunteers, employees and independent contractors shall not be considered agents, officers or employees of theLessor. 10.Assignment: The Lessee shall not assign this Agreement to another party without the Lessor's prior written consent which shall not be unreasonablywithheld. 11.Insurance:TheLesseeshallprovideproofofinsurance inaccordancewiththerequirements establishedinExhibit"C"tothisAgreement.12.Indemnification: The Lessee shall indemnify and save harmless the Lessor, its officers, agents, and employeesagainst: a. Anyandalldamageto ordestructionofthepropertyoftheLessor,itsofficers,agentsor employees,occupiedorusedbyorinthecare,custody,orcontroloftheLessee,orin proximitytothesiteoftheLessee'swork,causedbyanyactoromissionoftheLessee under thisAgreement; b. Any and all claims and demands which may be made against the Lessor, its officers, agents or employees by reason of injury to or death of or damage suffered or sustained by an employee or agent of the of the Lessee under this Agreement to the extent of the Lessee' s negligence or willful misconduct. The Lessor shall be liable to the extent of its gross negligence or willful misconduct in any scenario which is covered by Clause12 (b); c. AnyandallclaimsanddemandswhichmaybemadeagainsttheLessor,itsofficers, agents or employees by reason of

infringement or alleged infringement of any trademarkorcopyrightrightsorclaimscausedbytheuseofanyapparatus,appliance, ormaterialsfurnishedbytheLesseeunderthisAgreement;d. Anyandallpenaltiesimposedordamagessoughtonaccountoftheviolationofanylaw orregulationorofanytermorconditionofanypermit,whensaidviolationofanylaw

orregulationorofanytermorconditionofanypermitisduetonegligenceonthepart of the Lessee;and e. TheLessee,atitsowncosts,expense,and riskshalldefendanyandallsuits,actions,or otherlegalproceedings thatmaybebroughtagainstorforemployeesonanysuch claim ordemandofsuchthird persons,ortoenforce anysuchpenalty,andpayandsatisfyany judgment or decree that may be rendered against the Lessor, its officers, agents or employees in any such suit, action, or other legal proceeding, when same were due to negligenceoftheLessee. 13. ControllingLaw: ThisAgreementshallbeinterpretedandenforcedinaccordancewiththelaws of the Republic ofTurkey 14. Notice:Allnoticeprovidedrelativetothetermsandconditionsof thisAgreementshallbein writingtotheaddressesatthestartofthisAgreement.15.Entirety and Integrity of this Agreement: This document represents the entire and integrated AgreementbetweentheLessorandtheLessee.Thisdocumentsupersedes and negatesallprior negotiations, representations, agreements and amendments, either written or oral, regarding theLeasedPremisesandtheuseoftheLeased PremisesbyLessee.Bothpartiesalsorecognize thatsomeissues maynothavebeenanticipatedoraddressedherein,andthatchangesto the Agreement may be warranted. This Agreement may be amended upon written consent of both parties.

EX-21.1

Exhibit 21.1

Subsidiaries of TransAtlantic Petroleum Ltd.

Subsidiary	Jurisdiction of Incorporation
Amity Oil International Pty Ltd	Australia
Incremental Petroleum Pty Ltd	Australia
TransAtlantic Australia Pty Ltd	Australia
TransAtlantic Exploration Mediterranean International Pty Ltd	Australia
TransAtlantic (Holdings) Australia Pty Ltd	Australia
DMLP, Ltd.	Bahamas
Talon Exploration, Ltd.	Bahamas
TransAtlantic Turkey, Ltd.	Bahamas
TransAtlantic Worldwide, Ltd.	Bahamas
TransAtlantic Holdings, Ltd.	Bahamas
TransAtlantic Holdings B.C. Ltd.	British Columbia
Direct Petroleum Bulgaria EOOD	Bulgaria
TransAtlantic Petroleum Cyprus Limited	Cyprus
TransAtlantic Petroleum (USA) Corp.	Delaware
TransAtlantic Worldwide Romania SRL	Romania
Amity Ham Petrol ve Doğal Gaz Arama ve Üretim A.Ş.	Turkey
DMLP Ham Petrol ve Doğal Gaz Arama ve Üretim A.Ş.	Turkey
Petrogas Petrol Gaz ve Petrokemya Urunleri Insaat Sanayive Ticaret A.S.	Turkey
Talon Ham Petrol ve Doğal Gaz Arama ve Üretim A.Ş.	Turkey
TAT Petroleum Ham Petrol ve Doğal Gaz Arama ve Üretim A.Ş.	Turkey
Transatlantic Petroleum Ham Petrol ve Doğal Gaz Arama ve Üretim A.Ş.	Turkey

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

The Board of Directors

TransAtlantic Petroleum Ltd.

We hereby consent to the incorporation by reference in the registration statements of Form S-8 (Nos. 333-162814, 333-200705, and 333-232442) and on Form S-3 (Nos. 333-204376 and 333-203696) of Transatlantic Petroleum Ltd. of our report dated March 25, 2020 relating to the consolidated financial statements of the Company as of December 31, 2019 and 2018 and for each of the two years in the period ended December 31, 2019, which includes an explanatory paragraph regarding the substantial doubt about the Company’s ability to continue as a going concern.

/s/ RBSM LLP

New York, NY

March 25, 2020

EX-23.2

Exhibit 23.2

DeGolyer and MacNaughton

5001 Spring Valley Road 

Suite 800 East

Dallas, Texas 75244 

March 25, 2020

TransAtlantic Petroleum Ltd.

16803 Dallas Parkway

Addison, Texas 75001

Ladies and Gentlemen:

We hereby consent to references to DeGolyer and MacNaughton as an independent petroleum engineering consulting firm under the headings “Glossary of Selected Oil and Natural Gas Terms,” “Part I – Item 1. Business,” “Part I – Item 2. Properties,” “Part I – Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Supplemental Oil and Natural Gas Reserves Information (Unaudited)” of the Annual Report on Form 10-K for the year ended December 31, 2019, of TransAtlantic Petroleum Ltd. (TransAtlantic) to be filed with the United States Securities and Exchange Commission on or about March 25, 2020 (the Annual Report), including any amendments thereto, and to the inclusion of our report of third party dated March 3, 2020, containing our estimates of the proved, probable, and possible reserves attributable to certain properties in Turkey and Bulgaria in which TransAtlantic has represented it holds an interest as of December 31, 2019.

We hereby further consent to the incorporation by reference of the foregoing in the Registration Statements on Form S-8 (Registration Nos. 333-162814, 333-200705, and 333-232442) and on Form S-3 (Registration Nos. 333-204376 and 333-203696) of TransAtlantic.

Exhibit 23.2

DeGolyer and MacNaughton

5001 Spring Valley Road 

Suite 800 East

Dallas, Texas 75244 

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-31.1

Exhibit 31.1

CERTIFICATION

I, N. Malone Mitchell 3rd, certify that:

1. I have reviewed this Annual Report on Form 10-K of TransAtlantic Petroleum Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 25, 2020	/s/ N. Malone Mitchell 3rd
	N. Malone Mitchell 3rd
	Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Michael P. Hill, certify that:

1. I have reviewed this Annual Report on Form 10-K of TransAtlantic Petroleum Ltd.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

March 25, 2020	/s/ Michael P. Hill
	Michael P. Hill
	Chief Accounting Officer (Principal Financial Officer and Principal Accounting Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of TransAtlantic Petroleum Ltd. (the “Company”) for the year ended December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), I, N. Malone Mitchell 3rd, Chief Executive Officer of the Company, hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:	March 25, 2020	/s/ N. Malone Mitchell 3rd
		N. Malone Mitchell 3rd
		Chief Executive Officer

A signed original of this written statement required by Section 906 has been provided to TransAtlantic Petroleum Ltd. and will be retained by TransAtlantic Petroleum Ltd. and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report on Form 10-K of TransAtlantic Petroleum Ltd. (the “Company”) for the year ended December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), I, Michael P. Hill Chief Accounting Officer of the Company, hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated:	March 25, 2020	/s/ Michael P. Hill
		Michael P. Hill Chief Accounting Officer
		(Principal Financial Officer and Principal Accounting Officer)

A signed original of this written statement required by Section 906 has been provided to TransAtlantic Petroleum Ltd. and will be retained by TransAtlantic Petroleum Ltd. and furnished to the Securities and Exchange Commission or its staff upon request.

The foregoing certification is being furnished as an exhibit to the Form 10-K pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Form 10-K for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

EX-99.1

Exhibit 99.1

DeGolyer and MacNaughton

5001 Spring Valley Road 

Suite 800 East

Dallas, Texas 75244

March 3, 2020

TransAtlantic Petroleum Ltd.

16803 Dallas Parkway, Suite 200

Addison, Texas 75001

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2019, of the extent and value of the estimated proved, probable, and possible oil, condensate, and sales gas reserves of certain properties in Turkey and Bulgaria in which TransAtlantic Petroleum Ltd. (TransAtlantic) has represented it holds an interest. This evaluation was completed on March 3, 2020. TransAtlantic has represented that these properties account for 100 percent on a net equivalent barrel basis of TransAtlantic’s net proved, probable, and possible reserves as of December 31, 2019. The net proved, probable, and possible reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a)
(1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by TransAtlantic.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2019. Net reserves are defined as that portion of the gross reserves attributable to the interests held by TransAtlantic after deducting all interests held by others.

Values for proved, probable, and possible reserves in this report are expressed in terms of estimated future gross revenue, future net revenue, and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves before reduction

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for net profits (where applicable). Future net revenue is calculated by deducting operating expenses, capital costs, abandonment costs, and net profits,where

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applicable,from future gross revenue.Operating expenses include field operating expenses, transportation and processing expenses, and an allocation of overhead that directly relates to production activities. Capital costs include drilling and completion costs, facilities costs, and the capitalized portion of field maintenance costs. Abandonment costs are represented by TransAtlantic to be inclusive of those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment. At the request of TransAtlantic, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a nominal discount rate of 10 percent compounded monthly over the expected period of realization.Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Estimates of reserves and revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was obtained from TransAtlantic. In the preparation of this report we have relied, without independent verification, upon information furnished by TransAtlantic with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, estimation of taxes, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves included in this report are classified by degree of proof as proved, probable, or possible. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating

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conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, 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.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Probable reserves – Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the

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proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (iv) and (vi) of the definition of possible reserves.

Possible reserves – Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the

7

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reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (iii) of the proved oil and gas reserves definition, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

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DeGolyer and MacNaughton

Undevelopedoil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019.” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by TransAtlantic, and analyses of areas offsetting

9

DeGolyer and MacNaughton

existing wells with test or production data, reserves were classified as proved, probable, or possible.The proved undeveloped reserves estimates were based on opportunities identified in the plan of development provided by TransAtlantic.

TransAtlantic has represented that its senior management is committed to the development plan provided by TransAtlantic and that TransAtlantic has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

When applicable, the volumetric method was used to estimate the original gas in place (OGIP) and the original oil in place (OOIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation.

When appropriate, estimates of ultimate recovery were obtained after applying recovery factors to OGIP or OOIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the fluids and rock properties, the structural positions of the properties, and the production histories. When applicable, other engineering methods were used to estimate recovery factors based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production‑decline curves and reserves forecasts, reserves were estimated only to the limits of economic production as defined under the Definition of Reserves heading of this report or to a license limit, including extensions if applicable, whichever comes first.

In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available.

Data provided by TransAtlanticfrom wells drilled through December 31, 2019, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through October 31, 2019. Estimated

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DeGolyer and MacNaughton

cumulative production, as of December 31, 2019, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

Oil and condensate reserves estimated herein are to be recovered by normal field separation and are expressed in barrels (bbl). In these estimates, 1 barrel equals 42 United States gallons. For the fields evaluated herein, condensate reserves were estimated to be zero.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities estimated herein are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.7 pounds per square inch absolute (psia). Gas quantities included in this report are expressed in thousands of cubic feet (10³ft³).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

Proved developed producing reserves were estimated based on performance trends. Proved undeveloped reserves were estimated for drilling and sidetracks based on statistical analysis of the performance of existing wells and recent drilling results, as well as volumetric analysis where sufficient data were available. Probable and possible reserves were based on better well performance than projected for the proved reserves plus incremental volumetric recovery relating to the drilling and recompletion estimates.

The fields evaluated herein are subject to a royalty of 12.5 percent. Certain wells are also subject to a net profits interest burden of 5 percent.

The net reserves quantities reported herein reflect the appropriate quantity reductions for royalty interests and overriding royalty interests, as well as the quantity reduction yielded from the estimated revenue associated with the net profits payable, where applicable.

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Primary Economic Assumptions

Revenue values in this report were estimated using initial prices, expenses, and costs provided by TransAtlantic in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein:

Oil, Condensate, and Gas Prices

TransAtlantic has represented that the oil, condensate, and gas prices used in this evaluation were based on a 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. The average Brent Oil price during this period was U.S.$62.74 per barrel. The oil, condensate, and gas prices used to estimate reserves herein are presented in the following table, expressed in United States dollars per barrel (U.S.$/bbl) and United States dollars per thousand cubic feet (U.S.$/10³ft³):

Country Field	Oil and Condensate Price (U.S.$/bbl)	Gas Price (U.S.$/103ft3)
Turkey
AG	NA	6.09
Arpatepe	58.07	NA
Bahar	58.86	NA
Bakuk	NA	3.18
Edirne	NA	6.09
Goksu	55.06	NA
Molla	58.86	NA
Selmo	58.65	NA
Yeniev	58.86	NA
Other TAT fields	NA	6.09
Bulgaria
West Koynare	NA	NA
Note: Fields with no sellable quantities of oil, condensate, or gas have been denoted as NA (not applicable).

The overall volume-weighted average oil and condensate prices used in this report were U.S.$58.79 per barrel, U.S.$58.65 per barrel, and U.S.$58.78 per barrel for proved, probable, and possible reserves, respectively. The average reference gas price during this period was the Botas Gas exchange price of

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DeGolyer and MacNaughton

U.S.$7.17 per thousand cubic feet (10³ft³). The overall volume‑weighted average gas prices in this report were U.S.$5.29per 10³ft³, U.S.$4.94per 10³ft³, and U.S.$5.16per 10³ft³ for proved, probable, and possible reserves, respectively. These prices were held constant for the lives of the properties.

Operating Expenses and Capital Costs

Estimates of operating expenses and capital costs were based on historical, current, and budgeted expenses and costs provided by TransAtlantic. In certain cases, future operating expenses, either higher or lower than current expenses, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Future capital expenditures were estimated using current values and were not adjusted for inflation.

Abandonment Costs

Abandonment costs were provided by TransAtlantic. These costs were estimated using current values and were not adjusted for inflation. Abandonment costs are represented by TransAtlantic to be inclusive of those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration (if any) associated with the abandonment. In some instances, abandonment costs were assigned to certain completion projections to ensure that well abandonment costs were included on a per-well basis and not duplicated for multiple recompletions in a single wellbore. TransAtlantic has represented that it will relinquish operation of the Selmo field to the Turkish Government at the end of June 2025, and therefore will not be responsible for abandonment costs pertaining to wells in the Selmo field that produce beyond June 2025.

Net Profits Interest

As represented by TransAtlantic, there is a 5-percent net profits interest burden for certain wells in the Alpullu, Edirne, Karapurcek, and REDY fields in Turkey. Where applicable, the

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DeGolyer and MacNaughton

net profits reduced TransAtlantic’s ownership of reserves and revenue.

Royalty

All fields are subject to a royalty of 12.5 percent. Certain wells in the Edirne field are subject to a third-party carried net revenue interest of 2.625 percent.

Taxes

TransAtlantic has represented that there are no production taxes to be paid in Turkey or Bulgaria. No other taxes, including income taxes for Turkey, Bulgaria, or the United States, were considered in this evaluation.

In our opinion, the information relating to estimated proved, probable, and possible reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932‑235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation
S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (5), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary of Conclusions

The estimated net proved reserves, as of December 31, 2019, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are

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DeGolyer and MacNaughton

summarized as follows, are summarized as follows, expressed in barrels (bbl) and thousands of cubic feet (10³ft³):

	Estimated by DeGolyer and MacNaughton Net Reserves as of December 31, 2019
	Oil (bbl)	Condensate (bbl)	Sales Gas (103ft3)
Proved Developed	5,623,938	0	2,281,610
Proved Undeveloped	4,634,768	0	185,216
Total Proved	10,258,706	0	2,466,826
Probable Developed	920,128	0	815,131
Probable Undeveloped	6,291,611	0	29,814
Total Probable	7,211,739	0	844,945
Possible Developed	1,062,299	0	950,845
Possible Undeveloped	5,679,655	0	32,562
Total Possible	6,741,954	0	983,407
Note: Probable and possible reserves have not been risk adjusted to make them comparable to proved reserves.

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of December 31, 2019, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in United States dollars (U.S.$):

	Estimated by DeGolyer and MacNaughton as of December 31, 2019
	Future Gross Revenue (U.S.$)	Operating Expenses (U.S.$)	Capital Costs (U.S.$)	Abandonment Costs (U.S.$)	Net Profits Reduction (U.S.$)	Future Net Revenue (U.S.$)	Present Worth at 10 Percent (U.S.$)
Proved Developed	342,406,436	83,016,997	1,312,500	927,837	84,983	257,064,119	178,977,330
Proved Undeveloped	273,852,221	42,504,764	54,855,000	376,350	49,523	176,066,584	109,532,996
Total Proved	616,258,657	125,521,761	56,167,500	1,304,187	134,506	433,130,703	288,510,326
Probable Developed	58,081,485	9,051,023	0	0	27,336	49,003,126	28,738,143
Probable Undeveloped	369,089,576	58,799,153	41,451,750	300,000	7,969	268,530,704	142,348,963
Total Probable	427,171,061	67,850,176	41,451,750	300,000	35,305	317,533,830	171,087,106
Possible Developed	67,331,424	10,574,299	0	0	37,232	56,719,893	31,268,069
Possible Undeveloped	334,092,731	31,770,276	7,200,000	80,000	8,708	295,033,747	147,950,974
Total Possible	401,424,155	42,344,575	7,200,000	80,000	45,940	351,753,640	179,219,043
Notes: 1. Values for probable and possible reserves have not been risk adjusted to make them comparable to values for proved reserves. 2. Future income taxes were not taken into account in the preparation of these estimates. 3. Net reserves and future net revenue reflect reductions for net profits, where applicable.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2019, reserves estimated herein.

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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in TransAtlantic. Our fees were not contingent on the results of our evaluation. This letter report has been prepared at the request of TransAtlantic. DeGolyer and MacNaughton has used all data, assumptions, procedures, and methods that it considers necessary to prepare this report.

Submitted,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/ Regnald A. Boles

Regnald A. Boles, P.E.

[Seal]Senior Vice President

DeGolyer and MacNaughton

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Regnald A. Boles, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to TransAtlantic Petroleum Ltd. dated March 3, 2020, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1983; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers; and that I have in excess of 36 years of experience in oil and gas reservoir studies and evaluations.

3. That DeGolyer and MacNaughton or its officers have no direct or indirect interest, nor do they expect to receive any direct or indirect interest in any properties or securities of TransAtlantic Petroleum Ltd. or affiliate thereof.

SIGNED: March 3, 2020

/s/ Regnald A. Boles

Regnald A. Boles, P.E.

[Seal]Senior Vice President

DeGolyer and MacNaughton

XML

Consolidated Statements of Operation and Comprehensive Loss - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues:
Total revenues	$ 67,380	$ 70,789
Costs and expenses:
Production	11,674	10,769
Exploration, abandonment and impairment	6,267	401
Seismic and other exploration	330	489
General and administrative	11,785	14,719
Depreciation, depletion and amortization	13,227	14,059
Accretion of asset retirement obligations	213	174
Total costs and expenses	48,597	45,276
Operating income	18,783	25,513
Other (expense) income:
Interest and other expense	(10,667)	(10,048)
Interest and other income	947	1,082
Loss on commodity derivative contracts	(966)	(1,797)
Foreign exchange loss	(4,569)	(10,292)
Total other expense	(15,255)	(21,055)
Income before income taxes	3,528	4,458
Current income tax expense	(3,119)	(2,820)
Deferred income tax expense	(5,775)	(6,854)
Net loss	(5,366)	(5,216)
Other comprehensive loss:
Foreign currency translation adjustment	(5,326)	(17,255)
Comprehensive loss	$ (10,692)	$ (22,471)
Net loss per common share:
Basic net loss per common share	$ (0.10)	$ (0.10)
Weighted average common shares outstanding	55,134	50,505
Diluted net loss per common share	$ (0.10)	$ (0.10)
Weighted average common and common equivalent shares outstanding	55,134	50,505
Oil and Natural Gas Sales [Member]
Revenues:
Total revenues	$ 66,829	$ 70,268
Other [Member]
Revenues:
Total revenues	551	521
Transportation Costs [Member]
Costs and expenses:
Cost of goods and services sold	$ 5,101	$ 4,665

XML

Related Party Transactions - Related Party Accounts Receivable and Accounts Payable (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Total related party accounts receivable	$ 561	$ 878
Total related party accounts payable	4,262	2,922
Service Agreement [Member]
Related Party Transaction [Line Items]
Total related party accounts receivable	433	526
Total related party accounts payable	204	372
PSIL MSA [Member]
Related Party Transaction [Line Items]
Total related party accounts receivable	128	352
Total related party accounts payable	3,959	2,439
Board of Directors [Member]
Related Party Transaction [Line Items]
Total related party accounts payable	$ 99	$ 111

XML

General

12 Months Ended

Dec. 31, 2019

Organization Consolidation And Presentation Of Financial Statements [Abstract]

General

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.

XML

Income Taxes - Components of Net Deferred Income Tax Liability (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
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)

XML

Shareholders' Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions						1 Months Ended	9 Months Ended	12 Months Ended
	Jul. 02, 2019	Dec. 31, 2018	Aug. 13, 2015	Apr. 24, 2015	Dec. 31, 2014	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Aggregate number of common shares issued to preferred share holders as payment of dividend								9,507,092
Antidilutive securities excluded from computation of earnings per share amount								41,600,000	42,000,000
Common share purchase warrants issued			233,333	233,333	233,334
Common share purchase		1							1
Common share purchase warrants, exercise price			$ 2.99	$ 5.65	$ 5.99
Warrants [Member]
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Common share purchase		1							1
Restricted Stock Units [Member]
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Estimated forfeiture rate of RSUs								12.50%
Restricted stock unit, vesting period								4 years
Share-based compensation expense								$ 0.4	$ 0.5
Unrecognized compensation expense						$ 0.5		$ 0.5
Unrecognized compensation expense recognition period								1 year 1 month 6 days
Series A Preferred Shares [Member]
Employee Service Share Based Compensation Allocation Of Recognized Period Costs [Line Items]
Aggregate number of common shares issued to preferred share holders as payment of dividend	2,321,568	1,808,001				4,521,360	2,664,164		1,808,001
Common shares issued, price per share	$ 0.7934	$ 1.0188				$ 0.4074	$ 0.6914	$ 0.4074	$ 1.0188
Preferred stock, dividend payment terms	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.	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.				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.	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.	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%.

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Income taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Reconciliation of Bermuda Income Tax Expense to Actual Income Tax Expense

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

Components of Net Deferred Income Tax Liability

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	)

Schedule of Unrecognized Tax Benefits

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

XML

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Related Party Accounts Receivable and Accounts Payable

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

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Segment information

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Segment information

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

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Asset Retirement obligations

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement obligations

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.

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New Accounting Pronouncements

12 Months Ended

Dec. 31, 2019

Accounting Changes And Error Corrections [Abstract]

New accounting pronouncements

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.

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.

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Property and Equipment (Tables)

12 Months Ended

Dec. 31, 2019

Property Plant And Equipment [Abstract]

Capitalized Costs under Successful Efforts Method for 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

Historical Cost of Equipment and Other Property on Gross Basis with Accumulated Depreciation

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

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Related Party Transactions

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Related party transactions

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.

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.

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 millionfor 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 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

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Related Party Transactions - Additional Information (Detail)										1 Months Ended	6 Months Ended		9 Months Ended	12 Months Ended
	Jul. 02, 2019 shares	Jun. 28, 2019 USD ($)	Dec. 31, 2018 USD ($) shares	Mar. 31, 2017 USD ($) shares	Nov. 04, 2016 USD ($) shares	Apr. 19, 2016 USD ($)	Aug. 13, 2015 $ / shares shares	Apr. 24, 2015 $ / shares shares	Dec. 31, 2014 $ / shares shares	Dec. 31, 2019 USD ($) shares	Jun. 30, 2023 USD ($)	Dec. 31, 2018 USD ($) NumberofParcelsofLand shares	Sep. 30, 2019 shares	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) shares	Dec. 31, 2018 USD ($) shares	Dec. 31, 2014 $ / shares shares	Jun. 14, 2018 ft²	Nov. 28, 2017 USD ($)	Aug. 31, 2016 USD ($)	Jun. 13, 2012 USD ($)
Related Party Transaction [Line Items]
Common share purchase warrants issued | shares							233,333	233,333	233,334
Common share purchase | shares			1									1						1
Common share purchase warrants, exercise price | $ / shares							$ 2.99	$ 5.65	$ 5.99										$ 5.99
Common share purchase warrants issued, expiration period																		Jan. 06, 2018
Aggregate number of common shares issued to preferred share holders as payment of dividend | shares																	9,507,092
Note receivable - related party										$ 3,951,000							$ 3,951,000						$ 11,500,000
Capital and operating expenditures																	10,500,000	$ 10,600,000
Dalea Promissory Note [Member]
Related Party Transaction [Line Items]
Debt instrument payment terms		(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.
Debt Instrument, principal payment		$ 61,500,000
Gundem Yard Lease [Member]
Related Party Transaction [Line Items]
Monthly rent												$ 8,500,000					$ 8,755,000
Lease commencements date																	Jul. 01, 2018
Lease expiration date																	Jun. 30, 2023
Number of parcels of land | NumberofParcelsofLand												4
Gundem Yard Lease [Member] | Forecast [Member]
Related Party Transaction [Line Items]
Monthly rent											$ 9,853,000			$ 9,566,000	$ 9,288,000	$ 9,017,000
Diyarbakir Yard Lease [Member]
Related Party Transaction [Line Items]
Monthly rent																	$ 40,000,000
Lease commencements date																	Jan. 01, 2018
Lease expiration date																	Jun. 30, 2023
Diyarbakir Yard Lease [Member] | Forecast [Member]
Related Party Transaction [Line Items]
Monthly rent											$ 44,153,000			$ 43,076,000	$ 42,025,000	$ 41,000,000
Dalea [Member]
Related Party Transaction [Line Items]
Aggregate number of common shares issued to preferred share holders as payment of dividend | shares																	6,710,071
Mitchell, and his Children [Member]
Related Party Transaction [Line Items]
Common share purchase warrants issued | shares							23,333	23,333											23,333
Mr. Mitchell [Member]
Related Party Transaction [Line Items]
Common share purchase warrants issued | shares							134,168	134,168											134,169
Randy Rochman [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares										15,000							15,000
Jonathon Fite [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares										69,000							69,000
Related Party [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares				84,000
Proceeds from issuance of preferred stocks				$ 4,200,000
Joint Venture [Member] | Dalea and Funds [Member]
Related Party Transaction [Line Items]
Convertible preferred shares issued upon conversion | shares					40,000
Joint Venture [Member] | Promissory Note [Member] | Dalea and Funds [Member]
Related Party Transaction [Line Items]
Note receivable - related party						$ 7,964,053
Cancellation of purchase price in promissory note						$ 3,500,000
Debt instrument, maturity date						Jun. 13, 2019
Debt instrument interest rate stated percentage						3.00%
Interest income																	$ 100,000	200,000
Promissory note, collateral amount						$ 2,000,000
Dalea Promissory Note [Member]
Related Party Transaction [Line Items]
Promissory notes default remedy period						30 days
Dalea Promissory Note [Member] | PSIL [Member]
Related Party Transaction [Line Items]
Noncontrolling equity voting interest percentage						50.00%
Gundem Fee Agreement [Member] | Gundem Real Estate [Member]
Related Party Transaction [Line Items]
Debt instrument interest rate stated percentage																						5.00%
Promissory note, collateral amount																						$ 10,000,000
Gundem Fee Agreement [Member] | Muratli Real Estate [Member]
Related Party Transaction [Line Items]
Debt instrument interest rate stated percentage																						5.00%
Promissory note, collateral amount																						$ 5,000,000
Diyarbakir Fee Agreement [Member] | Diyarbakir Real Estate [Member]
Related Party Transaction [Line Items]
Debt instrument interest rate stated percentage																						5.00%
Promissory note, collateral amount																						$ 5,000,000
Uras Fee Agreement [Member] | Ankara Real Estate [Member]
Related Party Transaction [Line Items]
Debt instrument interest rate stated percentage																					5.00%
Promissory note, collateral amount																					$ 5,200,000
Gundem Fee Agreement and the Diyarbakir Fee Agreement [Member]
Related Party Transaction [Line Items]
Decrease in principal amount of Amended Note																	$ 600,000	600,000
Longfellow [Member] | TransAtlantic USA [Member]
Related Party Transaction [Line Items]
Office sub lease space | ft²																				10,000
Office sub lease commencement date																	Jun. 14, 2018
Office sub Lease Expiration Date																	Jun. 30, 2020
Office sub lease monthly rent payable during first twelve months										$ 18,333,330							$ 18,333,330
Increase in office sub lease monthly rent payable from first year										$ 416,670							$ 416,670
Increase in office sub lease monthly rent payable, commencement date																	Jun. 30, 2019
Increase in office sub lease monthly rent payable, expiration date																	Jun. 30, 2021
Viking International Master Service Agreement [Member]
Related Party Transaction [Line Items]
Service agreement term																	5 years
Service agreement automatic extension term																	1 year
Amendment renewal term description																	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
2017 Notes [Member] | Dalea and Funds [Member]
Related Party Transaction [Line Items]
Repayments of debt																	$ 1,000,000
2017 Notes [Member] | Dalea and Funds [Member]
Related Party Transaction [Line Items]
Interest receivable			$ 5,800,000									$ 5,800,000						$ 5,800,000
Series A Preferred Shares [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares					921,000
Convertible preferred shares issued upon conversion | shares					45.754
Aggregate number of common shares issued to preferred share holders as payment of dividend | shares	2,321,568		1,808,001							4,521,360			2,664,164					1,808,001
Series A Preferred Shares [Member] | Dalea [Member]
Related Party Transaction [Line Items]
Aggregate number of common shares issued to preferred share holders as payment of dividend | shares			971,724
Series A Preferred Shares [Member] | Related Party [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares			495,000							821,000		495,000					821,000	495,000
Series A Preferred Shares [Member] | 2017 Notes [Member] | Private Placement Exchange Offer [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares					815,000
Amount of notes exchanged					$ 40,750,000
Convertible preferred shares issued upon conversion | shares					20
Value of principal amount on conversion					$ 1,000,000
Series A Preferred Shares [Member] | 2017 Notes [Member] | Private Placement Exchange Offer [Member] | Pinon Foundation [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares					200,000
Amount of notes exchanged					$ 10,000,000
Series A Preferred Shares [Member] | 2017 Notes [Member] | Private Placement Exchange Offer [Member] | Dalea [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares					41,000
Amount of notes exchanged					$ 2,100,000
Series A Preferred Shares [Member] | 2017 Notes [Member] | Private Placement Exchange Offer [Member] | Mitchell, and his Children [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares					40,000
Amount of notes exchanged					$ 2,000,000
Series A Preferred Shares [Member] | 2017 Notes [Member] | Private Placement [Member] | Pinon Foundation [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares					5,000
Proceeds from issuance of preferred stocks					$ 250,000
Series A Preferred Shares [Member] | 2017 Notes [Member] | Private Placement [Member] | Mitchell, and his Children [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares					1,000
Proceeds from issuance of preferred stocks					$ 50,000
Series A Preferred Shares [Member] | 2017 Notes [Member] | Private Placement [Member] | Certain Holders [Member]
Related Party Transaction [Line Items]
Preferred shares, issued | shares					106,000
Proceeds from issuance of preferred stocks					$ 5,300,000
Series A Preferred Stock [Member]
Related Party Transaction [Line Items]
Preferred Stock, Shares Issued | shares										328,000							328,000
Series A Preferred Stock [Member] | 2017 Notes [Member] | Dalea and Funds [Member]
Related Party Transaction [Line Items]
Repayments of debt																	$ 200,000
Series A Preferred Stock [Member] | 2017 Notes [Member] | Dalea and Funds [Member]
Related Party Transaction [Line Items]
Interest receivable										$ 4,000,000							$ 4,000,000

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Leases - Schedule of Operating Lease Costs (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Lessee Lease Description [Line Items]
Total lease costs	$ 970
Operations Yards [Member]
Lessee Lease Description [Line Items]
Total lease costs	584
Office Rent [Member]
Lessee Lease Description [Line Items]
Total lease costs	176
Vehicles [Member]
Lessee Lease Description [Line Items]
Total lease costs	128
Other [Member]
Lessee Lease Description [Line Items]
Total lease costs	$ 82

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Segment Information - Financial Information of Geographic Segments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting Information [Line Items]
Total revenues	$ 67,380	$ 70,789
Production	11,674	10,769
Exploration, abandonment and impairment	6,267	401
Seismic and other exploration	330	489
General and administrative	11,785	14,719
Depreciation, depletion and amortization	13,227	14,059
Accretion of asset retirement obligations	213	174
Total costs and expenses	48,597	45,276
Operating income	18,783	25,513
Interest and other expense	(10,667)	(10,048)
Interest and other income	947	1,082
Loss on commodity derivative contracts	(966)	(1,797)
Foreign exchange loss	(4,569)	(10,292)
Income before income taxes	3,528	4,458
Income tax expense	(8,894)	(9,674)
Net loss	(5,366)	(5,216)
Total assets	136,504	132,600
Capital expenditures	30,683	23,517
Transportation Costs [Member]
Segment Reporting Information [Line Items]
Cost of goods and services sold	5,101	4,665
Corporate, Non-Segment [Member]
Segment Reporting Information [Line Items]
General and administrative	5,373	9,222
Depreciation, depletion and amortization	132	142
Total costs and expenses	5,505	9,364
Operating income	(5,505)	(9,364)
Interest and other expense	(8,450)	(7,026)
Interest and other income	419	184
Foreign exchange loss	117	(351)
Income before income taxes	(13,419)	(16,557)
Net loss	(13,419)	(16,557)
Total assets	7,810	8,358
Operating Segments [Member] | Turkey [Member]
Segment Reporting Information [Line Items]
Total revenues	67,380	70,789
Production	11,513	10,649
Exploration, abandonment and impairment		401
Seismic and other exploration	330	488
General and administrative	6,274	5,344
Depreciation, depletion and amortization	13,095	13,917
Accretion of asset retirement obligations	190	151
Total costs and expenses	36,503	35,615
Operating income	30,877	35,174
Interest and other expense	(2,217)	(3,022)
Interest and other income	528	897
Loss on commodity derivative contracts	(966)	(1,797)
Foreign exchange loss	(4,626)	(9,932)
Income before income taxes	23,596	21,320
Income tax expense	(8,894)	(9,674)
Net loss	14,702	11,646
Total assets	127,986	122,325
Capital expenditures	25,146	23,517
Operating Segments [Member] | Turkey [Member] | Transportation Costs [Member]
Segment Reporting Information [Line Items]
Cost of goods and services sold	5,101	4,665
Operating Segments [Member] | Bulgaria [Member]
Segment Reporting Information [Line Items]
Production	161	120
Exploration, abandonment and impairment	6,267
Seismic and other exploration		1
General and administrative	138	153
Accretion of asset retirement obligations	23	23
Total costs and expenses	6,589	297
Operating income	(6,589)	(297)
Interest and other income		1
Foreign exchange loss	(60)	(9)
Income before income taxes	(6,649)	(305)
Net loss	(6,649)	(305)
Total assets	708	$ 1,917
Capital expenditures	$ 5,537

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Series A Preferred Shares - Schedule of Redemption Prices (Detail) - Series A Preferred Shares [Member]	Nov. 04, 2016
Redeemable Noncontrolling Interest [Line Items]
November 4, 2020	105.00%
November 4, 2021	103.00%
November 4, 2022	101.00%
November 4, 2023 and thereafter	100.00%

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Derivative Instruments - Fair Value of Derivative Instruments of Future Crude Oil Production (Detail) - Commodity Price [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) $ / bbl $ / Call bbl
Derivatives Fair Value [Line Items]
Estimated Fair Value of Liability | $	$ (966)
Three-way Collar - January 1, 2020 - April 30, 2020 [Member]
Derivatives Fair Value [Line Items]
Quantity (Bbl/day) | bbl	1,000
Collars Weighted Average Minimum Price (per Bbl) | $ / bbl	55.00
Weighted Average Maximum Price (per Bbl) | $ / bbl	72.90
Additional Call Ceiling | $ / Call	80.00
Estimated Fair Value of Liability | $	$ 21
Swap - January 1, 2020 - December 31, 2020 [Member]
Derivatives Fair Value [Line Items]
Quantity (Bbl/day) | bbl	986
Collars Weighted Average Minimum Price (per Bbl) | $ / bbl	60.30
Estimated Fair Value of Liability | $	$ (987)

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Series A Preferred Shares (Tables)

12 Months Ended

Dec. 31, 2019

Temporary Equity Disclosure [Abstract]

Schedule of Redemption Prices

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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Contingencies

12 Months Ended

Dec. 31, 2019

Commitments And Contingencies Disclosure [Abstract]

Contingencies

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 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 4^th 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.

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Leases - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019
Lessee Lease Description [Line Items]
Operating and financing lease options to renew, cancel or purchase	some contain options to renew, cancel or purchase
Weighted average remaining lease term	3 years 6 months
Weighted average discount rate	7.60%
Minimum [Member]
Lessee Lease Description [Line Items]
Lease agreements, term	1 year
Maximum [Member]
Lessee Lease Description [Line Items]
Lease agreements, term	5 years

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Segment Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019 Segment
Segment Reporting [Abstract]
Number of reportable geographic segments	2

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Contingencies - Additional Information (Detail) - USD ($)	1 Months Ended	12 Months Ended
	Oct. 31, 2015	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2012
Loss Contingencies [Line Items]
General and administrative		$ 11,785,000	$ 14,719,000
Bulgaria [Member]
Loss Contingencies [Line Items]
Recovery of contractual obligations				$ 2,000,000
Liquidated damages, claim amount	$ 200,000
Bulgaria [Member] | Aglen Exploration Permit Work Program [Member]
Loss Contingencies [Line Items]
General and administrative				$ 2,000,000

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Property and Equipment - Capitalized Costs under Successful Efforts Method for Oil and Natural Gas Properties (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Property Plant And Equipment [Line Items]
Oil and natural gas properties, proved	$ 167,948	$ 163,006
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
Turkey [Member]
Property Plant And Equipment [Line Items]
Oil and natural gas properties, proved	167,446	162,494
Oil and natural gas properties, unproved	12,978	14,965
Bulgaria [Member]
Property Plant And Equipment [Line Items]
Oil and natural gas properties, proved	$ 502	512
Oil and natural gas properties, unproved		$ 730

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Derivative Instruments - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Loss on derivative contracts	$ 966	$ 1,797

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Going Concern

12 Months Ended

Dec. 31, 2019

Going Concern [Abstract]

Going Concern

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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Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Common Shares [Member]	Treasury Stock [Member]	Warrants [Member]	Additional Paid-in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Accumulated Deficit [Member]
Beginning balance at Dec. 31, 2017	$ 32,605	$ 5,032	$ (970)		$ 575,412	$ (124,766)	$ (422,103)
Beginning balance, shares at Dec. 31, 2017		50,319,000	333,000	699,000
Issuance of common shares	1,841	$ 181			1,660
Issuance of common shares (in shares)		1,808,000
Issuance of restricted stock units		$ 28			(28)
Issuance of restricted stock units, shares		286,000
Expiration of warrants				(699,000)
Tax withholding on restricted stock units	(11)				(11)
Share-based compensation	455				455
Foreign currency translation adjustment	(17,255)					(17,255)
Net loss	(5,216)						(5,216)
Ending balance at Dec. 31, 2018	$ 12,419	$ 5,241	$ (970)		577,488	(142,021)	(427,319)
Ending balance, shares at Dec. 31, 2018	52,413,588	52,413,000	333,000
Issuance of common shares	$ 5,526	$ 950			4,576
Issuance of common shares (in shares)		9,507,000
Issuance of restricted stock units		$ 32			(32)
Issuance of restricted stock units, shares		310,000
Tax withholding on restricted stock units	(92)				(92)
Share-based compensation	419				419
Foreign currency translation adjustment	(5,326)					(5,326)
Net loss	(5,366)						(5,366)
Ending balance at Dec. 31, 2019	$ 7,580	$ 6,223	$ (970)		$ 582,359	$ (147,347)	$ (432,685)
Ending balance, shares at Dec. 31, 2019	62,230,058	62,230,000	333,000

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Subsequent events - Additional Information (Details) $ in Thousands			12 Months Ended
	Mar. 09, 2020 USD ($) $ / bbl $ / Call bbl	Feb. 24, 2020 USD ($) Employee Well	Dec. 31, 2019 USD ($) Boe Mcf	Dec. 31, 2018 USD ($)
Subsequent Event [Line Items]
Shares sold in exchange, amount			$ 5,526	$ 1,841
Subsequent Event [Member] | DenizBank [Member]
Subsequent Event [Line Items]
Derivative, net proceeds	$ 6,500
Subsequent Event [Member] | 2019 Term Loan [Member] | DenizBank [Member]
Subsequent Event [Line Items]
Term loan outstanding	$ 10,600
Subsequent Event [Member] | Three-way Collar - October 1, 2019 - April 30, 2020 [Member] | DenizBank [Member]
Subsequent Event [Line Items]
Quantity (Bbl/day) | bbl	1,000
Brent floor price | $ / bbl	55.00
Brent, cap price | $ / bbl	72.90
Additional Call Ceiling | $ / Call	80.00
Subsequent Event [Member] | Swap - January 1, 2020 - December 31, 2020 [Member] | DenizBank [Member]
Subsequent Event [Line Items]
Quantity (Bbl/day) | bbl	1,000
Brent strike price | $ / bbl	60.30
Petrogas [Member]
Subsequent Event [Line Items]
Average production for Petrogas Leases volume per day | Mcf			500
Average production for Petrogas Leases barrels Of oil equivalents per day | Boe			83
Petrogas [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Number of wells in exchange for release of plugging and abandonment obligations | Well		65
Petrogas [Member] | Reform Reform Ham Petrol Dogal Gaz Arama Uretim Sanayi ve Ticaret A.S. [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Number of employees | Employee		14
Shares sold in exchange, amount		$ 1,500

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Document and Entity Information - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2019

Mar. 20, 2020

Jun. 30, 2019

Cover [Abstract]

Document Type

10-K

Amendment Flag

false

Document Period End Date

Dec. 31, 2019

Document Fiscal Year Focus

2019

Document Fiscal Period Focus

FY

Title of 12(b) Security

Common shares, par value $0.10

Trading Symbol

TAT

Security Exchange Name

NYSEAMER

Entity Registrant Name

TRANSATLANTIC PETROLEUM LTD.

Entity Central Index Key

0001092289

Current Fiscal Year End Date

--12-31

Entity Well-known Seasoned Issuer

No

Entity Current Reporting Status

Yes

Entity Voluntary Filers

No

Entity Interactive Data Current

Yes

Entity Filer Category

Non-accelerated Filer

Entity Small Business

true

Entity Emerging Growth Company

false

Entity Shell Company

false

Entity Common Stock, Shares Outstanding

62,349,063

Entity Public Float

$ 17.0

Entity File Number

001-34574

Entity Incorporation, State or Country Code

D0

Entity Address, Address Line One

16803 Dallas Parkway

Entity Address, City or Town

Addison

Entity Address, State or Province

TX

Entity Address, Postal Zip Code

75001

City Area Code

214

Local Phone Number

220-4323

Document Annual Report

true

Document Transition Report

false

Documents Incorporated by Reference

The information required by Part III of this Annual Report on Form 10-K, to the extent not set forth herein, is incorporated by reference to the registrant’s definitive proxy statement relating to the 2020 Annual Meeting of Shareholders which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Annual Report on Form 10-K relates.

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Income Taxes - Reconciliation of Bermuda Income Tax Expense to Actual Income Tax Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
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

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Loans Payable - Additional Information (Detail) - USD ($)		12 Months Ended
	Apr. 27, 2017	Dec. 31, 2019	Dec. 31, 2018	May 28, 2018	Nov. 17, 2017	Aug. 31, 2016
Line Of Credit Facility [Line Items]
Interest expense		$ 10,667,000	$ 10,048,000
Loans payable		20,000,000	22,000,000
Non-cash Facilities [Member] | DenizBank [Member]
Line Of Credit Facility [Line Items]
Line Of Credit Facility Maximum Borrowing Capacity						$ 20,000,000
Loan Financing Costs [Member]
Line Of Credit Facility [Line Items]
Amortization of Deferred Loan Origination Fees, Net		$ 100,000	100,000
2016 TEMI Term Loan [Member]
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage		5.25%
Debt instrument interest rate basis for effective rate		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
Debt instrument payment terms		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
Amount of each installment payable through February 2017		$ 1,250,000
Amount of each installment payable through February 2018		$ 1,880,000
Line of credit facility, expiration date		Feb. 28, 2018
2016 TEMI Term Loan [Member] | Turkish Banking and Insurance Transactions Tax Rate [Member]
Line Of Credit Facility [Line Items]
Debt instrument basis spread on variable rate		0.2625%
2016 TEMI Term Loan [Member] | Credit Agreement [Member] | DenizBank [Member]
Line Of Credit Facility [Line Items]
Line of credit facility, initiation date		Aug. 31, 2016
Line Of Credit Facility Maximum Borrowing Capacity						$ 30,000,000
Line of credit facility, expiration date	Jun. 30, 2018
Debt instrument, monthly payments	$ 1,380,000
2017 Term Loan [Member]
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage		6.00%
Debt instrument interest rate basis for effective rate		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
Debt instrument payment terms		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
Line of credit facility, expiration date		Dec. 31, 2019
2017 Term Loan [Member] | Due until July 2018 [Member]
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage		0.00%
Debt instrument, principal installments		$ 0
2017 Term Loan [Member] | One Monthly Installment Payable through April 2019 [Member]
Line Of Credit Facility [Line Items]
Debt instrument, principal installments		1,380,000
2017 Term Loan [Member] | Nine Monthly Installments Payable through April 2019 [Member]
Line Of Credit Facility [Line Items]
Debt instrument, principal installments		1,200,000
2017 Term Loan [Member] | Eight Monthly Installments Payable through December 2019 [Member]
Line Of Credit Facility [Line Items]
Debt instrument, principal installments		1,000,000
2017 Term Loan [Member] | One Monthly Installment Occurring in October 2019 [Member]
Line Of Credit Facility [Line Items]
Amount of each installment payable occurring in October 2019		$ 1,200,000
2017 Term Loan [Member] | Turkish Banking and Insurance Transactions Tax Rate [Member]
Line Of Credit Facility [Line Items]
Debt instrument basis spread on variable rate		0.30%
2017 Term Loan [Member] | Credit Agreement [Member] | DenizBank [Member]
Line Of Credit Facility [Line Items]
Line of credit facility, initiation date		Nov. 17, 2017
Line Of Credit Facility Maximum Borrowing Capacity					$ 20,400,000
2018 Term Loan [Member]
Line Of Credit Facility [Line Items]
Debt instrument interest rate stated percentage		7.25%
Debt instrument interest rate basis for effective rate		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
Debt instrument payment terms		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
Line of credit facility, expiration date		Dec. 31, 2019
2018 Term Loan [Member] | Due through July 2018 [Member]
Line Of Credit Facility [Line Items]
Debt instrument, principal installments		$ 0
2018 Term Loan [Member] | Five Monthly Installments Payable through December 2018 [Member]
Line Of Credit Facility [Line Items]
Debt instrument, principal installments		200,000
2018 Term Loan [Member] | Four Monthly Installments Payable through April 2019 [Member]
Line Of Credit Facility [Line Items]
Debt instrument, principal installments		500,000
2018 Term Loan [Member] | Four Monthly Installments Payable through August 2019 [Member]
Line Of Credit Facility [Line Items]
Debt instrument, principal installments		1,000,000
2018 Term Loan [Member] | Four Monthly Installments Payable through December 2019 [Member]
Line Of Credit Facility [Line Items]
Debt instrument, principal installments		$ 750,000
2018 Term Loan [Member] | Turkish Banking and Insurance Transactions Tax Rate [Member]
Line Of Credit Facility [Line Items]
Debt instrument basis spread on variable rate		0.30%
2018 Term Loan [Member] | Credit Agreement [Member] | DenizBank [Member]
Line Of Credit Facility [Line Items]
Line of credit facility, initiation date		May 28, 2018
Line Of Credit Facility Maximum Borrowing Capacity				$ 10,000,000
2016, 2017, 2018 and 2019 Term Loan [Member]
Line Of Credit Facility [Line Items]
Interest expense		$ 2,200,000	1,800,000
Unsecured lines of credit [Member]
Line Of Credit Facility [Line Items]
Loans payable		$ 0	$ 0

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Segment information (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Financial Information of Geographic Segments

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

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General - Additional Information (Detail)			12 Months Ended
	Mar. 20, 2020 shares	Nov. 04, 2016	Dec. 31, 2019 Segment
Nature Of Business [Line Items]
Number of operating segments | Segment			2
Series A Preferred Shares [Member]
Nature Of Business [Line Items]
Preferred stock, dividend rate, percentage		12.00%
Subsequent Event [Member]
Nature Of Business [Line Items]
Percentage of common shares owned	49.90%
Subsequent Event [Member] | Series A Preferred Shares [Member]
Nature Of Business [Line Items]
Shares owned | shares	739,000
Preferred stock, dividend rate, percentage	12.00%

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Derivative instruments

12 Months Ended

Dec. 31, 2019

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Derivative instruments

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.”

 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

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Significant accounting policies

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 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.

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 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.

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Income taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income taxes

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

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.

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.

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Derivative instruments (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments And Hedging Activities Disclosure [Abstract]

Fair Value of Derivative Instruments of Future Crude Oil Production

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

)

Summary of Gross Fair Value of Commodity Derivative Instruments by Balance Sheet Classification

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

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Subsequent Events

12 Months Ended

Dec. 31, 2019

Subsequent Events [Abstract]

Subsequent events

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.

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Financial instruments

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Financial instruments

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 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, 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	)

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Series A Preferred Shares - Additional Information (Detail)				1 Months Ended	9 Months Ended	12 Months Ended
	Jul. 02, 2019	Dec. 31, 2018 USD ($) shares	Nov. 04, 2016 USD ($) Director $ / shares shares	Dec. 31, 2019 USD ($) shares	Sep. 30, 2019	Dec. 31, 2019 USD ($) shares	Dec. 31, 2018 USD ($) shares	Mar. 31, 2017 shares
Redeemable Noncontrolling Interest [Line Items]
Preferred stock dividends paid | $						$ 1,400,000
Preferred stock accrued dividends | $						9,507,092
Series A Preferred Shares [Member]
Redeemable Noncontrolling Interest [Line Items]
Preferred shares, issued			921,000
Preferred stock, shares issued value per share | $ / shares			$ 50.00
Preferred shares, value | $		$ 21,300,000		$ 5,000,000		$ 5,000,000	$ 21,300,000
Convertible preferred stock, terms of conversion						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).
Convertible preferred shares issued upon conversion			45.754
Conversion of stock, per share | $ / shares			$ 1.0928
Preferred stock redemption period end date			Nov. 04, 2024
Preferred stock redemption period start date			Nov. 04, 2020
Maximum closing sale price of common shares on conversion price			150.00%
Preferred stock, redemption description						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.
Change in control, offering redemption period			120 days
Preferred stock, dividend payment terms	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.	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.		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.	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.	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%.
Preferred stock, dividend rate, percentage			12.00%
Dividend payment description						Dividends are payable quarterly, on June 30, September 30, December 31, and March 31 of each year.
Preferred stock dividends paid | $							4,000,000
Preferred stock accrued dividends | $							$ 1,808,001
Preferred stock voting rights						no voting rights
Certificate of designation description						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.
Maximum amount of indebtedness for borrowed money allowed under certificate of designation | $			$ 100,000,000
PV10 reserve value percentage			35.00%
Series A Preferred Shares [Member] | Maximum [Member]
Redeemable Noncontrolling Interest [Line Items]
Right to elect number of directors | Director			2
Series A Preferred Shares [Member] | Minimum [Member]
Redeemable Noncontrolling Interest [Line Items]
Right to elect number of directors | Director			1
Series A Preferred Shares [Member] | Two Director [Member]
Redeemable Noncontrolling Interest [Line Items]
Preferred shares, outstanding			400,000
Series A Preferred Shares [Member] | One Director [Member] | Maximum [Member]
Redeemable Noncontrolling Interest [Line Items]
Preferred shares, outstanding			80,000
Series A Preferred Shares [Member] | One Director [Member] | Minimum [Member]
Redeemable Noncontrolling Interest [Line Items]
Preferred shares, outstanding			399,999
Series A Preferred Shares [Member] | Dividend Paid in Cash [Member]
Redeemable Noncontrolling Interest [Line Items]
Preferred stock, dividend rate, percentage			12.00%
Series A Preferred Shares [Member] | Dividend Paid in Common Shares [Member]
Redeemable Noncontrolling Interest [Line Items]
Preferred stock, dividend rate, percentage			16.00%
Related Party [Member]
Redeemable Noncontrolling Interest [Line Items]
Preferred shares, issued								84,000
Related Party [Member] | Series A Preferred Shares [Member]
Redeemable Noncontrolling Interest [Line Items]
Preferred shares, issued		495,000		821,000		821,000	495,000
Preferred shares, value | $		$ 24,750,000		$ 41,050,000		$ 41,050,000	$ 24,750,000
Preferred shares, outstanding		495,000		821,000		821,000	495,000

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Property and Equipment - Historical Cost of Equipment and Other Property on Gross Basis with Accumulated Depreciation (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Property Plant And Equipment [Line Items]
Gross equipment and other property	$ 10,202	$ 14,408
Accumulated depreciation	(5,378)	(5,268)
Net equipment and other property	4,824	9,140
Other equipment [Member]
Property Plant And Equipment [Line Items]
Gross equipment and other property	1,121	1,240
Land [Member]
Property Plant And Equipment [Line Items]
Gross equipment and other property	132	149
Inventory [Member]
Property Plant And Equipment [Line Items]
Gross equipment and other property	3,209	6,791
Gas gathering system and facilities [Member]
Property Plant And Equipment [Line Items]
Gross equipment and other property	172	194
Vehicles [Member]
Property Plant And Equipment [Line Items]
Gross equipment and other property	304	336
Leasehold improvements, office equipment and software [Member]
Property Plant And Equipment [Line Items]
Gross equipment and other property	$ 5,264	$ 5,698

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Asset Retirement Obligations - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations [Line Items]
Asset retirement obligation, net present value	$ 4,749	$ 4,667	$ 4,727
Asset retirement obligation, undiscounted value	$ 8,700
Turkey [Member]
Asset Retirement Obligations [Line Items]
Inflation rate per annum used to adjust asset retirement obligation	8.42%	12.65%
Turkey [Member] | Measurement Input, Discount Rate [Member]
Asset Retirement Obligations [Line Items]
Credit-adjusted risk-free rate used to discount asset retirement obligation	0.0755	0.0755

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Leases - Schedule of Future Non-Cancelable Minimum Lease Payments Under Operating and Financing Lease (Detail) $ in Thousands	Dec. 31, 2019 USD ($)
Leases [Abstract]
2020	$ 960
2021	867
2022	867
2023	557
2024	200
Total	3,451
Less: Imputed interest	342
Present value of lease liabilities	$ 3,109

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Financial Instruments - Additional Information (Detail) ₺ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) Institution	Dec. 31, 2019 TRY (₺)	Dec. 31, 2018 USD ($)	Dec. 31, 2018 TRY (₺)
Financial Statement Line Items With Differences In Reported Amount And Reporting Currency Denominated Amounts [Line Items]
Currency risk descriptions	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 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.
Allowance for doubtful accounts	$ 100,000		$ 500,000
Number of financial institutions | Institution	3
TUPRAS [Member]
Financial Statement Line Items With Differences In Reported Amount And Reporting Currency Denominated Amounts [Line Items]
Allowance for doubtful accounts	$ 0
Cash and cash equivalents [Member]
Financial Statement Line Items With Differences In Reported Amount And Reporting Currency Denominated Amounts [Line Items]
Cash and cash equivalents	$ 4,800,000	₺ 28.6	$ 1,500,000	₺ 7.8

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Income Taxes - Additional Information (Detail) ₺ in Millions, лв in Millions, in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2019 TRY (₺)	Dec. 31, 2018 TRY (₺)	Dec. 31, 2015 TRY (₺)	Dec. 31, 2019 TRY (₺)	Dec. 31, 2019 RON ( )	Dec. 31, 2019 BGN (лв)	Dec. 31, 2018 USD ($)
Income Tax [Line Items]
Valuation allowance	$ 12,030,000							$ 13,261,000
Liability for Uncertain Tax Positions, Noncurrent	6,800,000							$ 6,700,000
Unrecognized Tax Benefits, Period Increase (Decrease)	0
Turkish Foreign Subsidiaries [Member]
Income Tax [Line Items]
Withdrew reinvestment assertion | ₺				₺ 135.2
Dividend withholding taxes | ₺		₺ 383.7	₺ 329.7	₺ 135.2
Turkey [Member]
Income Tax [Line Items]
Non-capital tax losses	$ 1,200,000				₺ 7.1
Non-capital tax losses, expiration date	2020	2020
Romania [Member]
Income Tax [Line Items]
Non-capital tax losses	$ 400,000					1.6
Non-capital tax losses, expiration date	2020	2020
Bulgaria [Member]
Income Tax [Line Items]
Non-capital tax losses	$ 10,800,000						лв 18.9
Non-capital tax losses, expiration date	2020	2020
U.S [Member]
Income Tax [Line Items]
Non-capital tax losses	$ 50,600,000
Non-capital tax losses, expiration date	2020	2020

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Shareholders' Equity - Restricted Stock Unit Activity (Detail) - Restricted Stock Units [Member] shares in Thousands	12 Months Ended
	Dec. 31, 2019 $ / shares shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unvested RSUs outstanding, beginning balance | shares	454
Granted | shares	767
Forfeited | shares	(4)
Vested | shares	(362)
Unvested RSUs outstanding, ending balance | shares	855
Unvested RSUs, weighted average grant date fair value Per RSU, beginning balance | $ / shares	$ 1.42
Granted, weighted average grant date fair value Per RSU | $ / shares	0.77
Forfeited, weighted average grant date fair value Per RSU | $ / shares	1.29
Vested, weighted average grant date fair value Per RSU | $ / shares	1.42
Unvested RSUs weighted average grant date fair value Per RSU, ending balance | $ / shares	$ 0.84

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Asset Retirement Obligations - Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
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

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Consolidated Statements of Cash Flows (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019	Dec. 31, 2018	Jan. 01, 2018
Cash and cash equivalents	$ 9,664	$ 9,900	$ 9,892	$ 18,900
Other Assets [Member]
Restricted cash	$ 100	$ 100	$ 100	$ 1,500

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Common shares, par value	$ 0.10	$ 0.10
Common shares, authorized	200,000,000	200,000,000
Common shares, issued	62,230,058	52,413,588
Common shares, outstanding	62,230,058	52,413,588
Unrelated Party [Member] | Series A Preferred Shares [Member]
Preferred shares, par value	$ 0.01	$ 0.01
Preferred shares, authorized	100,000	426,000
Preferred shares, issued	100,000	426,000
Preferred shares, outstanding	100,000	426,000
Preferred shares, liquidation preference per share	$ 50	$ 50
Related Party [Member] | Series A Preferred Shares [Member]
Preferred shares, par value	$ 0.01	$ 0.01
Preferred shares, authorized	821,000	495,000
Preferred shares, issued	821,000	495,000
Preferred shares, outstanding	821,000	495,000
Preferred shares, liquidation preference per share	$ 50	$ 50

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Loans payable

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Loans payable

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.  

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.  

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 $0.1millionduring each of 2019 and 2018.

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Series A Preferred Shares

12 Months Ended

Dec. 31, 2019

Temporary Equity Disclosure [Abstract]

Series A preferred shares

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%

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.  

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Shareholders' equity (Tables)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Restricted Stock Units Activity

Share-based compensation of approximately $0.4 million and $0.5 millionwith 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

Basic and Diluted Earnings Per Common Share Computations

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	)

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Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Schedule of Operating Lease Costs

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

Schedule of Future Non-Cancelable Minimum Lease Payments Under Operating and Financing Lease

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

Schedule of Future Non-Cancelable Minimum Lease Payments Under Operating Lease

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

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Significant Accounting Policies - Additional information (Detail)		12 Months Ended
	Nov. 04, 2016 $ / shares shares	Dec. 31, 2019 USD ($) Contract	Dec. 31, 2018 USD ($)
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts		$ 100,000	$ 500,000
Determination of exploratory well's ability to produce, term		1 year
Number of sales contracts consists revenue | Contract		2
Liability for Uncertain Tax Positions, Noncurrent		$ 6,800,000	6,700,000
Series A Preferred Shares [Member]
Significant Accounting Policies [Line Items]
Preferred shares, issued | shares	921,000
Preferred stock, dividend rate, percentage	12.00%
Preferred stock, shares issued value per share | $ / shares	$ 50.00
TUPRAS [Member]
Significant Accounting Policies [Line Items]
Allowance for doubtful accounts		0
Oil and Natural Gas Sales [Member]
Significant Accounting Policies [Line Items]
Sales revenue, crude oil and natural gas		66,829,000	70,268,000
Oil and Natural Gas Sales [Member] | TUPRAS [Member]
Significant Accounting Policies [Line Items]
Sales revenue, crude oil and natural gas		$ 65,800,000	$ 68,200,000
Sales Revenue, Net [Member] | Revenue from Rights Concentration Risk [Member]
Significant Accounting Policies [Line Items]
Concentration Risk, Percentage		97.70%	96.40%
Minimum [Member]
Significant Accounting Policies [Line Items]
Equipment and other property, estimated useful lives		3 years
Maximum [Member]
Significant Accounting Policies [Line Items]
Equipment and other property, estimated useful lives		7 years

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Shareholders' Equity - Basic and Diluted Earnings Per Common Share Computations (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Equity [Abstract]
Net loss	$ (5,366)	$ (5,216)
Weighted average common shares outstanding	55,134	50,505
Basic net loss per common share	$ (0.10)	$ (0.10)
Weighted average common and common equivalent shares outstanding	55,134	50,505
Diluted net loss per common share	$ (0.10)	$ (0.10)

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Loans Payable - Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Loans payable	$ 20,000	$ 22,000
Less: current portion	17,143	22,000
Long-term portion	2,857
Term Loan [Member]
Debt Instrument [Line Items]
Loans payable	$ 20,000	$ 22,000

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Income Taxes - Schedule of Unrecognized Tax Benefits (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
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

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018
Operating activities:
Net loss		$ (5,366)		$ (5,216)
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-based compensation		419		455
Foreign currency loss		5,136		13,299
Loss on commodity derivative contracts		966		1,797
Cash settlement on commodity derivative contracts				(4,012)
Amortization on loan financing costs		41		42
Interest on Series A Preferred Shares paid in common shares		5,526		1,842
Deferred income tax expense		5,775		6,854
Exploration, abandonment and impairment		6,267		401
Depreciation, depletion and amortization		13,227		14,059
Accretion of asset retirement obligations		213		174
Changes in operating assets and liabilities:
Accounts receivable		(1,102)		(1,358)
Prepaid expenses and other assets		(7,013)		(6,673)
Accounts payable and accrued liabilities		9,114		7,031
Net cash provided by operating activities		33,203		28,695
Investing activities:
Additions to oil and natural gas properties		(29,348)		(23,517)
Additions to equipment and other properties		(1,482)		(3,015)
Net cash used in investing activities		(30,830)		(26,532)
Financing activities:
Tax withholding on restricted share units		(92)		(11)
Note receivable - related party		1,000
Loan proceeds		20,605		10,000
Loan repayment		(22,605)		(16,625)
Net cash used in financing activities		(1,092)		(6,636)
Effect of exchange rate on cash flows, cash equivalents and restricted cash		(1,504)		(5,931)
Net decrease in cash, cash equivalents and restricted cash		(223)		(10,404)
Cash, cash equivalents and restricted cash, beginning of year	[1]	10,027	[2]	20,431
Cash, cash equivalents and restricted cash, end of year	[2]	9,804		10,027	[1]
Supplemental disclosures:
Cash paid for interest		4,151		7,917
Cash paid for taxes		$ 3,436		$ 3,239

[1] The balance at January 1, 2018 includes cash and cash equivalents of $18.9 million and restricted cash of $1.5 million in other assets. The balance at January 1, 2019 includes cash and cash equivalents of $9.9 million and restricted cash of $0.1 million in other assets.

[2] The end of period balance at December 31, 2018 includes cash and cash equivalents of $9.9 million and restricted cash of $0.1 million in other assets. The end of period balance at December 31, 2019 includes cash and cash equivalents of $9.7 million and restricted cash of $0.1 million in other assets.

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 9,664	$ 9,892
Accounts receivable, net
Oil and natural gas sales	13,299	12,912
Joint interest and other	1,218	982
Related party	561	878
Prepaid and other current assets	12,375	8,696
Note receivable - related party		5,828
Inventory	7,091	5,167
Total current assets	44,208	44,355
Oil and natural gas properties (successful efforts method)
Proved	167,948	163,006
Unproved	12,978	15,695
Equipment and other property	10,202	14,408
Property and equipment, gross	191,128	193,109
Less accumulated depreciation, depletion and amortization	(106,610)	(105,850)
Property and equipment, net	84,518	87,259
Other long-term assets:
Other assets	3,827	986
Note receivable - related party	3,951
Total other assets	7,778	986
Total assets	136,504	132,600
Current liabilities:
Accounts payable	4,555	3,896
Accounts payable - related party	4,262	2,922
Accrued liabilities	15,244	13,073
Derivative liability	966
Loans payable	17,143	22,000
Total current liabilities	42,170	41,891
Long-term liabilities:
Asset retirement obligations	4,749	4,667
Accrued liabilities	10,370	7,259
Deferred income taxes	22,728	20,314
Loans payable	2,857
Total long-term liabilities	40,704	32,240
Total liabilities	82,874	74,131
Commitments and contingencies
Shareholders' equity:
Common shares, $0.10 par value, 200,000,000 shares authorized; 62,230,058 shares and 52,413,588 shares issued and outstanding as of December 31, 2019 and 2018, respectively	6,223	5,241
Treasury shares	(970)	(970)
Additional paid-in-capital	582,359	577,488
Accumulated other comprehensive loss	(147,347)	(142,021)
Accumulated deficit	(432,685)	(427,319)
Total shareholders' equity	7,580	12,419
Total liabilities, Series A preferred shares and shareholders' equity	136,504	132,600
Series A Preferred Shares [Member]
Long-term liabilities:
Preferred shares, value	5,000	21,300
Related Party [Member] | Series A Preferred Shares [Member]
Long-term liabilities:
Preferred shares, value	$ 41,050	$ 24,750

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Shareholders' equity

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Shareholders' equity

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 millionwith 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

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 42.0million 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.

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Property and equipment

12 Months Ended

Dec. 31, 2019

Property Plant And Equipment [Abstract]

Property and equipment

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.

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.

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Going Concern - Additional Information (Detail) - USD ($)		12 Months Ended
	Mar. 24, 2020	Dec. 31, 2019	Dec. 31, 2018	Jan. 01, 2019	Jan. 01, 2018
Going Concern [Line Items]
Net loss		$ 5,366,000	$ 5,216,000
Long-term debt		2,857,000
Short-term debt		17,143,000	22,000,000
Cash		9,664,000	$ 9,892,000	$ 9,900,000	$ 18,900,000
Working capital surplus		$ 2,000,000
Subsequent Event [Member]
Going Concern [Line Items]
Crude oil prices declined per barrel	$ 25

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Loans payable (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Debt

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.

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Financial instruments (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Valuation of Financial Liabilities

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	)

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	)

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General (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Nature of operations

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

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.

Basis of preparation

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

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

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

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

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

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 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

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

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

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

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.

Asset retirement obligations

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

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

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

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

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 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

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

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

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.

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.

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.

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Leases

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Leases

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

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

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Asset Retirement obligations (Tables)

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Changes in Asset Retirement Obligations

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

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New Accounting Pronouncements - Additional Information (Detail) - Accounting Standards Update 2016-02 [Member] $ in Millions	Jan. 01, 2019 USD ($)
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operating lease, right-of-use asset	$ 2.7
Operating lease, liability	$ 2.7

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Property and Equipment - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property Plant And Equipment [Line Items]
Proved development wells excluded from depletion	$ 200	$ 200
Acquisition costs of proved properties	5,000	6,500
Well costs and additional development costs	63,800	53,400
Exploratory dry hole costs	6,300	300
Capitalized exploratory cost greater than one year	0	0
Inventory	7,091	5,167
Inventory [Member]
Property Plant And Equipment [Line Items]
Property plant and equipment excluded from depreciation	$ 10,300	$ 12,000

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Leases - Schedule of Future Non-Cancelable Minimum Lease Payments Under Operating Lease (Detail) $ in Thousands	Dec. 31, 2018 USD ($)
Leases [Abstract]
2019	$ 963
2020	710
2021	636
2022	626
2023	316
Total	$ 3,251

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Financial Instruments - Valuation of Financial Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets (liabilities), fair value	$ (18,299)	$ (20,130)
Disclosed but not carried at fair value [Member] | 2019 Term Loan [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities, fair value	(17,333)
Disclosed but not carried at fair value [Member] | 2017 Term Loan [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities, fair value		(11,938)
Disclosed but not carried at fair value [Member] | 2016 Term Loan [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities, fair value		(8,192)
Measured on a recurring basis [Member] | Derivative Financial Instruments (commodity) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities, fair value	(966)
Significant Other Observable Inputs (Level 2) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets (liabilities), fair value	(966)
Significant Other Observable Inputs (Level 2) [Member] | Measured on a recurring basis [Member] | Derivative Financial Instruments (commodity) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities, fair value	(966)
Significant Unobservable Inputs (Level 3) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Assets (liabilities), fair value	(17,333)	(20,130)
Significant Unobservable Inputs (Level 3) [Member] | Disclosed but not carried at fair value [Member] | 2019 Term Loan [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities, fair value	$ (17,333)
Significant Unobservable Inputs (Level 3) [Member] | Disclosed but not carried at fair value [Member] | 2017 Term Loan [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities, fair value		(11,938)
Significant Unobservable Inputs (Level 3) [Member] | Disclosed but not carried at fair value [Member] | 2016 Term Loan [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Liabilities, fair value		$ (8,192)