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, 2018
OR
(cid:4) 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
(State or other jurisdiction of
incorporation or organization)
16803 Dallas Parkway
Addison, Texas
(Address of principal executive offices)
None
(I.R.S. Employer
Identification No.)
75001
(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
Common shares, par value $0.10
Name of each exchange on which registered
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 (cid:4) 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 (cid:4) 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 (cid:4)
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 (cid:4)
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of
registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. (cid:4)
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
Non-accelerated filer
Emerging growth company
(cid:4)
(cid:4)
(cid:4)
Accelerated filer
Smaller reporting company
(cid:4)
⌧
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. (cid:4)
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes (cid:4) 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, 2018 (the last business day of the registrant’s most recently completed second fiscal quarter), was approximately $41.9 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 22, 2019, there were 52,496,666 common shares outstanding.
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 2019 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.
DOCUMENTS INCORPORATED BY REFERENCE
TRANSATLANTIC PETROLEUM LTD.
FORM 10-K
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2018
INDEX
PART I
Item 1.
Business ..............................................................................................................................................................................
Item 1A. Risk Factors ........................................................................................................................................................................
Item 1B. Unresolved Staff Comments...............................................................................................................................................
Properties ............................................................................................................................................................................
Item 2.
Item 3.
Legal Proceedings...............................................................................................................................................................
Item 4. Mine Safety Disclosures.....................................................................................................................................................
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities ........
Item 6.
Selected Financial Data ......................................................................................................................................................
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations ............................................
Item 7A. Quantitative and Qualitative Disclosures about Market Risk. ...........................................................................................
Financial Statements and Supplementary Data ..................................................................................................................
Item 8.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............................................
Item 9A. Controls and Procedures.....................................................................................................................................................
Item 9B. Other Information ...............................................................................................................................................................
PART III
Item 10. Directors, Executive Officers and Corporate Governance .................................................................................................
Item 11. Executive Compensation ....................................................................................................................................................
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters ..........................
Item 13. Certain Relationships and Related Transactions, and Director Independence...................................................................
Item 14. Principal Accountant Fees and Services.............................................................................................................................
PART IV
Item 15. Exhibits and Financial Statement Schedules .....................................................................................................................
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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; 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
actions by insurgent groups or other conflicts; 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
iii
project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including
governmental entities.
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, 2018 and 2017 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, 2018, we held interests in 372,050 and 162,500 net acres of developed and
undeveloped oil and natural gas properties in Turkey and Bulgaria, respectively. As of March 22, 2019, approximately 48% of our
outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, the chairman of our board of directors and our chief
executive officer.
Based on the reserves report prepared by DeGolyer and MacNaughton, independent petroleum engineers, our estimated proved
reserves at December 31, 2018 in Turkey were 10,383 Mboe, of which 96.1% was oil. Of these estimated proved reserves, 52.2%
were proved developed reserves. As of December 31, 2018, the Standardized Measure and PV-10 of our proved reserves in Turkey
were $266.2 million and $320.6 million, respectively. See “Item 2. Properties—Value of Proved Reserves” for a reconciliation of PV-
10 to the Standardized Measure.
Recent Developments
2019 Term Loan. On February 22, 2019, the Turkish branch of TransAtlantic Exploration Mediterranean International Pty Ltd
(“TEMI”) entered into a $20.0 million term loan (the “2019 Term Loan”) with DenizBank, A.S (“DenizBank”) under our general
credit agreement with DenizBank (the “Credit Agreement”).
The 2019 Term Loan bears interest at a fixed rate of 7.5% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish
government) per annum. The 2019 Term Loan has a ten-month grace period during which the 2019 Term Loan bears interest but no
payments are due other than a single interest only payment of $0.76 million in August 2019. After the ten-month grace period, the
2019 Term Loan is payable in fourteen monthly principal installments of $1.43 million plus interest. The 2019 Term Loan matures in
February 2021. Amounts repaid under the 2019 Term Loan may not be re-borrowed, and early repayments under the 2019 Term Loan
are subject to early repayment fees.
Our Properties and Operations
Summary of Geographic Areas of Operations
The following table shows net reserves information as of December 31, 2018:
Proved Developed
Reserves (Mboe)
Proved
Undeveloped
Total Proved
Reserves (Mboe)
Reserves (Mboe)
Probable Reserves
(Mboe)
Possible Reserves
(Mboe)
Turkey
5,423
4,960
10,383
5,884
6,360
Turkey
As of December 31, 2018, we held interests in five onshore exploration licenses and 18 onshore production leases covering a total
of 443,268 gross (372,050 net) acres in Turkey. As of December 31, 2018, we had total net proved reserves of 9,976 Mbbl of oil and
2,440 Mmcf of natural gas, net probable reserves of 5,748 Mbbl of oil and 817 Mmcf of natural gas and net possible reserves of 6,204
Mbbl of oil and 938 Mmcf of natural gas in Turkey. During 2018, our average wellhead production was 3,355 net Boepd of oil and
natural gas in Turkey. The following summarizes our core producing properties in Turkey:
Southeastern Turkey. During 2018, 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.
1
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 2018, our net wellhead production of crude
oil from the Selmo field was 653,719 Bbls at an average rate of 1,791 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, 2018, we had 55 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 2018, our wellhead production of crude oil from the Molla area was 468,514 Bbls at an average rate of 1,284 Bbl/d. At December
31, 2018, we had 16 gross and net producing wells on the Molla licenses.
We hold a 50% working interest in our Arpatepe production lease. For 2018, our share of wellhead production of net crude oil from
the Arpatepe field was 51,127 Bbls at an average rate of 140 Bbl/d. At December 31, 2018, we had five producing wells on the
Arpatepe production lease. We have operated the Arpatepe production lease since December 2015.
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 2018.
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 2018, our net
wellhead production was 238,865 Mcf at an average rate of 645 Mcf/d from all of the gas fields.
Bulgaria
As of December 31, 2018, we held interests in one production concession covering a total of 162,500 net undeveloped acres in
Bulgaria. During 2018, we had no production or reserves in Bulgaria.
Current Operations
Southeastern Turkey
Molla
Yeniev Field. Both the Yeniev-1 and West Yeniev-1 wells continue flowing naturally with little water. In November 2018, we
spud the East Yeniev-1 appraisal well to further delineate the structure. The well was drilled to a total measured depth of 9,900 feet
and encountered hydrocarbon shows in the Mardin and Bedinan formations. Completion operations began in January 2019 and
resulted in a discovery in the Mardin formation.
Other. We spud the Blackeye-1 well in January 2019. The well was drilled to a total measured depth of 11,105 feet and
encountered oil shows in the Hazro, Mardin, and Bedinan formations. Completion operations began in February 2019.
Selmo
We have completed the initial phase of operations in the Selmo-1 well to re-enter and test the Permian formation, establishing
the productivity of the Permian formation. During a short-term flow test of a previously untested interval, the Selmo-1 well tested 45.6
API condensate along with natural gas containing a high carbon dioxide percentage component. While the Selmo-1 well lies in what is
interpreted as the gas cap of the structure, the positive test results warrant further testing lower on the structure.
Northwestern Turkey
Thrace Basin BCGA
We continue to evaluate our prospects in the Thrace Basin’s Basin Center Gas Accumulation (“Thrace Basin BCGA”) in light of
the recent production test results at the Yamalik-1 exploration well operated by Valeura Energy Inc. (“Valeura”) with their partner
Equinor ASA (formerly Statoil ASA) (“Equinor”). The Yamalik-1 exploration well is located on a license directly adjacent to our
2
120,000 net acres in the Thrace Basin of which we believe approximately 50,000 net acres (100% working interest, 87.5% net revenue
interest) is in the Thrace Basin BCGA and analogous to the Valeura and Equinor acreage.
Subsequent to drilling and testing of the Yamalik-1 well, the joint venture between Valeura and Equinor announced a three-well
program. In the first quarter of 2019, Valeura and Equinor announced that they drilled and cased a second well in the Thrace Basin
BCGA, the Inanli-1 well. According to Valeura and Equinor, the well was drilled to a total depth of 4,885 meters and encountered
1,615 meters of high net-to-gross sandstone, which they interpreted to contain over-pressured gas. Valeura and Equinor announced
that they expect to complete the well in the first quarter of 2019. In the first quarter of 2019, Valeura and Equinor announced that they
spud the Devepinar-1 appraisal well and drilled it to intermediate casing point at 3,375 meters. According to Valeura and Equinor, the
Devepinar-1 appraisal well is designed as a 20-kilometer step-out well to test the lateral extent of the Thrace Basin BCGA.
We expect to spud a shallow exploration well on our license in the Thrace Basin in the second quarter of 2019.
Bulgaria
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. We are currently evaluating future activity in Bulgaria.
Planned Operations
We expect our net field capital expenditures for 2019 to range between $25.0 million and $30.0 million. We expect net field
capital expenditures during 2019 to include between $24.0 million and $29.0 million in drilling and completion expense for 10
planned wells and approximately $1.0 million for recompletions. We expect that cash on hand and cash flow from operations will be
sufficient to fund our 2019 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek
other funding sources. Our projected 2019 capital expenditure budget is subject to change.
Customers
Oil. During 2018, 87.5% 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 2018, we sold $68.2 million of oil to TUPRAS,
representing 96.4% 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 and delivered to our
TPAO Batman tanks and to the Boru Hatlari ile Petrol Tasima A.S. (“BOTAŞ”) Dörtyol plant. 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. No other
purchasers of our oil accounted for more than 10% of our total revenues.
Natural Gas. During 2018, 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.
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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
“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:
(cid:129) the risk of expropriation, nationalization, war, revolution, political instability, border disputes, renegotiation or modification
of existing contracts, and import, export and transportation regulations and tariffs;
(cid:129) 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;
(cid:129) the risk of not being able to procure residency and work permits for our expatriate personnel;
(cid:129) taxation policies, including royalty and tax increases and retroactive tax claims;
(cid:129) exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over
international operations;
(cid:129) laws and policies of the United States affecting foreign trade, taxation and investment, including anti-bribery and anti-
corruption laws;
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(cid:129) 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
(cid:129) 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.
There has been an increase in 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, with a combined annual
limit of $13.0 million per occurrence and $16.0 million in the aggregate. 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. We also maintain control of well insurance. Our control of
well insurance has a per occurrence and combined single limit of $25.0 million and is subject to deductibles ranging from $10,000 to
$250,000 per occurrence. In addition, we carry a political risk policy, which covers our scheduled production facilities in the event of
an act of terrorism with an annual limit of $8.6 million. 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 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
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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, 2018, we employed 112 people in Turkey, 30 people in Addison, Texas and 6 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.
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 US 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.
6
Executive Officers of the Registrant
The following table and text sets forth certain information with respect to our executive officers as of March 1, 2019:
Name
N. Malone Mitchell 3rd..................................... 57 Chairman and Chief Executive Officer
Todd C. Dutton................................................ 65 President
Michael P. Hill................................................. 37 Chief Accounting Officer
Tabitha T. Bailey ............................................. 33 Vice President, General Counsel and Corporate Secretary
Harold “Lee” Muncy ....................................... 66 Vice President of Geosciences
Positions
Age
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
(“Longfellow”), a Dallas, Texas-based independent oil and natural gas exploration and production company owned by our chairman
and chief executive officer, Mr. Mitchell 3rd and his family, since January 2007, where his primary responsibility is to originate and
develop oil and natural gas projects. He brings 40 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.
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 at 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.
Tabitha T. Bailey has 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 and Economics
from the University of Mississippi and a J.D. from Vanderbilt University Law School.
Harold “Lee” Muncy has served as our vice president of geosciences since June 2014. Mr. Muncy previously served as vice
president, exploration for the Bass Companies, a group of Fort Worth, Texas-based independent oil and natural gas exploration and
production companies, where he worked from 2000 to 2012. He brings more than 36 years of geological experience in the oil and
natural gas industry, where he has focused on exploration, exploitation and worldwide transactions. He began his career as a geologist
with Mobil Oil Corporation and served as exploration manager for Fina Oil & Chemical Company and vice president of exploration
and land for TransTexas Gas Corp. Mr. Muncy earned a B.S. and an M.S. in Geology & Mineralogy from The Ohio State University.
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Item 1A. Risk Factors
Risks Related to Our Business
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:
(cid:129) the risk of, and disruptions due to, expropriation, nationalization, war, terrorism, revolution, election outcomes, economic
instability, political instability, or border disputes;
(cid:129) the uncertainty of local contractual terms, renegotiation or modification of existing contracts and enforcement of contractual
terms in disputes before local courts;
(cid:129) the risk of import, export and transportation regulations and tariffs, including boycotts and embargoes;
(cid:129) the risk of not being able to procure residency and work permits for our expatriate personnel;
(cid:129) the requirements or regulations imposed by local governments upon local suppliers or subcontractors, or being imposed in an
unexpected and rapid manner;
(cid:129) taxation and revenue policies, including royalty and tax increases, retroactive tax claims and the imposition of unexpected
taxes or other payments on revenues;
(cid:129) exchange controls, currency fluctuations and other uncertainties arising out of foreign government sovereignty over foreign
operations;
(cid:129) laws and policies of Canada 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 anti-bribery and anti-
corruption laws;
(cid:129) 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;
(cid:129) 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
(cid:129) 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 could adversely affect our business.
During 2018, 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, hundreds of thousands of Syrian refugees have fled to Turkey. In addition, tensions continue between Turkey and
Syria. In addition, Turkey has experienced numerous terrorist incidents, and in July 2016, there was a failed attempt to overthrow the
government of President Recep Tayyip Erdoğan.
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, which are contiguous to the region where our Southeast Turkey licenses are located, and the aftermath the
attempted coup d’etat 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.
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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.
We have a history of losses and may not achieve consistent profitability in the future.
We have incurred substantial losses in prior years. During 2018, we generated a net loss of $5.2 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, 2018, of our total net undeveloped acreage, 16.2% and 32.2% will expire during 2019 and 2020, 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 96.4% of our
total revenues in 2018. If TUPRAS reduces its oil purchases or fails to purchase our oil production, or there is a material non-payment,
our results of operations could be materially and adversely affected. TUPRAS may be subject to its own operating risks that could
increase the risk that it could default on its obligations to us. Under Turkish law, TUPRAS is obligated to purchase all of our oil
production in Turkey, and we are prohibited from selling any of our oil produced in Turkey to any other customer. Pursuant to a
purchase and sale agreement with TUPRAS, the price of oil delivered to TUPRAS is determined under the Petroleum Market Law
No. 5015 under the laws of the Republic of Turkey. Changes to Turkish law could adversely affect our business and results of
operations.
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:
(cid:129) 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;
(cid:129) increase our vulnerability to general adverse economic, industry and competitive conditions, especially declines in oil and
natural gas prices;
(cid:129) limit our ability to borrow additional funds, and
(cid:129) 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, 2018, 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 historically have been volatile and may continue to be volatile in the future. Oil prices could move
downward or upward on a rapid or repeated basis, and, as of December 31, 2018, we do not have any commodity derivative contracts
that hedge our price risk. The decline since late 2014 in oil and natural gas prices has reduced our revenue, cash flows, and access to
capital, and while prices have risen from the lowest levels, prices could decline again in the future. 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:
(cid:129) worldwide and domestic supplies of oil and gas, and the productive capacity of the oil and gas industry as a whole;
(cid:129) changes in the supply and the level of consumer demand for such fuels;
(cid:129) overall global and domestic economic conditions;
(cid:129) political conditions in oil, natural gas, and other fuel-producing and fuel-consuming areas;
(cid:129) 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;
(cid:129) the price and level of imports of crude oil, refined petroleum products, and liquefied natural gas;
(cid:129) weather conditions, including effects of weather conditions on prices and supplies in worldwide energy markets;
(cid:129) technological advances affecting energy consumption and conservation;
(cid:129) the ability of the members of the Organization of Petroleum Exporting Countries and other exporting countries to agree to
and maintain crude oil prices and production controls;
(cid:129) the competitive position of each such fuel as a source of energy as compared to other energy sources;
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(cid:129) strengthening and weakening of the U.S. Dollar relative to other currencies; and
(cid:129) 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.
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.
Future 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
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. A
decline in oil or natural gas prices from current levels, or other factors, 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.
11
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:
(cid:129) unexpected drilling conditions;
(cid:129) pressure or irregularities in geological formations;
(cid:129) equipment failures or accidents;
(cid:129) pipeline and processing interruptions or unavailability;
(cid:129) title problems;
(cid:129) adverse weather conditions;
(cid:129) lack of market demand for oil and natural gas;
(cid:129) delays imposed by, or resulting from, compliance with environmental laws and other regulatory requirements;
(cid:129) declines in oil and natural gas prices; and
(cid:129) 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.
12
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, 2018, approximately 47.8% 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, 2018, 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.
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.
13
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.
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:
(cid:129) 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;
(cid:129) abnormally pressured formations;
14
(cid:129) 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;
(cid:129) spillage or mishandling of oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by third-
party service providers;
(cid:129) mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
(cid:129) fires and explosions;
(cid:129) personal injuries and death;
(cid:129) regulatory investigations and penalties; and
(cid:129) 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.
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.
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
15
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 22, 2019, Mr. Mitchell beneficially owned approximately 48% of our outstanding common shares. In addition,
persons and entities affiliated with Mr. Mitchell participated in our offering of $46.1 million aggregate principal amount of 12.0%
Series A Convertible Redeemable Preferred Shares (the “Series A Preferred Shares”) and have the right to convert their Series A
Preferred Shares to common shares subject to the terms and conditions of the Series A Preferred Shares. Dalea Partners, LP, an
affiliate of Mr. Mitchell, owns 42,000 Series A Preferred Shares; trusts benefitting Mr. Mitchell’s four children each own 41,000
Series A Preferred Shares; and Longfellow owns 205,000 Series A Preferred Shares. 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.
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:
(cid:129) general economic conditions in the United States, Turkey, Bulgaria and globally;
(cid:129) industry conditions, including fluctuations in the price of oil and natural gas;
(cid:129) governmental regulation of the oil and natural gas industry, including environmental regulation and regulation of fracture
stimulation activities;
(cid:129) fluctuation in foreign exchange or interest rates;
(cid:129) liabilities inherent in oil and natural gas operations;
(cid:129) geological, technical, drilling and processing problems;
(cid:129) unanticipated operating events which can reduce production or cause production to be shut in or delayed;
16
(cid:129) failure to obtain industry partner and other third-party consents and approvals, when required;
(cid:129) stock market volatility and market valuations;
(cid:129) competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;
(cid:129) the need to obtain required approvals from regulatory authorities;
(cid:129) worldwide supplies and prices of, and demand for, oil and natural gas;
(cid:129) political conditions and developments in each of the countries in which we operate;
(cid:129) political conditions in oil and natural gas producing regions;
(cid:129) revenue and operating results failing to meet expectations in any particular period;
(cid:129) investor perception of the oil and natural gas industry;
(cid:129) limited trading volume of our common shares;
(cid:129) announcements relating to our business or the business of our competitors;
(cid:129) the sale of assets;
(cid:129) the issuance of common shares, debt or other securities;
(cid:129) our liquidity;
(cid:129) our ability to raise additional funds or restructure our debt; and
(cid:129) 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
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.
17
Item 2. Properties
Turkey
General. As of December 31, 2018, we held interests in five onshore exploration licenses and 18 onshore production leases
covering a total of 443,268 gross (372,050 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:
27
Moldova
28
30
32
34
36
37
39
41
43
Ukraine
TURKEY LICENSE STATUS
Russia
45
Ü
5
4
Romania
3
4
Bulgaria
Umur-Kuzey Arpaci E17-C1-1
Ortakci E17-B4-1
Kisla E17-C1-2
Arpaci-Ikihoyuk E17-C2-1
Gocerler 4288
Gocerler 4200
Alpullu 4794
I
Adatepe 4959
DoguAdatepe F19-b4-1
1
4
Greece
Temrez F17-B3,
F18-A3, A4, B4
Banarli 5059
I
II
9
3
XVII
Turkey
A
e
7
3
g
e
a
n
S
e
a
XVIII
Black Sea
Georgia
IV
V
XIV
XIII
ANKARA
III
XV
XVI
VI
XII
VII
VIII
New Molla M45-A2
New Molla 4845
Selmo 829
West Molla 5046
XI
Goksu M45-A4-1
X
Molla M45-A1-1
Arpatepe 5003
Bakuk 5043
Armenia
Azerbaijan
9
3
IX
Iran
6
3
4
3
2
3
Cyprus
Syria
Mediterranean Sea
Lebanon
Iraq
TAT Licenses & JV
Production Leases
Districts
Egypt
27
28
30
32
34
36
Israel
Palestinian Territory
Jordan
37
0
50
100
200
300
Saudi Arabia
39
41
43
400
Km
45
Reserves. As of December 31, 2018, we had total net proved reserves of 9,976 Mbbl of oil and 2,440 Mmcf of natural gas, net
probable reserves of 5,748 Mbbl of oil and 817 Mmcf of natural gas and net possible reserves of 6,204 Mbbl of oil and 938 Mmcf of
natural gas in Turkey.
Equipment Yards. As of December 31, 2018, we leased equipment yards in Muratli and Diyarbakir and own an equipment yard at
Edirne.
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, 2018, 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.
18
5
4
3
4
1
4
7
3
6
3
4
3
2
3
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.
19
Southeastern Turkey. The following map shows our interests in Southeastern Turkey at December 31, 2018:
¹
TransAtlantic Licenses: SE Turkey
Selmo
829 (prod)
Russia
Georgia
I
II
IV
XVII
III
XV
XVIII
XVI
VI
VII
VIII
Armenia
Azerbaijan
V
Turkey
XIV
XIII
XII
XI
X
IX
Iran
Cyprus
Lebanon
Syria
Iraq
Bulgaria
Greece
I
Selmo
L46-C1
West Molla
M44-B2-1 (prod)
Molla
M45-A4-1 (prod)
XI
New Molla
4845
New Molla
M45-A2
Molla
M45-A1-1 (prod)
X
Arpatepe
5003 (prod)
LicenseStatus
Exploration
Production
Bakuk
5043 (prod)
0
5
0
10
10
Mile
20
Km
Arpatepe (Production Lease 5003). We own a 50% working interest in Production Lease 5003, which covers approximately 11,200
gross acres. For 2018, our wellhead production of oil from the Arpatepe field was 51,127 Bbls of oil, at an average rate of 140 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 2018.
Bati Yasince (Production Lease M45-A1-1). We own a 100% operated working interest in Production Lease M45-A1-1, which
covers 7,200 gross acres. In 2018, our wellhead production of oil from this production lease was 587 Bbls of oil, at an average rate of
1.60 Bbl/d. We are the operator of this production lease, which expires in December 2019, with extensions available under the new
petroleum laws. We expect to apply for extension of this production lease later in 2019.
Göksu (Production Lease M45-A4-1). We own a 100% operated working interest in Production Lease M45-A4-1, which covers
approximately 14,500 gross acres. For 2018, our wellhead production of oil from this production lease was 12,809 Bbls of oil, at an
average rate of 35 Bbls/d. We are the operator of this production lease, which expires in December 2020, with extensions available
under the new petroleum laws.
20
New Molla (Exploration License 4845). We own a 100% operated working interest in the Bahar appraisal wells in Exploration
License 4845 and Exploration License M45-A2, which cover approximately 32,700 gross acres. For 2018, our wellhead production of
oil from the Bahar appraisal wells was 372,747 Bbls of oil, at an average rate of 1,021 Bbl/d. We are the operator of this exploration
license, which expires in March 2019, with extensions available under the new petroleum laws. The production lease application for a
portion of this exploration license was submitted in 2017. We drilled the Bahar-8 and Bahar-10 wells, which started producing in
2018, and spud the Dogu (East) Yeniev-1 well with ongoing work-over operations. We also spud the Karagoz-1 well in the M45-A2
portion of this exploration license. Drilling operations are ongoing. In March 2019, we filed a production lease application for the
M45-A2 portion of this exploration license.
West Molla (Production Lease M44-B2-1). We own a 100% operated working interest in Production Lease M44-B2-1. In 2018, we
converted this license (formerly Exploration License 5046) to a production lease which covers 37,699 gross acres. For 2018, our
wellhead production of oil from the wells was 82,371 Bbls of oil, at an average rate of 226 Bbl/d. We are the operator of this
production lease, which expires in June 2023, with extensions available under the new petroleum laws. During 2018, we drilled the
Yeniev-1 and West Yeniev-1 wells in this production lease. Both wells began producing in 2018.
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 2018, our wellhead production of oil in the Selmo field was 653,719 Bbls of
oil, at an average rate of 1,791 Bbl/d. We are the operator of this production lease, which expires in June 2025. In 2018, we drilled the
Selmo-81H2 well in this production lease. The well began producing in 2018.
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.
21
Northwestern Turkey. The following map shows our interests in northwestern Turkey at December 31, 2018:
¹
N
°
2
4
Bulgaria
27° E
TransAtlantic Licenses: Thrace
28° E
Romania
Bulgaria
Greece
I
Russia
Georgia
I
II
IV
XVII
III
XV
XVIII
XVI
VI
VII
VIII
Armenia
Azerbaijan
V
Turkey
XIV
XIII
XII
XI
X
IX
Iran
Cyprus
Lebanon
Syria
Iraq
N
°
2
4
Ortakci
E17-B4-1 (prod)
Kisla
E17-C1-2 (prod)
Arpaci-Ikihoyuk
E17-C2-1 (prod)
Umur-Kuzey Arpaci
E17-C1-1 (prod)
Greece
Reisdere
E18-C3-2 (prod)
Alpullu
4794 (prod)
Temrez
F17-B3
Temrez
F18-A4
Temrez
F18-A3
Temrez
F18-B4
Banarli
5059 (prod)
Dikilitas
E19-D4-1 (prod)
Pelit
F19-A1-1 (prod)
Gocerler
4200 (prod)
Dogu Adatepe
F19-B4-1 (prod)
Adatepe
4959 (prod)
N
°
1
4
Exploration License
Production License
License Grid
Date: 2/26/2018
27° E
N
°
1
4
0
0
10
Km
10
Mi
28° E
Adatepe (Production Lease 4959). We own a 50% operated working interest in Production Lease 4959, which covers 3,086 gross
acres. We are the operator of this production lease, which expires in September 2031, with extensions available under the new
petroleum laws.
Alpullu (Production Lease 4794) and Temrez (Exploration Licenses F17B3, F18A3, F18A4, and F18B4). We own a 100% operated
working interest in this production lease and these exploration licenses, which cover 3,158 acres and 119,866 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. We may drill wells on Exploration License F18-B4 in 2019.
Banarli (Production Lease 5059). We own a 50% operated working interest in Production Lease 5059, which covers 4,608 gross
acres. We plan to maintain production to satisfy our obligation on this production lease. 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 own 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.
Edirne (Production Leases Ortaki E17-B4-1, Arpaci-Ikihoyur E17-C2-1, and Umur-Kuzey Arpaci E17-C1-1) and Habiller
(Production Lease Kisla E17-C1-2). We own a 55% operated working interest in Production Leases Ortaki E17-B4-1, Arpaci-
22
Ikihoyur E17-C2-1, and Umur-Kuzey Arpaci E17-C1-1 and a 100% operated working interest in Production Lease Kisla E17-C1-2,
which cover an aggregate of approximately 65,000 gross acres. We are the operator of these production leases, which each expire in
2020, with extensions available under the new petroleum laws. Gas production was shut in for most of 2017. We converted our gas
sales system from high pressure to low pressure and resumed gas sales in 2018.
Gocerler (Production Lease 4200 and Production Leases E18-C3-2, E19-D4-1, and F19-A1-1). We own 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 are 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.
In 2018, our net wellhead production was 238,865 Mcf at an average rate of 654 Mcf/d. from all the gas fields listed above.
23
Bulgaria
General. As of December 31, 2018, 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, 2018:
¹
Romania
Romania
Bulgaria
Serbia
FYROM
Greece
Turkey
Bulgaria
0
0
2.5
5
5
Miles
10
Km
Esri, HERE, DeLorme, MapmyIndia, © OpenStreetMap contributors, and the GIS user community
Koynare Concession
Reserves. As of December 31, 2018, 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.
24
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, 2018) per square kilometer, or 40 Bulgarian
Lev (approximately $23 at December 31, 2018) 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. 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 $44.33
million at December 31, 2018.
25
Summary of Oil and Natural Gas Reserves
The following table summarizes our net proved, probable, and possible reserves at December 31, 2018.
Reserves Category
Total (1)
Proved reserves
Proved developed
Proved undeveloped
Total proved
Probable reserves
Probable developed
Probable undeveloped
Total probable
Possible reserves
Possible developed
Possible undeveloped
Total possible
Oil and Condensate
(Mbbl)
Reserves
Natural Gas
(Mmcf)
Total
(Mboe)
5,047
4,929
9,976
901
4,847
5,748
1,132
5,072
6,204
2,256
184
2,440
787
30
817
906
32
938
5,423
4,960
10,383
1,032
4,852
5,884
1,283
5,077
6,360
(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, 2018:
Future net revenue
Total Standardized Measure (1)
Total PV-10 (2)
Total
(in thousands)
479,775
266,157
320,625
$
$
$
(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 PV-10
Future income taxes (1)
Discount of future income taxes at 10% per annum (1)
Standardized Measure (1)
Total
(in thousands)
320,625
(77,533)
23,065
266,157
$
$
(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.”
26
At December 31, 2018, our estimated proved reserves were 10,383 Mboe, a decrease of 5,093 Mboe, or 33%, compared to 15,476
Mboe at December 31, 2017. This decrease was primarily attributable to revisions of previously estimated recoveries from planned
wells in the Selmo field following revisions to our drilling plans in light of the expiration of our Selmo production lease in 2025,
which resulted in a decrease of 3,680 Mboe, and from planned wells in the Bahar field following the establishment of the oil/water
contact for the Bahar field, which resulted in a decrease of 2,618 Mboe. Additionally, proved reserves decreased 1,055 Mboe for
volumes sold. This decrease was partially offset by a 2,045 Mboe increase in proved reserves due to the discovery of productive pay in
the Yeniev oil field.
Proved Undeveloped Reserves
At December 31, 2018, our estimated proved undeveloped reserves were 4,960 Mboe, a decrease of 5,821 Mboe, or 54%,
compared to 10,781 Mboe at December 31, 2017. The decrease in proved undeveloped reserves was primarily attributable to revisions
of previously estimated recoveries from planned wells in the Selmo field following revisions to our drilling plans in light of the
expiration of our Selmo production lease in 2025, which resulted in a decrease of 3,680 Mboe, and from planned wells in the Bahar
field following the establishment of the oil/water contact for the Bahar field, which resulted in a decrease of 2,618 Mboe. This
decrease was partially offset by a 1,373 Mboe increase in proved undeveloped reserves due to the discovery of productive pay in the
Yeniev oil field. All of our proved undeveloped reserves as of December 31, 2018 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 $56.0 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.
27
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.
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 2018. 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, 2018 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 34 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 11 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, 2018 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.
28
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, 2018 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 2018 and 2017:
Year
2018
Turkey
Selmo field
Bahar field
Total Turkey
2017
Turkey
Selmo field
Bahar field
TBNG (2)
Total Turkey
Oil (1)
(Bbls)
Sales Volumes
Natural Gas
(Mcf)
Total
(Boe)
1,020,144
570,189
322,129
1,020,144
1,103,947
593,425
437,481
88
1,104,035
211,686
–
–
211,686
311,224
–
–
64,730
375,954
1,055,425
570,189
322,129
1,055,425
1,155,818
593,425
437,481
10,876
1,166,694
(1) “Oil” volumes include condensate (light oil) and medium crude oil.
(2) TBNG is reported separately due to the sale of the ownership interests in TBNG in February 2017.
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 2018 and 2017:
Turkey:
Average Sales Price Oil ($/Bbl)
Natural Gas ($/Mcf)
Unit Costs Production ($/Boe)
Drilling Activity
2018
2017
$
$
$
67.84
5.01
8.93
$
$
$
48.65
4.81
9.16
The following table sets forth the number of net productive and dry exploratory wells and net productive and dry development
wells we drilled in 2018 and 2017:
Development Wells
Exploratory Wells
Productive
Dry
Productive
Dry
Turkey:
2018
2017
Bulgaria:
2018
2017
–
–
–
–
2.0
–
–
–
–
–
–
–
3.0
2.0
–
–
29
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, 2018:
Turkey
Bulgaria
Oil
Natural Gas
Gross (1)
Net (2)
Gross (1)
Net (2)
73.0
–
71.0
–
32.0
–
21.2
–
(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, 2018:
Turkey
Bulgaria
Total
Developed Acres
Gross (1)
Net (2)
234,139
–
234,139
162,921
–
162,921
(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.
30
Undeveloped Acreage. The following table sets forth our undeveloped land position as of December 31, 2018:
Turkey
Bulgaria
Total
Undeveloped Acres
Gross (1)
Net (2)
209,129
162,800
371,929
209,129
162,800
371,929
(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, 2018
that is scheduled to expire in the next five years:
2019
2020
2021
2022
2023
Undeveloped Acres
Gross (1)
Net (2)
% of Total
Undeveloped Acres
Net (2)
60,342
119,866
-
-
28,922
60,342
119,866
-
-
28,922
16.2
32.2
–
–
7.8
(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 2019 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.
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 Appeal and sent back to the Kozluk Cadastre Court in April 2018.
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. In
February 2011, the Kozluk Cadastre Court decided to suspend the case until there is a resolution of 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,
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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. We continue to vigorously defend this claim.
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
As of March 22, 2019, we had 52,496,666 common shares issued and outstanding and held by 169 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, 2018, we held interests in 372,050 and 162,500 net acres of developed and
undeveloped oil and natural gas properties in Turkey and Bulgaria, respectively. As of March 22, 2018, approximately 48% of our
outstanding common shares were beneficially owned by Mr. Mitchell, the chairman of our board of directors and our chief executive
officer.
2018 Financial and Operational Performance
(cid:129) We derived 97.8% of our revenues from the production of oil and 1.5% of our revenues from the production of natural gas
during the year ended December 31, 2018.
(cid:129) Total oil and natural gas sales revenues increased 26.6% to $70.3 million for the year ended December 31, 2018, compared to
$55.5 million in 2017. The increase was primarily the result of an increase in our average realized price which increased
$19.00 to $66.58 per Boe in 2018 compared to $47.58 per Boe in 2017, resulting in a $16.0 million increase in revenue.
Additionally, revenues increased $4.7 million due to revenue reporting regulation ASC 606. This was partially offset by a
decrease in sales volumes of 112 Mboe, which resulted in lower revenues of $5.9 million.
(cid:129) Wellhead production was 1,020 Mbbls of oil and 212 Mmcf of natural gas for the year ended December 31, 2018, as
compared to 1,104 Mbbls of oil and 376 Mmcf of natural gas for 2017.
(cid:129) In 2018, we incurred $23.7 million in total capital expenditures, including license acquisition, seismic and corporate
expenditures, as compared to $20.6 million in total capital expenditures in 2017.
(cid:129) As of December 31, 2018, we had no long-term debt, $22.0 million in short-term debt and $46.1 million in Series A
Preferred Shares, as compared to $13.0 million in long-term debt, $15.6 million in short-term debt and $46.1 million Series A
Preferred Shares as of December 31, 2017.
2018 Operations
Southeastern Turkey
We drilled the Selmo-81H2 well to a total depth of 5,770 feet for a drilling cost of approximately $3.7 million. Due to issues
encountered while drilling, we completed the well vertically and established commercial production of 68 bbl/d.
We drilled the Bahar-8 well to a total depth of 10,650 feet for a drilling cost of approximately $3.1 million. The well was put on
production at an initial rate of 55 bbl/d from the Hazro F4 formation.
We drilled the Bahar-10 well to a total depth of 10,790 feet for a drilling cost of approximately $2.3 million. The well was put on
production at an initial rate of 145 bbl/d from the Hazro F3A formation.
We drilled the Yeniev-1 well to a total depth of 10,306 feet for a drilling cost of approximately $3.8 million. The well encountered
hydrocarbon shows in the Mardin and Bedinan formations. The well was a discovery on a new structure in the Molla area with the
potential for a significant number of future offset drilling locations. By natural flow, the well produced 68,427 bbl (350 bbl/d) through
December 31, 2018.
We drilled the West Yeniev-1 well to a total depth of 9,625 feet for a drilling cost of approximately $3.0 million. The well
encountered hydrocarbon shows in the Mardin and Bedinan formations and had an initial stabilized rate of 339 bbl/d producing
naturally under a 16/64” choke.
We drilled the East Yeniev-1 well to a total depth of 9,900 feet for a drilling cost of approximately $1.9 million. The well
encountered hydrocarbon shows in the Mardin and Bedinan formations. Completion operations began in January 2019 and resulted in
a discovery in the Mardin formation.
The Cavuslu-1 well was put on production at an initial production rate of 31 Boped from the Mardin formation. Additional oil that
was tested in the Bedinan and Dadas formations will be added after a long-term test period.
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The Pinar-1 well had been intermittently producing due to a mechanical blockage in the well. The equipment causing the blockage
was recovered in the third quarter of 2018, and the well was fracture stimulated in the Bedinan formation. The well was put on
production with an initial production rate of 65 bbl/d.
We completed the processing and initial interpretation of our East Molla 3D seismic data and have identified several prospects,
which we expect to drill in the first half of 2019.
Northwestern Turkey
We did not engage in any new drilling activities in northwestern Turkey during 2018.
Bulgaria
We commenced the side-track and re-drilling of the Deventci R-1 well in December 2018, targeting the Ozirovu and Dolmi Dabnik
formations.
Current Operations
Southeastern Turkey
Molla
Yeniev Field. Both the Yeniev-1 and West Yeniev-1 wells continue flowing naturally with little water. In November 2018, we
spud the East Yeniev-1 appraisal well to further delineate the structure. The well was drilled to a total measured depth of 9,900 feet
and encountered hydrocarbon shows in the Mardin and Bedinan formations. Completion operations began in January 2019.
Other. We spud the Blackeye-1 well in January 2019. The well was drilled to a total measured depth of 11,105 feet and
encountered oil shows in the Hazro, Mardin, and Bedinan formations. Completion operations began in February 2019.
Selmo
We have completed the initial phase of operations in the Selmo-1 well to re-enter and test the Permian formation, establishing
the productivity of the Permian formation. During a short-term flow test of a previously untested interval, the Selmo-1 well tested 45.6
API condensate along with natural gas containing a high carbon dioxide percentage component. While the Selmo-1 well lies in what is
interpreted as the gas cap of the structure, the positive test results warrant further testing lower on the structure.
Northwestern Turkey
Thrace Basin BCGA
We continue to evaluate our prospects in the Thrace Basin’s Basin Center Gas Accumulation (“Thrace Basin BCGA”) in light of
the recent production test results at the Yamalik-1 exploration well operated by Valeura Energy Inc. (“Valeura”) with their partner
Equinor ASA (formerly Statoil ASA) (“Equinor”). The Yamalik-1 exploration well is located on a license directly adjacent to our
120,000 net acres in the Thrace Basin of which we believe approximately 50,000 net acres (100% working interest, 87.5% net revenue
interest) is in the Thrace Basin BCGA and analogous to the Valeura and Equinor acreage.
Subsequent to drilling and testing of the Yamalik-1 well, the joint venture between Valeura and Equinor announced a three-well
program. In the first quarter of 2019, Valeura and Equinor announce that they drilled and cased a second well in the Thrace Basin
BCGA, the Inanli-1 well. According to Valeura and Equinor, the well was drilled to a total depth of 4,885 meters and encountered
1,615 meters of high net -to-gross sandstone, which they interpreted to contain over-pressured gas. Valeura and Equinor announced
that they expect to complete the well in the first quarter of 2019. In the first quarter of 2019, Valeura and Equinor announced that they
spud the Devepinar-1 appraisal well and drilled it to intermediate casing point at 3,375 meters. According to Valeura and Equinor, the
Devepinar-1 appraisal well is designed as a 20-kilometer step-out well to test the lateral extent of the Thrace Basin BCGA.
We expect to spud a shallow exploration well on our license in the Thrace Basin in the second quarter of 2019.
35
Bulgaria
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. We are currently evaluating future activity in Bulgaria.
Planned Operations
We expect our net field capital expenditures for 2019 to range between $25.0 million and $30.0 million. We expect net field
capital expenditures during 2019 to include between $24.0 million and $29.0 million in drilling and completion expense for 10
planned wells and approximately $1.0 million for recompletions. We expect that cash on hand and cash flow from operations will be
sufficient to fund our 2019 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek
other funding sources. Our projected 2019 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
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.
36
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, 2018.
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
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 May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, its final standard on revenue from
contracts with customers. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising
from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The
core principle of the revenue model is that an entity recognizes revenue to depict the transfer of promised goods or services to
customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or
services. In applying the revenue model to contracts within its scope, an entity identifies the contract(s) with a customer, identifies the
performance obligations in the contract, determines the transaction price, allocates the transaction price to the performance obligations
in the contract and recognizes revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 applies to all contracts
with customers and requires significantly expanded disclosures about revenue recognition. ASU 2014-09 has been amended several
37
times with subsequent ASUs including ASU 2015-14 Revenue from Contracts with Customers (Topic 606): Deferral of the Effective
Date.
We adopted ASU 2014-09 on January 1, 2018 using the modified retrospective approach. We have a small number of contracts
with customers and have identified transactions within the scope of the standard. As a result of adoption of ASU 2014-09, we have
determined that we will change our method of recording certain transportation and processing charges that were previously recorded
as a reduction of revenues to record such charges as an expense under the new standard. The result of this change was an increase to
both revenue and expenses of $4.7 million for the twelve months ended December 31, 2018. The application of the new standard has
no impact on our retained earnings and no impact to our net income on an ongoing basis. During the twelve months ended December
31, 2017, this standard would have increased both revenue and expenses by $4.4 million.
Contracts for the sale of natural gas and crude oil are evidenced by (1) base contracts for the sale and purchase of natural gas or
crude oil, which document the general terms and conditions for the sale, and (2) transaction confirmations, which document the terms
of each specific sale.
Revenue is measured based on consideration specified in the contract with the customer. We recognize revenue in the amount that
reflects the consideration we expect to be entitled to in exchange for transferring control of those goods to the customer. Revenues are
recognized for the sale of our net share of production volumes. Sales on behalf of other working interest owners and royalty interest
owners are not recognized as revenues. The contract consideration in our contracts are typically allocated to specific performance
obligations in the contract according to the price stated in the contract, which usually sets the base oil and natural gas prices based on
benchmark prices based on volumes and adjustments for product quality. Payment is generally received one or two months after the
sale has occurred.
The following table displays the disaggregation of revenue by product type for the twelve months ended December 31, 2018 and
2017:
Oil
Natural gas
Total revenue from customers
2018
2017
(in thousands)
$ 69,207
1,061
$ 70,268
$ 58,109
1,807
$ 59,916
All of our revenues from contracts with customers represent products transferred at the point in time control is transferred to the
customer and are generated in Turkey.
Transaction price allocated to remaining performance obligations. A significant number of our product sales are short-term in
nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient exempting us from
disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract
that has an original expected duration of one year or less.
Contract balances. Receivables from contracts with customers are recorded when the right to consideration becomes
unconditional, generally when control of the product has been transferred to the customer. Receivables from contracts with customers
were $12.9 million and $15.8 million as of December 31, 2018 and December 31, 2017, respectively, and are reported in accounts
receivable, net on our consolidated balance sheets. We currently have no assets or liabilities related to our revenue contracts, including
no upfront or rights to deficiency payments.
Practical expedients. We have made use of certain practical expedients in adopting the new revenue standard, including the value
of unsatisfied performance obligations are not disclosed for (i) contracts with an original expected length of one year or less, (ii)
contracts for which we recognize revenue at the amount to which we have the right to invoice, (iii) variable consideration which is
allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (iv) only
contracts that are not completed at transition. We have not adjusted the promised amount of consideration for the effects of a
significant financing component if we expect, at contract inception, that the period between when we transfer a promised good or
service to the customer and when the customer pays for that good or service will be one year or less.
In February 2016, the FASB issued ASU 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 will become effective for us
38
beginning with the first quarter of 2019. We will adopt the accounting standard using a prospective transition approach, which applies
the provisions of the new guidance at the effective date without adjusting the comparative periods presented. We have elected the
package of practical expedients permitted under the transition guidance within the new standard, which among other things, allows us
to carry forward the historical accounting relating to lease identification and classification for existing leases upon adoption. We have
made an accounting policy election to keep leases with an initial term of 12 months or less off of the consolidated balance sheet. We
are finalizing our evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial
statements and estimate approximately $2.7 million of additional right-of-use assets and liabilities will be recognized in our
consolidated balance sheet upon adoption.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the
impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt
securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of
allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within
those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within
that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning
of the first reporting period in which the guidance is adopted. We are currently assessing the potential impact of ASU 2016-13 on our
consolidated financial statements and results of operations.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts
and Cash Payments (“ASU 2016-15”). ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the
statement of cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment
or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are
insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business
combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance
policies, and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning
after December 15, 2017. We adopted ASU 2016-15 effective January 1, 2018. The adoption of ASU 2016-15 had no impact on our
retained earnings or net income.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”).
ASU 2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and
amounts generally described as restricted cash or restricted cash equivalents. The amounts generally described as restricted cash and
restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-
period total amounts shown on the statements of cash flows. We adopted ASU 2016-18 effective January 1, 2018. The adoption of
ASU 2016-18 had no impact on our retained earnings, and no impact to our net income on an ongoing basis. The amendments have
been applied using a retrospective transition method to each period presented, as required. The period ended December 31, 2017 has
been reclassified to reflect this change.
In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, which clarifies Topic 718, Compensation – Stock
Compensation, such that an entity must apply modification accounting to changes in the terms or conditions of a share-based payment
award unless all of the following criteria are met: (1) the fair value of the modified award is the same as the fair value of the original
award immediately before the modification and the ASU indicates that if the modification does not affect any of the inputs to the
valuation technique used to value the award, the entity is not required to estimate the value immediately before and after the
modification; (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award
immediately before the modification; and (3) the classification of the modified award as an equity instrument or a liability instrument
is the same as the classification of the original award immediately before the modification. The ASU is effective for fiscal years
beginning after December 15, 2017. The adoption of this ASU had no impact on our consolidated financial statements and results of
operations. We adopted ASU 2017-09 effective January 1, 2018.
In August 2017, the FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for
Hedging Activities, which amends the hedge accounting recognition and presentation requirements in Accounting Standards
Codification (“ASC”) Topic 815. The new standard provides partial relief on the timing of certain aspects of hedge documentation and
eliminates the requirement to recognize hedge ineffectiveness separately in income. The amendments in this ASU are effective for
fiscal years beginning after December 15, 2018 and for interim periods therein. Early adoption as of the date of issuance is permitted.
The new standard does not impact accounting for derivatives that are not designated as accounting hedges. We do not currently
account for any of our derivative position as accounting hedges.
39
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.
Results of Operations—Year Ended December 31, 2018 Compared to Year Ended December 31, 2017
Sales volumes:
Oil (Mbbl)
Natural gas (Mmcf)
Total production (Mboe)
Average daily sales volumes (Boepd)
Average prices:
Oil (per Bbl)
Natural gas (per Mcf)
Oil equivalent (per Boe)
Revenues:
Oil and natural gas sales
Sales of purchased natural gas
Other
Total revenues
Costs and expenses:
Production
Transportation costs
Exploration, abandonment and impairment
Cost of purchased natural gas
Seismic and other exploration
General and administrative
Depletion
Depreciation and amortization
Interest and other expense
Foreign exchange loss
Deferred income tax expense
(Loss) gain on commodity derivative contracts:
Cash settlements on derivative contracts
Change in fair value on derivative contracts
Total loss on derivative contracts
Oil and natural gas costs per Boe:
Production
Depletion
Year Ended December 31,
2017
2018
(in thousands of U.S. Dollars, except per
unit amounts and production volumes)
Change
2018-2017
$
$
$
$
1,020
212
1,055
2,892
67.84 $
5.01 $
66.58 $
70,268 $
-
521
70,789
10,769
4,665
401
-
489
14,719
13,387
672
10,048
10,292
6,854
(4,012)
1,186
(2,826)
1,104
376
1,167
3,144
48.65 $
4.81 $
47.58 $
55,523 $
654
462
56,639
12,249
-
934
568
4,723
12,817
15,989
936
8,838
1,861
3,356
32
(1,884)
(1,852)
$
$
8.93 $
11.10 $
9.16 $
11.99 $
(84)
(164)
(112)
(252)
19.19
0.20
19.00
14,745
(654)
59
14,150
(1,480)
4,665
(533)
(568)
(4,234)
1,902
(2,602)
(264)
1,210
8,431
3,498
(4,044)
3,070
(974)
(0.23)
(0.89)
Oil and Natural Gas Sales. Total oil and natural gas sales increased to $70.3 million in 2018 compared to $55.5 million in 2017.
The $14.7 million increase was primarily a result of an increase in our average realized price by $19.00 to $66.58 per Boe in 2018,
compared to $47.58 per Boe in 2017, resulting in a $16.0 million increase in revenue. Additionally, revenues increased $4.7 million
due to revenue reporting regulation ASC 606. This was partially offset by a decrease in sales volumes of 112 Mboe, which resulted in
lower revenues of $5.9 million. Our sales of oil are denominated in U.S. Dollars and are not impacted by foreign exchange rates.
Sales of Purchased Natural Gas. Sales of purchased natural gas for the year ended December 31, 2018 decreased $0.7 million due
to the divestiture of TBNG in February 2017.
Production. Production expenses for the year ended December 31, 2018 decreased to $10.8 million or $8.93 per Boe (WI),
compared to $12.2 million or $9.16 per Boe (WI) for the year ended December 31, 2017. The $1.5 million decrease was primarily due
40
to the devaluation of the TRY compared to the U.S. Dollar in 2018, as most of our production expenses are denominated in Turkish
Lira, reduced headcount and cost-cutting measures in our field operations for the year ended December 31, 2018.
Transportation and Processing. Transportation and processing expense increased to $4.7 million for the twelve months ended
December 31, 2018. The increase was due to the 2018 adoption of ASU 2014-09, which now requires this cost, previously netted in
revenue, to be reported separately.
Exploration, Abandonment and Impairment. Exploration, abandonment and impairment costs decreased to $0.4 million in
2018, compared to $0.9 million for 2017. The decrease was primarily due to a decrease in impairment cost due to the increase in oil
price.
Cost of Purchased Natural Gas. Cost of purchased natural gas for the year ended December 31, 2018 decreased $0.6 million to
$0 due to the divestiture of TBNG in February 2017.
Seismic and Other Exploration. Seismic and other exploration costs decreased to $0.5 million for 2018, compared to $4.7 million
for 2017. The decrease was primarily due to higher seismic acquisition activities during 2017, particularly on our Molla license.
General and Administrative. General and administrative expense increased $1.9 million to $14.7 million for 2018, compared to
$12.8 million for 2017. The increase was primarily due to an increase in wages and strategic transaction costs in 2018. The increase in
wages was primarily due to bonus pay and the accrual for strategic transaction retention incentive agreements entered into with certain
employees in 2018.
Depletion. Depletion expense decreased to $13.4 million or $11.10 per Boe for 2018, compared to $16.0 million or $11.99 per Boe
for 2017. The decrease was due primarily to a reduction in our sales volumes year-over-year and the devaluation of the TRY.
Interest and Other Expense. Interest and other expense increased to $10.0 million in 2018, compared to $8.8 million in 2017. The
increase was primarily due to a higher average interest rate during 2018 as compared to 2017.
Foreign Exchange Loss. We recorded a foreign exchange loss of $10.3 million in 2018, compared to $1.9 million in 2017. 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 increase in foreign exchange loss in 2018 was due to a 39.5% devaluation of the
TRY compared to the U.S. Dollar in 2018, compared to a 7.0% devaluation during 2017 and was partially offset by fluctuations in our
U.S. Dollar denominated balances in Turkey. At December 31, 2018, the exchange rate was 5.2609 as compared to 3.7719 at
December 31, 2017.
Deferred Income Tax Expense. Deferred income tax expense increased to an expense of $6.9 million for the year ended
December 31, 2018, compared to a $3.4 million expense for 2017. The increase was primarily due to changes in our deferred tax
liabilities related to our permanent reinvestment assertion in Turkey and increases in uncertain tax positions, which were partially
offset by changes in temporary differences between our U.S. GAAP and statutory balances in Turkey.
Loss on Commodity Derivative Contracts. During 2018, we recorded a net loss on derivative contracts of $2.8 million, compared
to $1.9 million for 2017. In 2018, we recorded a $4.0 million loss on settled contracts and a $1.2 million gain to mark our commodity
derivative contracts to their fair value. In 2017, we recorded a $0.03 million loss on settled contracts and a $1.9 million loss to mark
our commodity derivative contracts to their fair value.
Capital Expenditures
For 2018, we incurred $24.3 million in total capital expenditures, including license acquisition, seismic and corporate expenditures
from operations, compared to $20.6 million for 2017.
We expect our net field capital expenditures for 2019 to range between $25.0 million and $30.0 million. We expect net field
capital expenditures during 2019 to include between $24.0 million and $29.0 million in drilling and completion expense for 10
planned wells and approximately $1.0 million for recompletions. We expect that cash on hand and cash flow from operations will be
sufficient to fund our 2019 net field capital expenditures. If not, we will either curtail our discretionary capital expenditures or seek
other funding sources. Our projected 2019 capital expenditure budget is subject to change.
41
Liquidity and Capital Resources
Our primary sources of liquidity for 2018 were our cash and cash equivalents, cash flow from operations, borrowings under the
2017 Term Loan and our additional $10.0 million term loan with DenizBank. At December 31, 2018, we had 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,
compared to cash and cash equivalents of $18.9 million, $13.0 million in long-term debt, $15.6 million in short-term debt and a
working capital surplus of $12.8 million.
During 2018, we repaid the 2016 Term Loan in full in accordance with its terms. In addition, we entered into the 2018 Term Loan
under the Credit Agreement.
Based on current forecasted oil prices for 2019 and beyond, we believe that our cash flows from operations and existing cash on
hand are sufficient to conduct our planned operations and meet our contractual requirements, including license obligations through
March 31, 2020.
Net cash provided by operations during 2018 was $28.7 million, an increase from net cash provided by operations of $17.9 million
in 2017, primarily due to an increase in revenue, partially offset by an increase in general and administrative expenses.
Net cash used investing activities during 2018 was $26.5 million, compared to net cash provided by investing activities of $1.9
million in 2017, primarily due to an $8.0 million increase in additions of oil and gas properties in 2018 and $17.8 million from sale
proceeds of TBNG in 2017.
Net cash used in financing activities was $6.6 million in 2018, compared to net cash used in financing activities of $13.4 million in
2017. The decrease was primarily due to higher term loan repayments in 2017.
As of December 31, 2018, we had $22.0 million of debt and $46.1 million of Series A Preferred Shares outstanding, which are
discussed below.
Series A Preferred Shares. On November 4, 2016, we issued 921,000 shares of our Series A Preferred Shares. Of the 921,000
Series A Preferred Shares, (i) 815,000 shares were issued in exchange for $40.75 million aggregate principal amount 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, and (ii) 106,000 shares were issued and sold to certain holders of the 2017 Notes. All of the Series A Preferred
Shares were issued at a value of $50.00 per share, raising gross proceeds of $5.3 million. We used $4.3 million of the gross proceeds
to redeem a portion of the remaining 2017 Notes. The remaining proceeds were used for general corporate purposes. 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
November 4, 2020
November 4, 2021
November 4, 2022
November 4, 2023 and thereafter
Redemption Price
105.000%
103.000%
101.000%
100.000%
42
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. For the year ended December 31, 2018, we
paid $5.3 million in cash and issued 1,808,001 common shares as dividends on the Series A Preferred Shares. We paid the December
31, 2018 quarterly dividend in shares on December 31, 2018.
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. Amounts repaid under the 2016 Term Loan
could not be re-borrowed and early repayments under the 2016 Term Loan were subject to early repayment fees.
The 2016 Term Loan was guaranteed by DMLP, Ltd. (“DMLP”), TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”), Talon
Exploration, Ltd. (“Talon Exploration”), and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”).
The 2016 Term Loan contained standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting
of liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain
investments, selling assets or transferring revenue, and other similar matters. In addition, the 2016 Term Loan prohibited Amity Oil
International Pty Ltd (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Urunleri Insaat Sanayi ve Ticaret A.S. (“Petrogas”) from
incurring additional debt. An event of default under the 2016 Term Loan included, among other events, failure to pay principal or
interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and the
occurrence of a material adverse effect.
The 2016 Term Loan was secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii)
substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate
owned by Gundem Turizm Yatirim ve Isletmeleri A.S. (“Gundem”), and (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell
and 20% 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 2016 Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr.
Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.
On June 28, 2018, we repaid the 2016 Term Loan in full in accordance with its terms.
43
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 bears interest at a fixed rate of 6.0% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish
government) per annum. The 2017 Term Loan had a grace period which bore no interest or payments due until July 2018. Thereafter,
the 2017 Term Loan is payable in one monthly installment of $1.38 million, nine monthly installments of $1.2 million each through
April 2019 and thereafter in eight monthly installments of $1.0 million each through December 2019, with the exception of one
monthly installment of $1.2 million occurring in October 2019. The 2017 Term Loan matures in December 2019. Amounts repaid
under the 2017 Term Loan may not be re-borrowed, and early repayments under the 2017 Term Loan are subject to early repayment
fees. The 2017 Term Loan is guaranteed by Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.
The 2017 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting
of liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain
investments, selling assets or transferring revenue, and other similar matters. In addition, the 2017 Term Loan prohibits Amity and
Petrogas from incurring additional debt. An event of default under the 2017 Term Loan includes, among other events, failure to pay
principal or interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and
the occurrence of a material adverse effect.
The 2017 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii)
substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate
owned by Gundem, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% 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 2017 Term Loan.
At December 31, 2018, we had $13.0 million outstanding under the 2017 Term Loan and no availability, and we were in
compliance with the covenants in the 2017 Term Loan.
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 bears 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 is payable monthly and the principal on the 2018 Term Loan is 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 matures in December 2019. Amounts repaid under the 2018 Term Loan may not be
reborrowed, and early repayments under the 2018 Term Loan are subject to early repayment fees. The 2018 Term Loan is guaranteed
by Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.
The 2018 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 2018 Term Loan prohibits
Amity, Talon Exploration, DMLP, and TransAtlantic Turkey from incurring additional debt. An event of default under the 2018 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 2018 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, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% 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 2018 Term Loan.
At December 31, 2018, we had $9.0 million outstanding under the 2018 Term Loan and no availability, and we were in compliance
with the covenants in the 2018 Term Loan
2017 Notes. The 2017 Notes were issued pursuant to an indenture, dated as of February 20, 2015 (the “Indenture”), between us and
U.S. Bank National Association, as trustee (the “Trustee”). The 2017 Notes bore interest at an annual rate of 13.0% per annum.
44
Interest was payable semi-annually, in arrears, on January 1 and July 1 of each year. The 2017 Notes matured on July 1, 2017, and we
paid off and retired all remaining outstanding 2017 Notes on July 3, 2017.
Off-Balance Sheet Arrangements
We did not have any off-balance sheet arrangements at December 31, 2018.
45
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, 2018, management carried out an evaluation, under the supervision and with the participation of our chief
executive officer and principal accounting and financial officer, of the effectiveness of our disclosure controls and procedures. Based
upon the evaluation, our chief executive officer and principal accounting and financial officer concluded that, as of December 31,
2018, 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, 2018.
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, 2018
that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
46
Item 9B. Other Information.
None.
47
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Certain information required in response to this Item 10 is contained under the heading “Executive Officers of the Registrant” 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.
48
Item 15. Exhibits and Financial Statement Schedules
(a) Documents filed as part of the Report.
PART IV
1.
2.
Reports of Independent Registered Public Accounting Firm (RBSM 2018)
Reports of Independent Registered Public Accounting Firm (PMB 2017)
Consolidated Balance Sheets as of December 31, 2018 and 2017
Consolidated Statements of Operation and Comprehensive Loss for the years ended December 31, 2018 and 2017
Consolidated Statements of Equity for the years ended December 31, 2018 and 2017
Consolidated Statements of Cash Flows for the years ended December 31, 2018 and 2017
Notes to Consolidated Financial Statements
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.
49
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
3.3
3.4
3.5*
4.1
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).
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).
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).
Memorandum of Increase of Share Capital of TransAtlantic Petroleum Ltd., dated July 2017.
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).
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†
TransAtlantic Petroleum Corp. 2009 Long-Term Incentive Plan (incorporated by reference to Appendix B to the
Definitive Proxy Statement filed by TransAtlantic Petroleum Corp. with the SEC on April 30, 2009).
10.5†
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 16, 2009, filed with the SEC on June 22, 2009).
10.6†
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).
10.7
10.8
10.9
10.10
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).
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).
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).
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).
50
10.11
10.12
10.13
10.14
10.15
10.16
10.17
10.18
10.19
10.20
10.21
10.22
21.1*
23.1*
23.2*
23.3*
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).
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).
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).
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).
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).
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).
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).
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).
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).
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).
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).
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).
Subsidiaries of the Company.
Consent of RBSM LLP.
Consent of PMB Helin Donovan, LLP.
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.
51
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 February 13, 2019.
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.
52
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.
SIGNATURES
March 26, 2019
TRANSATLANTIC PETROLEUM LTD.
/S/ N. MALONE MITCHELL 3rd
N. Malone Mitchell 3rd
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
/S/ N. MALONE MITCHELL 3rd
N. Malone Mitchell 3rd
Chairman and Chief Executive Officer
(Principal Executive Officer)
/S/ MICHAEL P. HILL
Michael P. Hill
Chief Accounting Officer
(Principal Financial Officer and Principal Accounting Officer)
/S/ BOB G. ALEXANDER
Bob G. Alexander
/S/ BRIAN E. BAYLEY
Brian Bayley
/S/ CHARLES J. CAMPISE
Charles J. Campise
/S/ JONATHON T. FITE
Jonathon T. Fite
/S/ GREGORY K. RENWICK
Gregory K. Renwick
/S/ MEL G. RIGGS
Mel G. Riggs
/S/ RANDY I. ROCHMAN
Randy I. Rochman
Director
Director
Director
Director
Director
Director
Director
Date
March 26, 2019
March 26, 2019
March 26, 2019
March 26, 2019
March 26, 2019
March 26, 2019
March 26, 2019
March 26, 2019
March 26, 2019
53
[THIS PAGE INTENTIONALLY LEFT BLANK]
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Reports of Independent Registered Public Accounting Firm (RBSM 2018)...................................................................................... F-2
Reports of Independent Registered Public Accounting Firm (PMB 2017) ....................................................................................... F-3
Consolidated Balance Sheets as of December 31, 2018 and 2017 ..................................................................................................... F-4
Consolidated Statements of Operation and Comprehensive Loss for the years ended December 31, 2018 and 2017 ...................... F-5
Consolidated Statements of Equity for the years ended December 31, 2018 and 2017 ..................................................................... F-6
Consolidated Statements of Cash Flows for the years ended December 31, 2018 and 2017 ............................................................. F-7
Notes to Consolidated Financial Statements....................................................................................................................................... F-8
F-1
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of
Transatlantic Petroleum Ltd.
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheet of Transatlantic Petroleum Ltd. and subsidiaries (the “Company”) as of
December 31, 2018 and the related consolidated statements of operations and comprehensive loss, stockholders’ equity, and cash
flows for the year then ended, and the related notes and schedules (collectively, the consolidated 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, 2018, and the results of its operations and comprehensive loss and its cash flows for the year then ended, in conformity
with U.S. generally accepted accounting principles.
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.
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 audit. We are a public accounting firm registered with the 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 audit 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 audit, 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 audit of the consolidated financial statements 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 audit 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 audit provide a reasonable basis for
our opinion.
/s/ RBSM LLP
We have served as the Company’s auditor since 2018.
New York, NY
March 26, 2019
F-2
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
TransAtlantic Petroleum Ltd.:
Opinion on the Financial Statements
We have audited, before the effects of the adjustments to retrospectively apply the application of presenting restricted cash in the
statement of cash flows as described in note 4, the accompanying consolidated balance sheet of TransAtlantic Petroleum Ltd. (a
Bermuda corporation) and subsidiaries (the “Company”) as of December 31, 2017, and the related consolidated statements of
comprehensive income (loss), equity, and cash flows for the year ended December 31, 2017, and the related notes (collectively
referred to as the “financial statements”). The 2017 financial statements before the effects of the adjustments on restricted cash in the
Statement of Cash Flows are not presented herein. In our opinion, the financial statements, before the effects of the adjustments to
retrospectively apply the application of restricted cash described in note 4, referred to above present fairly, in all material respects, the
consolidated financial position of the Company as of December 31, 2017, and the results of its operations, changes in equity, and cash
flows for the year ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of
America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these
financial statements based on our audit. 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 U.S. federal
securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit 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 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 if the Company’s internal control over financial reporting. Accordingly, we express no such
opinion.
Our audit included performing procedures to assess the risk of material misstatement of the 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
supporting the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
We were not engaged to audit, review, or apply any procedures to the adjustments to retrospectively apply the application of
presenting restricted cash in the statement of cash flows as described in note 4 and, accordingly, we do not express an opinion or any
other form of assurance about whether such adjustments are appropriate and have been properly applied. Those adjustments were
audited by a successor auditor.
Emphasis of a Matter
As discussed in Notes 1 and 16 to the financial statements, there are a number of significant related party transactions with the primary
shareholder of the Company. This shareholder, who is the Company's chief executive officer and chairman of the board of directors,
owns approximately 47% of the common stock of the Company. Significant related party transactions with this shareholder include
ownership of Series A Preferred Shares, equity transactions, a note receivable, pledge fee agreements, service transactions, a note
payable balance and warrants between the Company and affiliated entities or persons.
We have served as the Company’s Auditors since 2016.
PMB HELIN DONOVAN, LLP
/s/ PMB Helin Donovan, LLP
Austin, Texas
March 21, 2018
F-3
TRANSATLANTIC PETROLEUM LTD.
Consolidated Balance Sheets
As of December 31, 2018 and 2017
(in thousands of U.S. Dollars, except share data)
ASSETS
Current assets:
Cash and cash equivalents
Accounts receivable, net
Oil and natural gas sales
Joint interest and other
Related party
Prepaid and other current assets
Note receivable - related party
Inventory
Total current assets
Property and equipment:
Oil and natural gas properties (successful efforts method)
Proved
Unproved
Equipment and other property
Less accumulated depreciation, depletion and amortization
Property and equipment, net
Other long-term assets:
Other assets
Note receivable - related party
Total other assets
Total assets
LIABILITIES, SERIES A PREFERRED SHARES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable
Accounts payable - related party
Accrued liabilities
Derivative liability
Loans payable
Total current liabilities
Long-term liabilities:
Asset retirement obligations
Accrued liabilities
Deferred income taxes
Loans payable
Total long-term liabilities
Total liabilities
Commitments and contingencies
Series A preferred shares, $0.01 par value, 426,000 shares authorized; 426,000 shares issued and outstanding with a liquidation
preference of $50 per share as of December 31, 2018
Series A preferred shares-related party, $0.01 par value, 495,000 shares authorized; 495,000 shares issued and outstanding with a
liquidation preference of $50 per share as of December 31, 2018
Shareholders' equity:
Common shares, $0.10 par value, 200,000,000 shares authorized; 52,413,588 shares and 50,319,156 shares issued and outstanding
as of December 31, 2018 and 2017, respectively
Treasury shares
Additional paid-in-capital
Accumulated other comprehensive loss
Accumulated deficit
Total shareholders' equity
Total liabilities, Series A preferred shares and shareholders' equity
2018
2017
$
9,892
$
18,926
12,912
982
878
8,696
5,828
5,167
44,355
163,006
15,695
14,408
193,109
(105,850 )
87,259
986
–
986
132,600
3,896
2,922
13,073
–
22,000
41,891
4,667
7,259
20,314
–
32,240
74,131
21,300
24,750
$
$
15,808
1,576
1,023
3,866
–
7,494
48,693
193,647
24,445
14,075
232,167
(129,183 )
102,984
2,247
6,726
8,973
160,650
4,853
3,141
10,014
2,215
15,625
35,848
4,727
8,810
19,611
13,000
46,148
81,996
21,300
24,750
5,241
(970 )
577,488
(142,021 )
(427,319 )
12,419
132,600
$
5,032
(970 )
575,411
(124,766 )
(422,103 )
32,604
160,650
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
F-4
TRANSATLANTIC PETROLEUM LTD.
Consolidated Statements of Operation and Comprehensive Loss
For the Years ended December 31, 2018 and 2017
(U.S. Dollars and shares in thousands, except per share amounts)
Revenues:
Oil and natural gas sales
Sales of purchased natural gas
Other
Total revenues
Costs and expenses:
Production
Transportation costs
Exploration, abandonment and impairment
Cost of purchased natural gas
Seismic and other exploration
General and administrative
Depreciation, depletion and amortization
Accretion of asset retirement obligations
Total costs and expenses
Operating income
Other (expense) income:
Loss on sale of TBNG
Interest and other expense
Interest and other income
Loss on commodity derivative contracts
Foreign exchange loss
Total other expense
Income (loss) before income taxes
Current income tax expense
Deferred income tax expense
Net loss
Other comprehensive loss:
Foreign currency translation adjustment
Comprehensive loss
Net loss per common share:
Basic net loss per common share
Weighted average common shares outstanding
Diluted net loss per common share
Weighted average common and common equivalent shares outstanding
2018
2017
70,268 $
–
521
70,789
10,769
4,665
401
–
489
14,719
14,059
174
45,276
25,513
–
(10,048)
1,082
(1,797)
(10,292)
(21,055)
4,458
(2,820)
(6,854)
(5,216)
(17,255)
(22,471) $
(0.10) $
50,505
(0.10) $
50,505
55,523
654
462
56,639
12,249
–
934
568
4,723
12,817
16,925
190
48,406
8,233
(15,226)
(8,838)
1,098
(1,852)
(1,861)
(26,679)
(18,446)
(2,073)
(3,356)
(23,875)
15,550
(8,325)
(0.50)
48,196
(0.50)
48,196
$
$
$
$
The accompanying notes are an integral part of these consolidated financial statements.
F-5
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-
F
TRANSATLANTIC PETROLEUM LTD.
Consolidated Statements of Cash Flows
For the Years ended December 31, 2018 and 2017
(in thousands of U.S. Dollars)
Operating activities:
Net loss
Adjustments to reconcile net loss to net cash provided by operating activities:
Share-based compensation
Foreign currency (income) loss
Loss on commodity derivative contracts
Cash settlement on commodity derivative contracts
Amortization on loan financing costs
Interest on Series A Preferred Shares paid in common shares
Deferred income tax expense
Exploration, abandonment and impairment
Depreciation, depletion and amortization
Accretion of asset retirement obligations
Loss on Sale of TBNG
Changes in operating assets and liabilities:
Accounts receivable
Prepaid expenses and other assets
Accounts payable and accrued liabilities
Net cash provided by operating activities
Investing activities:
Additions to oil and natural gas properties
Additions to equipment and other properties
Proceeds from asset sale
Net cash provided by (used in) investing activities
Financing activities:
Tax withholding on restricted share units
Loan proceeds
Loan repayment
Loan repayment - related party
Net cash used in financing activities
Effect of exchange rate on cash flows, cash equivalents and restricted cash
Net increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash, beginning of year (1)
Cash, cash equivalents and restricted cash, end of year (2)
Supplemental disclosures:
Cash paid for interest
Cash paid for taxes
2018
2017
$
(5,216)
$
(23,875)
455
13,299
1,797
(4,012)
42
1,842
6,854
401
14,059
174
–
(1,358)
(6,673)
7,031
28,695
(23,517)
(3,015)
–
(26,532)
(11)
10,000
(16,625)
–
(6,636)
(5,931)
(10,404)
20,431
10,027
7,917
3,239
$
$
$
693
(440)
1,852
32
82
1,842
3,356
934
16,925
190
15,226
2,255
(859)
(333)
17,880
(15,478)
(366)
17,779
1,935
(92)
20,375
(30,475)
(3,219)
(13,411)
(1,044)
5,360
15,071
20,431
5,620
2,151
$
$
$
(1) The balance at January 1, 2017 includes cash and cash equivalents of $10.0 million, restricted cash of $3.5 million in other assets and TBNG cash held for
sale of $1.6 million. 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.
(2) The end of period balance at December 31, 2017 includes cash and cash equivalents of $18.9 million and restricted cash of $1.5 million in other assets. 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 accompanying notes are an integral part of these consolidated financial statements.
F-7
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 22, 2019, approximately 48% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, our
chief executive officer and chairman of our board of directors.
TransAtlantic is a holding company with two operating segments – Turkey and Bulgaria. Its assets consist of its ownership interests
in subsidiaries that primarily own assets in Turkey and Bulgaria.
Basis of presentation
Our consolidated financial statements are expressed in U.S. Dollars and have been prepared by management in accordance with
accounting principles generally accepted in the United States (“U.S. GAAP”). All amounts in 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.
On February 24, 2017, we closed the sale of our ownership interests in our subsidiary Thrace Basin Natural Gas (Turkiye) Corporation
(“TBNG”) for gross proceeds of $20.7 million and net cash proceeds of $16.1 million, which reflect a $0.2 million post-closing
purchase price adjustment. Although the sale of TBNG met the threshold to classify its assets and liabilities as held for sale, it did not
meet the requirements to classify its operations as discontinued, as the sale was not considered a strategic shift in our operations. As
such, TBNG’s results of operations are classified as continuing operations for all periods presented (see Note 17 “Divestitures and
discontinued operations”).
2. Liquidity
During 2018, we repaid the 2016 Term Loan in full in accordance with its terms and entered into the 2018 Term Loan with
DenizBank, A.S. (“DenizBank”) for $10.0 million. (see Note 9 “Loans Payable”).
As of December 31, 2018, we had no long-term debt, $22.0 million in short-term debt, $9.9 million in cash and a $2.5 million working
capital surplus.
Based on current forecasted oil prices for 2019 and beyond, we believe that our cash flows from operations and existing cash on hand
are sufficient to conduct our planned operations and meet our contractual requirements, including license obligations through March
31, 2020.
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, 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
F-8
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 $0.5 million at December 31, 2018 and 2017.
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
acquisition. 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:
Level 2:
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted
assets or liabilities.
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
F-9
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
As explained below (see Note 4 “New accounting pronouncements”), on January 1, 2018, we adopted FASB 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
F-10
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. The
Company believes its business processes, systems, and controls are appropriate to support recognition and disclosure ASU 2014-09.
We do not expect any impact to our net income from the adoption of ASU 2014-09 on an ongoing basis.
The Company recognizes revenue in accordance with FASB, ASC 606, Revenue from Contracts with Customers (“ASC 606”).
Revenues are recognized when control is transferred to customers in amounts that reflect the consideration the Company expects to be
entitled to receive in exchange for those goods. Revenue recognition is evaluated through the following five steps: (i) identification of
the contract, or contracts, 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, 2018 and 2017, we sold $68.2 million and $54.9 million, respectively, of oil to Türkiye Petrol
Rafinerileri A.Ş. (“TUPRAS”), a privately-owned oil refinery in Turkey, which represented approximately 96.4%, and 97.0% 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”). 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, and (ii) 106,000 shares were issued and sold for $5.3 million of cash to certain holders of the 2017
Notes. All of the Series A Preferred Shares were issued at a value of $50.00 per share (see Note 5 “Series A Preferred Shares”). As
the shares can be redeemed, they have been classified outside of equity.
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, 2018 and 2017, we have recorded a $6.7 million and $8.7 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.
F-11
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 May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers, its final standard on revenue from contracts
with customers. ASU 2014-09 outlines a single comprehensive model for entities to use in accounting for revenue arising from
contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The core
principle of the revenue model is that an entity recognizes revenue to depict the transfer of promised goods or services to customers in
an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In applying
the revenue model to contracts within its scope, an entity identifies the contract(s) with a customer, identifies the performance
obligations in the contract, determines the transaction price, allocates the transaction price to the performance obligations in the
contract and recognizes revenue when (or as) the entity satisfies a performance obligation. ASU 2014-09 applies to all contracts with
customers and requires significantly expanded disclosures about revenue recognition. ASU 2014-09 has been amended several times
with subsequent ASUs including ASU 2015-14 Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.
We adopted ASU 2014-09 on January 1, 2018 using the modified retrospective approach. We have a small number of contracts with
customers and have identified transactions within the scope of the standard. As a result of adoption of ASU 2014-09, we have
determined that it will change our method of recording certain transportation and processing charges that were previously recorded as
a reduction of revenues to record such charges as an expense under the new standard. The result of this change was an increase to both
revenue and expenses of $4.7 million for the twelve months ended December 31, 2018. The application of the new standard has no
impact on our retained earnings and no impact to our net income on an ongoing basis. During the twelve months ended December 31,
2017, this standard would have increased both revenue and expenses by $4.4 million.
Contracts for the sale of natural gas and crude oil are evidenced by (1) base contracts for the sale and purchase of natural gas or crude
oil, which document the general terms and conditions for the sale, and (2) transaction confirmations, which document the terms of
each specific sale.
Revenue is measured based on consideration specified in the contract with the customer. We recognize revenue in the amount that
reflects the consideration we expect to be entitled to in exchange for transferring control of those goods to the customer. Revenues are
recognized for the sale of our net share of production volumes. Sales on behalf of other working interest owners and royalty interest
owners are not recognized as revenues. The contract consideration in our contracts are typically allocated to specific performance
obligations in the contract according to the price stated in the contract, which usually sets the base oil and natural gas prices based on
benchmark prices based on volumes and adjustments for product quality. Payment is generally received one or two months after the
sale has occurred.
F-12
The following table displays the disaggregation of revenue by product type for the twelve months ended December 31, 2018 and
2017:
Oil
Natural gas
Total revenue from customers
2018
2017
(in thousands)
$ 69,207
1,061
$ 70,268
$ 58,109
1,807
$ 59,916
All of our revenues from contracts with customers represent products transferred at the point in time control is transferred to the
customer and are generated in Turkey.
Transaction price allocated to remaining performance obligations. A significant number of our product sales are short-term in nature
with a contract term of one year or less. For those contracts, we have utilized the practical expedient exempting us from disclosure of
the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an
original expected duration of one year or less.
Contract balances. Receivables from contracts with customers are recorded when the right to consideration becomes unconditional,
generally when control of the product has been transferred to the customer. Receivables from contracts with customers were $12.9
million and $15.8 million as of December 31, 2018 and December 31, 2017, respectively, and are reported in accounts receivable, net
on our consolidated balance sheets. We currently have no assets or liabilities related to our revenue contracts, including no upfront or
rights to deficiency payments.
Practical expedients. We have made use of certain practical expedients in adopting the new revenue standard, including the value of
unsatisfied performance obligations are not disclosed for (i) contracts with an original expected length of one year or less, (ii)
contracts for which we recognize revenue at the amount to which we have the right to invoice, (iii) variable consideration which is
allocated entirely to a wholly unsatisfied performance obligation and meets the variable allocation criteria in the standard and (iv) only
contracts that are not completed at transition. We have not adjusted the promised amount of consideration for the effects of a
significant financing component if we expect, at contract inception, that the period between when we transfer a promised good or
service to the customer and when the customer pays for that good or service will be one year or less.
In February 2016, the FASB issued ASU 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 will become effective for us beginning with the first
quarter of 2019. We will adopt the accounting standard using a prospective transition approach, which applies the provisions of the
new guidance at the effective date without adjusting the comparative periods presented. We have elected the package of practical
expedients permitted under the transition guidance within the new standard, which among other things, allows us to carry forward the
historical accounting relating to lease identification and classification for existing leases upon adoption. We have made an accounting
policy election to keep leases with an initial term of 12 months or less off of the consolidated balance sheet. We are finalizing our
evaluation of the impacts that the adoption of this accounting guidance will have on the consolidated financial statements and estimate
approximately $2.7 million of additional right-of-use assets and liabilities will be recognized in our consolidated balance sheet upon
adoption.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13 changes the
impairment model for most financial assets and certain other instruments, including trade and other receivables, held-to-maturity debt
securities and loans, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of
allowance for losses. This update is effective for fiscal years beginning after December 15, 2019, including interim periods within
those fiscal years. Early adoption is permitted for a fiscal year beginning after December 15, 2018, including interim periods within
that fiscal year. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning
of the first reporting period in which the guidance is adopted. We are currently assessing the potential impact of ASU 2016-13 on our
consolidated financial statements and results of operations.
In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and
Cash Payments (“ASU 2016-15”). ASU 2016-15 reduces diversity in practice in how certain transactions are classified in the
statement of cash flows. The amendments in ASU 2016-15 provide guidance on specific cash flow issues including debt prepayment
or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are
insignificant in relation to the effective interest rate of the borrowing, contingent consideration payments made after a business
F-13
combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance
policies, and distributions received from equity method investees. ASU 2016-15 is effective for annual and interim periods beginning
after December 15, 2017. We adopted ASU 2016-15 effective January 1, 2018. The adoption of ASU 2016-15 had no impact on our
retained earnings or net income.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (“ASU 2016-18”). ASU
2016-18 requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts
generally described as restricted cash or restricted cash equivalents. The amounts generally described as restricted cash and restricted
cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total
amounts shown on the statements of cash flows. We adopted ASU 2016-18 effective January 1, 2018. The adoption of ASU 2016-18
had no impact on our retained earnings, and no impact to our net income on an ongoing basis. The amendments have been applied
using a retrospective transition method to each period presented, as required. The period ended December 31, 2017 has been
reclassified to reflect this change.
In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, which clarifies Topic 718, Compensation – Stock
Compensation, such that an entity must apply modification accounting to changes in the terms or conditions of a share-based payment
award unless all of the following criteria are met: (1) the fair value of the modified award is the same as the fair value of the original
award immediately before the modification and the ASU indicates that if the modification does not affect any of the inputs to the
valuation technique used to value the award, the entity is not required to estimate the value immediately before and after the
modification; (2) the vesting conditions of the modified award are the same as the vesting conditions of the original award
immediately before the modification; and (3) the classification of the modified award as an equity instrument or a liability instrument
is the same as the classification of the original award immediately before the modification. The ASU is effective for fiscal years
beginning after December 15, 2017. The adoption of this ASU had no impact on our consolidated financial statements and results of
operations. We adopted ASU 2017-09 effective January 1, 2018.
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 are effective for fiscal years beginning after December 15,
2018 and for interim periods therein. Early adoption as of the date of issuance is permitted. The new standard does not impact
accounting for derivatives that are not designated as accounting hedges. We do not currently account for any of our derivative position
as accounting hedges.
We have reviewed other recently issued, but not yet adopted, accounting standards in order to determine their effects, if any, on our
consolidated results of operations, financial position and cash flows. Based on that review, we believe that none of these
pronouncements will have a significant effect on current or future earnings or operations.
5. Series A Preferred Shares
Series A Preferred Shares
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 the 2017 Notes, at an exchange rate of 20 Series A Preferred Shares for each $1,000
principal amount of 2017 Notes, and (ii) 106,000 shares were issued and sold for $5.3 million of cash to certain holders of the 2017
Notes. All of the Series A Preferred Shares were issued at a value of $50.00 per share. We used $4.3 million of the gross proceeds to
redeem a portion of the remaining 2017 Notes on January 1, 2017. The remaining proceeds were used for general corporate purposes.
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, 2018, there were $21.3 million of Series A Preferred Shares and $24.8 million of
Series A Preferred Shares – related party outstanding (see Note 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).
F-14
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
November 4, 2020
November 4, 2021
November 4, 2022
November 4, 2023 and thereafter
Redemption Price
105.000%
103.000%
101.000%
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. As of December 31, 2018 and 2017, we paid $5.3
million and accrued $6.0 million, respectively, in dividends on the Series A Preferred Shares, which is recorded in our consolidated
statements of comprehensive loss under the caption “Interest and other expense”. These amounts were paid in cash and common
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.
F-15
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:
Oil and natural gas properties, proved:
Turkey
Bulgaria
Total oil and natural gas properties, proved
Oil and natural gas properties, unproved:
Turkey
Bulgaria
Total oil and natural gas properties, unproved
Gross oil and natural gas properties
Accumulated depletion
Net oil and natural gas properties
2018
2017
(in thousands)
$
162,494 $
512
163,006
193,111
536
193,647
14,965
730
15,695
178,701
(100,582)
$
78,119 $
24,445
-
24,445
218,092
(123,225)
94,867
The decline in oil and natural gas properties during the year ended December 31, 2018 was primarily driven by the devaluation of the
Turkish Lira (“TRY”) versus the U.S. Dollar. For the year ended December 31, 2018 and 2017, we have recorded foreign currency
translation adjustments which reduced oil and natural gas properties and increased accumulated other comprehensive loss within
shareholders’ equity on our consolidated balance sheet.
At December 31, 2018 and 2017, we excluded $0.5 million of costs from the depletion calculation for development wells in progress.
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.
At December 31, 2017, the capitalized costs of our oil and natural gas properties included $11.2 million relating to acquisition costs of
proved properties, which are being amortized by the unit-of-production method using total proved reserves, and $58.7 million relating
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, 2018, we recorded $0.3 million of impairment of proved properties and exploratory well costs
which are primarily measured using Level 3 inputs primarily relating to two of our gas fields.
During the year ended December 31, 2017, we recorded $0.8 million of impairment of proved properties and exploratory well costs
which are primarily measured using Level 3 inputs primarily relating to two of our gas fields.
Capitalized costs greater than one year
As of December 31, 2018, there were no capitalized exploratory well costs greater than one year.
As of December 31, 2017, we had $4.0 million of exploratory well costs capitalized for the Pinar-1 well in Turkey. During the first
quarter of 2018, the well began producing.
F-16
Equipment and other property
The historical cost of equipment and other property, presented on a gross basis with accumulated depreciation, is summarized as
follows:
Other equipment
Land
Inventory
Gas gathering system and facilities
Vehicles
Leasehold improvements, office equipment and software
Gross equipment and other property
Accumulated depreciation
Net equipment and other property
2018
2017
(in thousands)
1,240 $
149
6,791
194
336
5,698
14,408
(5,268)
9,140 $
1,764
–
4,619
135
343
7,214
14,075
(5,958)
8,118
$
$
At December 31, 2018 and 2017, we classified $5.2 million and $7.5 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, 2018 and 2017, we excluded $12.0 million and $12.1 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 comprehensive loss under the caption “(Loss)
gain on derivative contracts.” Settlements of derivative contracts are included in operating activities on our consolidated statements of
cash flows under the caption “Cash settlement on derivative contracts.”
F-17
At December 31, 2018, we had no outstanding commodity derivative contracts with respect to our future crude oil production.
At December 31, 2017, 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, 2017
Period
Quantity
(Bbl/day)
Collars
Weighted
Average
Minimum
Price
(per Bbl)
Weighted
Average
Maximum Price
(per Bbl)
Estimated Fair
Value of Liability
(in thousands)
January 1, 2018—
February 28, 2018
January 1, 2018—
March 31, 2018
January 1, 2018—
May 31, 2018
January 1, 2018—
June 30, 2018
458
500
298
746
$
$
$
$
50.00 $
61.50 $
47.00 $
59.65
47.50 $
61.00
(178)
(376)
(286)
47.50 $
57.10
(1,375)
$
(2,215)
Type
Collar
Collar
Collar
Collar
Total Estimated Fair Value of
Liability
Foreign currency 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 foreign exchange derivative contracts are settled based upon the contract rate. We recognize
gains and losses related to these contracts on a fair value basis in our consolidated statements of 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, 2018 and 2017, we had no outstanding derivative contracts with respect to our foreign exchange rates.
During the years ended December 31, 2018 and 2017, we recorded a net loss on derivative contracts of $1.8 million and $1.9 million,
respectively.
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, 2017, and (ii) the net recorded fair value as reflected on our
consolidated balance sheets at December 31, 2017. At December 31, 2018, we did not have any commodity or foreign exchange
derivative contracts.
Underlying Commodity
Location on Balance Sheet
Gross
Amount of
Recognized
Assets
As of December 31, 2017
Gross
Amount
Offset in the
Consolidated
Balance
Sheet
(in thousands)
Net Amount of
Assets
Presented in the
Consolidated
Balance Sheet
Crude oil
Current liabilities
$
2,215 $
– $
2,215
F-18
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, 2018, the net
present value of our total ARO was estimated to be $4.7 million, with the undiscounted value being $8.2 million. Total ARO at
December 31, 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 approximately 12.65% per annum for
Turkey. These values are discounted to present value using our credit-adjusted risk-free rate of 7.55% per annum for Turkey for the
year ended December 31, 2018. The following table summarizes the changes in our ARO for the years ended December 31, 2018 and
2017:
Asset retirement obligations at beginning of period
Liabilities settled
Foreign exchange change effect
Additions
Accretion expense
Asset retirement obligations at end of period
Long-term portion
2018
2017
(in thousands)
$
$
4,727 $
–
(1,270)
1,036
174
4,667
4,667 $
4,833
(37)
(259)
–
190
4,727
4,727
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:
Fixed and floating rate loans
Term Loan (1)
Loans payable
Less: current portion
Long-term portion
_______________________________________________________________________________________________________________
(1) Includes 2018, 2017 and 2016 Term Loans.
2016 Term Loan
December 31,
2018
December 31,
2017
$
$
(in thousands)
22,000 $
22,000
22,000
– $
28,625
28,625
15,625
13,000
On August 31, 2016, 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. Amounts repaid under the 2016 Term Loan could not be
re-borrowed and early repayments under the 2016 Term Loan were subject to early repayment fees.
The 2016 Term Loan was guaranteed by DMLP, Ltd. (“DMLP”), TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”), Talon
Exploration, Ltd. (“Talon Exploration”), and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”).
F-19
The 2016 Term Loan contained standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting of
liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain
investments, selling assets or transferring revenue, and other similar matters. In addition, the 2016 Term Loan prohibited Amity Oil
International Pty Ltd (“Amity”) and Petrogas Petrol Gaz ve Petrokimya Urunleri Insaat Sanayi ve Ticaret A.S. (“Petrogas”) from
incurring additional debt. An event of default under the 2016 Term Loan included, among other events, failure to pay principal or
interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and the
occurrence of a material adverse effect.
The 2016 Term Loan was secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii)
substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate
owned by Gundem Turizm Yatirim ve Isletmeleri A.S. (“Gundem”) and (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell
and 20% 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 2016 Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr.
Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.
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 bears interest at a fixed rate of 6.0% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish
government) per annum. The 2017 Term Loan had a grace period which bore no interest or payments due until July 2018. Thereafter,
the 2017 Term Loan is payable in one monthly installment of $1.38 million, nine monthly installments of $1.2 million each through
April 2019 and thereafter in eight monthly installments of $1.0 million each through December 2019, with the exception of one
monthly installment of $1.2 million occurring in October 2019. The 2017 Term Loan matures in December 2019. Amounts repaid
under the 2017 Term Loan may not be re-borrowed, and early repayments under the 2017 Term Loan are subject to early repayment
fees. The 2017 Term Loan is guaranteed by Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.
The 2017 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on granting of
liens on its assets, incurring additional debt, dissolving, liquidating, merging, consolidating, paying dividends, making certain
investments, selling assets or transferring revenue, and other similar matters. In addition, the 2017 Term Loan prohibits Amity and
Petrogas from incurring additional debt. An event of default under the 2017 Term Loan includes, among other events, failure to pay
principal or interest when due, breach of certain covenants, representations, warranties and obligations, bankruptcy or insolvency and
the occurrence of a material adverse effect.
The 2017 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon Exploration, (ii)
substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) the Gundem real estate and Muratli real estate
owned by Gundem, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% 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 2017 Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children, and Mr.
Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president, Turkey.
At December 31, 2018, we had $13.0 million outstanding under the 2017 Term Loan and no availability, and we were in compliance
with the covenants in the 2017 Term Loan.
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 bears 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 is payable monthly and the principal on the 2018 Term Loan is 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 matures in December 2019. Amounts repaid under the 2018 Term Loan may not be
reborrowed, and early repayments under the 2018 Term Loan are subject to early repayment fees. The 2018 Term Loan is guaranteed
by Petrogas, Amity, Talon Exploration, DMLP, and TransAtlantic Turkey.
F-20
The 2018 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 2018 Term Loan prohibits Amity, Talon
Exploration, DMLP, and TransAtlantic Turkey from incurring additional debt. An event of default under the 2018 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 2018 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, (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% 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 2018 Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children,
and Mr. Uras. Mr. Mitchell is our chief executive officer and chairman of our board of directors. Mr. Uras is our vice president,
Turkey.
At December 31, 2018, we had $9.0 million outstanding under the 2018 Term Loan and no availability, and we were in compliance
with the covenants in the 2018 Term Loan.
During the years ended December 31, 2018 and 2017, we recorded interest expense related to the 2016, 2017 and 2018 Term Loan of
$1.8 million and $0.9 million, respectively.
2017 Notes
The 2017 Notes were issued pursuant to an indenture, dated as of February 20, 2015 (the “Indenture”), between us and U.S. Bank
National Association, as trustee (the “Trustee”). The 2017 Notes bore interest at an annual rate of 13.0%, payable semi-annually, in
arrears, on January 1 and July 1 of each year. The 2017 Notes matured on July 1, 2017, and on July 3, 2017, we paid off and retired
all remaining outstanding 2017 Notes.
ANBE Note
On December 30, 2015, TransAtlantic Petroleum (USA) Corp (“TransAtlantic USA”) entered into a $5.0 million draw down
convertible promissory note (the “ANBE Note”) with ANBE Holdings, L.P. (“ANBE”), an entity owned by the adult children of our
chairman and chief executive officer, Mr. Mitchell, and controlled by an entity managed by Mr. Mitchell and his wife. The ANBE
Note bore interest at a rate of 13.0% per annum. On December 30, 2015, we borrowed $3.6 million under the ANBE Note (the
“Initial Advance”). The Initial Advance was used for general corporate purposes.
On October 31, 2016, TransAtlantic USA entered into an amendment of the ANBE Note with ANBE (the “ANBE Amendment”).
The ANBE Amendment extended the maturity date of the ANBE Note from October 31, 2016 to September 30, 2017, provided for the
ANBE Note to be repaid in four quarterly installments of $0.9 million each in December 2016 and March, June and September 2017,
and provided for monthly payments of interest.
On February 27, 2017, we repaid the ANBE Note in full with proceeds from the sale of TBNG and terminated it.
Unsecured lines of credit
Our wholly-owned subsidiaries operating in Turkey are party to unsecured, non-interest bearing lines of credit with a Turkish bank.
At December 31, 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 $0.1 million during 2018 and 2017.
F-21
10. Shareholders’ equity
Share issuances to holders of Series A Preferred Shares
On October 2, 2017, we issued an aggregate of 2,591,384 common shares to holders of the Series A Preferred Shares as payment of
the September 30, 2017 quarterly dividend on the Series A Preferred Shares. Each common share was issued at a value of $0.7108 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, 2017.
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.
Restricted stock units
Under our 2009 Long-Term Incentive Plan (the “Incentive Plan”), 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 Plan, 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 Incentive Plan was February 9, 2009, the
date our board of directors approved the Incentive Plan.
Share-based compensation of approximately $0.5 million and $0.7 million with respect to awards of RSUs was recorded for the years
ended December 31, 2018 and 2017, respectively. As of December 31, 2018, we had approximately $0.3 million of unrecognized
compensation expense related to unvested RSUs, which is expected to be recognized over a weighted average period of 0.5 years. The
following table sets forth RSU activity for the year ended December 31, 2018:
Unvested RSUs outstanding at December 31, 2017
Granted
Forfeited
Vested
Unvested RSUs outstanding at December 31, 2018
Earnings per share
Number of RSUs
(in thousands)
Weighted Average
Grant Date Fair
Value Per RSU
513 $
311
(7)
(363)
454 $
1.38
1.55
1.18
1.49
1.42
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, 2018 and 2017 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, 2018 and 2017 are computed in the same manner as basic
earnings per common share after assuming the issuance of common shares for all potentially dilutive common share equivalents,
which includes stock options, RSUs, preferred shares and warrants, whether exercisable or not. The computation of diluted earnings
per common share excluded 42.0 million and 43.7 million antidilutive common share equivalents for the years ended December 31,
2018 and 2017, respectively.
F-22
The following table presents the basic and diluted earnings per common share computations:
(in thousands, except per share amounts)
Net loss
Basic net loss per common share:
Shares:
Weighted average common shares outstanding
Basic net loss per common share:
Diluted net loss per common share:
Shares:
Weighted average shares outstanding
Dilutive effect of:
Restricted share units
2017 Notes
2018
2017
$
(5,216) $
(23,875)
$
50,505
(0.10) $
48,196
(0.50)
50,505
48,196
–
–
–
–
Weighted average common and common equivalent shares
outstanding
Diluted net loss per common share:
$
50,505
(0.10) $
48,196
(0.50)
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 2018 and 2017 to income (loss) from operations as follows:
2017
2018
(in thousands except rates)
0.00%
0.00%
4,458
$
(18,446)
$
4,720
935
2,927
(4,743)
4,793
1,042
9,674
$
945
1,050
1,677
640
792
325
5,429
Statutory rate
Income (loss) before income taxes
Increase (decrease) resulting from:
Foreign tax rate differentials
Uncertain tax position
Unremitted earnings
Change in valuation allowance
Expiration of non-capital tax loss carryovers
Other
Total
$
$
$
F-23
The components of the net deferred income tax liability at December 31, 2018 and 2017 were as follows:
Deferred tax assets
Property and equipment
Unrealized gains on derivative contracts
Timing of accruals
Non-capital loss carryovers
Valuation allowance
Other
Total deferred tax assets
Deferred tax liabilities
Property and equipment
Unremitted earnings
Timing of accruals
Total deferred tax liabilities
Net deferred tax liabilities
Components of net deferred tax liabilities
Non-current assets
Non-current liabilities
Net deferred tax liabilities
2018
2017
(in thousands)
609 $
574
13,261
(13,261)
–
1,183 $
(9,728) $
(9,401)
(2,368)
(21,497)
(20,314) $
1,183 $
(21,497)
(20,314) $
1,279
432
132
16,502
(17,731)
47
661
(10,044)
(9,631)
(597)
(20,272)
(19,611)
661
(20,272)
(19,611)
$
$
$
$
$
$
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, 2018, we had non-capital tax losses in Turkey of approximately 57.8 million TRY (approximately
$11.0 million), which will begin to expire in 2019; non-capital tax losses in Romania of approximately 1.6 million Romanian New
Leu (approximately $0.4 million), which will begin to expire in 2019; non-capital losses in Bulgaria of approximately 9.8 million
Bulgarian Lev (approximately $5.7 million), which will begin to expire in 2019; and non-capital tax losses in the United States of
approximately $53.7 million, which will begin to expire in 2019. As of December 31, 2018 and 2017, we recorded a valuation
allowance of $13.3 million and $17.7 million, respectively, as a reduction to our net operating losses and deferred tax assets.
Effective October 1, 2009, we continued to the jurisdiction of Bermuda under the Bermuda Companies Act 1981. We have determined
that no taxes were payable upon the continuance. However, our tax filing positions are still subject to review by taxation authorities
who may successfully challenge our interpretation of the applicable tax legislation and regulations, with the result that additional taxes
could be payable by us.
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, 2018 and 2017, we recorded a $6.7 million and $8.7 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, 2018 and 2017 were as follows:
Unrecognized tax benefits at beginning of period
Gross increases - tax positions in prior period
Foreign exchange change effect
Unrecognized tax benefits at end of period
2018
2017
(in thousands)
$
$
8,663 $
935
(2,884)
6,714 $
8,079
1,125
(541)
8,663
As of December 31, 2018, 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.
F-24
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 the increase in our U.S. debt service obligations resulting from the issuance of the 2017 Notes in the aggregate
principal amount of $55.0 million in 2015 (see Note 9 “Loans payable”), 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 fiscal year 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. Although the 2017 Notes were retired on July 3, 2017 (see Note 9 “Loans Payable”), due to our
obligation to pay dividends on our Series A Preferred Shares issued on November 4, 2016 (see Note 5 “Series A Preferred Shares”), as
of December 31, 2018 and 2017, we maintain the same position, and we provided for Turkish dividend, withholding taxes on 329.7
million and 242.1 million TRY, respectively, of cumulative undistributed foreign Turkish earnings, resulting in an additional increase
in our deferred tax liability.
There is no certainty as to the timing of when or if such Turkish foreign earnings will be distributed in whole or in part.
F-25
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, 2018
Total revenues
Production
Transportation costs
Exploration, abandonment, and impairment
Seismic and other exploration
General and administrative
Depreciation, depletion and amortization
Accretion of asset retirement obligations
Total costs and expenses
Operating (loss) income
Interest and other expense
Interest and other income
Loss on commodity derivative contracts
Foreign exchange gain (loss)
(Loss) income before income taxes
Income tax expense
Net loss
Total assets at December 31, 2018
Capital expenditures for the year ended December 31, 2018
For the year ended December 31, 2017
Total revenues
Production
Exploration, abandonment, and impairment
Cost of purchased natural gas
Seismic and other exploration
General and administrative
Depreciation, depletion and amortization
Accretion of asset retirement obligations
Total costs and expenses
Operating (loss) income
Loss on sale of TBNG
Interest and other expense
Interest and other income
Loss on commodity derivative contracts
Foreign exchange gain (loss)
(Loss) income before income taxes
Income tax expense
Net loss
Total assets at December 31, 2017
Capital expenditures for the year ended December 31, 2017
$
$
$
– $
–
–
–
–
9,222
142
–
9,364
(9,364)
(7,026)
184
–
(351)
(16,557)
–
(16,557) $
8,358 $
– $
– $
36
–
–
–
6,739
188
–
6,963
(6,963)
(15,226)
(7,794)
250
–
365
(29,368)
–
(29,368) $
61,167 $
– $
F-26
$
70,789
10,649
4,665
401
488
5,344
13,917
151
35,615
35,174
(3,022)
897
(1,797)
(9,932)
21,320
(9,674)
11,646
122,325
23,517 $
$
$
– $
–
–
1
70,789
120 10,769
4,665
401
489
153 14,719
– 14,059
23
174
297 45,276
(297) 25,513
– (10,048)
1,082
1
–
(1,797)
(9) (10,292)
4,458
(9,674)
(5,216)
(305)
–
(305) $
1,917 $ 132,600
23,517
– $
56,639 $
12,136
934
568
4,723
5,729
16,737
169
40,996
15,643
–
(1,044)
847
(1,852)
(2,239)
11,355
(5,429)
5,926 $
109,699 $
15,854 $
– $
77
–
–
–
349
–
21
447
(447)
–
–
1
–
13
(433)
–
56,639
12,249
934
568
4,723
12,817
16,925
190
48,406
8,233
(15,226)
(8,838)
1,098
(1,852)
(1,861)
(18,446)
(5,429)
(433) $ (23,875)
(10,216) $ 160,650
15,854
– $
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 not used foreign currency
forward contracts to manage exchange rate fluctuations. At December 31, 2018 and 2017, we had 7.8 million TRY and $4.0 million
TRY, respectively (approximately $1.5 million and $1.1 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, accrued liabilities and the ANBE Note were each
estimated to have a fair value approximating the carrying amount at December 31, 2018 and 2017 due to the short maturity of those
instruments.
The financial assets and liabilities measured on a recurring basis at December 31, 2017 consisted of our commodity derivative
contracts. 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 contracts purchased 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.
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:
Liabilities:
2017 Term Loan
2018 Term Loan
Total
Fair Value Measurement Classification
Quoted Prices in
Active Markets for
Identical Assets or
Liabilities
Significant Other
Observable Inputs
Significant
Unobservable Inputs
(Level 1)
(Level 2)
(Level 3)
Total
(in thousands)
$
–
–
– $
F-27
–
–
– $
(11,938)
(8,192)
(20,130) $
(11,938)
(8,192)
(20,130)
The following table summarizes the valuation of our financial liabilities as of December 31, 2017:
Fair Value Measurement Classification
Quoted Prices in
Active Markets for
Identical Assets or
Liabilities
Significant Other
Observable Inputs
Significant
Unobservable Inputs
(Level 1)
(Level 2)
(Level 3)
Total
(in thousands)
Measured on a recurring basis
Liabilities:
Commodity derivative contracts
Disclosed but not carried at fair value
Liabilities:
2017 Term Loan
2016 Term Loan
Total
$
$
–
$
(2,215) $
–
$
(2,215)
–
–
– $
–
–
(2,215) $
(16,613)
(7,866)
(24,479) $
(16,613)
(7,866)
(26,694)
14. Commitments
Our aggregate annual commitments, other than our loans payable, as of December 31, 2018 were as follows:
Series A Preferred Shares
dividends (1)
Interest
Leases
Total
Total
2019
2020
Payments Due By Year
2021
(in thousands)
2022
2023
Thereafter
$
$
37,822 $
800
3,251
41,873 $
5,526 $
800
963
7,289 $
5,526 $
-
710
6,236 $
5,526 $
-
636
6,162 $
5,526 $
-
626
6,152 $
5,526 $ 10,192
-
-
5,842 $ 10,192
-
316
(1) Dividends on the Series A Preferred Shares may be paid by us, in our sole discretion, in cash at a rate of 12% per annum or
in common shares at a rate of 16% per annum or in a combination of cash and common shares. The amounts in the table
assume that we pay all future dividend payments solely in cash.
Normal operations purchase arrangements are excluded from the table as they are discretionary or being performed under contracts
which are cancelable immediately or with a 30-day notice period.
We lease office space in Dallas, Texas, Bulgaria, and Turkey. We also lease apartments in Turkey, as well as operations yards in
Turkey. Rent expense for the years ended December 31, 2018 and 2017 was $1.3 million and $1.2 million, respectively.
15. Contingencies
Contingencies relating to production leases and exploration permits
Selmo
We are involved in litigation with persons who claim ownership of a portion of the surface at the Selmo oil field in Turkey. These
cases are being vigorously defended by TEMI and Turkish governmental authorities. We do not have enough information to estimate
the potential additional operating costs we would incur in the event the purported surface owners’ claims are ultimately successful.
Any adjustment arising out of the claims will be recorded when it becomes probable and measurable.
Morocco
During 2012, we were notified that the Moroccan government may seek to recover approximately $5.5 million in contractual
obligations under our Tselfat exploration permit work program. In February 2013, the Moroccan government drew down our $1.0
million bank guarantee that was put in place to ensure our performance of the Tselfat exploration permit work program. Although we
believe that the bank guarantee satisfies our contractual obligations, we recorded $5.0 million in accrued liabilities relating to our
F-28
Tselfat exploration permit during 2012 for this contingency. In September 2016, management determined that, because it had
received no communication from the Moroccan government since early 2013, the probability of payment of this contingency is
remote, and therefore we reversed the $6.0 million in contingent liabilities previously classified as liabilities held for sale.
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. We continue to vigorously defend this claim.
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.
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 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, an affiliate of Mr.
Mitchell. 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 June 30, 2016, we issued an aggregate of 5,773,305 common shares in private placements under the Securities Act. Of the
5,773,305 common shares, (i) 1,974,452 common shares were issued to Dalea, the trusts of Mr. Mitchell’s four adult children and
Pinon Foundation, at their election to receive common shares in lieu of cash interest on the 2017 Notes; (ii) 355,826 common shares
were issued to ANBE in lieu of cash interest on the ANBE Note and (iii) 814,627 common shares were issued to Dalea and the trusts
F-29
of Mr. Mitchell’s four adult children for cash, which was used to pay cash interest to certain holders of the 2017 Notes (see Note 10
“Shareholders’ equity”).
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 value) were re-classified to related party.
On October 2, 2017, we issued an aggregate of 2,591,384 common shares to holders of the Series A Preferred Shares as payment of
the September 30, 2017 quarterly dividend on the Series A Preferred Shares (see Note 10 “Shareholder’s Equity”). Of the 2,591,384
common shares, 1,392,768 common shares were issued to Dalea, the trusts of Mr. Mitchell’s four children, Pinon Foundation, a
nonprofit entity controlled by Mrs. Mitchell, KMF Investment Partners, LP, and Randy Rochman.
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.
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.
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.
F-30
On June 30, 2016, we entered into a waiver with Dalea, whereby we waived our right under the Pledge Agreement to receive the
interest payment due July 1, 2016 under the Dalea Convertible Notes in connection with the payment of 201,459 common shares to
Dalea with respect to the 2017 Note interest payment paid on June 30, 2016.
As of December 31, 2018 and 2017, the amount receivable under the Amended Note was $5.8 million and $6.7 million, respectively.
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).
Pledge fee agreements
In connection with the pledge of the Gundem real estate and Muratli real estate to DenizBank as collateral for the 2016 Term Loan, on
August 31, 2016, we entered into a pledge fee agreement with Gundem (the “Gundem Fee Agreement”) pursuant to which we pay
Gundem a fee equal to 5% per annum of the collateral value of the Gundem real estate and Muratli real estate. Pursuant to the
Gundem Fee Agreement, the Gundem real estate has a deemed collateral value of $10.0 million and the Muratli real estate has a
deemed collateral value of $5.0 million.
In connection with the pledge of certain Diyarbakir real estate to DenizBank as collateral for the 2016 Term Loan, on August 31,
2016, we entered into a pledge fee agreement with Messrs. Mitchell and Uras (the “Diyarbakir Fee Agreement”) pursuant to which we
pay 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.
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 year ended December 31, 2018 and 2017, we reduced the principal
amount of the Amended Note by $0.6 million for amounts earned under the pledge fee agreements.
Service transactions
Effective May 1, 2008, we entered into a service agreement, as amended (the “Service Agreement”), with Longfellow Energy, LP
(“Longfellow”), Viking Drilling LLC (“Viking Drilling”), MedOil Supply, LLC and Riata Management, LLC (“Riata Management”).
Mr. Mitchell and his wife own 100% of Riata Management. In addition, Mr. Mitchell, his wife and his children indirectly own 100%
of Longfellow. Riata Management owns 100% of MedOil Supply, LLC. Dalea owns 100% of Viking Drilling. Under the terms of the
Service Agreement, we pay, or are paid, for the actual cost of the services rendered plus the actual cost of reasonable expenses on a
monthly basis.
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.
F-31
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.
On March 20, 2017, we entered into a second amendment to the Master Services Agreement among us and Longfellow Energy, LP, a
Texas limited partnership, Viking Drilling, LLC, a Nevada limited liability company, RIATA Management, LLC, an Oklahoma
limited liability company, Longfellow Nemaha, LLC, a Texas limited liability company, Red Rock Minerals, LP, a Delaware limited
partnership, Red Rock Advisors, LLC, a Texas limited liability company, Production Solutions International Limited , a Bermuda
exempted company, and Nexlube Operating, LLC, a Delaware limited liability company, and their subsidiaries (collectively, the
“Riata Entities”), adding and removing certain of the Riata Entities and expanding the scope of services.
For the years ended December 31, 2018 and 2017, we incurred capital and operating expenditures of $10.6 million and $9.3 million,
respectively, related to our various related party agreements.
ANBE Note
On December 30, 2015, TransAtlantic USA entered into the $5.0 million Note with ANBE, an entity owned by the children of our
chairman and chief executive officer, Mr. Mitchell and controlled by an entity managed by Mr. Mitchell and his wife. The ANBE
Note bears interest at a rate of 13.0% per annum. On December 30, 2015, we borrowed the Initial Advance of $3.6 million for general
corporate purposes. On June 30, 2016, we issued 355,826 common shares in a private placement to ANBE in lieu of paying cash
interest on the ANBE Note.
On October 31, 2016, TransAtlantic USA entered into an amendment of the ANBE Note with ANBE (the “ANBE Amendment”).
The ANBE Amendment extended the maturity date of the ANBE Note from October 31, 2016 to September 30, 2017, provided for the
ANBE Note to be repaid in four quarterly installments of $0.9 million each in December 2016 and March, June and September 2017,
and provided for monthly payments of interest.
On February 27, 2017, we repaid the ANBE Note in full and terminated it with proceeds from the sale of TBNG.
The following table summarizes related party accounts receivable and accounts payable as of December 31, 2018 and December 31,
2017:
Related party accounts receivable:
Riata Management Service Agreement
PSI MSA
Total related party accounts receivable
Related party accounts payable:
Riata Management Service Agreement
PSI MSA
Board of Directors
Interest payable on Series A Preferred Shares
Total related party accounts payable
2018
2017
(in thousands)
$
$
$
$
526 $
352
878
$
372
2,439
111
–
2,922
$
$
576
447
1,023
341
2,119
–
681
3,141
F-32
17. Divestitures and discontinued operations
TBNG
On October 13, 2016, we entered into a share purchase agreement (the “Purchase Agreement”) with Valeura Energy Netherlands B.V.
(“Valeura”) for the sale of all of the equity interests in TBNG, our wholly-owned subsidiary. TBNG owned a portion our interests in
the Thrace Basin area in Turkey.
Although the sale of TBNG met the threshold to classify its assets and liabilities as held for sale, it did not meet the requirements to
classify its operations as discontinued as the sale was not considered a strategic shift in our operations. As such, TBNG’s results of
operations are classified as continuing operations for all periods presented.
On February 24, 2017, we closed on the sale of TBNG for gross proceeds of $20.7 million and net cash proceeds of $16.1 million,
effective as of March 31, 2016. The purchase price was subject to post-closing adjustments, and we agreed to escrow $3.1 million of
the purchase price for 30 days to satisfy any agreed upon purchase price adjustments. We agreed to a $0.2 million reduction to the
purchase price, and on April 10, 2017, we collected $2.9 million of the escrowed funds.
For the year ended December 31, 2017, we recorded a non-cash net loss of $15.2 million on the sale of TBNG. The loss related to the
reclassification of the TBNG accumulated foreign currency translation adjustment that was realized into earnings from accumulated
other comprehensive loss within shareholders’ equity. The calculation of the loss on sale is presented below:
Total cash proceeds for TBNG
Less: TBNG net assets
Gain on sale before accumulated foreign currency translation adjustment
Less: TBNG accumulated foreign currency translation adjustment
Net loss on sale of TBNG
Loss on Sale
(in thousands)
20,707
12,869
7,838
(23,064)
(15,226)
$
$
Discontinued operations in Albania
As of December 31, 2015, we classified our Albania segment as assets and liabilities held for sale and presented the operating results
within discontinued operations for all periods presented.
In February 2016, we sold all of the outstanding equity in our wholly-owned subsidiary, Stream Oil & Gas Ltd. (“Stream”), to GBC
Oil Company.
On September 1, 2016, we completed a joint venture transaction with respect to the assets in the Delvina gas field in Albania (the
“Delvina Assets”). We transferred (the “Transfer”) 75% of the outstanding shares of Delvina Gas Company Ltd. (“DelvinaCo”),
which owned the Delvina Assets, to Ionian Gas Company Ltd. (“Ionian”) in exchange for Ionian’s agreement to pay $12.0 million to
DelvinaCo, which was to be used primarily to repay debt and for general corporate purposes with respect to the Delvina Assets. After
the Transfer, we retained a 25% equity interest in DelvinaCo and agreed to pay 25% of the operating costs of DelvinaCo, subject to a
three-year deferral of capital expenditures.
On August 9, 2017, due to continued failures by our joint venture partners to timely meet their obligations, uncompleted local
governmental ratifications, and our prioritization of funds, we transferred our 25% equity interest in DelvinaCo to Delvina Investment
Partners Ltd. in exchange for a release of all claims with respect to DelvinaCo and a cash payment of $300,000 for amounts owed to
us under agreements entered into in connection with the DelvinaCo joint venture transaction. Additionally, we terminated all of our
responsibilities as operator and our obligations to pay any operating costs or any other expenditures with respect to DelvinaCo. This
divestiture completed our departure from all Albanian operations and assets.
18. Subsequent events
2019 Term Loan
On February 22, 2019, TEMI entered into a $20.0 million term loan (the “2019 Term Loan”) with DenizBank under the Credit
Agreement.
F-33
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 ten-month grace period during which the 2019 Term Loan bears interest but no
payments are due other than a single interest only payment of $0.76 million in August 2019. After the ten-month grace period, the
2019 Term Loan is payable in fourteen monthly principal installments of $1.43 million plus interest. The 2019 Term Loan matures in
February 2021. Amounts repaid under the 2019 Term Loan may not be re-borrowed, and early repayments under the 2019 Term Loan
are subject to early repayment fees.
The 2019 Term Loan is guaranteed by Petrogas, Amity, Talon Exploration, DMLP, and 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, (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 has assigned its Turkish collection accounts and its receivables from the sale
of oil to the Lender as additional security for the 2019 Term Loan. Gundem is beneficially owned by Mr. Mitchell, his adult children,
and Mr. Uras. Mr. Mitchell is our Chief Executive Officer and Chairman of the Board. Mr. Uras is our Vice President, Turkey.
Note Amendment
On February 28, 2019, we and Dalea entered into the Note Amendment to the Amended 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).
PSI MSA Amendment
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 year each, unless terminated by PSI or TEMI by written notice at least 60 days prior to the end of the primary term or any
successive renewal term.
F-34
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, 2018 and 2017.
For the year ended December 31, 2018:
Revenues
Net loss
Comprehensive (loss) income
Basic and diluted net loss per common share
For the year ended December 31, 2017:
Revenues
Net (loss) income
Comprehensive income (loss)
Basic and diluted net (loss) income per common share
March 31,
Three Months Ended (1)
June 30,
September 30,
December 31,
(in thousands, except per share data)
$
$
$
$
16,926 $
(1,775)
(4,118)
(0.04) $
18,198 $
(1,006)
(10,115)
(0.02) $
20,140 $
(1,720)
(13,485)
(0.03) $
15,525
(715)
5,247
(0.01)
16,436 $
(16,049)
4,870
(0.34) $
12,341 $
566
2,698
0.01 $
12,675 $
(4,353)
(5,576)
(0.09) $
15,187
(4,039)
(10,317)
(0.08)
(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-35
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 2018 and 2017. The oil and natural gas prices
used to estimate reserves are shown in the table below.
Turkey
2018
2017
12-Month
Average Price
Oil
per (Bbl)
Natural Gas
per (Mcf)
$
$
64.91 $
47.57 $
4.82
3.98
The following table sets forth our estimated net proved reserves, including changes therein, and proved developed reserves:
Disclosure of reserves quantities
Total proved reserves
December 31, 2016
Revisions of previous estimates
Sale of reserves
Sales volumes
December 31, 2017
Revisions of previous estimates
Extensions and discoveries
Sales volumes
December 31, 2018
Proved developed reserves
December 31, 2017:
Proved developed producing
Proved developed non-producing
Total
December 31, 2018:
Proved developed producing
Proved developed non-producing
Total
Proved undeveloped reserves
As of December 31, 2017
As of December 31, 2018
Turkey
Albania(1)
TBNG(2)
Total
Oil (Mbbls)
12,730
3,156
-
(1,103)
14,783
(5,872)
2,085
(1,020)
9,976
3,998
217
4,215
4,575
472
5,047
10,568
4,929
52
(52)
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
3
-
(2)
(1)
-
-
-
-
-
-
-
-
-
-
-
12,785
3,104
(2)
(1,104)
14,783
(5,872)
2,085
(1,020)
9,976
3,998
217
4,215
4,575
472
5,047
-
-
10,568
4,929
F-36
Total proved reserves
December 31, 2016
Revisions of previous estimates
Sale of reserves
Sales volumes
December 31, 2017
Revisions of previous estimates
Sales volumes
December 31, 2018
Proved developed reserves
December 31, 2017:
Proved developed producing
Proved developed non-producing
Total
December 31, 2018:
Proved developed producing
Proved developed non-producing
Total
Proved undeveloped reserves
As of December 31, 2017
As of December 31, 2018
Turkey
Albania(1)
TBNG(2)
Total
Gas (Mmcf)
5,212
(742)
-
(312)
4,158
(1,506)
(212)
2,440
1,411
(1,411)
-
-
-
-
-
-
9,037
-
(8,973)
(64)
-
-
-
-
15,660
(2,153)
(8,973)
(376)
4,158
(1,506)
(212)
2,440
1,671
1,206
2,877
424
1,833
2,257
1,281
184
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
-
1,671
1,206
2,877
424
1,833
2,257
1,281
184
(1) We classified our Albanian segment as assets and liabilities held for sale and presented the operating results within
discontinued operations for all periods presented before 2018.
(2) Consists of amounts related to our TBNG assets that were sold in February 2017.
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, 2018, our estimated proved reserves, were 10,383 Mboe, a decrease of 5,093 Mboe, or 33%, compared to 15,476
Mboe at December 31, 2017. This decrease was primarily attributable to revisions of previously estimated recoveries from planned
wells in the Selmo field following revisions to our drilling plans in light of the expiration of our Selmo production lease in 2025,
which resulted in a decrease of 3,680 Mboe, and from planned wells in the Bahar field following the establishment of the oil/water
contact for the Bahar field, which resulted in a decrease of 2,618 Mboe. Additionally, proved reserves decreased 1,055 Mboe for
volumes sold. This decrease was partially offset by a 2,045 Mboe increase in proved reserves due to the discovery of productive pay in
the Yeniev oil field.
Proved Undeveloped Reserves
At December 31, 2018, our estimated proved undeveloped reserves were 4,960 Mboe, a decrease of 5,821 Mboe, or 54%, compared to
10,781 Mboe at December 31, 2017. The decrease in proved undeveloped reserves was primarily attributable to revisions of
previously estimated recoveries from planned wells in the Selmo field following revisions to our drilling plans in light of the
expiration of our Selmo production lease in 2025, which resulted in a decrease of 3,680 Mboe, and from planned wells in the Bahar
field following the establishment of the oil/water contact for the Bahar field, which resulted in a decrease of 2,618 Mboe. This
decrease was partially offset by a 1,373 Mboe increase in proved undeveloped reserves due to the discovery of productive pay in the
Yeniev oil fields. All of our proved undeveloped reserves as of December 31, 2018 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 $56.0 million.
F-37
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.
Standardized measure of discounted future net cash flows
The Standardized Measure relating to estimated proved reserves as of December 31, 2018 and 2017 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.
As of and for the year ended December 31, 2018
Future cash inflows
Future production costs
Future development costs
Future income tax expense
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
related to proved reserves
As of and for the year ended December 31, 2017
Future cash inflows
Future production costs
Future development costs
Future income tax expense
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
related to proved reserves
$
$
$
Total
(in thousands)
659,435
(122,767)
(56,893)
(77,533)
402,242
(136,085)
266,157
720,106
(144,871)
(163,315)
(54,409)
357,511
(130,378)
$
227,133
F-38
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, 2018 and 2017.
Turkey
Albania
TBNG (1)
Total
(in thousands)
For the year ended December 31, 2018
Standardized measure, January 1,
Net change in sales and transfer prices and in production (lifting)
costs related to future production
Changes in future estimated development costs
Sales and transfers of oil and natural gas during the period
Net change due to extensions and discoveries
Net change due to revisions in quantity estimates
Previously estimated development costs incurred during the period
Accretion of discount
Other
Net change in income taxes
Standardized measure, December 31,
For the year ended December 31, 2017
Standardized measure, January 1,
Net change in sales and transfer prices and in production (lifting)
costs related to future production
Changes in future estimated development costs
Sales and transfers of oil and natural gas during the period
Net change due to sales of reserves
Net change due to revisions in quantity estimates
Previously estimated development costs incurred during the period
Accretion of discount
Other
Net change in income taxes
Standardized measure, December 31,
$ 227,133 $
139,915
55,559
(58,797)
72,036
(211,509)
23,285
27,955
6,033
(15,453)
$ 266,157 $
$ 126,538 $
83,470
(976)
(42,830)
-
85,752
4,220
10,999
(8,077)
(31,963)
$ 227,133 $
- $
-
-
-
-
-
-
-
-
- $
- $ 227,133
- 139,915
55,559
-
(58,797)
72,036
- (211,509)
23,285
-
27,955
-
6,033
-
-
(15,453)
- $ 266,157
738 $
17,658 $ 144,934
-
-
-
-
-
-
-
(738)
-
- $
83,470
-
(976)
-
(43,310)
(480)
(17,178)
(17,178)
85,752
-
4,220
-
10,999
-
(8,815)
-
(31,963)
-
- $ 227,133
(1) Consists of amounts related to our TBNG assets that were sold in February 2017.
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,
2018 and 2017 are summarized as follows:
For the year ended December 31, 2018
Exploration
Development
Total costs incurred
For the year ended December 31, 2017
Exploration
Development
Total costs incurred
Total
(in thousands)
$
$
$
$
12,079
11,516
23,595
11,568
4,220
15,788
F-39
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