tat-10k_20191231.htm

 

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

(Mark One)

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

For the fiscal year ended December 31, 2019

OR

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

For the transition period from                      to                      

Commission file number 001-34574

 

TRANSATLANTIC PETROLEUM LTD.

(Exact name of registrant as specified in its charter)

 

 

Bermuda

 

None

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

 

 

 

16803 Dallas Parkway

Addison, Texas

 

75001

(Address of principal executive offices)

 

(Zip Code)

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

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

 

Title of each class 

 

Ticker Symbol 

 

Name of each exchange on which registered 

Common shares, par value $0.10

 

TAT

 

NYSE American

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

None

 

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

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

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

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

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

 

Large accelerated filer

Accelerated filer

Non-accelerated filer

☐  

Smaller reporting company

Emerging growth company

 

 

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

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

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

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

 

DOCUMENTS INCORPORATED BY REFERENCE

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

 

 

 

 

 


 

TRANSATLANTIC PETROLEUM LTD.

FORM 10-K

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2019

INDEX

 

 

 

Page

PART I

 

 

Item 1.

Business

1

Item 1A.

Risk Factors

10

Item 1B.

Unresolved Staff Comments

21

Item 2.

Properties

22

Item 3.

Legal Proceedings

34

Item 4.

Mine Safety Disclosures

36

 

 

 

PART II

 

 

Item 5.

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

37

Item 6.

Selected Financial Data

37

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

38

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk.

48

Item 8.

Financial Statements and Supplementary Data

48

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

48

Item 9A.

Controls and Procedures

48

Item 9B.

Other Information

49

 

 

 

PART III

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

50

Item 11.

Executive Compensation

50

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

50

Item 13.

Certain Relationships and Related Transactions, and Director Independence

50

Item 14.

Principal Accountant Fees and Services

50

 

 

 

PART IV

 

 

Item 15.

Exhibits and Financial Statement Schedules

51

 

 

  

 


 

Forward-Looking Statements

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

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

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

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

Glossary of Selected Oil and Natural Gas Terms

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

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

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

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

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

Bbl/d. Barrels of oil per day.

i


 

Bcf. One billion cubic feet of natural gas.

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

Boepd. Barrels of oil equivalent per day.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Mbbl. One thousand stock tank barrels.

Mboe. One thousand barrels of oil equivalent.

Mboepd. One thousand barrels of oil equivalent per day.

ii


 

Mcf. One thousand cubic feet of natural gas.

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

Mmbbl. One million stock tank barrels.

Mmboe. One million barrels of oil equivalent.

Mmcf. One million cubic feet of natural gas.

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

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

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

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

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

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

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

Proved reserves. Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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

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

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

iii


 

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

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

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

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

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

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

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

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

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

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

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

Tcf. One trillion cubic feet of natural gas.

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

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

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

 

 

 

iv


 

PART I

 

 

Item 1. Business

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

Our Business

We are an international oil and natural gas company engaged in acquisition, exploration, development, and production. We have focused our operations in countries that have established, yet underexplored, petroleum systems, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of December 31, 2019, we held interests in 365,171 and 162,800 net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria, respectively. As of March 20, 2020, N. Malone Mitchell 3rd beneficially owned approximately 49.9% of our outstanding common shares. Persons and entities associated with Mr. Mitchell also owned 739,000 of our 12.0% Series A Convertible Redeemable Preferred Shares (“Series A Preferred Shares”). Mr. Mitchell’s affiliates are currently prohibited from converting any of their Series A Preferred Shares to common shares if such conversion would cause Mr. Mitchell or his affiliates to obtain beneficial ownership in excess of 49.9% of the outstanding common shares; however, Mr. Mitchell, upon 61 days’ prior notice, may increase or decrease such percentage cap.

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

Internal Restructuring

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

Recent Oil Price Decline and Going Concern

We incurred a net loss of $5.4 million for the year ended December 31, 2019.  As of December 31, 2019, we had $2.9 million in long-term debt, $17.1 million in short-term debt, $9.7 million in cash and a $2.0 million working capital surplus.  

 

In March 2020, crude oil prices declined to approximately $25 per barrel for Brent crude as a result of market concerns about the economic impact from the coronavirus (COVID-19) as well as the ability of OPEC and Russia to agree on a perceived need to implement further production cuts in response to weaker worldwide demand. The current futures forward curve for Brent crude indicates that prices may continue at or near current prices for an extended time. As a result, we have reduced our planned capital expenditures to those necessary for production lease maintenance and those projecting a return on invested capital at current prices. In order to mitigate the impact of reduced prices on our 2020 cash flows and liquidity, we plan to implement cost reduction measures to reduce our operating costs and general and administrative expenses. In connection therewith, we intend to prioritize funding operating expenditures over general and administrative expenditures, whenever possible.

Notwithstanding these measures, there remain risks and uncertainties regarding our ability to generate sufficient revenues at current oil prices to pay our debt obligations and accounts payable when due. As a result, there is substantial doubt about our ability to continue as a going concern.  

Management believes the going concern assumption to be appropriate for these consolidated financial statements.  If the going concern assumption was not appropriate, adjustments would be necessary to the carrying values of assets and liabilities, reported revenues and expenses and in the balance sheet classifications used in these consolidated financial statements

1


 

Recent Developments

On February 24, 2020, we sold the shares in our wholly-owned subsidiary Petrogas Petrol Gaz ve Petrokemya Urunleri Insaat Sanayive Ticaret A.S. (“Petrogas”), which held the Edirne, Dogu Adatepe, Adatepe, and Gocerler production leases (the “Petrogas Leases”) and 14 employees, to Reform Ham Petrol Dogal Gaz Arama Uretim Sanayi ve Ticaret A.S. (“Reform”) in exchange for $1.5 million and a release of all plugging and abandonment obligations for 65 wells on the Petrogas Leases and certain former leases. During 2019, average production for the Petrogas Leases was approximately 500 Mcf/d or 83 Boepd.

On March 9, 2020, we unwound our three-way collar contract with DenizBank, A.S. (“Denizbank”), which hedged approximately 1,000 Bbl/d of our oil production in Turkey. The three-way collar contract had a Brent floor of $55.00, a Brent ceiling of $72.90, and a Brent long call of $80.00, and was in place through April 30, 2020. We also unwound our swap contract with Denizbank, which hedged approximately 1,000 Bbl/d of our oil production in Turkey. The swap contract had a Brent strike price of $60.30 and was in place through December 31, 2020. In connection with these transactions, we received approximately $6.5 million. We used these proceeds to pay down the 2019 Term Loan (as defined below), which left approximately $10.6 million outstanding under the 2019 Term Loan. Following these transactions, we do not have any commodity derivative contracts that hedge our oil price risk.

Our Properties and Operations

Summary of Geographic Areas of Operations

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

 

 

 

 

 

 

Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved Developed

 

 

Undeveloped

 

 

Total Proved

 

 

Probable Reserves

 

 

Possible Reserves

 

 

Reserves (Mboe)

 

 

Reserves (Mboe)

 

 

Reserves (Mboe)

 

 

(Mboe)

 

 

(Mboe)

 

Turkey

 

6,004

 

 

 

4,666

 

 

 

10,670

 

 

 

7,353

 

 

 

6,906

 

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

Turkey

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

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

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

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

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

2


 

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

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

Bulgaria

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

Current Operations

Southeastern Turkey

Molla

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

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

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

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

Selmo

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

Bulgaria

We are currently evaluating future activity in Bulgaria.

Planned Operations

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

Customers

 

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

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

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

Competition

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

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

Fracture Stimulation Program

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

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

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

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

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

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

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

Governmental Regulations

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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

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

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

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

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

Insurance

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

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

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

Bermuda Tax Exemption

As a Bermuda exempted company and under current Bermuda law, we are not subject to tax on profits, income or dividends, nor is there any capital gains tax applicable to us in Bermuda. Profits can be accumulated, and it is not obligatory for us to pay dividends.

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

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

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

Employees

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

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Formation

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

Available Information

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

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

 


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Information about our Executive Officers

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

 

Name 

 

Age

 

Positions 

N. Malone Mitchell 3rd

 

58

 

Chairman and Chief Executive Officer

Todd C. Dutton

 

66

 

President

Selami E. Uras

 

62

 

Executive Vice President, Turkey

G. Fabian Anda

 

48

 

Vice President, Finance

Tabitha T. Bailey

 

34

 

Vice President, General Counsel and Corporate Secretary

Michael P. Hill

 

38

 

Chief Accounting Officer

David G. Mitchell

 

39

 

Vice President of Engineering

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

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

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

 

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

 

Tabitha T. 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 from the University of Mississippi and a J.D. from Vanderbilt University Law School.

 

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

 

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

 

 

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Item 1A. Risk Factors

Risks Related to Our Business

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

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

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

We incurred a net loss of $5.4 million for the fiscal year ended December 31, 2019. We continue to experience decreased liquidity as a result of the decline in oil commodity prices. In March 2020, crude oil prices declined to approximately $25 per barrel for Brent crude as a result of market concerns about the economic impact from the coronavirus (COVID-19) as well as the ability of OPEC and Russia to agree on a perceived need to implement further production cuts in response to weaker worldwide demand. The current futures forward curve for Brent crude indicates that prices may continue at or near current prices for an extended time. As a result, we have reduced our planned capital expenditures to those necessary for production lease maintenance and those projecting a return on invested capital at current prices. In order to mitigate the impact of reduced prices on our 2020 cash flows and liquidity, we plan to implement cost reduction measures to reduce our operating costs and general and administrative expenses. In connection therewith, we intend to prioritize funding operating expenditures over general and administrative expenditures, whenever possible. Notwithstanding these measures, there remain risks and uncertainties regarding our ability to generate sufficient revenues at current oil prices to pay our debt obligations and accounts payable when due. These risks and uncertainties raise substantial doubt about our ability to continue as a going concern. The consolidated financial statements included in this report do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts of liabilities that might result from the outcome of this uncertainty.

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

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

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laws and policies 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 sanctions and anti-bribery and anti-corruption laws;

 

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

 

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

 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

TUPRAS, an affiliate of Koç Holding, purchases substantially all of our oil production from Turkey, representing 97.7% of our total revenues in 2019. Under Turkish law, TUPRAS is obligated to purchase all of our oil production in Turkey, and we are prohibited from selling any of our oil produced in Turkey to any other customer. Pursuant to a purchase and sale agreement with TUPRAS, the price of oil delivered to TUPRAS is determined under the Petroleum Market Law No. 5015 (the “Pricing Amendment”) under the laws of the Republic of Turkey. In February 2019, Turkey amended Petroleum Market Law No. 5015 to change the statutory pricing formula for purchases of Turkish domestic crude oil. In November 2019, TUPRAS filed a lawsuit against us, and filed similar lawsuits against other domestic oil producers, in the Batman 4th Civil Court of First Instance seeking restitution from TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”) for alleged overpayments resulting from the implementation of the Pricing Amendment plus interest thereon. In addition, TUPRAS claimed that the Pricing Amendment violates the Constitution of the Republic of Turkey and seeks to have the Pricing Amendment cancelled. If TUPRAS reduces its oil purchases or fails to purchase our oil production, or there is a material non-payment, our results of operations could be materially and adversely affected. TUPRAS may be subject to its own operating risks that could increase the risk that it could default on its obligations to us. Changes to Turkish law or our commercial relationship with TUPRAS could adversely affect our business and results of operations.

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

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

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

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

 

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

 

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

 

limit our ability to borrow additional funds; and

 

limit our financial flexibility.

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

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

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

Risks Related to the Oil and Natural Gas Industry

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

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

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

 

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

 

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

 

overall global and domestic economic conditions;

 

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

 

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

 

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

 

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

 

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

 

technological advances affecting energy consumption and conservation;

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

 

the oil price war between Russia and Saudi Arabia;

 

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

 

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

 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 

unexpected drilling conditions;

 

pressure or irregularities in geological formations;

 

equipment failures or accidents;

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pipeline and processing interruptions or unavailability;

 

title problems;

 

adverse weather conditions;

 

lack of market demand for oil and natural gas;

 

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

 

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

 

declines in oil and natural gas prices; and

 

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

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

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

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

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

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

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

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We are subject to operating hazards.

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

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

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

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

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

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

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

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

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

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

 

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

 

abnormally pressured formations;

 

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

 

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

 

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

 

fires and explosions;

 

personal injuries and death;

 

regulatory investigations and penalties; and

 

natural disasters or other catastrophic events.

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

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

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

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

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

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

 

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

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

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

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

Risks Related to Our Common Shares

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

As of March 20, 2020, Mr. Mitchell beneficially owned approximately 49.9% of our outstanding common shares. Persons and entities associated with Mr. Mitchell also own Series A Preferred Shares. Dalea Partners, LP, an affiliate of Mr. Mitchell, owns 42,000 Series A Preferred Shares; trusts benefitting three of Mr. Mitchell’s children each own 41,000 Series A Preferred Shares; one of Mr. Mitchell’s children owns 41,000 Series A Preferred Shares, and Longfellow owns 533,000 Series A Preferred Shares. Mr. Mitchell’s affiliates are currently prohibited from converting any of their Series A Preferred Shares to common shares if such conversion would cause Mr. Mitchell or his affiliates to obtain beneficial ownership in excess of 49.9% of the outstanding common shares; however, Mr. Mitchell, upon 61 days’ prior notice, may increase or decrease such percentage cap. As a result, Mr. Mitchell could control substantially all matters requiring shareholder approval, including the election of directors and approval of significant corporate transactions. In addition, this concentration of ownership may delay or prevent a change in control of the Company and make some future transactions more difficult or impossible without the support of Mr. Mitchell. The interests of Mr. Mitchell may not coincide with your interests or the interests of our other shareholders.

 

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

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

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

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

 

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

 

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

 

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

 

the oil price war between Russia and Saudi Arabia;

 

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

 

fluctuation in foreign exchange or interest rates;

 

liabilities inherent in oil and natural gas operations;

 

geological, technical, drilling and processing problems;

 

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

 

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

 

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

 

stock market volatility and market valuations;

 

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

 

the need to obtain required approvals from regulatory authorities;

 

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

 

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

 

political conditions in oil and natural gas producing regions;

 

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

 

investor perception of the oil and natural gas industry;

 

limited trading volume of our common shares;

 

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

 

the sale of assets;

 

the issuance of common shares, debt or other securities;

 

our liquidity;

 

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

 

loss of key management.

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

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

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

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

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

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

 

Item 1B. Unresolved Staff Comments

Not applicable.

 

 

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Item 2. Properties

Turkey

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

 

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

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

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

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

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

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

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

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

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

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

23


 

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

 

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

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

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

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

24


 

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

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

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

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

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

25


 

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

 

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

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

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

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

26


 

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

 

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

 

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

27


 

Bulgaria

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

 

 

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

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

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

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

28


 

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

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

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

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

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

29


 

Summary of Oil and Natural Gas Reserves

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

 

 

Reserves

 

 

Oil and Condensate

(Mbbl)

 

 

Natural Gas

(Mmcf)

 

 

Total

(Mboe)

 

Reserves Category

 

 

 

 

 

 

 

 

 

 

 

Total (1)

 

 

 

 

 

 

 

 

 

 

 

Proved reserves

 

 

 

 

 

 

 

 

 

 

 

Proved developed

 

5,624

 

 

 

2,281

 

 

 

6,004

 

Proved undeveloped

 

4,635

 

 

 

185

 

 

 

4,666

 

Total proved

 

10,259

 

 

 

2,466

 

 

 

10,670

 

Probable reserves

 

 

 

 

 

 

 

 

 

 

 

Probable developed

 

920

 

 

 

815

 

 

 

1,056

 

Probable undeveloped

 

6,292

 

 

 

30

 

 

 

6,297

 

Total probable

 

7,212

 

 

 

845

 

 

 

7,353

 

Possible reserves

 

 

 

 

 

 

 

 

 

 

 

Possible developed

 

1,062

 

 

 

951

 

 

 

1,221

 

Possible undeveloped

 

5,680

 

 

 

33

 

 

 

5,686

 

Total possible

 

6,742

 

 

 

984

 

 

 

6,906

 

 

 

(1)

All of our reserves are located in Turkey

Value of Proved Reserves

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

 

 

Total

 

 

(in thousands)

 

Future net revenue

$

433,131

 

Total Standardized Measure (1)

$

234,468

 

Total PV-10 (2)

$

288,510

 

 

 

(1)

DeGolyer and MacNaughton did not estimate the Standardized Measure.  

 

(2)

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

 

 

Total

 

 

(in thousands)

 

Total PV-10

$

288,510

 

Future income taxes (1)

 

(76,762

)

Discount of future income taxes at 10% per annum (1)

 

22,720

 

Standardized Measure (1)

$

234,468

 

 

 

(1)

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

Proved Reserves

Estimates of proved developed and undeveloped reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes, and other factors. See “Oil and Natural Gas Reserves under U.S. Law.”

30


 

At December 31, 2019, our estimated proved reserves were 10,670 Mboe, an increase of 287 Mboe, or 2.8%, compared to 10,383 Mboe at December 31, 2018.  This increase was primarily attributable to the discovery of productive pay in the Beloka formation in the Yeniev field of 1,059 Mboe.  This was partially offset by 1,038 Mboe for volumes sold.

Proved Undeveloped Reserves

At December 31, 2019, our estimated proved undeveloped reserves were 4,666 Mboe, a decrease of 294 Mboe, or 5.9%, compared to 4,960 Mboe at December 31, 2018. The decrease in proved undeveloped reserves was primarily attributable to revisions of previously estimated recoveries in the Yeniev, Bahar and Selmo oil fields.  This decrease was partially offset by a 1,059 Mboe increase in proved undeveloped reserves due to the discovery of productive pay in the Beloka formation in the Yeniev oil field.  All of our proved undeveloped reserves as of December 31, 2019 will be developed within five years of the date the reserve was first disclosed as a proved undeveloped reserve. The estimated undiscounted capital costs associated with our proved undeveloped reserves in Turkey is $54.9 million.

The proved undeveloped reserves assume development costs will be funded from future cash flows from operations and financing activities, which may not be sufficient or available at commercially economic terms and could impact the timing of these development activities.  

Probable Reserves

Estimates of probable reserves are inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of probable reserves is an estimate of those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors. See “—Oil and Natural Gas Reserves under U.S. Law.”

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

Possible Reserves

Estimates of possible reserves are also inherently imprecise. When producing an estimate of the amount of oil and natural gas that is recoverable from a particular reservoir, an estimated quantity of possible reserves is an estimate that might be achieved, but only under more favorable circumstances than are likely. Estimates of possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors. See “—Oil and Natural Gas Reserves under U.S. Law.”

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

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

31


 

Internal Controls

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

Oil and Natural Gas Reserves under U.S. Law

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

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

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

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

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

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Oil and Natural Gas Reserves under Canadian Law

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

Oil and Natural Gas Sales Volumes

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

 

 

Sales Volumes

 

 

Oil (1)

 

 

Natural Gas

 

 

Total

 

Year

(Bbls)

 

 

(Mcf)

 

 

(Boe)

 

2019

 

 

 

 

 

 

 

 

 

 

 

Total Turkey

 

1,004,980

 

 

 

197,753

 

 

 

1,037,939

 

Selmo field

 

485,760

 

 

 

 

 

 

485,760

 

Bahar field

 

303,534

 

 

 

 

 

 

303,534

 

Yeniev field

 

151,870

 

 

 

 

 

 

151,870

 

2018

 

 

 

 

 

 

 

 

 

 

 

Total Turkey

 

1,020,144

 

 

 

211,686

 

 

 

1,055,425

 

Selmo field

 

570,189

 

 

 

 

 

 

570,189

 

Bahar field

 

322,129

 

 

 

 

 

 

322,129

 

 

 

(1)

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

Average Sales Price and Production Costs

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

 

 

2019

 

 

2018

 

Turkey:

 

 

 

 

 

 

 

Average Sales Price Oil ($/Bbl)

$

65.34

 

 

$

67.84

 

Natural Gas ($/Mcf)

$

5.88

 

 

$

5.01

 

Unit Costs Production ($/Boe)

$

9.85

 

 

$

8.93

 

Drilling Activity

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

 

 

Development Wells

 

 

Exploratory Wells

 

 

Productive

 

 

Dry

 

 

Productive

 

 

Dry

 

Turkey:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2019

 

3.0

 

 

 

 

 

 

3.0

 

 

 

 

2018

 

3.0

 

 

 

 

 

 

2.0

 

 

 

 

Bulgaria:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2019

 

 

 

 

 

 

 

 

 

 

1.0

 

2018

 

 

 

 

 

 

 

 

 

 

 

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Oil and Natural Gas Properties, Wells, Operations and Acreage

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

 

 

Oil

 

 

Natural Gas

 

 

Gross (1)

 

 

Net (2)

 

 

Gross (1)

 

 

Net (2)

 

Turkey

 

75.0

 

 

 

73.0

 

 

 

33.0

 

 

 

23.5

 

Bulgaria

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

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

 

(2)

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

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

 

 

Developed Acres

 

 

Gross (1)

 

 

Net (2)

 

Turkey

 

287,601

 

 

 

216,384

 

Bulgaria

 

 

 

 

 

       Total

 

287,601

 

 

 

216,384

 

 

 

(1)

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

 

(2)

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

 

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

 

 

Undeveloped Acres

 

 

Gross (1)

 

 

Net (2)

 

Turkey

 

148,787

 

 

 

148,787

 

Bulgaria

 

162,800

 

 

 

162,800

 

Total

 

311,587

 

 

 

311,587

 

 

 

(1)

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

 

(2)

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

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

 

 

Undeveloped Acres

 

 

% of Total Undeveloped Acres

 

 

Gross (1)

 

 

Net (2)

 

 

Net (2)

 

2020

 

119,865

 

 

 

119,865

 

 

 

38.5

 

2021

 

-

 

 

 

-

 

 

 

 

2022

 

-

 

 

 

-

 

 

 

 

2023

 

28,922

 

 

 

28,922

 

 

 

9.3

 

2024

 

-

 

 

 

-

 

 

 

 

 

 

(1)

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

 

(2)

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

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

 

 

Item 3. Legal Proceedings

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

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

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

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

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

 

Bulgarian Minister of Energy. In October 2015, the Bulgarian Minister of Energy filed a suit in the Sofia City Court against Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”), claiming $200,000 in liquidated damages for Direct Bulgaria’s alleged failure to fulfill its obligations under the Aglen exploration permit work program. In May 2018, the Sofia City Court concluded that Direct Bulgaria did not fail to fulfill its obligations under the Aglen exploration permit work program as Direct Bulgaria received a force majeure event recognition as a result of a fracture stimulation ban in 2012, imposed by the Bulgarian Parliament, which force majeure event had not been terminated before the expiry of Direct Bulgaria’s obligations under the Aglen exploration permit work program. Additionally, the Sofia City Court concluded that, even if Direct Bulgaria had failed to fulfill its obligations under the Aglen exploration permit work program, the Bulgarian Minister of Energy failed to file suit within the three-year limitation period. Therefore, the Sofia City Court dismissed all claims of the Bulgarian Minister of Energy and ordered the Bulgarian Minister of Energy to pay Direct Bulgaria’s attorney’s fees and legal costs for court experts. In June 2018, the Bulgarian Minister of Energy filed an appeal in the Sofia Court of Appeal. In November 2018, the Sofia Court of Appeal concluded that the judgement of the Sofia City Court was correct and, therefore, dismissed the Bulgarian Minister of Energy’s appeal. In January 2019, the Bulgarian Minister of Energy filed an appeal in the Supreme Court of Cassation. The Supreme Court of Cassation held a court hearing on October 21, 2019. Pursuant to a notice on the website of the Supreme Court of Cassation, a ruling was issued on March 10, 2020, by virtue of which the court rejected to admit the appeal of the Minster of Energy. Such ruling should be final; however, it has not been published as of the date hereof, and therefore, we cannot conclusively confirm the ruling.

 

TUPRAS Litigation. During 2019, we sold $65.8 million of oil to TUPRAS, representing 97.7% of our total revenues. We sell all of our Southeastern Turkey oil to TUPRAS pursuant to a domestic crude oil purchase and sale agreement between TUPRAS and TEMI. The price of the oil delivered pursuant to the purchase and sale agreement is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. In February 2019, Turkey entered into the Pricing Amendment to change the statutory pricing formula for purchases of Turkish domestic crude oil.

In November 2019, TUPRAS filed a lawsuit against us, and filed similar lawsuits against other domestic oil producers, in the Batman 4th Civil Court of First Instance seeking restitution from TEMI for alleged overpayments resulting from the implementation of

35


 

the Pricing Amendment plus interest thereon. In addition, TUPRAS claimed that the Pricing Amendment violates the Constitution of the Republic of Turkey and seeks to have the Pricing Amendment cancelled. TEMI is vigorously defending against these allegations.

Item 4. Mine Safety Disclosures

Not applicable.

 

36


 

PART II

 

 

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

 

Common Shares and Dividends

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

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

 

Foreign Exchange Control Regulations

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

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

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

Item 6. Selected Financial Data

Not applicable.

 

 

37


 

Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations

We are an international oil and natural gas company engaged in acquisition, exploration, development and production. We have focused our operations in countries that have established, yet underexplored, petroleum systems, are net importers of petroleum, have an existing petroleum transportation infrastructure and provide favorable commodity pricing, royalty rates and tax rates to exploration and production companies. As of December 31, 2019, we held interests in 365,171 and 162,800 net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria, respectively. As of March 20, 2020, Mr. Mitchell beneficially owned approximately 49.9% of our outstanding common shares. Persons and entities associated with Mr. Mitchell also owned 739,000 of our Series A Preferred Shares. Mr. Mitchell’s affiliates are currently prohibited from converting any of their Series A Preferred Shares to common shares if such conversion would cause Mr. Mitchell or his affiliates to obtain beneficial ownership in excess of 49.9% of the outstanding common shares; however, Mr. Mitchell, upon 61 days’ prior notice, may increase or decrease such percentage cap.  

 

Recent Oil Price Decline and Going Concern

We incurred a net loss of $5.4 million for the year ended December 31, 2019.  As of December 31, 2019, we had $2.9 million in long-term debt, $17.1 million in short-term debt, $9.7 million in cash and a $2.0 million working capital surplus.  

 

In March 2020, crude oil prices declined to approximately $25 per barrel for Brent crude as a result of market concerns about the economic impact from the coronavirus (COVID-19) as well as the ability of OPEC and Russia to agree on a perceived need to implement further production cuts in response to weaker worldwide demand. The current futures forward curve for Brent crude indicates that prices may continue at or near current prices for an extended time. As a result, we have reduced our planned capital expenditures to those necessary for production lease maintenance and those projecting a return on invested capital at current prices. In order to mitigate the impact of reduced prices on our 2020 cash flows and liquidity, we plan to implement cost reduction measures to reduce our operating costs and general and administrative expenses. In connection therewith, we intend to prioritize funding operating expenditures over general and administrative expenditures, whenever possible.

Notwithstanding these measures, there remain risks and uncertainties regarding our ability to generate sufficient revenues at current oil prices to pay our debt obligations and accounts payable when due.   As a result, there is substantial doubt about our ability to continue as a going concern.  

Management believes the going concern assumption to be appropriate for these consolidated financial statements.  If the going concern assumption was not appropriate, adjustments would be necessary to the carrying values of assets and liabilities, reported revenues and expenses and in the balance sheet classifications used in these consolidated financial statements

2019 Financial and Operational Performance

 

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

 

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

 

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

 

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

 

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

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2019 Operations

Southeastern Turkey

Molla

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

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

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

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

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

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

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

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

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

Selmo

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

Northwestern Turkey

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

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

Bulgaria

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

39


 

Current Operations

Southeastern Turkey

Molla

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

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

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

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

Selmo

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

Bulgaria

We are currently evaluating future activity in Bulgaria.

Planned Operations

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

Critical Accounting Policies

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

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

Oil and Natural Gas Properties. In accordance with the successful efforts method of accounting for oil and natural gas properties, costs of productive wells, developmental dry holes and productive leases are capitalized into appropriate groups of properties based on geographical and geological similarities. Acquisition costs of proved properties are amortized using the unit-of-production method based on total proved reserves, and exploration well costs and additional development costs are amortized using the unit-of-production method based on proved developed reserves. Proceeds from the sale of properties are credited to property costs, and a gain or loss is recognized when a significant portion of an amortization base is sold or abandoned. Exploration costs, such as exploratory geological

40


 

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 wells ability to produce generally must be made within one year from the completion of drilling activities. The acquisition costs of unproved acreage are initially capitalized and are carried at cost, net of accumulated impairment provisions, until such leases are transferred to proved properties or charged to exploration expense as impairments of unproved properties.

Impairment of Long-Lived Assets. We follow the provisions of Accounting Standards Codification (“ASC”) 360, Property, Plant and Equipment (“ASC 360”). ASC 360 requires that our long-lived assets be assessed for potential impairment of their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. Proved oil and natural gas properties are evaluated by field for potential impairment. An impairment on proved properties is recognized when the estimated undiscounted future net cash flows of a field are less than its carrying value. If an impairment occurs, the carrying value of the impaired field is reduced to its estimated fair value, which is generally estimated using a discounted cash flow approach.

Unproved oil and natural gas properties do not have producing properties and are valued on acquisition by management, with the assistance of an independent expert when necessary. As reserves are proved through the successful completion of exploratory wells, the cost is transferred to proved properties. The cost of the remaining unproved basis is periodically evaluated by management to assess whether the value of a property has diminished. To do this assessment, management considers (i) estimated potential reserves and future net revenues from an independent expert, (ii) our history in exploring the area, (iii) our future drilling plans per our capital drilling program prepared by our reservoir engineers and operations management, and (iv) other factors associated with the area. Impairment is taken on the unproved property value if it is determined that the costs are not likely to be recoverable. The valuation is subjective and requires management to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual results.

Business Combinations. We follow ASC 805, Business Combinations (“ASC 805”) and ASC 810-10-65, Consolidation. ASC 805 requires most identifiable assets, liabilities, non-controlling interests, and goodwill acquired in a business combination to be recorded at “fair value.” The statement applies to all business combinations, including combinations among mutual entities and combinations by contract alone. Under ASC 805, all business combinations will be accounted for by applying the acquisition method.

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

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

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

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

Income Taxes. We follow the asset and liability method prescribed by ASC 740, Income Taxes (“ASC 740”). Under this method of accounting for income taxes, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those

41


 

temporary differences are expected to be recovered or settled. Under ASC 740, the effect on deferred tax assets and liabilities of a change in enacted tax rates is recognized in earnings in the period that includes the enactment date.

Other Recent Accounting Pronouncements and Reporting Rules.

 

     In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which establishes a new lease accounting model for leases. The most significant changes include the clarification of the definition of a lease, the requirement for lessees to recognize for all leases a right-of-use asset and a lease liability in the consolidated balance sheet, and additional quantitative and qualitative disclosures which are designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. Expenses are recognized in the consolidated statement of income in a manner similar to current accounting guidance. Lessor accounting under the new standard is substantially unchanged. The new standard became effective for us beginning with the first quarter of 2019. We adopted the accounting standard using a prospective transition approach, which applied the provisions of the new guidance at the effective date without adjusting the comparative periods presented. We elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed us to carry forward the historical accounting relating to lease identification and classification for existing leases upon adoption. We also made an accounting policy election to keep leases with an initial term of 12 months or less off of the consolidated balance sheet. On January 1, 2019 we recognized $2.7 million of additional right-of-use assets and liabilities on our consolidated balance sheets.

 

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

 

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

     In June 2018, the FASB issued ASU 2018-07, Stock Compensation - Improvements to Nonemployee Share-Based Payment Accounting.  This update applied the existing employee guidance to nonemployee share-based transactions, with the exception of specific guidance related to the attribution of compensation cost. This update became effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within that fiscal year. We adopted this standard effective January 1, 2019. The adoption of this update had no impact on our consolidated financial statements and results of operations.

     In November 2018, the FASB issued ASU 2018-19, Codification Improvements to Topic 326, Financial Instruments-Credit Losses. This update clarifies that receivables arising from operating leases are not in scope of this topic, but rather Topic 842, Leases. This update will be effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years. This update will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. We do not believe the adoption of this standard will have an impact on its consolidated financial statements.

     In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes. This update removes certain exceptions to the general principles in Topic 740 and provides clarifications related to certain franchise taxes, transactions with a government that result in a step-up in the tax basis of goodwill, allocation of current and deferred income tax expense and the annual effective tax rate.  This update is effective January 1, 2021.  We are currently assessing the potential impact of this update on our consolidated financial statements and results of operations.

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

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

 

 

Year Ended December 31,

 

 

Change

 

 

2019

 

 

2018

 

 

2019-2018

 

 

(in thousands of U.S. Dollars, except per

unit amounts and production volumes)

 

Sales volumes:

 

 

 

 

 

 

 

 

 

 

 

Oil (Mbbl)

 

1,005

 

 

 

1,020

 

 

 

(15

)

Natural gas (Mmcf)

 

198

 

 

 

212

 

 

 

(14

)

Total production (Mboe)

 

1,038

 

 

 

1,055

 

 

 

(17

)

Average daily sales volumes (Boepd)

 

2,844

 

 

 

2,892

 

 

 

(48

)

Average prices:

 

 

 

 

 

 

 

 

 

 

 

Oil (per Bbl)

$

65.34

 

 

$

67.84

 

 

$

(2.50

)

Natural gas (per Mcf)

$

5.88

 

 

$

5.01

 

 

$

0.87

 

Oil equivalent (per Boe)

$

64.39

 

 

$

66.58

 

 

$

(2.19

)

Revenues:

 

 

 

 

 

 

 

 

 

 

 

Oil and natural gas sales

$

66,829

 

 

$

70,268

 

 

$

(3,439

)

Other

 

551

 

 

 

521

 

 

 

30

 

Total revenues

 

67,380

 

 

 

70,789

 

 

 

(3,409

)

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

Production

 

11,674

 

 

 

10,769

 

 

 

905

 

Transportation costs

 

5,101

 

 

 

4,665

 

 

 

436

 

Exploration, abandonment and impairment

 

6,267

 

 

 

401

 

 

 

5,866

 

Seismic and other exploration

 

330

 

 

 

489

 

 

 

(159

)

General and administrative

 

11,785

 

 

 

14,719

 

 

 

(2,934

)

Depletion

 

12,702

 

 

 

13,387

 

 

 

(685

)

Depreciation and amortization

 

525

 

 

 

672

 

 

 

(147

)

Interest and other expense

 

10,667

 

 

 

10,048

 

 

 

619

 

Foreign exchange loss

 

4,569

 

 

 

10,292

 

 

 

(5,723

)

Deferred income tax expense

 

5,775

 

 

 

6,854

 

 

 

(1,079

)

(Loss) gain on commodity derivative contracts:

 

 

 

 

 

 

 

 

 

 

 

Cash settlements on derivative contracts

 

-

 

 

 

(4,012

)

 

 

4,012

 

Change in fair value on derivative contracts

 

(966

)

 

 

2,215

 

 

 

(3,181

)

Total loss on derivative contracts

 

(966

)

 

 

(1,797

)

 

 

831

 

Oil and natural gas costs per Boe:

 

 

 

 

 

 

 

 

 

 

 

Production

$

9.85

 

 

$

8.93

 

 

$

0.92

 

Depletion

$

10.71

 

 

$

11.10

 

 

$

(0.39

)

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

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

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

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

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

43


 

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

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

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

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

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

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

Capital Expenditures

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

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

Liquidity and Capital Resources

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

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

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

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

44


 

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

 

In March 2020, crude oil prices declined to approximately $25 per barrel for Brent crude as a result of market concerns about the economic impact from the coronavirus (COVID-19) as well as the ability of OPEC and Russia to agree on a perceived need to implement further production cuts in response to weaker worldwide demand. The current futures forward curve for Brent crude indicates that prices may continue at or near current prices for an extended time. As a result, we have reduced our planned capital expenditures to those necessary for production lease maintenance and those projecting a return on invested capital at current prices. In order to mitigate the impact of reduced prices on our 2020 cash flows and liquidity, we plan to implement cost reduction measures to reduce our operating costs and general and administrative expenses. In connection therewith, we intend to prioritize funding operating expenditures over general and administrative expenditures, whenever possible.

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

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

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

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

 

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

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

 

Period Commencing

Redemption Price

November 4, 2020

105.000%

November 4, 2021

103.000%

November 4, 2022

101.000%

November 4, 2023 and thereafter

100.000%

 

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

45


 

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 2019, we paid $1.4 million in cash and issued 9,507,092 common shares as dividends on the Series A Preferred Shares.

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

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

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

The 2016 Term Loan bore interest at a fixed rate of 5.25% (plus 0.2625% for Banking and Insurance Transactions Tax per the Turkish government) per annum and was payable in six monthly installments of $1.25 million each through February 2017 and thereafter in twelve monthly installments of $1.88 million each through February 2018. On April 27, 2017, TEMI and DenizBank approved a revised amortization schedule for the 2016 Term Loan. Pursuant to the revised amortization schedule, the maturity date of the 2016 Term Loan was extended from February 2018 to June 2018, and the monthly principal payments were reduced from $1.88 million to $1.38 million.  The other terms of the 2016 Term Loan remained unchanged.

On June 28, 2018, we repaid the 2016 Term Loan in full in accordance with its terms.

2017 Term Loan. On November 17, 2017, DenizBank entered into a $20.4 million term loan (the “2017 Term Loan”) with TEMI under the Credit Agreement.  

The 2017 Term Loan bore interest at a fixed rate of 6.0% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2017 Term Loan had a grace period which bore no interest or payments due until July 2018. Thereafter, the 2017 Term Loan was payable in one monthly installment of $1.38 million, nine monthly installments of $1.2 million each through April 2019 and thereafter in eight monthly installments of $1.0 million each through December 2019, with the exception of one monthly installment of $1.2 million occurring in October 2019.  The 2017 Term Loan matured in December 2019.    

On December 30, 2019, we repaid the 2017 Term Loan in full in accordance with its terms.

 

2018 Term Loan. On May 28, 2018, DenizBank entered into a $10.0 million term loan (the “2018 Term Loan”) with TEMI under the Credit Agreement.

 

The 2018 Term Loan bore interest at a fixed rate of 7.25% (plus 0.3% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2018 Term Loan had a grace period through July 2018 during which no payments were due. Thereafter, accrued interest on the 2018 Term Loan was payable monthly and the principal on the 2018 Term Loan was payable in five monthly installments of $0.2 million each through December 2018, four monthly installments of $0.5 million each through April 2019, four monthly installments of $1.0 million each through August 2019, and four monthly installments of $0.75 million each through December 2019. The 2018 Term Loan matured in December 2019.

On December 30, 2019, we repaid the 2018 Term Loan in full in accordance with its terms.

2019 Term Loan. On February 22, 2019, DenizBank entered into a $20.0 million term loan (the “2019 Term Loan”) with TEMI under the Credit Agreement.

46


 

The 2019 Term Loan bears interest at a fixed rate of 7.5% (plus 0.375% for Banking and Insurance Transactions Tax per the Turkish government) per annum. The 2019 Term Loan had a grace period through December 2019 during which no payments were due. Thereafter, accrued interest on the 2019 Term Loan is payable monthly, and the principal on the 2019 Term Loan is payable in 14 monthly installments of $1.4 million each. The 2019 Term Loan matures in February 2021. Amounts repaid under the 2019 Term Loan may not be reborrowed, and early repayments under the 2019 Term Loan are subject to early repayment fees. The 2019 Term Loan is guaranteed by and Petrogas, Amity Oil International Pty Ltd (“Amity”), Talon Exploration, Ltd. (“Talon Exploration”), DMLP, Ltd. (“DMLP”), and TransAtlantic Turkey, Ltd. (“TransAtlantic Turkey”).

The 2019 Term Loan contains standard prohibitions on the activities of TEMI as the borrower, including prohibitions on encumbering or creating restrictions or limitations on all or a part of its assets, revenues, or properties, giving guaranties or sureties, selling assets or transferring revenues, dissolving, liquidating, merging, or consolidating, incurring additional debt, paying dividends, making certain investments, undergoing a change of control, and other similar matters. In addition, the 2019 Term Loan prohibits Amity, Talon Exploration, DMLP, and TransAtlantic Turkey from incurring additional debt. An event of default under the 2019 Term Loan includes, among other events, failure to pay principal or interest when due, breach of certain covenants, representations, warranties, and obligations, bankruptcy or insolvency, and the occurrence of a material adverse effect.

The 2019 Term Loan is secured by a pledge of (i) the stock of TEMI, DMLP, TransAtlantic Turkey, and Talon, (ii) substantially all of the assets of TEMI, (iii) certain real estate owned by Petrogas, (iv) certain Gundem real estate and Muratli real estate owned by Gundem Turizm Yatirim ve Isletmeleri A.S. (“Gundem”), (v) certain Diyarbakir real estate owned 80% by Mr. Mitchell and 20% by Mr. Uras, and (vi) certain Ankara real estate owned 100% by Mr. Uras. In addition, TEMI assigned its Turkish collection accounts and its receivables from the sale of oil to DenizBank as additional security for the 2019 Term Loan.

At December 31, 2019, we had $20.0 million outstanding under the 2019 Term Loan and no availability, and we were in compliance with the covenants in the 2019 Term Loan. On March 9, 2020, we unwound our commodity derivative contracts with respect to our future crude oil production. See “Item 1. Business—Recent Developments.” In connection with these transactions, we received approximately $6.5 million. We used these proceeds to pay down the 2019 Term Loan, which left approximately $10.6 million outstanding under the 2019 Term Loan.

Off-Balance Sheet Arrangements

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

 

47


 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

Not applicable.

Item 8. Financial Statements and Supplementary Data

See Index to Financial Statements on page F-1.

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

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

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

Management’s Annual Report on Internal Control Over Financial Reporting

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

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

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

Changes in Internal Control Over Financial Reporting

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

48


 

Item 9B. Other Information.

None.

 

 

 

49


 

PART III

 

 

Item 10. Directors, Executive Officers and Corporate Governance

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

Code of Business Conduct

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

 

 

Item 11. Executive Compensation

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

 

 

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

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

 

 

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

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

 

 

Item 14. Principal Accountant Fees and Services

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

 

 

 

50


 

PART IV

 

 

Item 15. Exhibits and Financial Statement Schedules

(a)

Documents filed as part of the Report.

 

1.

Report of Independent Registered Public Accounting Firm

 

Consolidated Balance Sheets as of December 31, 2019 and 2018

 

Consolidated Statements of Operation and Comprehensive Loss for the years ended December 31, 2019 and 2018

 

Consolidated Statements of Equity for the years ended December 31, 2019 and 2018

 

Consolidated Statements of Cash Flows for the years ended December 31, 2019 and 2018

 

Notes to Consolidated Financial Statements

2.

Exhibits required to be filed by Item 601 of Regulation S-K

 

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


51


 

EXHIBIT INDEX

 

 

 

 

 

 

3.1

  

Certificate of Continuance of TransAtlantic Petroleum Ltd., dated October 1, 2009 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 1, 2009, filed with the SEC on October 7, 2009).

 

 

 

3.2

  

Altered Memorandum of Continuance of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).

 

 

 

3.3

  

Amended Bye-Laws of TransAtlantic Petroleum Ltd., dated March 4, 2014 (incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated March 6, 2014, filed with the SEC on March 6, 2014).

 

 

 

3.4

 

Certificate of Designations of 12.0% Series A Convertible Redeemable Preferred Shares of TransAtlantic Petroleum Ltd. (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated October 31, 2016, filed with the SEC on November 4, 2016).