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EX-31.2 - EX-31.2 - TRANSATLANTIC PETROLEUM LTD.tat-ex312_7.htm
EX-21.1 - EX-21.1 - TRANSATLANTIC PETROLEUM LTD.tat-ex211_10.htm
EX-23.2 - EX-23.2 - TRANSATLANTIC PETROLEUM LTD.tat-ex232_298.htm
EX-99.1 - EX-99.1 - TRANSATLANTIC PETROLEUM LTD.tat-ex991_299.htm
EX-23.1 - EX-23.1 - TRANSATLANTIC PETROLEUM LTD.tat-ex231_386.htm
EX-10.22 - EX-10.22 - TRANSATLANTIC PETROLEUM LTD.tat-ex1022_756.htm
EX-32.1 - EX-32.1 - TRANSATLANTIC PETROLEUM LTD.tat-ex321_14.htm
EX-31.1 - EX-31.1 - TRANSATLANTIC PETROLEUM LTD.tat-ex311_18.htm
EX-32.2 - EX-32.2 - TRANSATLANTIC PETROLEUM LTD.tat-ex322_16.htm

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-K

 

(Mark One)

x

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

For the fiscal year ended December 31, 2015

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 

 

Name of each exchange on which registered 

Common shares, par value $0.10

 

NYSE MKT

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  x

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  x

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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No   ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ¨

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

 

Large accelerated filer

¨

Accelerated filer

x

 

 

 

 

Non-accelerated filer

¨  (Do not check if a smaller reporting company)

Smaller reporting company

¨

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

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, 2015 (the last business day of the registrant’s most recently completed second fiscal quarter), was approximately $22.1 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 29, 2016, there were 41,106,194 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 2016 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, 2015

INDEX

 

 

 

Page

PART I

 

 

Item 1.

Business

6

Item 1A.

Risk Factors

14

Item 1B.

Unresolved Staff Comments

25

Item 2.

Properties

26

Item 3.

Legal Proceedings

41

Item 4.

Mine Safety Disclosures

42

 

 

 

PART II

 

 

Item 5.

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

43

Item 6.

Selected Financial Data

45

Item 7.

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

46

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk.

60

Item 8.

Financial Statements and Supplementary Data

61

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

61

Item 9A.

Controls and Procedures

61

Item 9B.

Other Information

62

 

 

 

PART III

 

 

Item 10.

Directors, Executive Officers and Corporate Governance

63

Item 11.

Executive Compensation

63

Item 12.

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

63

Item 13.

Certain Relationships and Related Transactions, and Director Independence

63

Item 14.

Principal Accountant Fees and Services

63

 

 

 

PART IV

 

 

Item 15.

Exhibits and Financial Statement Schedules

64

 

 

 

 


 

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, sell assets, repay our borrowing base deficiency, continue as a going concern and restructure our debt; fluctuations in and volatility of the market prices for oil and natural gas products; the ability to produce and transport oil and natural gas; the results of exploration and development drilling and related activities; global economic conditions, particularly in the countries in which we carry on business, especially economic slowdowns; actions by governmental authorities including increases in taxes, legislative and regulatory initiatives related to fracture stimulation activities, changes in environmental and other regulations, and renegotiations of contracts; political uncertainty, including actions by insurgent groups or other conflicts; the negotiation and closing of material contracts or sale of assets; future capital requirements and the availability of financing; estimates and economic assumptions used in connection with our acquisitions; 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; our ability to effectively integrate companies and properties that we acquire; 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; negotiations with creditors; 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.

i


 

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.

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 the Company 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 production expenses and taxes.

Completion. The 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 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 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 assignment of 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 succession of sedimentary beds that were deposited under the same general geologic conditions.

Frac; fracture stimulation. A stimulation treatment involving the fracturing of a reservoir and then injecting water, sand and chemicals into the fractures under pressure 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 vertically to a certain depth and then drilled at a right angle with a specified interval.

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 costs of production.

Play. A term applied to 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

iii


 

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.

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.

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 mostly of consolidated clay or mud. 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, 2015, 2014 and 2013 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.

iv


 

Wellhead production. The volume of oil or natural gas produced after 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.

 

 

 

v


 

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, 2015, we held interests in approximately 880,000 and 567,000 net acres of developed and undeveloped oil and natural gas properties in Turkey and Bulgaria, respectively. As of March 29, 2016, approximately 36% of our outstanding common shares were beneficially owned by N. Malone Mitchell 3rd, the chairman of our board of directors and our chief executive officer.

Based on the reserves report prepared by DeGolyer and MacNaughton, independent petroleum engineers, our estimated proved reserves at December 31, 2015 in Turkey were approximately 13,457 Mboe, of which 80.4% was oil. Of these estimated proved reserves, 52.5% were proved developed reserves. As of December 31, 2015, the PV-10 and Standardized Measure, as calculated by the Company, of our proved reserves in Turkey were $222.5 million and $199.2 million, respectively. See “Item 2. Properties—Value of Proved Reserves” for a reconciliation of PV-10 to the Standardized Measure.

Recent Developments

Convertible Promissory Note. On December 30, 2015, we entered into a $5.0 million draw down convertible promissory note (the “Note”) with ANBE Holdings, L.P. (“ANBE”), an entity owned by Mr. Mitchell’s children and controlled by an entity managed by Mr. Mitchell and his wife. The Note bears interest at a rate of 13.0% per annum and matures on June 30, 2016. On December 30, 2015, we borrowed $3.6 million under the Note (the “Initial Advance”). The conversion price of the Initial Advance is $1.3755 per share.  The Initial Advance was used for general corporate purposes.  We can request subsequent advances of $500,000 under the Note prior to June 15, 2016. The Note is an unsecured obligation of the Company and is structurally subordinated to all indebtedness of our subsidiaries.

Senior Credit Facility Borrowing Base Deficiency.  Due to the significant decline in Brent crude oil prices during 2015, the borrowing base under the Company’s senior credit facility (the “Senior Credit Facility”) with BNP Paribas (Suisse) SA (“BNP Paribas”) and the International Finance Corporation (“IFC”) was decreased to $16.6 million effective December 30, 2015. The decline in the borrowing base resulted in a $15.5 million borrowing base deficiency under the Senior Credit Facility as of December 30, 2015.  

On December 30, 2015, the lenders granted us a waiver of certain defaults under the Senior Credit Facility that existed as of December 30, 2015, including, among other things, the borrowing base deficiency.  The waiver is conditioned upon, among other things, no borrowing base deficiency existing as of March 31, 2016.

As of December 31, 2015, the Company had $32.1 million outstanding under the Senior Credit Facility and no availability and was not in compliance with the current ratio financial covenant in the Senior Credit Facility.  As of March 30, 2016, the borrowing base deficiency was $14.2 million.  

We have negotiated a preliminary waiver of the existing defaults under the Senior Credit Facility and an extension of the borrowing base deficiency repayment obligation until at least September 30, 2016.  This preliminary waiver and extension is subject to the approval of the lenders’ respective credit committees.  The lenders have advised us that they will seek credit committee approval of the preliminary waiver and extension in early April 2016.  We cannot guarantee that this waiver and extension will be approved by our lenders.  Because we are currently in default under the Senior Credit Facility and will be unable to repay the borrowing base deficiency by March 31, 2016, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, could foreclose against the assets securing their borrowings, and we could be forced into bankruptcy or liquidation.  In addition, a payment default under the Senior Credit Facility could result in a cross default under our 13.0% convertible notes due 2017 (“Convertible Notes”).

Sale of Albania Operations. In February 2016, we sold all of the outstanding equity in our wholly-owned subsidiary, Stream Oil & Gas Ltd. (“Stream”), to GBC Oil Company Ltd. (“GBC Oil”) in exchange for (i) the future payment of $2.3 million to Raiffeisen

6


 

Bank Sh.A (“Raiffeisen”) to pay down a term loan facility (the “Term Loan Facility”) dated as of September 17, 2014 between Stream’s wholly-owned subsidiary, TransAtlantic Albania Ltd. (“TransAtlantic Albania”), and Raiffeisen, and (ii) the assumption of $29.2 million of liabilities owed by Stream, consisting of $23.1 million of accounts payable and accrued liabilities and $6.1 million of debt.  TransAtlantic Albania owns all of our former Albanian assets and operations.  In addition, GBC Oil issued us a warrant pursuant to which we have the option to acquire up to 25% of the fully diluted equity interests in TransAtlantic Albania for nominal consideration at any time on or before March 1, 2019.  Prior to the sale of Stream to GBC Oil, TransAtlantic Albania entered into an assignment and assumption agreement pursuant to which TransAtlantic Albania will assign its Delvina natural gas assets and $12.9 million of associated liabilities (the “Delvina Gas Liabilities”) to Delvina Gas Company, Ltd. (“Delvina Gas”), our newly formed, wholly-owned subsidiary, to be effective immediately upon receipt of required contractual consents.  There is no assurance that we will be able to obtain the required contractual consents.  In addition, we agreed to indemnify GBC Oil and Stream for the Delvina Gas Liabilities.  We are currently negotiating a joint venture with a third party for the purchase of a portion of Delvina Gas.  There is no assurance that we will be able to complete a joint venture for the purchase of a portion of Delvina Gas.  

Our Properties and Operations

Summary of Geographic Areas of Operations

The following table shows net reserves information as of December 31, 2015:

 

 

 

 

 

 

Proved

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Proved Developed

 

 

Undeveloped

 

 

Total Proved

 

 

Probable Reserves

 

 

Possible Reserves

 

 

Reserves (Mboe)

 

 

Reserves (Mboe)

 

 

Reserves (Mboe)

 

 

(Mboe)

 

 

(Mboe)

 

Turkey

 

7,061

 

 

 

6,396

 

 

 

13,457

 

 

 

14,307

 

 

 

22,995

 

Albania(1)

 

4,241

 

 

 

938

 

 

 

5,179

 

 

 

15,439

 

 

 

13,601

 

 

 

(1)

As of December 31, 2015, we have classified our Albanian assets and liabilities as held for sale and presented the operating results within discontinued operations for all periods presented in our consolidated financial statements in this Annual Report on Form 10-K.  In February 2016, we sold all of the outstanding equity in Stream to GBC Oil.  Stream’s wholly owned subsidiary, TransAtlantic Albania, owns all of our former Albanian assets and operations.  Prior to the sale of Stream to GBC Oil, TransAtlantic Albania entered into an assignment and assumption agreement pursuant to which TransAtlantic Albania will assign its Delvina natural gas assets and the Delvina Gas Liabilities to Delvina Gas to be effective immediately upon receipt of required contractual consents. There is no assurance that we will be able to obtain the required contractual consents.  We are currently negotiating a joint venture with a third party for the purchase of a portion of Delvina Gas.  There is no assurance that we will be able to complete a joint venture for the purchase of a portion of Delvina Gas.  

Turkey

As of December 31, 2015, we held interests in 18 onshore and offshore exploration licenses and 25 onshore production leases covering a total of 1.4 million gross acres (880,000 net acres) in Turkey. As of December 31, 2015, we had total net proved reserves of 10,815 Mbbl of oil and 15,847 Mmcf of natural gas, net probable reserves of 10,931 Mbbl of oil and 20,253 Mmcf of natural gas and net possible reserves of 11,205 Mbbl of oil and 70,739 Mmcf of natural gas in Turkey. During 2015, our average wellhead production was approximately 5,128 net Boepd of oil and natural gas in Turkey. The following summarizes our core producing properties in Turkey:

Southeastern Turkey. During 2015, substantially all of our oil production was concentrated in southeastern Turkey, primarily in the Arpatepe, Bahar, Goksu and Selmo oil fields. These fields are located southwest of the Turkish portion of the Zagros fold belt. The Zagros fold belt 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. The Selmo oil field is the second largest oil field in Turkey in terms of historical cumulative production and is responsible for the largest portion of our current crude oil production. We expanded our waterflood program and executed several low-cost production optimizations in the Selmo field in 2015.  We believe secondary recovery will continue to increase production recovery from the field. For 2015, our net wellhead production of crude oil from the Selmo field was 934,777 Bbls at an average rate of approximately 2,561 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 from the Selmo oil field, which is transported by truck to their neighboring facilities. At December 31, 2015, we had 69 gross and net producing wells in the Selmo oil field.

We hold a 100% working interest in each of our three Molla exploration licenses, which contain the Goksu and Bahar oil fields. In the Goksu field, we are primarily targeting the Mardin formation, and in the Bahar field, we are primarily targeting the Bedinan and

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Hazro formations. In 2015, we drilled three wells, completed one well, and completed one re-entry well as a water injection well in the Bahar field. For 2015, our wellhead production of crude oil from the Molla exploration licenses was 491,090 Bbls at an average rate of approximately 1,345 Bbl/d. At December 31, 2015, we had six gross and net producing wells on the Molla exploration licenses.

We hold a 50% working interest in our Arpatepe production lease and exploration license. For 2015, our wellhead production of crude oil from the Arpatepe field was 51,527 Bbls at an average rate of approximately 141 Bbl/d. At December 31, 2015, we had seven gross (3.5 net) producing wells on the Arpatepe production lease. We became the operator of the Arpatepe production lease in December 2015.

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 near Istanbul.

Bulgaria

As of December 31, 2015, we held interests in one onshore exploration license and one onshore production concession covering a total of 567,106 acres in Bulgaria. During 2015, we had no production in Bulgaria.  At December 31, 2015, we had no reserves in Bulgaria.

Albania

In November 2015, we launched a marketing process for the sale of all of our oil and natural gas assets and operations in Albania.  Accordingly, as of December 31, 2015, we have classified our Albanian segment as assets and liabilities held for sale and presented the operating results within discontinued operations for all periods presented in our consolidated financial statements included in this Annual Report on Form 10-K.  

In February 2016, we sold all of the outstanding equity in Stream to GBC Oil.  Stream’s wholly owned subsidiary, TransAtlantic Albania, owns all of our former Albanian assets and operations.  Prior to the sale of Stream to GBC Oil, TransAtlantic Albania entered into an assignment and assumption agreement pursuant to which TransAtlantic Albania will assign its Delvina natural gas assets and the Delvina Gas Liabilities to Delvina Gas to be effective immediately upon receipt of required contractual consents. There is no assurance that we will be able to obtain the required contractual consents.  We are currently negotiating a joint venture with a third party for the purchase of a portion of Delvina Gas.  There is no assurance that we will be able to complete a joint venture for the purchase of a portion of Delvina Gas.  See “—Recent Developments.”  

Current Operations

As of March 24, 2016, our net wellhead production in Turkey was an aggregate of approximately 3,750 Bbl/d, primarily from the Selmo production lease, Arpatepe production lease and Molla exploration licenses, and approximately 5.7 Mmcf/d of natural gas, primarily from our various Thrace Basin production leases and exploration licenses.

In January 2016, we completed the Bahar-7 and Bahar-9 wells in the Bedinan formation.  The initial production rate on the Bahar-7 well was approximately 570 Bbl/d of oil and 300 Mmcf/d of natural gas.  The Bahar-9 well tested both oil and water and was temporarily plugged back.  In February 2016, we completed the Hazro formation in the Bahar-9 well, which had an initial production rate of approximately 100 Bbl/d of oil.  We expect to commingle producing zones when our electrification and our artificial lift program is completed later in 2016.  We are continuing our well optimization work program in the Selmo oil field and have been able to stem natural decline as a result.

Planned Operations

We expect our net field capital expenditures for 2016 to range between $5.0 million and $15.0 million. Given the market conditions and our limited access to capital, our 2016 development plan may be limited to drilling obligation wells and performing low cost, high return well optimizations.  We expect net field capital expenditures during 2016 to include approximately $5.0 million of drilling and completion expense for gross obligation wells to hold our most promising licenses in Turkey. We expect cash on hand and cash flow from operations will be sufficient to fund our 2016 net field capital expenditures.  If not, we will either curtail our discretionary capital expenditures or seek other funding sources. Our projected 2016 capital expenditure budget is subject to change.

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Principal Markets

In accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, Segment Reporting (“ASC 280”), we had three reportable geographic segments during 2015: Turkey, Albania and Bulgaria. For financial information about our operating segments and geographic areas, refer to “Note 12—Segment information” to our consolidated financial statements.

Customers

Oil. During 2015, 56.6% of our oil production was concentrated in the Selmo field in Turkey. TUPRAS purchases the majority of our oil production. During 2015, we sold $63.0 million of oil to TUPRAS, representing approximately 74.0% of our total revenues. We sell all of our southeastern Turkey oil to TUPRAS pursuant to a domestic crude oil purchase and sale agreement. Under the purchase and sale agreement, TUPRAS purchases oil produced by us and delivered to our Boru Hatlari ile Petrol Tasima A.S. (“BOTAŞ”) Batman tanks and to the BOTAŞ Dörtyol plant. The price of the oil delivered pursuant to the purchase and sale agreement is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. The purchase and sale agreement automatically renews for successive one-year terms unless earlier terminated in writing by either party. No other purchasers of our oil accounted for more than 10% of our total revenues.

Natural Gas. During 2015, no purchasers of our natural gas 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 intense competition from independent, technology-driven companies as well as 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, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. We have successfully utilized fracture stimulation in our Thrace Basin, Molla and Selmo licenses and production leases.

For unconventional reservoirs, including the Mezardere formation in the Thrace Basin, a typical fracture stimulation consists of injecting between 20,000 and 100,000 gallons of fluid that contain between 10,000 and 150,000 pounds of sand. Fluids vary depending on formation and treatment objective but, in general, are either slickwater (fresh water with salt and friction reducer) or a gelled fluid containing organic polymers with a 4% potassium chloride solution and required breakers. Fracture stimulations in 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 10,000 and 100,000 pounds of sand. Fluids are generally a mixture of slickwater and gells, which is typical in  stimulation. The size of fracture stimulation treatments is dependent on net pay thickness and the proximity of the hydrocarbon zones of interest to water bearing zones.

Although the cost of each well will vary, on average approximately 30% of the total cost of drilling and completing a well in the unconventional Mezardere formation in the Thrace Basin and approximately 15% of the total cost of completing a well at Selmo 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 believe that the stacked nature of the sandstone intervals within the Mezardere unconventional formation, which is up to approximately 5,300 feet thick, and the limited number of deep penetrations to date on these structures provides significant opportunities for additional drilling and multi-stage fracs as the program matures.

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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 into the surface casing 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. 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, including recycling approximately 50% of these fluids.

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

Governmental Regulations

Government Regulation. 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, 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 restrictions on the repatriation of earnings or capital to foreign entities from Turkey, Albania or Bulgaria. However, there can be no assurance that any such restrictions 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.

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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.

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

Insurance

We currently carry general liability insurance and excess liability insurance, including pollution insurance, with a combined annual limit of $22.0 million per occurrence and $24.0 million in the aggregate. These insurance policies contain maximum policy limits and are subject to customary exclusions and limitations. Our general liability insurance covers us and our subsidiaries for third-party claims and liabilities arising out of lease operations and related activities. The excess liability insurance is in addition to, and is triggered if, the general liability insurance per occurrence limit is reached.  We also maintain control of well insurance. Our control of well insurance has a per occurrence and combined single limit of $15.0 million and is subject to deductibles ranging from $150,000 to $500,000 per occurrence.  We will continue to monitor our insurance coverage and will maintain appropriate levels of insurance to satisfy applicable regulations, as well as maintain levels of insurance appropriate for prudent operations within the industry in which we operate.

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

We also require our third-party service providers that perform fracture stimulation operations for us to sign master service agreements containing the indemnification provisions noted above. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to fracture stimulation operations. We believe that our general liability, excess 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.

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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, 2015, we employed 402 people in Albania, 178 people in Turkey, 39 people in Addison, Texas and three people in Bulgaria. Approximately 38 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”). Approximately 36 of our employees at another of our subsidiaries operating in Turkey were represented by a separate collective bargaining agreement with PETROL-IS. We consider our employee relations to be satisfactory.

Formation

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

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our website at www.transatlanticpetroleum.com as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC.

Executive Officers of the Registrant

The following table and text sets forth certain information with respect to our executive officers as of March 1, 2016:

 

Name 

 

Age

 

Positions 

N. Malone Mitchell 3rd

 

54

 

Chairman and Chief Executive Officer

Todd C. Dutton

 

62

 

President

Wil F. Saqueton

 

46

 

Vice President and Chief Financial Officer

Chad D. Burkhardt

 

41

 

Vice President, General Counsel and Corporate Secretary

Harold “Lee” Muncy

 

63

 

Vice President of Geosciences

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, 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.

Todd C. Dutton has served as our president since May 2014.  Mr. Dutton has served as president of Longfellow Energy, LP ("Longfellow"), a Dallas, Texas-based independent oil and natural gas exploration and production company owned by the Company's chairman and chief executive officer, N. Malone Mitchell 3rd and his family, since January 2007, where his primary responsibility is to originate and develop oil and natural gas projects. He brings 39 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.

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Wil F. Saqueton has served as the Company’s vice president and chief financial officer since August 2011. Mr. Saqueton previously served as the Company’s corporate controller from May 2011 until August 2011 and as a consultant to the Company from February 2011 until May 2011. Prior to joining the Company, Mr. Saqueton served as the vice president and chief financial officer of BCSW, LLC, the owner of Just Brakes in Dallas, Texas, from July 2006 to December 2010. From July 1995 until July 2006, he held a variety of positions at Intel Corporation, including strategic controller at the Chipset Group, operations controller at the Americas Sales and Marketing Organization Division, finance manager at the Intel Online Services, Inc. Division and senior financial analyst at the Chipset Group. Prior to 1995, Mr. Saqueton was a senior associate at Price Waterhouse, LP.

Chad D. Burkhardt has served as the Company’s vice president, general counsel and corporate secretary since August 2015.  From 2008 until August 2015, Mr. Burkhardt served as partner in the corporate department of Baker Botts L.L.P., where he advised clients on various corporate transactions including corporate securities offerings, mergers and acquisitions and various public company filings.  Mr. Burkhardt brings significant cross-border and international transaction experience from a variety of industries ranging from oil and gas exploration, midstream, and oil field services to high-tech and start-up transactions. Mr. Burkhardt is a graduate of Duke University School of Law.

Harold “Lee” Muncy has served as the Company’s vice president of geosciences since June 2014.  Mr. Muncy previously served as vice president, exploration for the Bass Companies, a group of Fort Worth, Texas-based independent oil and natural gas exploration and production companies, where he worked from 2000 to 2012. He brings more than 35 years of geological experience in the oil and natural gas industry, where he has focused on exploration, exploitation and worldwide transactions. He began his career as a geologist with Mobil Oil Corporation and served as exploration manager for Fina Oil & Chemical Company and vice president of exploration and land for TransTexas Gas Corp. Mr. Muncy earned a B.S. and an M.S. in Geology & Mineralogy from The Ohio State University.

 

 

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Item 1A. Risk Factors

Risks Related to Our Business

We are currently in default under our Senior Credit Facility, and our Senior Credit Facility lenders could foreclose against the assets securing their borrowings, and we could be forced into bankruptcy or liquidation.

As of December 31, 2015, we had $32.1 million outstanding under the Senior Credit Facility and no availability and were not in compliance with the current ratio financial covenant in the Senior Credit Facility.  

In addition, we had a borrowing base deficiency as of December 30, 2015.  On December 30, 2015, the lenders granted us a waiver of certain defaults under the Senior Credit Facility that existed as of December 30, 2015, including, among other things, the borrowing base deficiency. The waiver is conditioned upon, among other things, no borrowing base deficiency existing as of March 31, 2016. As of March 30, 2016, the borrowing base deficiency was $14.2 million.  We will not be able to repay the borrowing base deficiency by March 31, 2016.  A payment default under the Senior Credit Facility could result in a cross default under the Convertible Notes.

As a result of our current rational financial covenant default under the Senior Credit Facility or our future failure to repay the borrowing base deficiency on or before March 31, 2016, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, could foreclose against the assets securing their borrowings, and we could be forced into bankruptcy or liquidation.

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

Our current liquidity position is very constrained.  Even if we obtain the funds to repay our borrowing base deficiency, we would need some form of debt restructuring, capital raising effort or asset sale in order to fund our operations and meet our substantial debt service obligations of approximately $41.9 million in 2016 and $55.0 million in 2017. 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, 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, our secured lenders could foreclose against the assets securing their borrowings or freeze our accounts, 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 from continuing operations for the fiscal year ended December 31, 2015 of $26.7 million. In addition, we had a working capital deficit (excluding assets and liabilities held for sale) of $30.1 million at December 31, 2015. We continue to experience decreased liquidity as a result of the decline in oil and natural gas commodity prices and other factors discussed below.  As of March 30, 2016, we had a borrowing base deficiency of $14.2 million under the Senior Credit Facility that must be repaid by March 31, 2016 and were not in compliance with the current ratio financial covenant as of December 31, 2015.  We will not be able to repay the borrowing base deficiency by March 31, 2016.  Consequently, we have undertaken marketing effects with respect to certain assets to fund our operations and debt obligations. However, proceeds from these potential asset sales may not provide sufficient liquidity to fund operations and debt obligations for the next twelve months. These factors 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.

Oil prices have decreased substantially from historic highs and may remain depressed for the foreseeable future. The decline in oil prices has materially and adversely affected our cash generated from operations, results of operations, financial position, our ability to repay our debt, and the trading price of our common shares.

Since the second half of 2014, oil prices have declined significantly. As a result of the decrease in oil prices, we incurred an impairment of proved oil and natural gas properties and exploratory well costs of $16.0 million, not including an impairment on goodwill of $5.5 million, during the year ended December 31, 2015, which reduced earnings and shareholders’ equity. In addition, as a result of decreased oil and natural gas prices, our borrowing base under the Senior Credit Facility was reduced, which resulted in a borrowing base deficiency of $14.2 million as of March 30, 2016.  

We may incur additional impairments of our oil and natural gas properties and experience continued constrained liquidity if prices do not increase. The possibility and amounts of any future impairments or losses are difficult to predict, and will depend, in part, upon

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future oil and natural gas prices. If prices for oil continue to remain depressed for lengthy periods, we may be required to write down the value of our oil and natural gas properties, and some of our current projects may no longer be economically viable. In addition, sustained low prices for oil will negatively impact the value of our estimated proved reserves and reduce the amounts of cash we would otherwise have available to fund the drilling of obligation wells, pay expenses and service our indebtedness. If we are unable to fund the drilling of some or all of our obligation wells, we could lose some or all of our licenses.

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

We have incurred substantial losses in prior years. During 2015, we generated a net loss from continuing operations of $26.7 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.

Our Senior Credit Facility contains various restrictive covenants that limit our management’s discretion in the operation of our business and could lead to an event of default that may adversely affect our business, financial condition and results of operations.

The operating and financial restrictions and covenants in our Senior Credit Facility may adversely affect our ability to finance future operations or capital needs or to engage in other business activities.

Our Senior Credit Facility contains various covenants that restrict our ability to, among other things:

 

·

incur additional debt;

 

·

create liens;

 

·

enter into any hedge agreement for speculative purposes;

 

·

engage in business other than as an oil and natural gas exploration and production company;

 

·

enter into sale and leaseback transactions;

 

·

enter into any merger, consolidation or amalgamation;

 

·

declare or provide for any dividends or other payments or distributions;

 

·

redeem or purchase any shares; or

 

·

guarantee the obligations of any other person.

In addition, the Senior Credit Facility requires us to maintain specified financial ratios and tests.  Various risks, uncertainties and events beyond our control could affect our ability to comply with the covenants and financial tests and ratios required by the Senior Credit Facility and could result in an event of default under the Senior Credit Facility.  As of December 31, 2015, we were not in compliance with the current ratio financial covenant in the Senior Credit Facility, which is an event of default.  

An event of default under the Senior Credit Facility includes, among other events, failure to pay principal or interest when due, breach of certain covenants and obligations, cross default to other indebtedness, bankruptcy or insolvency, failure to meet the required financial covenant ratios and the occurrence of a material adverse effect. In addition, the occurrence of a change of control is an event of default. A change of control is defined as the occurrence of any of the following: (i) our failure to own, of record and beneficially, all of the equity of TransAtlantic Exploration Mediterranean International Pty Ltd (“TEMI”), Talon Exploration, Ltd. (“Talon Exploration”), TransAtlantic Turkey, Amity Oil International Pty. Ltd. (“Amity”), Petrogas Petrol Gaz ve Petrokimya Ürünleri Inşaat Sanayi ve Ticaret A.Ş. (“Petrogas”), and DMLP, Ltd. (“DMLP,” and together with TEMI, Talon Exploration, TransAtlantic Turkey, Amity and Petrogas, the “Borrowers”) or either of TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide, Ltd. (“TransAtlantic Worldwide”) or to exercise, directly or indirectly, day-to-day management and operational control of any Borrower or TransAtlantic Petroleum (USA) Corp. and TransAtlantic Worldwide; (ii) the failure by the Borrowers to own or hold, directly or indirectly, all of the interests granted to Borrowers pursuant to certain hydrocarbon licenses designated in the Senior Credit Facility; or (iii) (a) Mr. Mitchell ceases for any reason to be the executive chairman of our board of directors at any time, (b) Mr. Mitchell and certain of his affiliates cease to own of record and beneficially at least 35% of our common shares; or (c) any person or group, excluding Mr. Mitchell and certain of his affiliates, shall become, or obtain rights to become, the beneficial owner, directly or indirectly, of more than 35% of our outstanding common shares entitled to vote for members of our board of directors on a fully-diluted basis; provided that, if Mr. Mitchell ceases to be executive chairman of our board of directors by reason of his death or disability, such event shall not constitute an event of default unless we have not appointed a successor reasonably acceptable to the lenders within 60 days of the occurrence of such event.

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In the event of a default and acceleration of indebtedness under the Senior Credit Facility, our business, financial condition and results of operations may be materially and adversely affected.

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.

The majority 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 purchases all of our oil production from Turkey, representing 74.0% of our total revenues in 2015. If TUPRAS reduces its oil purchases or fails to purchase our oil production, or there is a material non-payment, our results of operations could be materially and adversely affected. TUPRAS may be subject to its own operating risks that could increase the risk that it could default on its obligations to us. Under Turkish law, TUPRAS is obligated to purchase all of our oil production in Turkey, and we are prohibited from selling any of our oil produced in Turkey to any other customer. Pursuant to a purchase and sale agreement with TUPRAS, the price of oil delivered to TUPRAS is determined under the Petroleum Market Law No. 5015 under the laws of the Republic of Turkey. Changes to Turkish law could adversely affect our business and results of operations.

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

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

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, 2015, of our total net undeveloped acreage, 25.0% and 7.0% will expire during 2016 and 2017, 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 or all of our obligation wells, and we could lose some or all of our licenses.

Virtually 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.

Virtually all of our international operations are performed in the emerging markets of Turkey and Bulgaria, which may expose us to greater risks 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, 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;

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·

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;

 

·

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

 

·

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 southeastern Turkey and nearby countries could adversely affect our business.

During 2015, we derived 56.6% of our oil production from the Selmo oil field in southeastern Turkey. Historically, the southeastern area of Turkey and nearby countries such as Iran, Iraq and Syria have experienced political, social, security and economic problems, terrorist attacks, insurgencies, war and civil unrest. Since December 2010, political instability has increased markedly in a number of countries in the Middle East and North Africa. As a result of the civil war in Syria, hundreds of thousands of Syrian refugees have fled to Turkey and more can be expected to cross the border as the conflict continues. Moreover, tensions continue between Turkey and Syria, and Turkey’s relations with Russia have recently deteriorated.

The current conflict with the terrorist group Islamic State in Iraq and Syria (“ISIS”), as well as tension in and involving the Kurdish regions of northern Iraq, which are contiguous to the region where our southeast Turkey licenses are located, may have political, social or security implications in Turkey or otherwise have a negative impact on the Turkish economy. Stability and security in Iraq deteriorated significantly since 2014 due to the conflict with ISIS.  

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.

In response to escalating violence, the United States has increased military operations against ISIS. In addition, Turkey has authorized military action, engaging in recent land and air strikes, against ISIS and PKK.  This instability has raised concerns regarding security in the region, including Turkey, and these situations may escalate in the future to more violent events.  

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. Despite these precautions, the safety of our personnel and operations in these locations may continue to be at risk, and we may in the future suffer the loss of employees and contractors or our operations could be disrupted, any of which could have a material adverse effect on our business and results of operations.

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

As of December 31, 2015, approximately 39 of our employees at one of our subsidiaries operating in Turkey were represented by collective bargaining agreements with PETROL-IS. In 2015, we negotiated a collective bargaining agreement with PETROL-IS covering approximately 41 employees at another of our subsidiaries operating in Turkey. Potential work disruptions from labor disputes with these employees could disrupt our business and adversely affect our financial condition and results of operations.

We could be assessed for Canadian federal tax as a result of our 2009 continuance under the Bermuda Companies Act 1981.

For Canadian tax purposes, we were deemed, immediately before the completion of our 2009 continuance under the Bermuda Companies Act 1981, to have disposed of each property owned by us for proceeds equal to the fair market value of that property, and

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will be subject to tax on any resulting net income. In addition, we were required to pay a special “branch tax” equal to 25% of any excess of the fair market value of our property over the “paid-up capital” (as defined in the Income Tax Act (Canada)) of our outstanding common shares and our liabilities. However, management, together with its professional advisors, has determined that the paid-up capital of our common shares and our liabilities exceeded the fair market value of our property, resulting in no “branch tax” being payable. The Canada Revenue Agency (“CRA”) may not accept our determination of the fair market value of our property. In the event that CRA’s determination of fair market value is significantly higher than our valuation and such determination is final, we may be subject to material amounts of tax resulting from the deemed disposition.

Risks Related to the Oil and Natural Gas Industry

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

Oil and natural gas prices historically have been volatile and may continue to be volatile in the future. Therefore, even if oil prices recover for a period of time, volatility will remain, and prices could move downward or upward on a rapid or repeated basis. The decline since late 2014 in oil and natural gas prices has reduced our revenue, cash flows and access to capital and, unless commodity prices improve, this trend will likely continue or worsen. 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 our ability to maintain or increase our current levels of borrowing, our ability to repay current or future indebtedness, our ability to 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;

 

·

technological advances affecting energy consumption and conservation;

 

·

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

 

·

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.

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

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.

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

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

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

We follow the successful efforts method of accounting for our oil and gas operations. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether proved reserves have been discovered. If proved reserves are not discovered with an exploratory well, the costs of drilling the well are expensed.

The capitalized costs of our oil and natural gas properties, on a depletion pool basis, cannot exceed the estimated undiscounted future net cash flows of that depletion pool. If net capitalized costs exceed undiscounted future net revenues, we generally must write down the costs of each depletion pool to the estimated fair value (discounted future net cash flows of that depletion pool). Any such charge will not affect our cash flow from operating activities, but will reduce our earnings and shareholders’ equity. For example, in the year ended December 31, 2015, as a result of significant declines in oil commodity prices, we incurred a loss of $16.0 million on proved impairment and exploratory well costs, not including an impairment on goodwill of $5.5 million. A further decline in oil or natural gas prices from current levels, or other factors, could cause a further 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.

After oil and natural gas prices recover, the long-term performance of our business will depend upon our ability to identify, acquire and develop additional oil and natural gas reserves that are economically recoverable. Future success will depend 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.

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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.

After oil and natural gas prices recover, 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;

 

·

pipeline and processing interruptions or unavailability;

 

·

title problems;

 

·

adverse weather conditions;

 

·

lack of market demand for oil and natural gas;

 

·

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.

At December 31, 2015, approximately 47.5% 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, 2015, 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, sand and chemicals into rock formations 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

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questions regarding the drilling fluids used in the fracturing process, their effect on drinking water supplies, the use of water in connection with completion operations, and the potential for impact to surface water, groundwater and the environment generally.

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

We are subject to operating hazards.

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

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. Our costs to comply with these numerous laws, regulations, licenses and permits are significant.

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

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accidental spills, leakages or other circumstances could expose us to extensive liability. We are unable to predict the effect of additional environmental laws and regulations that may be adopted in the future, including whether any such laws or regulations would materially adversely increase our cost of doing business or affect operations in any area.

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

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

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

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

 

·

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.

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.  

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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.

Our hedging transactions expose us to counterparty credit risk.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

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

We operate in the highly competitive areas of oil and natural gas exploration, development, production and acquisition with a number of other companies, including U.S.-based and foreign companies doing business in each of the countries in which we operate. We face intense competition from independent, technology-driven companies as well as from both major and other independent oil 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 29, 2016, Mr. Mitchell beneficially owned approximately 36% of our outstanding common shares. In addition, persons and entities affiliated with Mr. Mitchell participated in our offering of $55.0 million aggregate principal amount of Convertible Notes and have the right to convert their Convertible Notes to common shares subject to the terms and conditions of the Convertible Notes.  Dalea Partners, LP, an affiliate of Mr. Mitchell, purchased $2.0 million of the Convertible Notes; trusts benefitting Mr. Mitchell’s four children each purchased $2.0 million of the Convertible Notes; Pinon Foundation, a non-profit charitable organization directed by Mr. Mitchell’s spouse, purchased $10.0 million of the Convertible Notes; and a trust benefitting Barbara and Terry Pope, Mr. Mitchell’s sister-in-law and brother-in-law, purchased $200,000 of the Convertible Notes.  Also, on December 30, 2015, we entered into a $5.0 million draw down convertible promissory note (the “Note”) with ANBE Holdings L.P. (“ANBE”), an entity owned by the children of Mr. Mitchell, and controlled by an entity managed by Mr. Mitchell and his wife.  ANBE has the right to convert the principal amount outstanding under the Note to common shares ($3.6 million as of December 31, 2015) subject to the terms and conditions of the Note.   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 our 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.

 

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

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

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

 

·

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

 

·

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

 

·

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;

 

·

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; and

 

·

our ability to raise additional funds or restructure our debt.

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.

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

Management believes that we are not currently a passive foreign investment company. However, we may have been a passive foreign investment company during one or more of our prior taxable years and could become a passive foreign investment company in the future. In general, classification of our company as a passive foreign investment company during a period when a U.S. shareholder holds common shares could result in certain adverse U.S. federal income tax consequences to such shareholder.

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

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

Risks Related to Our Indebtedness

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

We have a significant amount of indebtedness. Our substantial 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, our ability to raise capital and our future operating performance, which will be affected by prevailing economic conditions and financial, business and other factors affecting our company and industry, many of which are beyond our control.

 

 

Item 1B. Unresolved Staff Comments

Not applicable.

 

 

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Item 2. Properties

Turkey

General. As of December 31, 2015, we held interests in 18 onshore and offshore exploration licenses and 25 onshore production leases covering a total of approximately 1.4 million gross acres (approximately 880,000 net acres) in Turkey. We acquired our interests in Turkey through acquisitions, as well as through farm-in agreements with existing third-party license holders and through applications submitted to the Turkish General Directorate for Petroleum Affairs (the “GDPA”), 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, 2015, we had total net proved reserves of 10,815 Mbbl of oil and 15,847 Mmcf of natural gas, net probable reserves of 10,931 Mbbl of oil and 20,253 Mmcf of natural gas and net possible reserves of 11,205 Mbbl of oil and 70,739 Mmcf of natural gas in Turkey.

Equipment Yards. As of December 31, 2015, we leased equipment yards in Muratli, Diyarbakir and Tekirdag and owned equipment yards at Selmo and Edirne.

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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% and the corporate income tax rate is 20%. Our revenue from the Selmo oil field is subject to an additional 10% royalty, which is offset by the amount of exploration expense that TEMI and DMLP, the owners of our interest in the Selmo oil field, incur in Turkey. As of December 31, 2015, our carryforward exploration credit from TEMI and DMLP was $56.5 million and $6.2 million, respectively.  If those exploration expenses do not equal or exceed the amount of this additional 10% royalty, we would owe the difference. 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.

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 GDPA. 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 GDPA 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. The term of a lease is for 20 years and may be extended for two further terms of 10 years each. 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 20 years plus two further 10 year extensions if production is maintained. We have applied to the GDPA to convert some of our qualifying acreage into the new petroleum law regulations. This will be a gradual process, but we anticipate that conversion into the new petroleum law will provide for the renewal of the exploration license terms for qualifying acreage.

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Northwestern Turkey. The following map shows our interests in northwestern Turkey at December 31, 2015:

 

Adatepe (Production Lease 4959 and License 5016). We own a 50% working interest in Production Lease 4959 and License 5016, which cover approximately 3,086 gross acres and 117,000 gross acres, respectively. As of December 31, 2015, we had six gross (three net) producing wells on the Adatepe Production Lease. We are the operator of Production Lease 4959 and License 5016. The current terms of Production Lease 4959 and License 5016 expire in September 2031 and January 2016, respectively.  We are evaluating extension options for License 5016, and Production Lease 4959 has extensions available under the petroleum law.

Alpullu (Production Lease 4794) and Temrez (Licenses F17B3, F18A3, F18A4, and F18B4). We own a 100% working interest in the Alpullu Production Lease and the Temrez Licenses, which cover approximately 3,158 acres and 134,296 acres, respectively. As of December 31, 2015, we had nine gross (8.8 net) producing wells on the Alpullu Production Lease. We plan to maintain production to satisfy our obligation on the Alpullu Production Lease. We are the operator of the Alpullu Production Lease and the Temrez License, which expire in September 2028 and July 2020, respectively, with extensions available under the petroleum law.

Atakoy (Production Lease 5122). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in Production Lease 5122, which covers approximately 440 gross acres. As of December 31, 2015, we had 14 gross (5.8 net) producing wells on the Atakoy production lease. We plan to maintain production to satisfy our obligation on Production Lease 5122. We are the operator of Production Lease 5122, which expires in November 2032, with extensions available under the old and new petroleum laws.

Banarli (Production Lease 5059). We own a 50% working interest in Production Lease 5059, which covers approximately 4,608 gross acres. As of December 31, 2015, we had one gross (0.5 net) producing well on the Banarli Production Lease. We plan to maintain production to satisfy our obligation on Production Lease 5059. We are the operator of Production Lease 5059, which expires in February 2032, with extensions available under the petroleum law.

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Bekirler (License 4126). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in License 4126, which covers approximately 124,000 gross acres. We are the operator of License 4126, which expired in December 2015, but we have filed an application to convert the productive areas into a new production lease.

Dogu Adatepe (Production Lease F19-b4-1). We own a 50% working interest in the Dogu Adatepe Production Lease, which covers part of our former Cayirdere license. The lease covers approximately 4,000 gross acres and expires in October 2017, with an additional 28 years of extensions under the new petroleum law available with the maintenance of production on the production lease.

Edirne Production Leases and Habiller Production Lease. We own a 55% working interest in three Edirne Production Leases and a 100% working interest in the Habiller Production Lease, which cover an aggregate of approximately 65,000 gross acres. As of December 31, 2015, we had 20 gross (14.7 net) producing wells on the Edirne and Habiller Production Leases. We are the operator of the Edirne Production Leases and the Habiller Production Lease which expire in 2034 and March 2020, respectively, with extensions available under the petroleum law.

Gocerler (Production Lease 4200 and License 4288). We own a 50% working interest in Production Lease 4200 and License 4288, which cover approximately 3,363 gross acres and 119,000 gross acres, respectively. As of December 31, 2015, we had seven gross (3.5 net) producing wells on the Gocerler Production Lease and 13 gross (6.4 net) producing wells on License 4288. We plan to drill one well in 2016 on License 4288 to satisfy the work program for License 4288 and we plan to maintain production to satisfy our obligations on Production Lease 4200. We are the operator of Production Lease 4200 and License 4288, which expire in May 2023 and August 2017, respectively, with extensions available under the petroleum law.

Hayrabolu (Production Lease 2926). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in Production Lease 2926, which covers approximately 12,400 gross acres. As of December 31, 2015, we had 16 gross (6.6 net) producing wells on the Hayrabolu Production Lease. We plan to maintain production which satisfies our obligation on Production Lease 2926. We are the operator of Production Lease 2926, which expires in February 2020, with one ten-year extension available under the old and new petroleum laws.

Karaevli (Production Lease). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in the Karaevli Production Lease, which covers approximately 8,500 gross acres. As of December 31, 2015, we had seven gross (2.9 net) producing wells on the Karaevli lease. We are the operator of the Karaevli Production Lease.  The Karaevli Production Lease expires in November 2020, with extensions available under the petroleum law.  We have submitted an application for another Karaevli Production Lease covering approximately 15,800 gross acres, which is pending.

Karanfiltepe (Licenses F17c-2,3 and F18d-1,2,4). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in the Karanfiltepe licenses, which cover approximately 160,000 gross acres. As of December 31, 2015, we had five gross (2.1 net) producing wells on the Karanfiltepe licenses. We are the operator of the Karanfiltepe licenses, which expire in June 2020, with extensions available under the petroleum law.

Osmanli Production Leases. We own 41.5%, subject to a 0.415% overriding royalty interest, in six Osmanli Production Leases, which cover approximately 107,000 gross acres. As of December 31, 2015, we had 114 gross (47.3 net) producing wells on the Osmanli Production Leases.  We are the operator of the Osmanli Production Leases, which will not expire for 40 years if production is maintained.

Tekirdag (Production Lease 3860) and Gazioglu (Production Lease 3861). We own a 41.5% working interest, subject to a 0.415% overriding royalty interest, in Production Leases 3860 and 3861, which cover an aggregate of approximately 4,300 gross acres. As of December 31, 2015, we had 67 gross (28.2 net) producing wells on the Tekirdag and Gazioglu Production Leases. We plan to maintain production to satisfy our obligation on Production Leases 3860 and 3861. We are the operator of Production Leases 3860 and 3861, which expire in December 2023 and December 2021, respectively, with extensions available under the petroleum law.

29


 

Southeastern Turkey. The following map shows our interests in southeastern Turkey at December 31, 2015:

 

Arpatepe (Production Lease 5003 and License 5025). We own a 50% working interest in Production Lease 5003 and License 5025, which cover approximately 11,200 and 84,800 gross acres, respectively. For 2015, our wellhead production of oil from the Arpatepe field was 51,527 Bbls of oil, at an average rate of approximately 141 Bbl/d. As of December 31, 2015, we had seven gross (3.5 net) producing wells on the Arpatepe production lease. We are the operator of Production Lease 5003 and License 5025, which expire in November 2028 and February 2016, respectively, with extensions available under the old and new petroleum laws.  We are working on establishing production and extending License 5025 for at least two years.  

Bakuk (License 5064 and Production Lease 5043). We own a 50% working interest in License 5064 and Production Lease 5043. The exploration license covers approximately 61,000 gross acres, and the production lease covers approximately 34,400 gross acres. Production continues from the Bakuk-101 well, and we are evaluating additional offset well locations. Tiway Turkey, Ltd. (“Tiway”) is the operator of License 5064 and Production Lease 5043, which expire in June 2016 and January 2032, respectively, with extensions available under the petroleum law.

Bati Yasince Production Lease (Lease M45A1-1). We own a 100% working interest in the Bati Yasince Production Lease, which covers approximately 7,200 gross acres. We drilled the Bati Yasince-1 discovery well in the fourth quarter of 2014, which was producing oil as of December 31, 2015. We are the operator of the lease, which expires in 2035 with two 10 year extensions available under the petroleum law.

Gaziantep (Gaziantep Licenses). We own a 62.5% working interest in the Gaziantep Licenses, subject to a 0.313% overriding royalty interest, which cover an aggregate of 152,000 gross acres. We are the operator of the Gaziantep Licenses, which expire in October 2019. We are currently evaluating additional prospects on the Gaziantep Licenses, including an offset to the Alibey-1H discovery well.

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Idil (License 4642). We own a 50% working interest in License 4642, which covers approximately 123,000 gross acres. In February 2014, we entered into a farm-out agreement with Onshore Petroleum Company AS (“Onshore”). We are the operator of License 4642, which expires in October 2016.

Molla (Licenses 4174 and 4845) and West Molla (License 5046). We own a 100% working interest in Licenses 4174, 4845 and 5046, which cover an aggregate of approximately 109,000 gross acres. As of December 31, 2015, we had six gross and net wells producing on the Molla licenses. We continue to interpret the 800 sq. km. 3D seismic data to delineate prospects on the Molla licenses. We are the operator of Licenses 4174, 4845 and 5046, which expire in June 2016, March 2017 and June 2016, respectively, with extensions available under the old and new petroleum laws.

Selmo (Production Lease 829). We own a 100% working interest in Production Lease 829, which covers 8,900 acres and includes the Selmo oil field. As of December 31, 2015, there were 69 gross and net producing wells on the Selmo production lease. For 2015, our wellhead production of oil in the Selmo field was approximately 934,777 Bbls of oil, at an average rate of approximately 2,561 Bbl/d. We are the operator of Production Lease 829, which expires in June 2025.

Bulgaria

General. As of December 31, 2015, we held interests in one onshore exploration permit and one onshore production concession in Bulgaria. We acquired all of our Bulgarian interests through the purchase of Direct Petroleum Bulgaria EOOD (“Direct Bulgaria”) in February 2011. 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, 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, 2015:

Reserves. As of December 31, 2015, there were no economic reserves associated with our properties in Bulgaria.

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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.

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, nor is customs duty payable on the import of material necessary to conduct petroleum operations. 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 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 $25 at December 31, 2015) per square kilometer, or 40 Bulgarian Lev (approximately $25 at December 31, 2015) 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 the company upon conversion to a production concession.

Koynare. We own a 100% working interest, subject to a 3.02% overriding royalty interest and Koynare Development Ltd.’s (“KDL”) 50% farm-in interest, in the Koynare production concession covering approximately 163,000 acres. The Koynare Concession Area contains the Deventci-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. In November 2011, we commenced drilling the Deventci-R2 appraisal well on the Koynare Concession Area, which we suspended following the enactment of the Bulgarian government’s January 2012 legislation. During the second half of 2013, we resumed drilling the Deventci-R2 directional well on our Koynare Concession Area. In January 2014, we reached target depth of 14,100 feet on the Deventci-R2 well, and conducted a long-term test on the well during the second quarter of 2014 with an initial production test of approximately 2.0 Mmcf/d of natural gas with condensates. In the fourth quarter of 2014, we received approval from the Bulgarian government to acidize the well. We conducted the acidizing operation in December 2014 to enhance its productivity. Following the acidizing operation, the Deventci-R2 well was deemed unproductive and was temporarily abandoned in the second quarter of 2015.

Stefenetz. In November 2011, we initiated the application process for a production concession covering approximately 395,000 acres over the southern portion of our former A-Lovech exploration permit. The Stefenetz Concession Area is estimated to contain over 300,000 prospective acres for Etropole shale at a depth of approximately 12,500 feet, which the Bulgarian government has certified as a geologic discovery. During 2012, we initiated an environmental impact assessment, which the Bulgarian government must approve prior to granting the production concession.

In September 2011, we entered into an agreement with Esrey Energy (“Esrey”) pursuant to which Esrey funded the drilling of an exploration well on the Stefenetz Concession Area to core and test the Etropole shale formation. This well, the Peshtene-R11, reached total depth in late November 2011, from which we collected more than 900 feet of core. We suspended the completion of the Peshtene-R11 well following enactment of the Bulgarian government’s January 2012 legislation. If we obtain a production concession over the Stefenetz Concession Area, Esrey would fund up to an additional $12.5 million in exchange for a 50% working interest in the production concession. The remaining 50% working interest in the production concession would be split equally between us and KDL.

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Aglen. We have applied to relinquish the Aglen exploration permit, which covers approximately 1,700 acres within the boundaries of the former A-Lovech exploration permit and lies within the boundary of the Stefenetz Concession Area.

Albania

General. As of December 31, 2015, we owned 100% of the interests in three onshore oil fields and one onshore gas field.  The following map shows our interests in Albania at December 31, 2015:

 

Reserves. As of December 31, 2015, we had total net proved reserves of 4,258 Mbbl of oil and 5,527 Mmcf of natural gas, net probable reserves of 13,062 Mbbl of oil and 14,256 Mmcf of natural gas and net possible reserves of 9,620 Mbbl of oil and 23,884 Mmcf of natural gas in Albania.  In February 2016, we sold all of the outstanding equity in Stream to GBC Oil.  Stream’s wholly owned subsidiary, TransAtlantic Albania, owns all of our former Albanian assets and operations.  Prior to the sale of Stream to GBC Oil, TransAtlantic Albania entered into an assignment and assumption agreement pursuant to which TransAtlantic Albania will assign its Delvina natural gas assets and the Delvina Gas Liabilities to Delvina Gas to be effective immediately upon receipt of required

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contractual consents. There is no assurance that we will be able to obtain the required contractual consents.  We are currently negotiating a joint venture with a third party for the purchase of a portion of Delvina Gas.  There is no assurance that we will be able to complete a joint venture for the purchase of a portion of Delvina Gas.  See “Item 1. Business—Recent Developments.”  

Commercial Terms. The following description of the commercial terms in Albania is limited to the Delvina gas field.  The Delvina gas field is subject to a License Agreement between Agjencia Kombëtare e Burimeve Natyrore, the Albanian National Agency of Natural Resources (“AKBN”), and Albpetrol, the state owned oil company in Albania, and a Petroleum Agreement with Albpetrol, which together give the owner the right to access and develop the onshore gas field. The License Agreement has a 25-year term, with unlimited five-year renewal options.  

The operator is required to submit annual work programs and budgets to Albpetrol each year, including the nature and amount of capital expenditures, which is required to be consistent with the plans of development (“PODs”) for the Delvina gas field approved by AKBN.  Significant deviations from the PODs are subject to the approval of AKBN and Albpetrol.

Pursuant to the terms of the Petroleum Agreement, the operator pays a 2% to 7.2% gross over-riding royalty to Albpetrol, which may be paid in kind or cash. In addition, the operator is required to pay a royalty to Albpetrol based on the amount of pre-existing production (“PEP”) from the wells taken over from Albpetrol.  The PEP royalty is calculated on a well by well basis and is initially equal to 65% to 70% of the PEP preceding the takeover of the well from Albpetrol.  The PEP royalty declines at a rate of 5% per year.  

In 2008, a new 10% mineral tax was enacted by the Albanian Ministry of Finance. The new mineral tax is equal to 10% of gross sales after deducting any PEP royalties paid.  Under the Petroleum Agreement, any new financial burdens (including new mineral taxes) are to be neutralized by amendments to the Petroleum Agreement. The operator is working with officials from Albpetrol and AKBN to finalize amendments to the Petroleum Agreement to neutralize the 10% mineral tax.

Delvina Field. The Delvina natural gas field was discovered in 1987 and produces natural gas and natural gas liquids from reservoirs at a depth of 2,800 to 3,500 meters from fractured carbonates of Cretaceous-Paleocene age. The Delvina natural gas field is connected to potential markets by an existing pipeline, but needs additional downstream capacity. The field has two previously producing vertical wells, the Delvina D4 and D12 wells.

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Summary of Oil and Natural Gas Reserves

The following table summarizes our net proved, probable and possible reserves at December 31, 2015.

 

 

Reserves

 

 

Oil and Condensate

(Mbbl)

 

 

Natural Gas

(Mmcf)

 

 

Total

(Mboe)

 

Reserves Category

 

 

 

 

 

 

 

 

 

 

 

Turkey (continuing operations)

 

 

 

 

 

 

 

 

 

 

 

Proved reserves

 

 

 

 

 

 

 

 

 

 

 

Proved developed

 

5,598

 

 

 

8,776

 

 

 

7,061

 

Proved undeveloped

 

5,217

 

 

 

7,071

 

 

 

6,396

 

Total proved

 

10,815

 

 

 

15,847

 

 

 

13,457

 

Probable reserves

 

 

 

 

 

 

 

 

 

 

 

Probable developed

 

1,062

 

 

 

2,931

 

 

 

1,551

 

Probable undeveloped

 

9,869

 

 

 

17,322

 

 

 

12,756

 

Total probable

 

10,931

 

 

 

20,253

 

 

 

14,307

 

Possible reserves

 

 

 

 

 

 

 

 

 

 

 

Possible developed

 

1,249

 

 

 

2,832

 

 

 

1,721

 

Possible undeveloped

 

9,956

 

 

 

67,907

 

 

 

21,274

 

Total possible

 

11,205

 

 

 

70,739

 

 

 

22,995

 

Albania (discontinued operations)(1)

 

 

 

 

 

 

 

 

 

 

 

Proved reserves

 

 

 

 

 

 

 

 

 

 

 

Proved developed

 

4,085

 

 

 

935

 

 

 

4,241

 

Proved undeveloped

 

173

 

 

 

4,592

 

 

 

938

 

Total proved

 

4,258

 

 

 

5,527

 

 

 

5,179

 

Probable reserves

 

 

 

 

 

 

 

 

 

 

 

Probable developed

 

12,391

 

 

 

1,233

 

 

 

12,597

 

Probable undeveloped

 

671

 

 

 

13,023

 

 

 

2,842

 

Total probable

 

13,062

 

 

 

14,256

 

 

 

15,439

 

Possible reserves

 

 

 

 

 

 

 

 

 

 

 

Possible developed

 

8,533

 

 

 

2,421

 

 

 

8,937

 

Possible undeveloped

 

1,087

 

 

 

21,463

 

 

 

4,664

 

Total possible

 

9,620

 

 

 

23,884

 

 

 

13,601

 

Total

 

 

 

 

 

 

 

 

 

 

 

Proved reserves

 

 

 

 

 

 

 

 

 

 

 

Proved developed

 

9,683

 

 

 

9,711

 

 

 

11,302

 

Proved undeveloped

 

5,390

 

 

 

11,663

 

 

 

7,334

 

Total proved

 

15,073

 

 

 

21,374

 

 

 

18,636

 

Probable reserves

 

 

 

 

 

 

 

 

 

 

 

Probable developed

 

13,453

 

 

 

4,164

 

 

 

14,148

 

Probable undeveloped

 

10,540

 

 

 

30,345

 

 

 

15,598

 

Total probable

 

23,993

 

 

 

34,509

 

 

 

29,746

 

Possible reserves

 

 

 

 

 

 

 

 

 

 

 

Possible developed

 

9,782

 

 

 

5,253

 

 

 

10,658

 

Possible undeveloped

 

11,043

 

 

 

89,370

 

 

 

25,938

 

Total possible

 

20,825

 

 

 

94,623

 

 

 

36,596

 

 

 

(1)

In February 2016, we sold all of the outstanding equity in Stream to GBC Oil.  Stream’s wholly owned subsidiary, TransAtlantic Albania, owns all of our former Albanian assets and operations.  Prior to the sale of Stream to GBC Oil, TransAtlantic Albania entered into an assignment and assumption agreement pursuant to which TransAtlantic Albania will assign its Delvina natural gas assets and the Delvina Gas Liabilities to Delvina Gas to be effective immediately upon receipt of required contractual consents. There is no assurance that we will be able to obtain the required contractual consents.  We are currently negotiating a joint venture with a third party for the purchase of a portion of Delvina Gas.  There is no assurance that we will be able to complete a joint venture for the purchase of a portion of Delvina Gas.  As of December 31, 2015, our Albanian assets and liabilities were classified as held for sale and presented within discontinued operations for all periods presented in our consolidated financial statements in this Annual Report on Form 10-K.  

35


 

Value of Proved Reserves

The following table shows our estimated future net revenue, PV-10 and Standardized Measure as of December 31, 2015:

 

 

Turkey

 

 

Albania

 

 

Total

 

 

(in thousands)

 

Future net revenue(1)

$

340,243

 

 

$

62,738

 

 

$

402,981

 

Total PV-10(1)(2)

$

222,497

 

 

$

26,887

 

 

$

249,384

 

Total Standardized Measure(1)

$

199,227

 

 

$

26,887

 

 

$

226,114

 

 

 

(1)

Includes amounts related to our Albanian assets that were sold in February 2016  As of December 31, 2015, our Albanian assets and liabilities were classified as held for sale and presented within discontinued operations for all periods presented in our consolidated financial statements in this Annual Report on Form 10-K.  

 

(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:

 

 

Turkey

 

 

Albania

 

 

Total

 

 

(in thousands)

 

Total PV-10(1)

$

222,497

 

 

$

26,887

 

 

$

249,384

 

Future income taxes

 

(28,900

)

 

 

-

 

 

 

(28,900

)

Discount of future income taxes at 10% per annum

 

5,630

 

 

 

-

 

 

 

5,630

 

Standardized Measure

$

199,227

 

 

$

26,887

 

 

$

226,114

 

 

 

(1)

Includes amounts related to our Albanian assets that were sold in February 2016.  As of December 31, 2015, our Albanian assets and liabilities were classified as held for sale and presented within discontinued operations for all periods presented in our consolidated financial statements in this Annual Report on Form 10-K.  

The following discussion of our proved reserves, proved undeveloped reserves, probable reserves and possible reserves as of December 31, 2015 has not been adjusted to reflect the sale of our Albanian assets in February 2016.

Proved Reserves

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

At December 31, 2015, our estimated proved reserves were 18,636 Mboe, a decrease of 14,113 Mboe, or 43.1%, compared to 32,749 Mboe at December 31, 2014.  This decrease was primarily attributable to the substantial decline in oil prices which caused developed and undeveloped reserves to become uneconomic at an earlier time, and technical revisions on Albanian reserves based on actual performance following the 2015 work program.    

At December 31, 2015, we recorded a decrease in proved reserves due to technical revisions of 12,303 Mbbl and 638 Mmcf (12,409 Mboe total).  The revision in oil of 12,303 Mbbls was mostly attributable to pricing and economics due to the substantial decline in oil prices.  As Brent oil price drops, wells become uneconomic at an earlier time thus reducing future reserves.  Approximately 75% of these reductions were attributable to the Albania properties.  There were no material revisions due to performance in Turkey.  The revision in natural gas of 638 Mmcf was primarily attributable to a reduction in Delvina natural gas reserves of 2,722 Mmcf due to market constraints and a reduced realized price, which was partially offset by an increase in proved natural gas reserves for our Turkey assets of 2,084 Mmcf due to improved performance.  The decrease in proved reserves also consisted of sales volumes of 2,066 Mboe in 2015, consisting of 1,651 Mbbls of oil and 2,491 Mmcf of natural gas.  The estimated undiscounted capital costs associated with our proved reserves in Turkey is $167.9 million.    

At December 31, 2015, we recorded an increase in proved reserves of 362 Mboe through extensions and discoveries.  These increases were due to the discovery of productive pay in the Hazro formation in the Bahar oil field.

36


 

Proved Undeveloped Reserves

At December 31, 2015, our estimated proved undeveloped reserves were 7,334 Mboe, a decrease of 3,066 Mboe, or 29.5%, compared to 10,400 Mboe at December 31, 2014. Of this decrease in proved undeveloped reserves, 2,566 Mboe was due to lower pricing and capital constraints forcing a slower development of these locations.  All of our proved undeveloped reserves as of December 31, 2015 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 $163.1 million of which $1.5 million is expected to be incurred in 2016.  In addition, during 2015, we converted 500 Mboe from proved undeveloped to proved developed reserves and incurred $8.6 million of capital expenditures during 2015 to convert such reserves.    

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.

37


 

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 retain an outside independent engineering firm to prepare estimates of our proved, probable and possible reserves. 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 2015. 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, 2015 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 Mechanical Engineering from Kansas State University. He has over 32 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 13 years of experience in oil and natural gas reservoir studies and evaluations. He has a Bachelor of Science degree in Petroleum Engineering from Texas Tech University.

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, 2015 included a detailed evaluation of our Selmo, Arpatepe, Bakuk, Molla and Thrace Basin properties in Turkey, our Cakran, Gorisht, Ballsh and Delvina properties in Albania and our West Koynare field in Bulgaria. 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.

38


 

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 the Company’s reserves as of December 31, 2015, 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 at December 31, 2015) for 2015, 2014 and 2013:

 

 

Sales Volumes

 

 

Oil (1)

 

 

Natural Gas

 

 

Total

 

Year

(Bbls)

 

 

(Mcf)

 

 

(Boe)

 

2015

 

 

 

 

 

 

 

 

 

 

 

Total Turkey

 

1,420,035

 

 

 

2,491,017

 

 

 

1,835,205

 

Selmo field

 

933,925

 

 

 

 

 

 

933,925

 

Bahar field

 

431,199

 

 

 

 

 

 

431,199

 

Total Albania

 

230,855

 

 

 

 

 

 

230,855

 

2014

 

 

 

 

 

 

 

 

 

 

 

Total Turkey

 

1,302,439

 

 

 

3,258,537

 

 

 

1,845,529

 

Selmo field

 

1,023,877

 

 

 

 

 

 

1,023,877

 

Total Albania

 

36,200

 

 

 

 

 

 

36,200

 

Gorisht-Kocul field

 

19,306

 

 

 

 

 

 

19,306

 

2013

 

 

 

 

 

 

 

 

 

 

 

Total Turkey

 

932,463

 

 

 

3,495,698

 

 

 

1,515,079

 

Selmo field

 

665,025

 

 

 

 

 

 

665,025

 

 

 

(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 2015, 2014 and 2013:

 

 

2015

 

 

2014

 

 

2013

 

Turkey:

 

 

 

 

 

 

 

 

 

 

 

Average Sales Price Oil ($/Bbl)

$

44.69

 

 

$

82.92

 

 

$

101.05

 

Natural Gas ($/Mcf)

$

7.73

 

 

$

8.67

 

 

$

9.43

 

Unit Costs Production ($/Boe)

$

6.10

 

 

$

8.56

 

 

$

10.62

 

Albania:

 

 

 

 

 

 

 

 

 

 

 

Average Sales Price Oil ($/Bbl)

$

37.10

 

 

$

52.43

 

 

$

 

Unit Costs Production ($/Boe)

$

26.02

 

 

$

31.15

 

 

$

 

39


 

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 2015, 2014 and 2013:

 

 

Development Wells

 

 

Exploratory Wells

 

 

Productive

 

 

Dry

 

 

Productive

 

 

 

 

Dry

 

Turkey:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

2.4

 

 

 

-

 

 

 

-

 

 

 

 

 

1.4

 

2014

 

14.7

 

 

 

2.0

 

 

 

4.6

 

 

 

 

 

0.4

 

2013

 

10.5

 

 

 

0.5

 

 

 

3.5

 

 

 

 

 

4.4

 

Bulgaria:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

0.3

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Albania:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

2014

 

 

 

 

 

 

 

 

 

 

 

 

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil and Natural Gas Properties, Wells, Operations and Acreage

The following discussion of our productive wells, developed acreage and undeveloped acreage as of December 31, 2015 has not been adjusted to reflect the sale of our Albanian assets in February 2016.

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, 2015:

 

 

Oil

 

 

Natural Gas

 

 

Gross (1)

 

 

Net (2)

 

 

Gross (1)

 

 

Net (2)

 

Turkey

 

84.0

 

 

 

79.9

 

 

 

164.0

 

 

 

76.2

 

Bulgaria

 

 

 

 

 

 

 

 

 

 

 

Albania

 

215.0

 

 

 

215.0

 

 

 

1.0

 

 

 

1.0

 

 

 

(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, 2015:

 

 

Developed Acres

 

 

Gross (1)

 

 

Net (2)

 

Turkey

 

278,000

 

 

 

148,000

 

Albania

 

20,000

 

 

 

20,000

 

Total

 

298,000

 

 

 

168,000

 

 

 

(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, 2015:

 

 

Undeveloped Acres

 

 

Gross (1)

 

 

Net (2)

 

Turkey

 

1,105,000

 

 

 

732,000

 

Bulgaria

 

567,000

 

 

 

567,000

 

Albania

 

56,000

 

 

 

56,000

 

Total

 

1,728,000

 

 

 

1,355,000

 

 

 

(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.

40


 

Undeveloped Acreage Expirations. The following table summarizes by year our undeveloped acreage as of December 31, 2015 that is scheduled to expire in the next five years:

 

 

Undeveloped Acres (1)

 

 

% of Total Undeveloped Acres

 

 

Gross (2)

 

 

Net (3)

 

 

Net (3)

 

2016

 

506,290

 

 

 

343,490

 

 

 

25.0

 

2017

 

152,006

 

 

 

92,361

 

 

 

7.0

 

2018

 

 

 

 

 

 

 

 

2019

 

152,107

 

 

 

95,067

 

 

 

7.0

 

2020

 

294,761

 

 

 

200,889

 

 

 

15.0

 

 

 

(1)

Excludes the Stefenetz Concession Area for which we have applied for a production concession.

 

(2)

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

 

(3)

“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 2016 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. These cases are being vigorously defended by TEMI and Turkish government authorities. We do not have enough information to estimate the potential additional operating costs we could incur in the event the purported surface owners’ claims are ultimately successful. The following is a summary of these cases.

In 2003, the villagers applied to the Kozluk Civil Court of First Instance in Turkey with seven title survey certificates dating back to Ottoman times. These villagers were granted title registration certificates, and in 2005, these villagers applied to the Kozluk Civil Court of First Instance to enlarge the areas covered by the certificates to approximately 20 square kilometers. Neither we nor, to our knowledge, any ministry in the Turkish government received notice of this court proceeding. Almost all of our production wells at the Selmo oil field lie within this enlarged area. In 2009, the Supreme Court overruled the Kozluk Civil Court of First Instance and directed it to re-examine the case (the “Surface Litigation”).

In 2006, the Turkish Forestry Authority filed a claim in the Kozluk Cadastre Court against the villagers for attempting to register land that is registered with the Turkish government as forest. TEMI joined the Turkish government as a plaintiff in that case. In February 2011, the Kozluk Cadastre Court decided to suspend the case until there is a resolution of the Surface Litigation.

In addition, TEMI is a defendant in two nuisance cases filed in the Kozluk Cadastre Court and one claim for damages filed in the Kozluk Civil Court of First Instance. The plaintiffs in each of these cases are the same villagers in the Surface Litigation. 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 these nuisance cases until there is a resolution of the Surface Litigation. On December 27, 2012, the Kozluk Civil Court of First Instance dismissed the damages case, and the plaintiffs appealed that decision.

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 file 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 Kozluck 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.

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

Direct Petroleum. In December 2014, Direct Petroleum LLC (“Direct”) filed suit against the Company alleging that it was due liquidated damages of $5.0 million worth of common shares of the Company pursuant to the second amendment of the purchase agreement between the Company and Direct. On March 15, 2016, the Company entered into a settlement agreement pursuant to which we agreed to issue 225,000 common shares of the Company to Direct in exchange for a mutual release of all current and future claims against the other party in connection with the purchase agreement.

41


 

Bulgarian Ministry of Energy and Economy. In October 2015, the Bulgarian Ministry of Energy and Economy filed a suit against Direct Bulgaria, claiming a $200,000 penalty for Direct Bulgaria’s alleged failure to fulfill the work program associated with the Aglen exploration permit. Direct Bulgaria received a force majeure recognition in 2012 from the Bulgarian Ministry of Energy and Economy, and the force majeure event has not been rectified. We believe that Direct Bulgaria is not under any obligation to fulfill the work program until the force majeure event is rectified, and continue to vigorously defend this claim.

 

 

Item 4. Mine Safety Disclosures

Not applicable.

 

 

42


 

PART II

 

 

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

Canada

Our common shares are traded in Canada on the Toronto Stock Exchange (the “TSX”) under the trading symbol “TNP”. The following table sets forth the quarterly high and low sales prices per common share in Canadian dollars on the TSX for the periods indicated. The high and low sales prices per common share for each quarterly period within the two most recent fiscal years indicated below have been adjusted to reflect our 1-for-10 reverse stock split effected March 6, 2014.

 

 

High

 

 

Low

 

2015

 

 

 

 

 

 

 

Fourth Quarter

$

4.30

 

 

$

1.41

 

Third Quarter

$

6.79

 

 

$

3.22

 

Second Quarter

$

7.50

 

 

$

5.78

 

First Quarter

$

6.80

 

 

$

5.30

 

2014: